Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, 63110-63263 [2021-24202]

Download as PDF 63110 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 60 [EPA–HQ–OAR–2021–0317; FRL–8510–02– OAR] RIN 2060–AV16 Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review Environmental Protection Agency (EPA). ACTION: Proposed rule. AGENCY: This document comprises three distinct groups of actions under the Clean Air Act (CAA) which are collectively intended to significantly reduce emissions of greenhouse gases (GHGs) and other harmful air pollutants from the Crude Oil and Natural Gas source category. First, the EPA proposes to revise the new source performance standards (NSPS) for GHGs and volatile organic compounds (VOCs) for the Crude Oil and Natural Gas source category under the CAA to reflect the Agency’s most recent review of the feasibility and cost of reducing emissions from these sources. Second, the EPA proposes emissions guidelines (EG) under the CAA, for states to follow in developing, submitting, and implementing state plans to establish performance standards to limit GHGs from existing sources (designated facilities) in the Crude Oil and Natural Gas source category. Third, the EPA is taking several related actions stemming from the joint resolution of Congress, adopted on June 30, 2021 under the Congressional Review Act (CRA), disapproving the EPA’s final rule titled, ‘‘Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review,’’ Sept. 14, 2020 (‘‘2020 Policy Rule’’). This proposal responds to the President’s January 20, 2021, Executive order (E.O.) titled ‘‘Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,’’ which directed the EPA to consider taking the actions proposed here. DATES: Comments. Comments must be received on or before January 14, 2022. Under the Paperwork Reduction Act (PRA), comments on the information collection provisions are best assured of consideration if the Office of Management and Budget (OMB) receives a copy of your comments on or before December 15, 2021. khammond on DSKJM1Z7X2PROD with PROPOSALS2 SUMMARY: VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 Public hearing: The EPA will hold a virtual public hearing on November 30, 2021 and December 1, 2021. See SUPPLEMENTARY INFORMATION for information on the hearing. ADDRESSES: You may send comments, identified by Docket ID No. EPA–HQ– OAR–2021–0317 by any of the following methods: • Federal eRulemaking Portal: https://www.regulations.gov/ (our preferred method). Follow the online instructions for submitting comments. • Email: a-and-r-docket@epa.gov. Include Docket ID No. EPA–HQ–OAR– 2021–0317 in the subject line of the message. • Fax: (202) 566–9744. Attention Docket ID No. EPA–HQ–OAR–2021– 0317. • Mail: U.S. Environmental Protection Agency, EPA Docket Center, Docket ID No. EPA–HQ–OAR–2021– 0317, Mail Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460. • Hand/Courier Delivery: EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004. The Docket Center’s hours of operation are 8:30 a.m.–4:30 p.m., Monday–Friday (except Federal holidays). Instructions: All submissions received must include the Docket ID No. for this rulemaking. Comments received may be posted without change to https:// www.regulations.gov/, including any personal information provided. For detailed instructions on sending comments and additional information on the rulemaking process, see the ‘‘Public Participation’’ heading of the SUPPLEMENTARY INFORMATION section of this document. Out of an abundance of caution for members of the public and our staff, the EPA Docket Center and Reading Room are closed to the public, with limited exceptions, to reduce the risk of transmitting COVID–19. Our Docket Center staff will continue to provide remote customer service via email, phone, and webform. We encourage the public to submit comments via https:// www.regulations.gov/ or email, as there may be a delay in processing mail and faxes. Hand deliveries and couriers may be received by scheduled appointment only. For further information on EPA Docket Center services and the current status, please visit us online at https:// www.epa.gov/dockets. FOR FURTHER INFORMATION CONTACT: For questions about this proposed action, contact Ms. Karen Marsh, Sector Policies and Programs Division (E143– 05), Office of Air Quality Planning and PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541–1065; fax number: (919) 541–0516; and email address: marsh.karen@epa.gov or Ms. Amy Hambrick, Sector Policies and Programs Division (E143–05), Office of Air Quality Planning and Standards, Environmental Protection Agency, Research Triangle Park, North Carolina 27711, telephone number: (919) 541– 0964; facsimile number: (919) 541–3470; email address: hambrick.amy@epa.gov. SUPPLEMENTARY INFORMATION: Participation in virtual public hearing. Please note that the EPA is deviating from its typical approach for public hearings, because the President has declared a national emergency. Due to the current Centers for Disease Control and Prevention (CDC) recommendations, as well as state and local orders for social distancing to limit the spread of COVID–19, the EPA cannot hold in-person public meetings at this time. The public hearing will be held via virtual platform on November 30, 2021, and December 1, 2021, and will convene at 11:00 a.m. Eastern Time (ET) and conclude at 9:00 p.m. ET each day. On each hearing day, the EPA may close a session 15 minutes after the last preregistered speaker has testified if there are no additional speakers. The EPA will announce further details at https:// www.epa.gov/controlling-air-pollutionoil-and-natural-gas-industry. If the EPA receives a high volume of registrations for the public hearing, we may continue the public hearing on December 2, 2021. The EPA does not intend to publish a document in the Federal Register announcing the potential addition of a third day for the public hearing or any other updates to the information on the hearing described in this document. Please monitor https://www.epa.gov/ controlling-air-pollution-oil-andnatural-gas-industry for any updates to the information described in this document, including information about the public hearing. For information or questions about the public hearing, please contact the public hearing team at (888) 372–8699 or by email at SPPDpublichearing@epa.gov. The EPA will begin pre-registering speakers for the hearing upon publication of this document in the Federal Register. The EPA will accept registrations on an individual basis. To register to speak at the virtual hearing, follow the directions at https:// www.epa.gov/controlling-air-pollutionoil-and-natural-gas-industry or contact the public hearing team at (888) 372– E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules 8699 or by email at SPPDpublichearing@epa.gov. The last day to pre-register to speak at the hearing will be November 24, 2021. Prior to the hearing, the EPA will post a general agenda that will list preregistered speakers in approximate order at: https://www.epa.gov/ controlling-air-pollution-oil-andnatural-gas-industry. The EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearings to run either ahead of schedule or behind schedule. Each commenter will have 5 minutes to provide oral testimony. The EPA encourages commenters to provide the EPA with a copy of their oral testimony electronically (via email) by emailing it to marsh.karen@epa.gov and hambrick.amy@epa.gov. The EPA also recommends submitting the text of your oral testimony as written comments to the rulemaking docket. The EPA may ask clarifying questions during the oral presentations but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as oral testimony and supporting information presented at the public hearing. If you require the services of an interpreter or a special accommodation such as audio description, please preregister for the hearing with the public hearing team and describe your needs by November 22, 2021. The EPA may not be able to arrange accommodations without advanced notice. Docket. The EPA has established a docket for this rulemaking under Docket ID No. EPA–HQ–OAR–2021–0317. All documents in the docket are listed in https://www.regulations.gov/. Although listed, some information is not publicly available, e.g., Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy. With the exception of such material, publicly available docket materials are available electronically in https:// www.regulations.gov/. Instructions. Direct your comments to Docket ID No. EPA–HQ–OAR–2021– 0317. The EPA’s policy is that all comments received will be included in the public docket without change and may be made available online at https:// www.regulations.gov/, including any personal information provided, unless the comment includes information VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 claimed to be CBI or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through https:// www.regulations.gov/ or email. This type of information should be submitted by mail as discussed below. The EPA may publish any comment received to its public docket. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (i.e., on the Web, cloud, or other file sharing system). For additional submission methods, the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit https://www.epa.gov/dockets/ commenting-epa-dockets. The https://www.regulations.gov/ website allows you to submit your comment anonymously, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through https:// www.regulations.gov/, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any digital storage media you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption and be free of any defects or viruses. For additional information about the EPA’s public docket, visit the EPA Docket Center homepage at https:// www.epa.gov/dockets. The EPA is temporarily suspending its Docket Center and Reading Room for public visitors, with limited exceptions, to reduce the risk of transmitting COVID–19. Our Docket Center staff will continue to provide remote customer service via email, phone, and webform. We encourage the public to submit comments via https:// www.regulations.gov/ as there may be a delay in processing mail and faxes. Hand deliveries or couriers will be received by scheduled appointment PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 63111 only. For further information and updates on EPA Docket Center services, please visit us online at https:// www.epa.gov/dockets. The EPA continues to carefully and continuously monitor information from the CDC, local area health departments, and our Federal partners so that we can respond rapidly as conditions change regarding COVID–19. Submitting CBI. Do not submit information containing CBI to the EPA through https://www.regulations.gov/ or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on any digital storage media that you mail to the EPA, mark the outside of the digital storage media as CBI and then identify electronically within the digital storage media the specific information that is claimed as CBI. In addition to one complete version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not contain the information claimed as CBI directly to the public docket through the procedures outlined in Instructions above. If you submit any digital storage media that does not contain CBI, mark the outside of the digital storage media clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and the EPA’s electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. Send or deliver information identified as CBI only to the following address: OAQPS Document Control Officer (C404–02), OAQPS, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA– HQ–OAR–2021–0317. Note that written comments containing CBI submitted by mail may be delayed and no hand deliveries will be accepted. Preamble acronyms and abbreviations. We use multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here: ACE Affordable Clean Energy rule AEO Annual Energy Outlook AMEL alternate means of emissions limitation ANGA American Natural Gas Alliance ANSI American National Standards Institute APCD air pollution control devices API American Petroleum Institute ARPA–E Advanced Research Projects Agency-Energy ASME American Society of Mechanical Engineers E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63112 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules ASTM American Society for Testing and Materials AVO audio, visual, olfactory BACT best achievable control technology BOEM Bureau of Ocean Energy Management BLM Bureau of Land Management BMP best management practices boe barrels of oil equivalents BSER best system of emission reduction BTEX benzene, toluene, ethylbenzene, and xylenes CAA Clean Air Act CBI Confidential Business Information CDC Center for Disease Control CDX EPA’s Central Data Exchange CEDRI Compliance and Emissions Data Reporting Interface CFR Code of Federal Regulations CH4 methane cm centimeter CPI consumer price index CPI–U consumer price index urban CO carbon monoxide COPD chronic obstructive pulmonary disease CO2 carbon dioxide CO2 Eq. carbon dioxide equivalent COA condition of approval COS carbonyl sulfide CRA Congressional Review Act CS2 carbon disulfide CVS closed vent systems DC direct current DOE Department of Energy DOI Department of the Interior DOT Department of Transportation EAV equivalent annualized value EDF Environmental Defense Fund EG emission guidelines ECOS Environmental Council of the States EGU electricity generating units EIA U.S. Energy Information Administration EJ environmental justice EO Executive Order EPA Environmental Protection Agency ERT Electronic Reporting Tool FERC The U.S. Federal Energy Regulatory Commission fpm feet per minute GC gas chromatograph GHGs greenhouse gases GHGI Inventory of U.S. Greenhouse Gas Emissions and Sinks GHGRP Greenhouse Gas Reporting Program GRI Gas Research Institute GWP global warning potential HAP hazardous air pollutant(s) HC hydrocarbons HFC hydrofluorocarbons H2S hydrogen sulfide ICR Information Collection Request IOGCC Interstate Oil and Gas Compact Commission IPCC Intergovernmental Panel on Climate Change IR infrared IRFA initial regulatory flexibility analysis kt kilotons kg kilograms low-e low emission LDAR leak detection and repair Mcf thousand cubic feet MMT million metric tons MRR monitoring, recordkeeping, and reporting VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 MW megawatt NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification System NCA4 2017–2018 Fourth National Climate Assessment NEI National Emissions Inventory NEMS National Energy Modeling System NESHAP National Emissions Standards for Hazardous Air Pollutants NGL natural gas liquid NGO non-governmental organization NOAA National Oceanic and Atmospheric Administration NOX nitrogen oxides NSPS new source performance standards NTTAA National Technology Transfer and Advancement Act OCSLA The Outer Continental Shelf Lands Act OAQPS Office of Air Quality Planning and Standards OIG Office of the Inspector General OGI optical gas imaging OMB Office of Management and Budget PE professional engineer PFCs perfluorocarbons PHMSA Pipeline and Hazardous Materials Safety Administration PM particulate matter PM2.5 PM with a diameter of 2.5 micrometers or less ppb parts per billion ppm parts per million PRA Paperwork Reduction Act PRD pressure release device PRV pressure release valve PSD Prevention of Significant Deterioration psig pounds per square inch gauge PTE potential to emit PV present value REC reduced emissions completion RFA Regulatory Flexibility Act RIA Regulatory Impact Analysis RTC response to comments SBAR Small Business Advocacy Review SC-CH4 social cost of methane SCF significant contribution finding scf standard cubic feet scfh standard cubic feet per hour scfm standard cubic feet per minute SF6 sulfur hexafluoride SIP State Implementation Plan SO2 sulfur dioxide SOX sulfur oxides tpy tons per year D.C. Circuit U.S. Court of Appeals for the District of Columbia Circuit TAR Tribal Authority Rule TIP Tribal Implementation Plan TSD technical support document TTN Technology Transfer Network UAS unmanned aircraft systems UIC underground injection control UMRA Unfunded Mandates Reform Act U.S. United States USGCRP U.S. Global Change Research Program USGS U.S. Geologic Survey VCS Voluntary Consensus Standards VOC volatile organic compounds VRD vapor recovery device VRU vapor recovery unit PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 Organization of this document. The information in this preamble is organized as follows: I. Executive Summary A. Purpose of the Regulatory Action B. Summary of the Major Provisions of This Regulatory Action C. Costs and Benefits II. General Information A. Does this action apply to me? B. How do I obtain a copy of this document, background information, other related information? III. Air Emissions From the Crude Oil and Natural Gas Sector and Public Health and Welfare A. Impacts of GHGs, VOC and SO2 Emissions on Public Health and Welfare B. Oil and Natural Gas Industry and Its Emissions IV. Statutory Background and Regulatory History A. Statutory Background of CAA Sections 111(b), 111(d) and General Implementing Regulations B. What is the regulatory history and litigation background of NSPS and EG for the oil and natural gas industry? C. Effect of the CRA V. Related Emissions Reduction Efforts A. Related State Actions and Other Federal Actions Regulating Oil and Natural Gas Sources B. Industry and Voluntary Actions To Address Climate Change VI. Environmental Justice Considerations, Implications, and Stakeholder Outreach A. Environmental Justice and the Impacts of Climate Change B. Impacted Stakeholders C. Outreach and Engagement D. Environmental Justice Considerations VII. Other Stakeholder Outreach A. Educating the Public, Listening Sessions, and Stakeholder Outreach B. EPA Methane Detection Technology Workshop C. How is this information being considered in this proposal? VIII. Legal Basis for Proposal Scope A. Recent History of the EPA’s Regulation of Oil and Gas Sources and Congress’s Response B. Implications of Congress’s Disapproval of the 2020 Policy Rule C. Alternative Conclusion Affirming the Legal Interpretations in the 2016 Rule D. Impacts on Regulation of Methane Emissions From Existing Sources IX. Overview of Control and Control Costs A. Control of Methane and VOC Emissions in the Crude Oil and Natural Gas Source Category—Overview B. How does EPA evaluate control costs in this action? X. Summary of Proposed Action for NSPS OOOOa A. Amendments to Fugitive Emissions Monitoring Frequency B. Technical and Implementation Amendments XI. Summary of Proposed NSPS OOOOb and EG OOOOc A. Fugitive Emissions From Well Sites and Compressor Stations E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules B. Storage Vessels C. Pneumatic Controllers D. Well Liquids Unloading Operations E. Reciprocating Compressors F. Centrifugal Compressors G. Pneumatic Pumps H. Equipment Leaks at Natural Gas Processing Plants I. Well Completions J. Oil Wells With Associated Gas K. Sweetening Units L. Centralized Production Facilities M. Recordkeeping and Reporting N. Prevention of Significant Deterioration and Title V Permitting XII. Rationale for Proposed NSPS OOOOb and EG OOOOc A. Proposed Standards for Fugitive Emissions From Well Sites and Compressor Stations B. Proposed Standards for Storage Vessels C. Proposed Standards for Pneumatic Controllers D. Proposed Standards for Well Liquids Unloading Operations E. Proposed Standards for Reciprocating Compressors F. Proposed Standards for Centrifugal Compressors G. Proposed Standards for Pneumatic Pumps H. Proposed Standards for Equipment Leaks at Natural Gas Processing Plants I. Proposed Standards for Well Completions J. Proposed Standards for Oil Wells With Associated Gas K. Proposed Standards for Sweetening Units XIII. Solicitations for Comment on Additional Emission Sources and Definitions A. Abandoned Wells B. Pigging Operations and Related Blowdown Activities C. Tank Truck Loading D. Control Device Efficiency and Operation E. Definition of Hydraulic Fracturing XIV. State, Tribal, and Federal Plan Development for Existing Sources A. Overview B. Components of EG C. Establishing Standards of Performance in State Plans D. Components of State Plan Submission E. Timing of State Plan Submissions and Compliance Times F. EPA Action on State Plans and Promulgation of Federal Plans G. Tribes and The Planning Process Under CAA Section 111(d) XV. Prevention of Significant Deterioration and Title V Permitting A. Overview B. Applicability of Tailoring Rule Thresholds Under the PSD Program C. Implications for Title V Program XVI. Impacts of This Proposed Rule A. What are the air impacts? B. What are the energy impacts? C. What are the compliance costs? D. What are the economic and employment impacts? E. What are the benefits of the proposed standards? XVII. Statutory and Executive Order Reviews VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Reduction Act (PRA) C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act (UMRA) E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act (NTTAA) J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations I. Executive Summary A. Purpose of the Regulatory Action This proposed rulemaking takes a significant step forward in mitigating climate-destabilizing pollution and protecting human health by reducing GHG and VOC emissions from the Oil and Natural Gas Industry,1 specifically the Crude Oil and Natural Gas source category.2 The Oil and Natural Gas Industry is the United States’ largest industrial emitter of methane, a highly potent GHG. Human activity-related emissions of methane are responsible for about one third of the warming due to well-mixed GHGs and constitute the second most important warming agent arising from human activity after carbon dioxide (a well-mixed gas is one with an atmospheric lifetime longer than a year or two, which allows the gas to be mixed around the world, meaning that the location of emission of the gas has little importance in terms of its impacts). According to the 1 The EPA characterizes the Oil and Natural Gas Industry operations as being generally composed of four segments: (1) Extraction and production of crude oil and natural gas (‘‘oil and natural gas production’’), (2) natural gas processing, (3) natural gas transmission and storage, and (4) natural gas distribution. 2 The EPA defines the Crude Oil and Natural Gas source category to mean (1) crude oil production, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other forms of transportation; and (2) natural gas production, processing, transmission, and storage, which include the well and extend to, but do not include, the local distribution company custody transfer station. For purposes of this proposed rulemaking, for crude oil, the EPA’s focus is on operations from the well to the point of custody transfer at a petroleum refinery, while for natural gas, the focus is on all operations from the well to the local distribution company custody transfer station commonly referred to as the ‘‘city-gate’’. PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 63113 Intergovernmental Panel on Climate Change (IPCC), strong, rapid, and sustained methane reductions are critical to reducing near-term disruption of the climate system and are a vital complement to reductions in other GHGs that are needed to limit the longterm extent of climate change and its destructive impacts. The Oil and Natural Gas Industry also emits other harmful pollutants in varying concentrations and amounts, including carbon dioxide (CO2), VOC, sulfur dioxide (SO2), nitrogen oxide (NOX), hydrogen sulfide (H2S), carbon disulfide (CS2), and carbonyl sulfide (COS), as well as benzene, toluene, ethylbenzene, and xylenes (this group is commonly referred to as ‘‘BTEX’’), and n-hexane. Under the authority of CAA section 111, this rulemaking proposes comprehensive standards of performance for GHG emissions (in the form of methane limitations) and VOC emissions for new, modified, and reconstructed sources in the Crude Oil and Natural Gas source category, including the production, processing, transmission and storage segments. For designated facilities,3 this rulemaking proposes EG containing presumptive standards for GHG in the form of methane limitations. When finalized, States shall utilize these EG to submit to the EPA plans that establish standards of performance for designated facilities and provide for implementation and enforcement of such standards. The EPA will provide support for States in developing their plans to reduce methane emissions from designated facilities within the Crude Oil and Natural Gas source category. The EPA is proposing these actions in accordance with its legal obligations and authorities following a review directed by E.O. 13990, ‘‘Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,’’ issued on January 20, 2021. The EPA intends for these proposed actions to address the far-reaching harmful consequences and real economic costs of climate change. According to the IPCC AR6 assessment, ‘‘It is unequivocal that human influence has warmed the atmosphere, ocean and land. Widespread and rapid changes in the atmosphere, ocean, cryosphere and biosphere have occurred.’’ The IPCC AR6 assessment states these changes have led to increases in heat waves and wildfire weather, reductions in air quality, more intense hurricanes and 3 The term ‘‘designated facility’’ means ‘‘any existing facility which emits a designated pollutant and which would be subject to a standard of performance for that pollutant if the existing facility were an affected facility.’’ See 40 CFR 60.21a(b). E:\FR\FM\15NOP2.SGM 15NOP2 63114 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 rainfall events, and rising sea level. These changes, along with future projected changes, endanger the physical survival, health, economic well-being, and quality of life of people living in the United States (U.S.), especially those in the most vulnerable communities. Methane is both the main component of natural gas and a potent GHG. One ton of methane in the atmosphere has 80 times the warming impact of a ton of CO2, and contributes to the creation of ground-level ozone which is another greenhouse gas. Because methane has a shorter lifetime than CO2, it has a smaller relative impact—although still significantly greater than CO2—when considering longer time periods. One standard metric is the 100-year global warming potential (GWP), which is a measure of the climate impact of emissions of one ton a greenhouse gas over 100 years relative to the impact of the emissions of one ton of CO2. Even over this long timeframe, methane has a 100-year GWP of almost 30. The IPCC AR6 assessment found that ‘‘Over time scales of 10 to 20 years, the global temperature response to a year’s worth of current emissions of SLCFs (short lived climate forcer) is at least as large as that due to a year’s worth of CO2 emissions.’’ 4 The IPCC estimated that, depending on the reference scenario, collective reductions in these SLCFs (methane, ozone precursors, and HFCs) could reduce warming by 0.2 degrees Celsius (°C) (more than one-third of a degree Fahrenheit (°F) in 2040 and 0.8 °C (almost 1.5 °F) by the end of the century, which is important in the context of keeping warming to well below 2 °C (3.6 °F). As methane is the most important SLCF, this makes methane mitigation one of the best opportunities for reducing near term warming. Emissions from human activities have already more than doubled atmospheric methane concentrations since 1750, and that concentration has been growing larger at record rates in recent years.5 In the 4 However, the IPCC AR6 assessment cautioned that ‘‘The effects of the SLCFs decay rapidly over the first few decades after pulse emission. Consequently, on time scales longer than about 30 years, the net long-term temperature effects of sectors and regions are dominated by CO2.’’ 5 Naik, V., S. Szopa, B. Adhikary, P. Artaxo, T. Berntsen, W.D. Collins, S. Fuzzi, L. Gallardo, A. Kiendler 41 Scharr, Z. Klimont, H. Liao, N. Unger, P. Zanis, 2021, Short-Lived Climate Forcers. In: Climate Change 42 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the 43 Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. 44 Pe´an, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. 45 Matthews, T.K. Maycock, T. Waterfield, O. Yelekc¸i, R. Yu and VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 absence of additional reduction policies, methane emissions are projected to continue rising through at least 2040. Methane’s radiative efficiency means that immediate reductions in methane emissions, including from sources in the Crude Oil and Natural Gas source category, can help reduce near-term warming. As natural gas is comprised primarily of methane, every natural gas leak, or intentional release of natural gas through venting or other processes, constitutes a release of methane. Reducing human-caused methane emissions, such as controlling natural gas leaks and releases as proposed in these actions, would contribute substantially to global efforts to limit temperature rise, aiding efforts to remain well below 2 °C above preindustrial levels. See preamble section III for further discussion on the Crude Oil and Natural Gas Emissions and Climate Change, including discussion of the GHGs, VOCs, and SO2 Emissions on Public Health and Welfare. Methane and VOC emissions from the Crude Oil and Natural Gas source category result from a variety of industry operations across the supply chain. As natural gas moves through the necessarily interconnected system of exploration, production, storage, processing, and transmission that brings it from wellhead to commerce, emissions primarily result from intentional venting, unintentional gas carry-through (e.g., vortexing from separator drain, improper liquid level settings, liquid level control valve on an upstream separator or scrubber does not seat properly at the end of an automated liquid dumping event, inefficient separation of gas and liquid phases occurs upstream of tanks allowing some gas carry-through), routine maintenance, unintentional fugitive emissions, flaring, malfunctions, abnormal process conditions, and system upsets. These emissions are associated with a range of specific equipment and practices, including leaking valves, connectors, and other components at well sites and compressor stations; leaks and vented emissions from storage vessels; releases from natural gas-driven pneumatic pumps and controllers; liquids unloading at well sites; and venting or under-performing flaring of associated gas from oil wells. But technical innovations have produced a range of technologies and best practices to monitor, eliminate or minimize these emissions, which in many cases have the benefit of reducing multiple pollutants at once and recovering B. Zhou (eds.)]. Cambridge University 46 Press. In Press. PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 saleable product. These technologies and best practices have been deployed by individual oil and natural gas companies, required by State regulations, or reflected in regulations issued by the EPA and other Federal agencies. In this action, the EPA has taken a comprehensive analysis of the available data from emission sources in the Crude Oil and Natural Gas source category and the latest available information on control measures and techniques to identify achievable, cost-effective measures to significantly reduce emissions, consistent with the requirements of section 111 of the CAA. If finalized and implemented, the actions proposed in this rulemaking would lead to significant and costeffective reductions in climate and health-harming pollution and encourage development and deployment of innovative technologies to further reduce this pollution in the Crude Oil and Natural Gas source category. The actions proposed in this rulemaking would: • Update, strengthen, and expand current requirements under CAA section 111(b) for methane and VOC emissions from new, modified, and reconstructed facilities, • establish new limits for methane, and VOC emissions from new, modified, and reconstructed facilities that are not currently regulated under CAA section 111(b), • establish the first nationwide EG for States to limit methane pollution from existing designated facilities in the source category under CAA section 111(d), and • take comment on additional sources of pollution that, with understanding gained from more information, may offer opportunities for emission reductions, which the EPA would present in a supplemental rulemaking proposal under both CAA section 111(b) and (d). In developing this proposal, the EPA drew on its own prior experience in regulating sources in the Crude Oil and Natural Gas source category under section 111 and other CAA programs; applied lessons learned from States’ regulatory efforts, the emission reduction efforts of leading companies, and the EPA’s long-standing voluntary emission reduction programs; and reviewed the latest available information about new and developing technologies, as well as, peer-reviewed research from emission measurement campaigns across the U.S. Further, the EPA undertook extensive pre-proposal outreach to the public and to stakeholders, including three full days E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules of public listening sessions, roundtables with State energy and environmental regulators, a two-day workshop on innovative methane detection technologies, and a nonregulatory docket established in May 2021 to receive written comments. Through this outreach, the EPA heard from diverse voices and perspectives including State and local governments, Tribal nations, communities affected by oil and gas pollution, environmental and public health organizations, and representatives of the oil and natural gas industry, all of which provided ideas and information that helped shape and inform this proposal. The EPA also considered community and environmental justice implications in the development of this proposal and sought to ensure equitable treatment and meaningful involvement of all people regardless of race, color, national origin, or income in the process. The EPA engaged and consulted representatives of frontline communities that are directly affected by and particularly vulnerable to the climate and health impacts of pollution from this source category through interactions such as webinars, listening sessions and meetings. These opportunities allowed the EPA to hear directly from the public, especially overburdened and underserved communities, on the development of the proposed rule and to factor these concerns into this proposal. For example, in addition to establishing EG that extend fugitive emission requirements to existing oil and natural gas facilities, the EPA is proposing to expand leak detection programs already in effect for new sources to include known sources of large emission events and proposing to require more frequent monitoring at sites with more emissions. The EPA is also taking comment on innovative mechanisms to ensure compliance and minimize emissions, including the possibility of providing a pathway for communities to detect and report large emitting events that may require follow-up and mitigation by owners and operators. The extensive pollution reduction measures in this proposal, if finalized, would collectively reduce a suite of harmful pollutants and their associated health impacts in communities adjacent to these emission sources. Further, to help ensure that the needs and perspectives of communities with environmental justice concerns are considered as States develop plans to establish and implement standards of performance for existing sources, the EPA is proposing to require that States demonstrate they have undertaken VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 meaningful outreach and engagement with overburdened and underserved communities as part of their State plan submissions under the EPA. A full discussion of the Environmental Justice Considerations, Implications, and Stakeholder Outreach can be found in section VI of the preamble. A full discussion of Other Stakeholder Outreach is found in section VII of the preamble. As described in more detail below, the EPA recognizes that several States and other Federal agencies currently regulate the Oil and Natural Gas Industry. The EPA also recognizes that these State and other Federal agency regulatory programs have matured since the EPA began implementing the current NSPS requirements in 2012 and 2016. The EPA further acknowledges the technical innovations that the Oil and Natural Gas Industry has made during the past decade; this industry operates at a fast pace and changes constantly as technology evolves. The EPA commends these efforts and recognizes States for their innovative standards, alternative compliance options, and implementation strategies, and intends these proposed actions to build upon progress made by certain States and Federal agencies in reducing GHG and VOC emissions. See preamble section V for fuller discussion of Related State Actions and Other Federal Actions Regulating Oil and Natural Gas Sources and Industry and Voluntary Actions to Address Climate Change. The EPA believes that a broad ensemble of mutually leveraging efforts across all States and all Federal agencies is essential to meaningfully address climate change effectively. As the Federal agency with primary responsibility to protect human health and the environment, the EPA has the unique responsibility and authority to regulate harmful air pollutants emitted by the Crude Oil and Natural Gas source category. The EPA recognizes that States and other Federal agencies regulate in accordance with their respective legal authorities and within their respective jurisdictions but collectively do not fully and consistently address the range of sources and emission reduction measures contained in this proposal. Direct Federal regulation of methane from new, reconstructed, and modified sources in this category, combined with approved State plans that are consistent with the EPA’s presumptive standards for designated facilities (existing sources), will help reduce both climateand other health-harming pollution from a large number of sources that are either unregulated or from which additional, cost-effective reductions are PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 63115 available, level the regulatory playing field, and help promote technological innovation. Throughout this action, unless noted otherwise, the EPA is requesting comments on all aspects of the proposal to enable the EPA to develop a final rule that, consistent with our responsibilities under section 111 of the CAA, achieves the greatest possible reductions in methane and VOC emissions while remaining achievable, cost effective, and conducive to technological innovation. As a further step in the rulemaking process and to solicit additional public input, the EPA plans to issue a supplemental proposal and supplemental RIA for the supplemental proposal to provide regulatory text for the proposed NSPS OOOOb and EG OOOOc. In light of certain innovative elements of this proposed rule and the EPA’s request for information that would support the regulation of additional sources in the Crude Oil and Natural Gas source category as part of this rulemaking, the EPA is considering including additional provisions in this supplemental proposal and RIA based on information and comment collected in response to this document. As noted later in this preamble, the supplemental proposal may address, among other issues: (1) Ways to mitigate methane from abandoned wells, (2) measures to reduce emissions from pipeline pigging operations and other pipeline blowdowns, (3) ways to minimize emissions from tank truck loading operations, and (4) ways to strengthen requirements to ensure proper operation and optimal performance of control devices. In addition, and as noted in the solicitations of comment in this document, the supplemental proposal may revisit and refine certain provisions of this proposal in response to information provided by the public. For instance, the EPA is seeking input on multiple aspects of the proposed approach for fugitive emissions monitoring at well sites, including the baseline emission threshold and other criteria (such as the presence of specific types of malfunction-prone equipment) that should be used to determine whether a well site is required to undertake ongoing fugitive emissions monitoring; the methodology for calculating baseline methane emissions and whether it should account for malfunctions or improper operation of controls at storage vessels; and ways to ensure that emissions from wells owned by small businesses are addressed while still recognizing the greater challenges that small businesses with less dedicated staff and resources for E:\FR\FM\15NOP2.SGM 15NOP2 63116 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 environmental compliance may have. The EPA is also seeking input on ways to ensure that captured associated gas is collected for a useful purpose rather than flared, and the feasibility of requiring broader use of zero-emitting technology for pneumatic pumps. Finally, the EPA is seeking comment and information on alternative measurement technologies, which we are proposing to allow in the rule. We have heard strong interest from various stakeholders on employing new tools for methane identification and quantification, particularly for large emission sources (commonly known as ‘‘super-emitters’’). Information provided in response to this proposal may be used to evaluate whether a change in BSER from the proposed quarterly OGI monitoring to a monitoring program using alternative measurement technologies is appropriate. Separate from the role of these alternative measurement technologies in a regulatory monitoring program, we are also soliciting comment on ways to structure a pathway for communities to identify large emission events which owners or operators would then be required to investigate, and mechanisms for the collection and public dissemination of this information, for possible further development as part of a supplemental proposal. This preamble includes comment solicitations/requests on several topics and issues. We have prepared a separate memorandum that presents these comment requests by section and topic as a guide to assist commenters in preparing comments. This memorandum can be obtained from the Docket for this action (see Docket ID No. EPA–HQ–OAR–2021–0317). The title of the memorandum is ‘‘Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review— Proposed Rule Summary of Comment Solicitations.’’ B. Summary of the Major Provisions of This Regulatory Action This proposed rulemaking includes three distinct groups of actions under the CAA that are each severable from the other. First, pursuant to CAA 111(b)(1)(B), the EPA has reviewed, and is proposing revisions to, the standards of performance for the Crude Oil and Natural Gas source category published in 2016 and amended in 2020, codified at 40 CFR part 60, subpart OOOOa— Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 September 18, 2015 (2016 NSPS OOOOa). Specifically, the EPA is proposing to update, strengthen, and expand the current requirements under CAA section 111(b) for methane and VOC emissions from sources that commenced construction, modification, or reconstruction after November 15, 2021. These proposed standards of performance will be in a new subpart, 40 CFR part 60, subpart OOOOb (NSPS OOOOb), and include standards for emission sources previously not regulated under the 2016 NSPS OOOOa. Second, pursuant to CAA 111(d), the EPA is proposing the first nationwide EG for States to limit methane pollution from designated facilities in the Crude Oil and Natural Gas source category. The EG being proposed in this rulemaking will be in a new subpart, 40 CFR part 60, subpart OOOOc (EG OOOOc). The EG are designed to inform States in the development, submittal, and implementation of State plans that are required to establish standards of performance for GHGs from their designated facilities in the Crude Oil and Natural Gas source category. Third, the EPA is taking several related actions stemming from the joint resolution of Congress, adopted on June 30, 2021 under the CRA, disapproving the EPA’s final rule titled, ‘‘Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review,’’ 85 FR 57018 (Sept. 14, 2020) (‘‘2020 Policy Rule’’). As explained in Section X of this action (Summary of Proposed Action for NSPS OOOOa), the EPA is proposing amendments to the 2016 NSPS OOOOa to address (1) certain inconsistencies between the VOC and methane standards resulting from the disapproval of the 2020 Policy Rule, and (2) certain determinations made in the final rule titled ‘‘Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Reconsideration,’’ 85 FR 57398 (September 15, 2020) (2020 Technical Rule), specifically with respect to fugitive emissions monitoring at low production well sites and gathering and boosting stations. With respect to the latter, as described below, the EPA is proposing to rescind provisions of the 2020 Technical Rule that were not supported by the record for that rule, or by our subsequent information and analysis. The regulatory text for these proposed amendments is included in the docket for this rulemaking at Docket ID EPA–HQ–OAR–2021–0317. In addition, in the final rule for this action, the EPA will update the NSPS OOOO and NSPS OOOOa provisions in the Code of Federal Regulations (CFR) to PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 reflect the Congressional Review Act (CRA) resolution’s disapproval of the final 2020 Policy Rule, specifically, the reinstatement of the NSPS OOOO and NSPS OOOOa requirements that the 2020 Policy Rule repealed but that came back into effect immediately upon enactment of the CRA resolution. It should be noted that these requirements have come back into effect already even though the EPA has not yet updated the CFR text to reflect them.6 These updates to the CFR text are also included in the docket for this rulemaking at Docket ID EPA–HQ–OAR–2021–0317 for public awareness, but the EPA is not soliciting comment on them as they merely reflect current law. Under 5 U.S.C. 553(b)(3)(B), notice and comment is not required ‘‘when the agency for good cause finds . . . that notice and public procedure thereon are . . . unnecessary . . . ,’’ 7 and, as just noted, notice and comment is not necessary for these updates. The EPA is waiting to make these updates to the CFR text until the final rule simply because it would be more efficient and clearer to amend the CFR once at the end of this rulemaking process to account for all changes to the 2012 NSPS OOOO (77 FR 49490, August 16, 2012) and 2016 NSPS OOOOa at the same time. As CAA section 111(a)(1) requires, the standards of performance being proposed in this action reflect ‘‘the degree of emission limitation achievable through the application of the best system of emission reduction [BSER] which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirement) the Administrator determines has been adequately demonstrated.’’ This action further proposes EG for designated facilities, under which States must submit plans which establish standards of performance that reflect the degree of emission limitation achievable through application of the BSER, as identified in the final EG. In this proposed rulemaking, we evaluated potential control measures available for the affected facilities, the emission reductions achievable through these measures, and employed multiple approaches to evaluate the reasonableness of control costs associated with the options under 6 See Congressional Review Act Resolution to Disapprove EPA’s 2020 Oil and Gas Policy Rule Questions and Answers (June 30, 2021) available at https://www.epa.gov/system/files/documents/202107/qa_cra_for_2020_oil_and_gas_policy_ rule.6.30.2021.pdf. 7 5 U.S.C. 553(b)(3)(B) is applicable to rules promulgated under CAA section 111(b), under CAA section 307(d)(1) (flush language at end). E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules consideration. For example, in evaluating controls for reducing VOC and methane emissions from new sources, we considered a control measure’s cost-effectiveness under both a ‘‘single pollutant cost-effectiveness’’ approach and a ‘‘multipollutant costeffectiveness’’ approach, to appropriately consider that the systems of emission reduction considered in this rule typically achieve reductions in multiple pollutants at once and secure 63117 a multiplicity of climate and public health benefits. For a detailed discussion of the EPA’s consideration of this and other BSER statutory elements, please see sections IV and IX of this preamble. khammond on DSKJM1Z7X2PROD with PROPOSALS2 TABLE 1—APPLICABILITY DATES FOR PROPOSED SUBPARTS ADDRESSED IN THIS PROPOSED ACTION Subpart Source type Applicable dates 40 CFR part 60, subpart OOOO ........................ New, modified, or reconstructed sources ........ 40 CFR part 60, subpart OOOOa ...................... New, modified, or reconstructed sources ........ 40 CFR part 60, subpart OOOOb ...................... 40 CFR part 60, subpart OOOOc ...................... New, modified, or reconstructed sources ........ Existing sources ............................................... After August 23, 2011 and on or before September 18, 2015. After September 18, 2015 and on or before November 15, 2021. After November 15, 2021. On or before November 15, 2021. 1. Proposed Standards for New, Modified and Reconstructed Sources After November 15, 2021 (Proposed NSPS OOOOb) As described in sections XI and XII of this preamble, under the authority of CAA section 111(b)(1)(B) the EPA has reviewed the VOC, GHG (in the form of limitations on methane), and SO2 standards in the 2016 NSPS OOOOa (as amended in 2020 by the Technical Rule). Based on its review, the EPA is proposing revisions to the standards for certain emissions sources to reflect the updated BSER for those affected sources. Where our analyses show that the BSER for an affected source remains the same, the EPA is proposing to retain the current standard for that affected source. In addition, the EPA is proposing methane and VOC standards for several new sources that are currently unregulated. The proposed NSPS described above would apply to new, modified, and reconstructed emission sources across the Crude Oil and Natural Gas source category, including the production, processing, transmission, and storage segments, for which construction, reconstruction, or modification commenced after November 15, 2021, which is the date of publication of the proposed revisions to the NSPS. In particular, this action proposes to retain the 2016 NSPS OOOOa SO2 performance standard for sweetening units and the 2016 OOOOa VOC and methane performance standards for well completions and centrifugal compressors; proposes revisions to strengthen the 2016 NSPS OOOOa VOC and methane standards addressing fugitive emissions from well sites and compressor stations, storage vessels, pneumatic controllers, reciprocating compressors, pneumatic pumps, and equipment leaks at natural gas processing plants; and proposes new VOC and methane standards for well liquids unloading operations and VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 intermittent vent pneumatic controllers, and oil wells with associated gas previously not regulated in the 2016 NSPS OOOOa. A summary of the proposed BSER determination and proposed NSPS for new, modified, and reconstructed sources (NSPS OOOOb) is presented in Table 2. See sections XI and XII of this preamble for a complete discussion of BSER determination and proposed NSPS requirements. This proposal also solicits certain information relevant to the potential identification of additional emissions sources as affected facilities. Specifically, the EPA is evaluating the potential for establishing standards for abandoned and unplugged wells, blowdown emissions associated with pipeline pig launchers and receivers, and tank truck loading operations. While the EPA has assessed these sources based on currently available information, we have determined that we need additional information to evaluate BSER and to propose NSPS for these emissions sources. A full discussion of the solicitation for comment regarding these additional emission sources is found in section XIII of the preamble. 2. Proposed EG for Sources Constructed Prior to November 15, 2021 (Proposed EG OOOOc) As described in sections XI and XII of this preamble, under the authority of CAA section 111(d), the EPA is proposing the first nationwide EG for GHG (in the form of methane limitations) for the Crude Oil and Natural Gas source category, including the production, processing, transmission, and storage segments (EG OOOOc). When the EPA establishes NSPS for a source category, the EPA is required to issue EG to reduce emissions of certain pollutants from existing sources in that same source category. In such circumstances, under CAA section PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 111(d), the EPA must issue regulations to establish procedures under which States submit plans to establish, implement, and enforce standards of performance for existing sources for certain air pollutants to which a Federal NSPS would apply if such existing source were a new source. Thus, the issuance of CAA section 111(d) final EG does not impose binding requirements directly on sources but instead provides requirements for states in developing their plans. Although State plans bear the obligation to establish standards of performance, under CAA sections 111(a)(1) and 111(d), those standards of performance must reflect the degree of emission limitation achievable through the application of the BSER as determined by the Administrator. As provided in section 111(d), a State may choose to take into account remaining useful life and other factors in applying a standard of performance to a particular source, consistent with the CAA, the EPA’s implementing regulations, and the final EG. In this action, the EPA is proposing BSER determinations and the degree of limitation achievable through application of the BSER for certain existing equipment, processes, and activities across the Crude Oil and Natural Gas source category. Section XIV of this preamble discusses the components of EG, including the steps, requirements, and considerations associated with the development, submittal, and implementation of State, Tribal, and Federal plans, as appropriate. For the EG, the EPA is proposing to translate the degree of emission limitation achievable through application of the BSER (i.e., level of stringency) into presumptive standards that States may use in the development of State plans for specific designated facilities. By doing this, the EPA has formatted the proposed EG such that if a State chooses to adopt these E:\FR\FM\15NOP2.SGM 15NOP2 63118 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules presumptive standards, once finalized, as the standards of performance in a State plan, the EPA could approve such a plan as meeting the requirements of CAA section 111(d) and the finalized EG, if the plan meets all other applicable requirements. In this way, the presumptive standards included in the EG serve a function similar to that of a model rule,8 because they are intended to assist States in developing their plan submissions by providing States with a starting point for standards that are based on general industry parameters and assumptions. The EPA believes that providing these presumptive standards will create a streamlined approach for States in developing plans and the EPA in evaluating State plans. However, the EPA’s action on each State plan submission is carried out via rulemaking, which includes public notice and comment. Inclusion of presumptive standards in the EG does not seek to pre-determine the outcomes of any future rulemaking. Designated facilities located in Indian country would not be encompassed within a State’s CAA section 111(d) plan. Instead, an eligible Tribe that has one or more designated facilities located in its area of Indian country would have the opportunity, but not the obligation, to seek authority and submit a plan that establishes standards of performance for those facilities on its Tribal lands. If a Tribe does not submit a plan, or if the EPA does not approve a Tribe’s plan, then the EPA has the authority to establish a Federal plan for that Tribe. A summary of the proposed EG for existing sources (EG OOOOc) for the oil and natural gas sector is presented in Table 3. See sections XI and XII of this preamble for a complete discussion of the proposed EG requirements. As discussed above for the proposed NSPS OOOOb, the EPA is considering including additional sources as affected facilities in a potential future supplemental rulemaking proposal 9 under CAA section 111(b). The EPA is also considering including these additional sources as designated facilities under the EG in OOOOc in a potential future supplemental rulemaking proposal under CAA section 111(d). As with the proposed NSPS OOOOb, the EPA is evaluating the potential for establishing EG applicable to abandoned and unplugged wells, blowdown emissions associated with pipeline pig launchers and receivers, and tank truck loading operations (assuming the EPA establishes NSPS for these emissions points). As described in section XIII of this preamble, the EPA is soliciting information to assist in this effort. 3. Proposed Amendments to 2016 NSPS OOOOa, and CRA-Related CFR Updates The EPA is also proposing certain modifications to the 2016 NSPS OOOOa to address certain amendments to the VOC standards for sources in the production and processing segments finalized in the 2020 Technical Rule. Because the methane standards for the production and processing segments and all standards for the transmission and storage segment were removed from the 2016 NSPS OOOOa via the 2020 Policy Rule prior to the finalization of the 2020 Technical Rule, the latter amendments apply only to the 2016 NSPS OOOOa VOC standards for the production and processing segments. In this proposed rulemaking, the EPA also is proposing to apply some of the 2020 Technical Rule amendments to the methane standards for all industry segments and to VOC standards for the transmission and storage segment in the 2016 NSPS OOOOa. These amendments are associated with the requirements for well completions, pneumatic pumps, closed vent systems, fugitive emissions, alternative means of emission limitation (AMELs), onshore natural gas processing plants, as well as other technical clarifications and corrections. The EPA also is proposing to repeal the amendments in the 2020 Technical Rule that (1) exempted low production well sites from monitoring fugitive emissions and (2) changed monitoring of VOC emissions at gathering and boosting compressor stations from quarterly to semiannual, which currently apply only to VOC standards (not methane standards) from the production and processing segments. A summary of the proposed amendments to the 2016 OOOOa NSPS is presented in section X of this preamble. Lastly, in the final rule for this action, the EPA will update the NSPS OOOO and OOOOa provisions in the CFR to reflect the CRA resolution’s disapproval of the final 2020 Policy Rule, specifically, the reinstatement of the OOOO and OOOOa requirements that the 2020 Policy Rule repealed but that came back into effect immediately upon enactment of the CRA resolution. The EPA is waiting to make the updates to the CFR text until the final rule simply because it would be more efficient and clearer to amend the CFR once at the end of this rulemaking process to account for all changes to the 2012 NSPS OOOO and 2016 NSPS OOOOa at the same time. In accordance with 5 U.S.C. 553(b)(3)(B), the EPA is not soliciting comment on these updates. TABLE 2—SUMMARY OF PROPOSED BSER AND PROPOSED STANDARDS OF PERFORMANCE FOR GHGS AND VOC khammond on DSKJM1Z7X2PROD with PROPOSALS2 [NSPS OOOOb] Affected source Proposed BSER Proposed standards of performance for GHGs and VOCs Fugitive Emissions: Well Sites with Baseline Emissions >0 to <3 tpy 1 Methane. Fugitive Emissions: Well Sites ≥3 tpy Methane. Demonstrate actual site emissions are reflected in calculation. Monitoring and repair based on quarterly monitoring using OGI 2. (Co-proposal) Fugitive Emissions: Well Sites with Baseline Emissions ≥3 to <8 tpy Methane. Monitoring and repair based on semiannual monitoring using OGI. Perform survey to verify that actual site emissions are reflected in calculation. Quarterly OGI monitoring following appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Semiannual OGI monitoring following appendix K. (Optional semiannual EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. 8 The presumptive standards are not the same as a Federal plan under CAA section 111(d)(2). The EPA has an obligation to promulgate a Federal plan if a state fails to submit a satisfactory plan. In such VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 circumstances, the final EG and presumptive standards would serve as a guide to the development of a Federal plan. See section XIV.F. for information on Federal plans. PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 9 A supplemental proposal would include an updated RIA. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules 63119 TABLE 2—SUMMARY OF PROPOSED BSER AND PROPOSED STANDARDS OF PERFORMANCE FOR GHGS AND VOC— Continued [NSPS OOOOb] Affected source Proposed BSER Proposed standards of performance for GHGs and VOCs (Co-proposal) Fugitive Emissions: Well Sites with Baseline Emissions ≥8 tpy Methane. Monitoring and repair based on quarterly monitoring using OGI. Fugitive Emissions: Compressor Stations Monitoring and repair based on quarterly monitoring using OGI. Fugitive Emissions: Well Sites and Compressor Stations on Alaska North Slope. Monitoring and repair based on annual monitoring using OGI. Fugitive Emissions: Well Sites and Compressor Stations. (Optional) Screening, monitoring, and repair based on bimonthly screening using an advanced measurement technology and annual monitoring using OGI. Capture and route to a control device ...... Quarterly OGI monitoring following appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm 3 defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Quarterly OGI monitoring following appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Annual OGI monitoring following appendix K. (Optional annual EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. (Optional) Alternative bimonthly screening with advanced measurement technology with annual OGI monitoring following appendix K. khammond on DSKJM1Z7X2PROD with PROPOSALS2 Storage Vessels: A Single Storage Vessel or Tank Battery with PTE 4 of 6 tpy or More of VOC. Pneumatic Controllers: Natural Gas Driven that Vent to the Atmosphere. Pneumatic Controllers: Alaska (at sites where onsite power is not available— continuous bleed natural gas driven). Pneumatic Controllers: Alaska (at sites where onsite power is not available— intermittent natural gas driven). Well Liquids Unloading ............................... Wet Seal Centrifugal Compressors (except for those located at single well sites). Reciprocating Compressors (except for those located at single well sites). VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 95 percent reduction of VOC and methane. Use of zero-emissions controllers ............ VOC and methane emission rate of zero. Installation of low-bleed pneumatic controllers. Natural gas bleed rate no greater than 6 scfh.5 Monitor and repair through fugitive emissions program. OGI monitoring and repair of emissions from controller malfunctions. Perform liquids unloading with zero methane or VOC emissions. If this is not feasible for safety or technical reasons, employ best management practices to minimize venting. Each affected well that unloads liquids employ techniques or technology(ies) that eliminate or minimize venting of emissions during liquids unloading events to the maximum extent. Capture and route emissions from the wet seal fluid degassing system to a control device or to a process. Replace the reciprocating compressor rod packing based on annual monitoring (when measured leak rate exceeds 2 scfm 7) or route emissions to a process. PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 Co Proposal Options: Option One—Affected facility would be defined as every well that undergoes liquids unloading. —If the method is one that does not result in any venting to the atmosphere, maintain records specifying the technology or technique and record instances where an unloading event results in emissions. —For unloading technologies or techniques that result in venting to the atmosphere, implement BMPs 6 to ensure that venting is minimized. —Maintain BMPs as records, and record instances when they were not followed. Option Two—Affected facility would be defined as every well that undergoes liquids unloading using a method that is not designed to eliminate venting. —Wells that utilize non-venting methods would not be affected facilities that are subject to the NSPS OOOOb. Therefore, they would not have requirements other than to maintain records to document that they used non-venting liquids unloading methods. —The requirements for wells that use methods that vent would be the same as described above under Option 1. Reduce emissions by 95 percent. Replace the reciprocating compressor rod packing when measured leak rate exceeds 2 scfm based on the results of annual monitoring or collect and route emissions from the rod packing to a process through a closed vent system under negative pressure. E:\FR\FM\15NOP2.SGM 15NOP2 63120 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules TABLE 2—SUMMARY OF PROPOSED BSER AND PROPOSED STANDARDS OF PERFORMANCE FOR GHGS AND VOC— Continued [NSPS OOOOb] Affected source Proposed BSER Proposed standards of performance for GHGs and VOCs Pneumatic Pumps: Natural Gas Processing Plants. Pneumatic Pumps: Production Segment ... A natural gas emission rate of zero ......... Pneumatic Pumps: Transmission and Storage Segment. Route diaphragm pneumatic pumps to an existing control device or process. Well Completions: Subcategory 1 (nonwildcat and non-delineation wells). Combination of REC 8 and the use of a completion combustion device. Well Completions: Subcategory 2 (exploratory and delineation wells and lowpressure wells). Use of a completion combustion device .. A natural gas emission rate of zero from diaphragm and piston pneumatic pumps. 95 percent control of diaphragm and piston pneumatic pumps if there is an existing control or process on site. 95 percent control not required if (1) routed to an existing control that achieves less than 95 percent or (2) it is technically infeasible to route to the existing control device or process. 95 percent control of diaphragm pneumatic pumps if there is an existing control or process on site. 95 percent control not required if (1) routed to an existing control that achieves less than 95 percent or (2) it is technically infeasible to route to the existing control device or process. Applies to each well completion operation with hydraulic fracturing. REC in combination with a completion combustion device; venting in lieu of combustion where combustion would present safety hazards. Initial flowback stage: Route to a storage vessel or completion vessel (frac tank, lined pit, or other vessel) and separator. Separation flowback stage: Route all salable gas from the separator to a flow line or collection system, reinject the gas into the well or another well, use the gas as an onsite fuel source or use for another useful purpose that a purchased fuel or raw material would serve. If technically infeasible to route recovered gas as specified above, recovered gas must be combusted. All liquids must be routed to a storage vessel or well completion vessel, collection system, or be re-injected into the well or another well. The operator is required to have (and use) a separator onsite during the entire flowback period. Applies to each well completion operation with hydraulic fracturing. khammond on DSKJM1Z7X2PROD with PROPOSALS2 Equipment Leaks at Natural Gas Processing Plants. Oil Wells with Associated Gas ................... Sweetening Units ....................................... 1 tpy Route diaphragm and piston pneumatic pumps to an existing control device or process. LDAR 9 with bimonthly OGI ...................... Route associated gas to a sales line. If access to a sales line is not available, the gas can be used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, or routed to a flare or other control device that achieves at least 95 percent reduction in methane and VOC emissions. Achieve SO2 emission reduction efficiency. The operator is not required to have a separator onsite. Either: (1) Route all flowback to a completion combustion device with a continuous pilot flame; or (2) Route all flowback into one or more well completion vessels and commence operation of a separator unless it is technically infeasible for a separator to function. Any gas present in the flowback before the separator can function is not subject to control under this section. Capture and direct recovered gas to a completion combustion device with a continuous pilot flame. For both options (1) and (2), combustion is not required in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost, or waterways. LDAR with OGI following procedures in appendix K. Route associated gas to a sales line. If access to a sales line is not available, the gas can be used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, or routed to a flare or other control device that achieves at least 95 percent reduction in methane and VOC emissions. Achieve required minimum SO2 emission reduction efficiency. (tons per year). VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules 63121 2 OGI (optical gas imaging). (parts per million). 4 PTE (potential to emit). 5 scfh (standard cubic feet per hour). 6 BMP (best management practices). 7 scfm (standard cubic feet per minute). 8 REC (reduced emissions completion). 9 LDAR (leak detection and repair). 3 ppm TABLE 3—SUMMARY OF PROPOSED BSER AND PROPOSED PRESUMPTIVE STANDARDS FOR GHGS FROM DESIGNATED FACILITIES [EG OOOOc] Designated facility Proposed BSER Proposed presumptive standards for GHGs Fugitive Emissions: Well Sites >0 to <3 tpy Methane. Fugitive Emissions: Well Sites ≥3 tpy Methane. Demonstrate actual site emissions are reflected in calculation. Monitoring and repair based on quarterly monitoring using OGI. (Co-proposal) Fugitive Emissions: Well Sites ≥3 to <8 tpy Methane. Monitoring and repair based on semiannual monitoring using OGI. (Co-proposal) Fugitive Emissions: Well Sites ≥8 tpy Methane. Monitoring and repair based on quarterly monitoring using OGI. Fugitive Emissions: Compressor Stations Monitoring and repair based on quarterly monitoring using OGI. Fugitive Emissions: Well Sites and Compressor Stations on Alaska North Slope. Monitoring and repair based on annual monitoring using OGI. Fugitive Emissions: Well Sites and Compressor Stations. (Optional) Screening, monitoring, and repair based on bimonthly screening using an advanced measurement technology and annual monitoring using OGI. Capture and route to a control device ...... Perform survey to verify that actual site emissions are reflected in calculation. Quarterly OGI monitoring following appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Semiannual OGI monitoring following appendix K. (Optional semiannual EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Quarterly OGI monitoring following appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Quarterly OGI monitoring following appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Annual OGI monitoring following appendix K. (Optional annual EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. (Optional) Alternative bimonthly screening with advanced measurement technology with annual OGI monitoring following appendix K. Storage Vessels: Tank Battery with PTE of 20 tpy or More of Methane. Pneumatic Controllers: Natural Gas Driven that Vent to the Atmosphere. Pneumatic Controllers: Alaska (at sites where onsite power is not available— continuous bleed natural gas driven). Pneumatic Controllers: Alaska (at sites where onsite power is not available— intermittent natural gas driven). Wet Seal Centrifugal Compressors (except for those located at single well sites). khammond on DSKJM1Z7X2PROD with PROPOSALS2 Reciprocating Compressors (except for those located at single well sites). Use of zero-emissions controllers ............ VOC and methane emission rate of zero. Installation of low-bleed pneumatic controllers. Natural gas bleed rate no greater than 6 scfh. Monitor and repair through fugitive emissions program. OGI monitoring and repair of emissions from controller malfunctions. Capture and route emissions from the wet seal fluid degassing system to a control device or to a process. Replace the reciprocating compressor rod packing based on annual monitoring (when measured leak rate exceeds 2 scfm) or route emissions to a process. Reduce emissions by 95 percent. Pneumatic Pumps: Natural Gas Processing Plants. Pneumatic Pumps: Locations Other Than Natural Gas Processing Plants. A natural gas emission rate of zero ......... Equipment Leaks at Natural Gas Processing Plants. LDAR with bimonthly OGI ........................ VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 95 percent reduction of methane. Route diaphragm pumps to an existing control device or process. PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 Replace the reciprocating compressor rod packing when measured leak rate exceeds 2 scfm based on the results of annual monitoring, or collect and route emissions from the rod packing to a process through a closed vent system under negative pressure. Zero natural gas emissions from diaphragm and piston pneumatic pumps. 95 percent control of diaphragm pneumatic pumps if there is an existing control or process on site. 95 percent control not required if (1) routed to an existing control that achieves less than 95 percent or (2) it is technically infeasible to route to the existing control device or process. LDAR with OGI following procedures in appendix K. E:\FR\FM\15NOP2.SGM 15NOP2 63122 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules TABLE 3—SUMMARY OF PROPOSED BSER AND PROPOSED PRESUMPTIVE STANDARDS FOR GHGS FROM DESIGNATED FACILITIES—Continued [EG OOOOc] Designated facility Proposed BSER Proposed presumptive standards for GHGs Oil Wells with Associated Gas ................... Route associated gas to a sales line. If access to a sales line is not available, the gas can be used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, or routed to a flare or other control device that achieves at least 95 percent reduction in methane and VOC emissions. Route associated gas to a sales line. If access to a sales line is not available, the gas can be used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, or routed to a flare or other control device that achieves at least 95 percent reduction in methane and VOC emissions. khammond on DSKJM1Z7X2PROD with PROPOSALS2 C. Costs and Benefits To satisfy requirements of E.O. 12866, the EPA projected the emissions reductions, costs, and benefits that may result from this proposed action. These results are presented in detail in the regulatory impact analysis (RIA) accompanying this proposal developed in response to E.O. 12866. The RIA focuses on the elements of the proposed rule that are likely to result in quantifiable cost or emissions changes compared to a baseline without the proposal that incorporates changes to regulatory requirements induced by the CRA resolution. We estimated the cost, emissions, and benefit impacts for the 2023 to 2035 period. We present the present value (PV) and equivalent annual value (EAV) of costs, benefits, and net benefits of this action in 2019 dollars. The initial analysis year in the RIA is 2023 as we assume the proposed rule will be finalized towards the end of 2022. The NSPS will take effect immediately and impact sources constructed after publication of the proposed rule. The EG will take longer to go into effect as States will need to develop implementation plans in response to the rule and have them approved by the EPA. We assume in the RIA that this process will take three years, and so EG impacts will begin in 2026. The final analysis year is 2035, which allows us to provide ten years of projected impacts after the EG is assumed to take effect. The cost analysis presented in the RIA reflects a nationwide engineering analysis of compliance cost and emissions reductions, of which there are two main components. The first component is a set of representative or model plants for each regulated facility, segment, and control option. The characteristics of the model plant include typical equipment, operating characteristics, and representative factors including baseline emissions and the costs, emissions reductions, and product recovery resulting from each control option. The second component is a set of projections of activity data for affected facilities, distinguished by vintage, year, and other necessary attributes (e.g., oil versus natural gas wells). Impacts are calculated by setting parameters on how and when affected facilities are assumed to respond to a particular regulatory regime, multiplying activity data by model plant cost and emissions estimates, differencing from the baseline scenario, and then summing to the desired level of aggregation. In addition to emissions reductions, some control options result in natural gas recovery, which can then be combusted in production or sold. Where applicable, we present projected compliance costs with and without the projected revenues from product recovery. The EPA expects climate and health benefits due to the emissions reductions projected under this proposed rule. The EPA estimated the global social benefits of CH4 emission reductions expected from this proposed rule using the SCCH4 estimates presented in the ‘‘Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under E.O. 13990 (IWG 2021)’’. These SC-CH4 estimates are interim values developed under E.O. 13990 for use in benefit-cost analyses until updated estimates of the impacts of climate change can be developed based on the best available science and economics. Under the proposed rule, the EPA expects that VOC emission reductions will improve air quality and are likely to improve health and welfare associated with exposure to ozone, PM2.5, and HAP. Calculating ozone impacts from VOC emissions changes requires information about the spatial patterns in those emissions changes. In addition, the ozone health effects from the proposed rule will depend on the relative proximity of expected VOC and ozone changes to population. In this analysis, we have not characterized VOC emissions changes at a finer spatial resolution than the national total. In light of these uncertainties, we present an illustrative screening analysis in Appendix B of the RIA based on modeled oil and natural gas VOC contributions to ozone concentrations as they occurred in 2017 and do not include the results of this analysis in the estimate of benefits and net benefits projected from this proposal. The projected national-level emissions reductions over the 2023 to 2035 period anticipated under the proposed requirements are presented in Table 4. Table 5 presents the PV and EAV of the projected benefits, costs, and net benefits over the 2023 to 2035 period under the proposed requirements using discount rates of 3 and 7 percent. TABLE 4—PROJECTED EMISSIONS REDUCTIONS UNDER THE PROPOSED RULE, 2023–2035 TOTAL Emissions reductions (2023–2035 total) Pollutant Methane (million short tons) a .................................................................................................................................................. VOC (million short tons) .......................................................................................................................................................... Hazardous Air Pollutant (million short tons) ............................................................................................................................ VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 E:\FR\FM\15NOP2.SGM 15NOP2 41 12 0.48 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules 63123 TABLE 4—PROJECTED EMISSIONS REDUCTIONS UNDER THE PROPOSED RULE, 2023–2035 TOTAL—Continued Emissions reductions (2023–2035 total) Pollutant Methane (million metric tons CO2 Eq.) b ................................................................................................................................. 920 a To convert from short tons to metric tons, multiply the short tons by 0.907. Alternatively, to convert metric tons to short tons, multiply metric tons by 1.102. b CO Eq. calculated using a global warming potential of 25. 2 TABLE 5—BENEFITS, COSTS, NET BENEFITS, AND EMISSIONS REDUCTIONS OF THE PROPOSED RULE, 2023 THROUGH 2035 [Dollar Estimates in Millions of 2019 Dollars] a 3 percent discount rate Present value Climate Benefits b ............................................................................................. Net Compliance Costs ..................................................................................... Compliance Costs .................................................................................... Product Recovery ..................................................................................... Net Benefits ..................................................................................................... Non-Monetized Benefits .................................................................................. 7 percent discount rate Equivalent annual value $55,000 7,200 13,000 5,500 48,000 $5,200 680 1,200 520 4,500 Present value Equivalent annual value ........................ 6,300 10,000 3,900 49,000 ........................ 760 1,200 470 4,500 Climate and ozone health benefits from reducing 41 million short tons of methane from 2023 to 2035. PM2.5 and ozone health benefits from reducing 12 million short tons of VOC from 2023 to 2035 c. HAP benefits from reducing 480 thousand short tons of HAP from 2023 to 2035. Visibility benefits. Reduced vegetation effects. a Values rounded to two significant figures. Totals may not appear to add correctly due to rounding. benefits are based on reductions in methane emissions and are calculated using four different estimates of the social cost of methane (SC-CH4) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). For the presentational purposes of this table, we show the benefits associated with the average SC-CH4 at a 3 percent discount rate, but the Agency does not have a single central SC-CH4 point estimate. We emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the present value (and equivalent annual value) of the additional benefit estimates ranges from $22 billion to $150 billion ($2.4 billion to $14 billion) over 2023 to 2035 for the proposed option. Please see Table 3–5 and Table 3–7 of the RIA for the full range of SCCH4 estimates. As discussed in Section 3 of the RIA, a consideration of climate benefits calculated using discount rates below 3 percent, including 2 percent and lower, are also warranted when discounting intergenerational impacts. All net benefits are calculated using climate benefits discounted at 3 percent. c A screening-level analysis of ozone benefits from VOC reductions can be found in Appendix B of the RIA, which is included in the docket. b Climate II. General Information A. Does this action apply to me? Categories and entities potentially affected by this action include: TABLE 6—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION Category NAICS code 1 Industry ..................................................................................................................... 211120 211130 221210 486110 486210 ............................ ............................ Federal Government ................................................................................................ State/local/Tribal government ................................................................................... khammond on DSKJM1Z7X2PROD with PROPOSALS2 1 North Examples of regulated entities Crude Petroleum Extraction. Natural Gas Extraction. Natural Gas Distribution. Pipeline Distribution of Crude Oil. Pipeline Transportation of Natural Gas. Not affected. Not affected. American Industry Classification System (NAICS). This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. Other types of entities not listed in the table could also be affected by this action. To determine whether your entity is affected by this VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 action, you should carefully examine the applicability criteria found in the final rule. If you have questions regarding the applicability of this action to a particular entity, consult the person listed in the FOR FURTHER INFORMATION CONTACT section, your air permitting PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 authority, or your EPA Regional representative listed in 40 CFR 60.4 (General Provisions). E:\FR\FM\15NOP2.SGM 15NOP2 63124 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules B. How do I obtain a copy of this document, background information, and other related information? In addition to being available in the docket, an electronic copy of the proposed action is available on the internet. Following signature by the Administrator, the EPA will post a copy of this proposed action at https:// www.epa.gov/controlling-air-pollutionoil-and-natural-gas-industry. Following publication in the Federal Register, the EPA will post the Federal Register version of the final rule and key technical documents at this same website. A redline version of the regulatory language that incorporates the proposed changes described in section X for NSPS OOOO and NSPS OOOOa is available in the docket for this action (Docket ID No. EPA–HQ– OAR–2021–0317). The EPA plans to propose the regulatory language for NSPS OOOOb and EG OOOOc through a supplemental action. III. Air Emissions From the Crude Oil and Natural Gas Sector and Public Health and Welfare khammond on DSKJM1Z7X2PROD with PROPOSALS2 A. Impacts of GHGs, VOCs and SO2 Emissions on Public Health and Welfare As noted previously, the Oil and Natural Gas Industry emits a wide range of pollutants, including GHGs (such as methane and CO2), VOCs, SO2, NOX, H2S, CS2, and COS. See 49 FR 2636, 2637 (January 20, 1984). As noted below, to this point, the EPA has focused its regulatory efforts on GHGs, VOC, and SO2.10 1. Climate Change Impacts From GHGs Emissions Elevated concentrations of GHGs are and have been warming the planet, leading to changes in the Earth’s climate including changes in the frequency and intensity of heat waves, precipitation, and extreme weather events; rising seas; and retreating snow and ice. The changes taking place in the atmosphere as a result of the well-documented buildup of GHGs due to human activities are changing the climate at a pace and in a way that threatens human health, society, and the natural environment. Human induced GHGs, largely derived from our reliance on fossil fuels, are causing serious and lifethreatening environmental and health impacts. 10 We note that the EPA’s focus on GHGs (in particular methane), VOC, and SO2 in these analyses, does not in any way limit the EPA’s authority to promulgate standards that would apply to other pollutants emitted from the Crude Oil and Natural Gas source category, if the EPA determines in the future that such action is appropriate. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 Extensive additional information on climate change is available in the scientific assessments and the EPA documents that are briefly described in this section, as well as in the technical and scientific information supporting them. One of those documents is the EPA’s 2009 Endangerment and Cause or Contribute Findings for GHGs Under Section 202(a) of the CAA (74 FR 66496, December 15, 2009).11 In the 2009 Endangerment Findings, the Administrator found under section 202(a) of the CAA that elevated atmospheric concentrations of six key well-mixed GHGs—CO2, CH4, N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)—‘‘may reasonably be anticipated to endanger the public health and welfare of current and future generations’’ (74 FR 66523, December 15, 2009), and the science and observed changes have confirmed and strengthened the understanding and concerns regarding the climate risks considered in the Finding. The 2009 Endangerment Findings, together with the extensive scientific and technical evidence in the supporting record, documented that climate change caused by human emissions of GHGs threatens the public health of the U.S. population. It explained that by raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses (74 FR 66497, December 15, 2009). While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the U.S. (74 FR 66525, December 15, 2009). The 2009 Endangerment Findings further explained that compared to a future without climate change, climate change is expected to increase tropospheric ozone pollution over broad areas of the U.S., including in the largest metropolitan areas with the worst tropospheric ozone problems, and thereby increase the risk of adverse effects on public health (74 FR 66525, December 15, 2009). Climate change is also expected to cause more intense hurricanes and more frequent and intense storms of other types and heavy precipitation, with impacts on other areas of public health, such as the potential for increased deaths, injuries, infectious and waterborne diseases, and stress-related disorders (74 FR 66525, December 15, 2009). Children, the 11 In describing these 2009 Findings in this proposal, the EPA is neither reopening nor revisiting them. PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 elderly, and the poor are among the most vulnerable to these climate-related health effects (74 FR 66498, December 15, 2009). The 2009 Endangerment Findings also documented, together with the extensive scientific and technical evidence in the supporting record, that climate change touches nearly every aspect of public welfare 12 in the U.S. with resulting economic costs, including: Changes in water supply and quality due to increased frequency of drought and extreme rainfall events; increased risk of storm surge and flooding in coastal areas and land loss due to inundation; increases in peak electricity demand and risks to electricity infrastructure; and the potential for significant agricultural disruptions and crop failures (though offset to some extent by carbon fertilization). These impacts are also global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S. (74 FR 66530, December 15, 2009). In 2016, the Administrator similarly issued Endangerment and Cause or Contribute Findings for GHG emissions from aircraft under section 231(a)(2)(A) of the CAA (81 FR 54422, August 15, 2016).13 In the 2016 Endangerment Findings, the Administrator found that the body of scientific evidence amassed in the record for the 2009 Endangerment Findings compellingly supported a similar endangerment finding under CAA section 231(a)(2)(A), and also found that the science assessments released between the 2009 and the 2016 Findings, ‘‘strengthen and further support the judgment that GHGs in the atmosphere may reasonably be anticipated to endanger the public health and welfare of current and future generations.’’ (81 FR 54424, August 15, 2016). Since the 2016 Endangerment Findings, the climate has continued to change, with new records being set for several climate indicators such as global average surface temperatures, GHG concentrations, and sea level rise. Moreover, heavy precipitation events 12 The CAA states in section 302(h) that ‘‘[a]ll language referring to effects on welfare includes, but is not limited to, effects on soils, water, crops, vegetation, manmade materials, animals, wildlife, weather, visibility, and climate, damage to and deterioration of property, and hazards to transportation, as well as effects on economic values and on personal comfort and well-being, whether caused by transformation, conversion, or combination with other air pollutants.’’ 42 U.S.C. 7602(h). 13 In describing these 2016 Findings in this proposal, the EPA is neither reopening nor revisiting them. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 have increased in the eastern U.S. while agricultural and ecological drought has increased in the western U.S. along with more intense and larger wildfires.14 These and other trends are examples of the risks discussed the 2009 and 2016 Endangerment Findings that have already been experienced. Additionally, major scientific assessments continue to demonstrate advances in our understanding of the climate system and the impacts that GHGs have on public health and welfare both for current and future generations. These updated observations and projections document the rapid rate of current and future climate change both globally and in the U.S. These assessments include: • U.S. Global Change Research Program’s (USGCRP) 2016 Climate and Health Assessment 15 and 2017–2018 Fourth National Climate Assessment (NCA4). 16 17 • IPCC’s 2018 Global Warming of 1.5 °C,18 2019 Climate Change and Land,19 and the 2019 Ocean and Cryosphere in a Changing Climate 20 14 See later in this section for specific examples. An additional resource for indicators can be found at https://www.epa.gov/climate-indicators. 15 USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change Research Program, Washington, DC, 312 pp. 16 USGCRP, 2017: Climate Science Special Report: Fourth National Climate Assessment, Volume I [Wuebbles, D.J., D.W. Fahey, K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 470 pp, doi: 10.7930/J0J964J6. 17 USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018. 18 IPCC, 2018: Global Warming of 1.5 °C. An IPCC Special Report on the impacts of global warming of 1.5 °C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Po¨rtner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Pe´an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)]. 19 IPCC, 2019: Climate Change and Land: an IPCC special report on climate change, desertification, land degradation, sustainable land management, food security, and greenhouse gas fluxes in terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V. Masson-Delmotte, H.-O. Po¨rtner, D.C. Roberts, P. Zhai, R. Slade, S. Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S. Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E. Huntley, K. Kissick, M. Belkacemi, J. Malley, (eds.)]. 20 IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere in a Changing Climate [H.-O. Po¨rtner, D.C. Roberts, V. Masson-Delmotte, P. Zhai, VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 assessments, as well as the 2021 IPCC Sixth Assessment Report (AR6).21 • The NAS 2016 Attribution of Extreme Weather Events in the Context of Climate Change,22 2017 Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide,23 and 2019 Climate Change and Ecosystems 24 assessments. • National Oceanic and Atmospheric Administration’s (NOAA) annual State of the Climate reports published by the Bulletin of the American Meteorological Society,25 most recently in August of 2020. • EPA Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts (2021).26 The most recent information demonstrates that the climate is continuing to change in response to the human-induced buildup of GHGs in the atmosphere. These recent assessments show that atmospheric concentrations of GHGs have risen to a level that has no precedent in human history and that they continue to climb, primarily as a result of both historic and current anthropogenic emissions, and that these elevated concentrations endanger our health by affecting our food and water sources, the air we breathe, the weather we experience, and our interactions with the natural and built environments. For example, atmospheric concentrations of one of these GHGs, CO2, measured at Mauna Loa in Hawaii and at other sites around the world reached 414 ppm in 2020 M. Tignor, E. Poloczanska, K. Mintenbeck, A. Alegrı´a, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M. Weyer (eds.)]. 21 IPCC, 2021: Summary for Policymakers. In: Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Pe´an, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekc¸i, R. Yu and B. Zhou (eds.)]. Cambridge University Press. In Press. 22 National Academies of Sciences, Engineering, and Medicine. 2016. Attribution of Extreme Weather Events in the Context of Climate Change. Washington, DC: The National Academies Press. https://dio.org/10.17226/21852. 23 National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. Washington, DC: The National Academies Press. https://doi.org/10.17226/24651. 24 National Academies of Sciences, Engineering, and Medicine. 2019. Climate Change and Ecosystems. Washington, DC: The National Academies Press. https://doi.org/10.17226/25504. 25 Blunden, J., and D.S. Arndt, Eds., 2020: State of the Climate in 2019. Bull. Amer. Meteor. Soc, S1–S429, https://doi.org/10.1175/2020BAMSStateof theClimate.1. 26 EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430–R–21–003. PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 63125 (nearly 50 percent higher than preindustrial levels),27 and has continued to rise at a rapid rate. Global average temperature has increased by about 1.1 degrees Celsius (°C) (2.0 degrees Fahrenheit (°F)) in the 2011–2020 decade relative to 1850–1900.28 The years 2014–2020 were the warmest seven years in the 1880–2020 record, contributing to the warmest decade on record with a decadal temperature of 0.82 °C (1.48 °F) above the 20th century.29 30 The IPCC determined (with medium confidence) that this past decade was warmer than any multicentury period in at least the past 100,000 years.31 Global average sea level has risen by about 8 inches (about 21 centimeters (cm)) from 1901 to 2018, with the rate from 2006 to 2018 (0.15 inches/year or 3.7 millimeters (mm)/ year) almost twice the rate over the 1971 to 2006 period, and three times the rate of the 1901 to 2018 period.32 The rate of sea level rise over the 20th century was higher than in any other century in at least the last 2,800 years.33 Higher CO2 concentrations have led to acidification of the surface ocean in recent decades to an extent unusual in the past 2 million years, with negative impacts on marine organisms that use calcium carbonate to build shells or skeletons.34 Arctic sea ice extent continues to decline in all months of the year; the most rapid reductions occur in September (very likely almost a 13 percent decrease per decade between 1979 and 2018) and are unprecedented in at least 1,000 years.35 Humaninduced climate change has led to heatwaves and heavy precipitation becoming more frequent and more intense, along with increases in 27 https://climate.nasa.gov/vital-signs/carbondioxide/. 28 IPCC, 2021. 29 NOAA National Centers for Environmental Information, State of the Climate: Global Climate Report for Annual 2020, published online January 2021, retrieved on February 10, 2021 from https:// www.ncdc.noaa.gov/sotc/global/202013. 30 Blunden, J., and D.S. Arndt, Eds., 2020: State of the Climate in 2019. Bull. Amer. Meteor. Soc, S1–S429, https://doi.org/10.1175/2020BAMSStateof theClimate.1. 31 IPCC, 2021. 32 IPCC, 2021. 33 USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018. 34 IPCC, 2021. 35 IPCC, 2021. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63126 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules agricultural and ecological droughts 36 in many regions.37 The assessment literature demonstrates that modest additional amounts of warming may lead to a climate different from anything humans have ever experienced. The present-day CO2 concentration of 414 ppm is already higher than at any time in the last 2 million years.38 If concentrations exceed 450 ppm, they would likely be higher than any time in the past 23 million years:39 at the current rate of increase of more than 2 ppm a year, this would occur in about 15 years. While GHGs are not the only factor that controls climate, it is illustrative that 3 million years ago (the last time CO2 concentrations were this high) Greenland was not yet completely covered by ice and still supported forests, while 23 million years ago (the last time concentrations were above 450 ppm) the West Antarctic ice sheet was not yet developed, indicating the possibility that high GHGs concentrations could lead to a world that looks very different from today and from the conditions in which human civilization has developed. If the Greenland and Antarctic ice sheets were to melt substantially, sea levels would rise dramatically—the IPCC estimated that over the next 2,000 years, sea level will rise by 7 to 10 feet even if warming is limited to 1.5 °C (2.7 °F), from 7 to 20 feet if limited to 2 °C (3.6 °F), and by 60 to 70 feet if warming is allowed to reach 5 °C (9 °F) above preindustrial levels.40 For context, almost all of the city of Miami is less than 25 feet above sea level, and the NCA4 stated that 13 million Americans would be at risk of migration due to 6 feet of sea level rise. Moreover, the CO2 being absorbed by the ocean has resulted in changes in ocean chemistry due to acidification of a magnitude not seen in 65 million years,41 putting many marine species— particularly calcifying species—at risk. The NCA4 found that it is very likely (greater than 90 percent likelihood) that by mid-century, the Arctic Ocean will be almost entirely free of sea ice by late summer for the first time in about 2 million years.42 Coral reefs will be at risk for almost complete (99 percent) losses with 1 °C (1.8 °F) of additional warming from today (2 °C or 3.6 °F since preindustrial). At this temperature, between 8 and 18 percent of animal, plant, and insect species could lose over 36 These are drought measures based on soil moisture. 37 IPCC, 2021. 38 IPCC, 2021. 39 IPCC, 2013. 40 IPCC, 2021. 41 IPCC, 2018. 42 USGCRP, 2018. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 half of the geographic area with suitable climate for their survival, and 7 to 10 percent of rangeland livestock would be projected to be lost.43 Every additional increment of temperature comes with consequences. For example, the half degree of warming from 1.5 to 2 °C (0.9 °F of warming from 2.7 °F to 3.6 °F) above preindustrial temperatures is projected on a global scale to expose 420 million more people to frequent extreme heatwaves, and 62 million more people to frequent exceptional heatwaves (where heatwaves are defined based on a heat wave magnitude index which takes into account duration and intensity—using this index, the 2003 French heat wave that led to almost 15,000 deaths would be classified as an ‘‘extreme heatwave’’ and the 2010 Russian heatwave which led to thousands of deaths and extensive wildfires would be classified as ‘‘exceptional’’). It would increase the frequency of sea-ice-free Arctic summers from once in a hundred years to once in a decade. It could lead to 4 inches of additional sea level rise by the end of the century, exposing an additional 10 million people to risks of inundation, as well as increasing the probability of triggering instabilities in either the Greenland or Antarctic ice sheets. Between half a million and a million additional square miles of permafrost would thaw over several centuries. Risks to food security would increase from medium to high for several lower income regions in the Sahel, southern Africa, the Mediterranean, central Europe, and the Amazon. In addition to food security issues, this temperature increase would have implications for human health in terms of increasing ozone concentrations, heatwaves, and vectorborne diseases (for example, expanding the range of the mosquitoes which carry dengue fever, chikungunya, yellow fever, and the Zika virus, or the ticks which carry Lyme. babesiosis, or Rocky Mountain Spotted Fever).44 Moreover, every additional increment in warming leads to larger changes in extremes, including the potential for events unprecedented in the observational record. Every additional degree will intensify extreme precipitation events by about 7 percent. The peak winds of the most intense tropical cyclones (hurricanes) are projected to increase with warming. In addition to a higher intensity, the IPCC found that precipitation and frequency of rapid intensification of these storms has already increased, while the movement 43 IPCC, 44 IPCC, PO 00000 2018. 2018. Frm 00018 Fmt 4701 Sfmt 4702 speed has decreased, and elevated sea levels have increased coastal flooding, all of which make these tropical cyclones more damaging.45 The NCA4 also evaluated a number of impacts specific to the U.S. Severe drought and outbreaks of insects like the mountain pine beetle have killed hundreds of millions of trees in the western U.S. Wildfires have burned more than 3.7 million acres in 14 of the 17 years between 2000 and 2016, and Federal wildfire suppression costs were about a billion dollars annually.46 The National Interagency Fire Center has documented U.S. wildfires since 1983, and the ten years with the largest acreage burned have all occurred since 2004.47 Wildfire smoke degrades air quality increasing health risks, and more frequent and severe wildfires due to climate change would further diminish air quality, increase incidences of respiratory illness, impair visibility, and disrupt outdoor activities, sometimes thousands of miles from the location of the fire. Meanwhile, sea level rise has amplified coastal flooding and erosion impacts, requiring the installation of costly pump stations, flooding streets, and increasing storm surge damages. Tens of billions of dollars of U.S. real estate could be below sea level by 2050 under some scenarios. Increased frequency and duration of drought will reduce agricultural productivity in some regions, accelerate depletion of water supplies for irrigation, and expand the distribution and incidence of pests and diseases for crops and livestock. The NCA4 also recognized that climate change can increase risks to national security, both through direct impacts on military infrastructure, but also by affecting factors such as food and water availability that can exacerbate conflict outside U.S. borders. Droughts, floods, storm surges, wildfires, and other extreme events stress nations and people through loss of life, displacement of populations, and impacts on livelihoods.48 Some GHGs also have impacts beyond those mediated through climate change. For example, elevated concentrations of carbon dioxide stimulate plant growth (which can be positive in the case of beneficial species, but negative in terms of weeds and invasive species, and can also lead to a reduction in plant 45 IPCC, 2021. 2018 47 NIFC (National Interagency Fire Center). 2021. Total wildland fires and acres (1983–2020). Accessed August 2021. www.nifc.gov/fireInfo/ fireInfo_stats_totalFires.html. 48 USGCRP, 2018. 46 USGCRP, E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules micronutrients) 49 and cause ocean acidification. Nitrous oxide depletes the levels of protective stratospheric ozone.50 As methane is the primary GHG addressed in this proposal, it is relevant to highlight some specific trends and impacts specific to methane. Concentrations of methane reached 1879 parts per billion (ppb) in 2020, more than two and a half times the preindustrial concentration of 722 ppb.51 Moreover, the 2020 concentration was an increase of almost 13 ppb over 2019—the largest annual increase in methane concentrations of the period since the early 1990s, continuing a trend of rapid rise since a temporary pause ended in 2007.52 Methane has a high radiative efficiency—almost 30 times that of carbon dioxide per ppb (and therefore, 80 times as much per unit mass).53 In addition, methane contributes to climate change through chemical reactions in the atmosphere that produce tropospheric ozone and stratospheric water vapor. Human emissions of methane are responsible for about one third of the warming due to well-mixed GHGs, the second most important human warming agent after carbon dioxide.54 Because of the substantial emissions of methane, and its radiative efficiency, methane mitigation is one of the best opportunities for reducing near term warming. The tropospheric ozone produced by the reaction of methane in the atmosphere has harmful effects for human health and plant growth in addition to its climate effects.55 In remote areas, methane is an important precursor to tropospheric ozone khammond on DSKJM1Z7X2PROD with PROPOSALS2 49 Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F. Garofalo, A.S. Khan, I. Loladze, A.A. Pe´rez de Leo´n, A.Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety, Nutrition, and Distribution. The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. U.S. Global Change Research Program, Washington, DC, 189– 216. https://dx.doi.org/10.7930/J0ZP4417 50 WMO (World Meteorological Organization), Scientific Assessment of Ozone Depletion: 2018, Global Ozone Research and Monitoring Project— Report No. 58, 588 pp., Geneva, Switzerland, 2018. 51 Blunden et al., 2020. 52 NOAA, https://gml.noaa.gov/webdata/ccgg/ trends/ch4/ch4_annmean_gl.txt, accessed August 19th, 2021. 53 IPCC, 2021. 54 IPCC, 2021. 55 Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik, R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air Quality. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 512–538. doi: 10.7930/NCA4. 2018. CH13 VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 formation.56 Approximately 50 percent of the global annual mean ozone increase since preindustrial times is believed to be due to anthropogenic methane.57 Projections of future emissions also indicate that methane is likely to be a key contributor to ozone concentrations in the future.58 Unlike NOX and VOC, which affect ozone concentrations regionally and at hourly time scales, methane emissions affect ozone concentrations globally and on decadal time scales given methane’s long atmospheric lifetime when compared to these other ozone precursors.59 Reducing methane emissions, therefore, will contribute to efforts to reduce global background ozone concentrations that contribute to the incidence of ozone-related health effects.60 The benefits of such reductions are global and occur in both urban and rural areas. These scientific assessments and documented observed changes in the climate of the planet and of the U.S. present clear support regarding the current and future dangers of climate change and the importance of GHG mitigation. 2. VOC Many VOC can be classified as HAP (e.g., benzene),61 which can lead to a variety of health concerns such as cancer and noncancer illnesses (e.g., respiratory, neurological). Further, VOC are one of the key precursors in the formation of ozone. Tropospheric, or ground-level, ozone is formed through reactions of VOC and NOX in the presence of sunlight. Ozone formation can be controlled to some extent through reductions in emissions of the ozone precursors VOC and NOX. Recent observational and modeling studies have found that VOC emissions from oil 56 U.S. EPA. 2013. ‘‘Integrated Science Assessment for Ozone and Related Photochemical Oxidants (Final Report).’’ EPA–600–R–10–076F. National Center for Environmental Assessment— RTP Division. Available at https://www.epa.gov/ ncea/isa/. 57 Myhre, G., D. Shindell, F.-M. Bre ´ on, W. Collins, J. Fuglestvedt, J. Huang, D. Koch, J.-F. Lamarque, D. Lee, B. Mendoza, T. Nakajima, A. Robock, G. Stephens, T. Takemura and H. Zhang, 2013: Anthropogenic and Natural Radiative Forcing. In: Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA. Pg. 680. 58 Ibid. 59 Ibid. 60 USGCRP, 2018. 61 Benzene Integrated Risk Information System (IRIS) Assessment: https://cfpub.epa.gov/ncea/iris2/ chemicalLanding.cfm?substance_nmbr=276. PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 63127 and natural gas operations can impact ozone levels.62 63 64 65 A significantly expanded body of scientific evidence shows that ozone can cause a number of harmful effects on health and the environment. Exposure to ozone can cause respiratory system effects such as difficulty breathing and airway inflammation. For people with lung diseases such as asthma and chronic obstructive pulmonary disease (COPD), these effects can lead to emergency room visits and hospital admissions. Studies have also found that ozone exposure is likely to cause premature death from lung or heart diseases. In addition, evidence indicates that longterm exposure to ozone is likely to result in harmful respiratory effects, including respiratory symptoms and the development of asthma. People most at risk from breathing air containing ozone include children; people with asthma and other respiratory diseases; older adults; and people who are active outdoors, especially outdoor workers. An estimated 25.9 million people have asthma in the U.S., including almost 7.1 million children. Asthma disproportionately affects children, families with lower incomes, and minorities, including Puerto Ricans, Native Americans/Alaska Natives, and African Americans.66 In the EPA’s 2020 Integrated Science Assessment (ISA) for Ozone and Related Photochemical Oxidants,67 the EPA estimates the incidence of air pollution effects for those health endpoints above where the ISA classified as either causal or likely-to-be-causal. In brief, the ISA for ozone found short-term (less than one month) exposures to ozone to be 62 Benedict, K. B., Zhou, Y., Sive, B. C., Prenni, A. J., Gebhart, K. A., Fischer, E. V., . . . & Collett Jr, J. L. 2019. Volatile organic compounds and ozone in Rocky Mountain National Park during FRAPPE. Atmospheric Chemistry and Physics, 19(1), 499–521. 63 Lindaas, J., Farmer, D. K., Pollack, I. B., Abeleira, A., Flocke, F., & Fischer, E. V. 2019. Acyl peroxy nitrates link oil and natural gas emissions to high ozone abundances in the Colorado Front Range during summer 2015. Journal of Geophysical Research: Atmospheres, 124(4), 2336–2350. 64 McDuffie, E. E., Edwards, P. M., Gilman, J. B., Lerner, B. M., Dube´, W. P., Trainer, M., . . . & Brown, S. S. 2016. Influence of oil and gas emissions on summertime ozone in the Colorado Northern Front Range. Journal of Geophysical Research: Atmospheres, 121(14), 8712–8729. 65 Tzompa-Sosa, Z. A., & Fischer, E. V. 2021. Impacts of emissions of C2-C5 alkanes from the US oil and gas sector on ozone and other secondary species. Journal of Geophysical Research: Atmospheres, 126(1), e2019JD031935. 66 National Health Interview Survey (NHIS) Data, 2011. https://www.cdc.gov/asthma/nhis/2011/ data.htm. 67 Integrated Science Assessment (ISA) for Ozone and Related Photochemical Oxidants (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R–20/012, 2020. E:\FR\FM\15NOP2.SGM 15NOP2 63128 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules causally related to respiratory effects, a ‘‘likely to be causal’’ relationship with metabolic effects and a ‘‘suggestive of, but not sufficient to infer, a causal relationship’’ for central nervous system effects, cardiovascular effects, and total mortality. The ISA reported that longterm exposures (one month or longer) to ozone are ‘‘likely to be causal’’ for respiratory effects including respiratory mortality, and a ‘‘suggestive of, but not sufficient to infer, a causal relationship’’ for cardiovascular effects, reproductive effects, central nervous system effects, metabolic effects, and total mortality. An example of quantified incidence of ozone health effects can be found in the Regulatory Impact Analysis for the Final Revised Cross-State Air Pollution Rule (CSAPR) Update. Scientific evidence also shows that repeated exposure to ozone can reduce growth and have other harmful effects on sensitive plants and trees. These types of effects have the potential to impact ecosystems and the benefits they provide. khammond on DSKJM1Z7X2PROD with PROPOSALS2 3. SO2 Current scientific evidence links short-term exposures to SO2, ranging from 5 minutes to 24 hours, with an array of adverse respiratory effects including bronchoconstriction and increased asthma symptoms. These effects are particularly important for asthmatics at elevated ventilation rates (e.g., while exercising or playing). Studies also show an association between short-term exposure and increased visits to emergency departments and hospital admissions for respiratory illnesses, particularly in at-risk populations including children, the elderly, and asthmatics. SO2 in the air can also damage the leaves of plants, decrease their ability to produce food—photosynthesis—and decrease their growth. In addition to directly affecting plants, SO2, when deposited on land and in estuaries, lakes, and streams, can acidify sensitive ecosystems resulting in a range of harmful indirect effects on plants, soils, water quality, and fish and wildlife (e.g., changes in biodiversity and loss of habitat, reduced tree growth, loss of fish species). Sulfur deposition to waterways also plays a causal role in the methylation of mercury.68 68 U.S. EPA. Integrated Science Assessment (ISA) for Oxides of Nitrogen and Sulfur Ecological Criteria (2008 Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R– 08/082F, 2008. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 B. Oil and Natural Gas Industry and Its Emissions This section generally describes the structure of the Oil and Natural Gas Industry, the interconnected production, processing, transmission and storage, and distribution segments that move product from well to market, and types of emissions sources in each segment and the industry’s emissions. 1. Oil and Natural Gas Industry— Structure The EPA characterizes the oil and natural gas industry’s operations as being generally composed of four segments: (1) Extraction and production of crude oil and natural gas (‘‘oil and natural gas production’’), (2) natural gas processing, (3) natural gas transmission and storage, and (4) natural gas distribution.69 70 The EPA regulates oil refineries as a separate source category; accordingly, as with the previous oil and gas NSPS rulemakings, for purposes of this proposed rulemaking, for crude oil, the EPA’s focus is on operations from the well to the point of custody transfer at a petroleum refinery, while for natural gas, the focus is on all operations from the well to the local distribution company custody transfer station commonly referred to as the ‘‘city-gate.’’ 71 a. Production Segment The oil and natural gas production segment includes the wells and all related processes used in the extraction, production, recovery, lifting, stabilization, and separation or treatment of oil and/or natural gas (including condensate). Although many wells produce a combination of oil and natural gas, wells can generally be grouped into two categories, oil wells and natural gas wells. Oil wells comprise two types, oil wells that produce crude oil only and oil wells 69 The EPA previously described an overview of the sector in section 2.0 of the 2011 Background Technical Support Document to 40 CFR part 60, subpart OOOO, located at Docket ID Item No. EPA– HQ–OAR–2010–0505–0045, and section 2.0 of the 2016 Background Technical Support Document to 40 CFR part 60, subpart OOOOa, located at Docket ID Item No. EPA–HQ–OAR–2010–0505–7631. 70 While generally oil and natural gas production includes both onshore and offshore operations, 40 CFR part 60, subpart OOOOa addresses onshore operations. 71 For regulatory purposes, the EPA defines the Crude Oil and Natural Gas source category to mean (1) Crude oil production, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other forms of transportation; and (2) Natural gas production, processing, transmission, and storage, which include the well and extend to, but do not include, the local distribution company custody transfer station. The distribution segment is not part of the defined source category. PO 00000 Frm 00020 Fmt 4701 Sfmt 4702 that produce both crude oil and natural gas (commonly referred to as ‘‘associated’’ gas). Production equipment and components located on the well pad may include, but are not limited to, wells and related casing heads; tubing heads; ‘‘Christmas tree’’ piping, pumps, compressors; heater treaters; separators; storage vessels; pneumatic devices; and dehydrators. Production operations include well drilling, completion, and recompletion processes, including all the portable non-self-propelled apparatuses associated with those operations. Other sites that are part of the production segment include ‘‘centralized tank batteries,’’ stand-alone sites where oil, condensate, produced water, and natural gas from several wells may be separated, stored, or treated. The production segment also includes gathering pipelines, gathering and boosting compressor stations, and related components that collect and transport the oil, natural gas, and other materials and wastes from the wells to the refineries or natural gas processing plants. Of these products, crude oil and natural gas undergo successive, separate processing. Crude oil is separated from water and other impurities and transported to a refinery via truck, railcar, or pipeline. As noted above, the EPA treats oil refineries as a separate source category, accordingly, for present purposes, the oil component of the production segment ends at the point of custody transfer at the refinery.72 The separated, unprocessed natural gas is commonly referred to as field gas and is composed of methane, natural gas liquids (NGL), and other impurities, such as water vapor, H2S, CO2, helium, and nitrogen. Ethane, propane, butane, isobutane, and pentane are all considered NGL and often are sold separately for a variety of different uses. Natural gas with high methane content is referred to as ‘‘dry gas,’’ while natural gas with significant amounts of ethane, propane, or butane is referred to as ‘‘wet gas.’’ Natural gas typically is sent to gas processing plants in order to separate NGLs for use as feedstock for petrochemical plants, burned for space heating and cooking, or blended into vehicle fuel. b. Processing Segment The natural gas processing segment consists of separating certain hydrocarbons (HC) and fluids from the natural gas to produce ‘‘pipeline quality’’ dry natural gas. The degree and 72 See 40 CFR part 60, subparts J and Ja, and 40 CFR part 63, subparts CC and UUU. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 location of processing is dependent on factors such as the type of natural gas (e.g., wet or dry gas), market conditions, and company contract specifications. Typically, processing of natural gas begins in the field and continues as the gas is moved from the field through gathering and boosting compressor stations to natural gas processing plants, where the complete processing of natural gas takes place. Natural gas processing operations separate and recover NGL or other non-methane gases and liquids from field gas through one or more of the following processes: oil and condensate separation, water removal, separation of NGL, sulfur and CO2 removal, fractionation of NGL, and other processes, such as the capture of CO2 separated from natural gas streams for delivery outside the facility. c. Transmission and Storage Segment Once natural gas processing is complete, the resulting natural gas exits the natural gas process plant and enters the transmission and storage segment where it is transmitted to storage and/ or distribution to the end user. Pipelines in the natural gas transmission and storage segment can be interstate pipelines, which carry natural gas across state boundaries, or intrastate pipelines, which transport the gas within a single state. Basic components of the two types of pipelines are the same, though interstate pipelines may be of a larger diameter and operated at a higher pressure. To ensure that the natural gas continues to flow through the pipeline, the natural gas must periodically be compressed, thereby increasing its pressure. Compressor stations perform this function and are usually placed at 40- to 100-mile intervals along the pipeline. At a compressor station, the natural gas enters the station, where it is compressed by reciprocating or centrifugal compressors. Another part of the transmission and storage segment are aboveground and underground natural gas storage facilities. Storage facilities hold natural gas for use during peak seasons. The main difference between underground and aboveground storage sites is that storage takes place in storage vessels constructed of non-earthen materials in aboveground storage. Underground storage of natural gas typically occurs in depleted natural gas or oil reservoirs and salt dome caverns. One purpose of this storage is for load balancing (equalizing the receipt and delivery of natural gas). At an underground storage site, typically other processes occur, including compression, dehydration, and flow measurement. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 d. Distribution Segment The distribution segment provides the final step in delivering natural gas to customers.73 The natural gas enters the distribution segment from delivery points located along interstate and intrastate transmission pipelines to business and household customers. The delivery point where the natural gas leaves the transmission and storage segment and enters the distribution segment is a local distribution company’s custody transfer station, commonly referred to as the ‘‘city-gate.’’ Natural gas distribution systems consist of over 2 million miles of piping, including mains and service pipelines to the customers. If the distribution network is large, compressor stations may be necessary to maintain flow; however, these stations are typically smaller than transmission compressor stations. Distribution systems include metering stations and regulating stations, which allow distribution companies to monitor the natural gas as it flows through the system. 2. Oil and Natural Gas Industry— Emissions The oil and natural gas industry sector is the largest source of industrial methane emissions in the U.S.74 Natural gas is comprised primarily of methane; every natural gas leak or intentional release through venting or other industrial processes constitutes a release of methane. Methane is a potent greenhouse gas; over a 100-year timeframe, it is nearly 30 times more powerful at trapping climate warming heat than CO2, and over a 20-year timeframe, it is 83 times more powerful.75 Because methane is a powerful greenhouse gas and is emitted in large quantities, reductions in methane emissions provide a significant benefit in reducing near-term warming. Indeed, one third of the warming due to GHGs that we are experiencing today is due to human emissions of methane. Additionally, the Crude Oil and Natural Gas sector emits, in varying concentrations and amounts, a wide range of other health-harming pollutants, including VOCs, SO2, NOX, H2S, CS2, and COS. The year 2016 modeling platform produced by U.S. EPA estimated about 3 million tons of 73 The distribution segment is not included in the definition of the Crude Oil and Natural Gas source category that is currently regulated under 40 CFR part 60, subpart OOOOa. 74 H.R. Rep. No. 117–64, 4 (2021) (Report by the House Committee on Energy and Commerce concerning H.J. Res. 34, to disapprove the 2020 Policy Rule) (House Report). 75 IPCC, 2021. PO 00000 Frm 00021 Fmt 4701 Sfmt 4702 63129 VOC are emitted by oil and gas-related sources.76 Emissions of methane and these copollutants occur in every segment of the Crude Oil and Natural Gas source category. Many of the processes and equipment types that contribute to these emissions are found in every segment of the source category and are highly similar across segments. Emissions from the crude oil portion of the regulated source category result primarily from field production operations, such as venting of associated gas from oil wells, oil storage vessels, and productionrelated equipment such as gas dehydrators, pig traps, and pneumatic devices. Emissions from the natural gas portion of the industry can occur in all segments. As natural gas moves through the system, emissions primarily result from intentional venting through normal operations, routine maintenance, unintentional fugitive emissions, flaring, malfunctions, and system upsets. Venting can occur through equipment design or operational practices, such as the continuous and intermittent bleed of gas from pneumatic controllers (devices that control gas flows, levels, temperatures, and pressures in the equipment). In addition to vented emissions, emissions can occur from leaking equipment (also referred to as fugitive emissions) in all parts of the infrastructure, including major production and processing equipment (e.g., separators or storage vessels) and individual components (e.g., valves or connectors). Flares are commonly used throughout each segment in the Oil and Natural Gas Industry as a control device to provide pressure relief to prevent risk of explosions and to destroy methane, which has a high global warming potential, and convert it to CO2 which has a lower global warming potential, and to also control other air pollutants such as VOC. ‘‘Super-emitting’’ events, sites, or equipment, where a small proportion of sources account for a large proportion of overall emissions, can occur throughout the Oil and Natural Gas Industry and have been observed to occur in the equipment types and activities covered by this proposed action. There are a number of definitions for the term ‘‘super-emitter.’’ A 2018 National Academies of Sciences, Engineering, and Medicine report 77 on methane discussed three categories of ‘‘highemitting’’ sources: 76 https://www.epa.gov/sites/default/files/202011/documents/2016v1_emismod_tsd_508.pdf. 77 https://www.nap.edu/download/24987#. E:\FR\FM\15NOP2.SGM 15NOP2 63130 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules • Routine or ‘‘chronic’’ high-emitting sources, which regularly emit at higher rates relative to ‘‘peers’’ in a sample. Examples include large facilities, or large emissions at smaller facilities caused by poor design or operational practices. • Episodic high-emitting sources, which are typically large in nature and are generally intentional releases from known maintenance events at a facility. Examples include gas well liquids unloading, well workovers and maintenance activities, and compressor station or pipeline blowdowns. • Malfunctioning high-emitting sources, which can be either intermittent or prolonged in nature and result from malfunctions and poor work practices. Examples include malfunctioning intermittent pneumatic controllers and stuck open dump valves. Another example is well blowout events. For example, a 2018 well blowout in Ohio was estimated to have emitted over 60,000 tons of methane.78 Super-emitters have been observed at many different scales, from site-level to component-level, across many research studies.79 Studies will often develop a study-specific definition such as a top percentile of emissions in a study population (e.g., top 10 percent), emissions exceeding a certain threshold (e.g., 26 kg/day), emissions over a certain detection threshold (e.g., 1–3 g/ s) or as facilities with the highest proportional emission rate.80 For certain equipment types and activities, the EPA’s GHG emission estimates include the full range of conditions, including ‘‘super-emitters.’’ For other situations, where data are available, emissions estimates for abnormal events are calculated separately and included in the Inventory of U.S. Greenhouse Gas Emissions and Sinks (‘‘GHGI’’) (e.g., Aliso Canyon leak event).81 Given the variability of practices and technologies across oil and gas systems and the occurrence of episodic events, it is possible that the EPA’s estimates do not include all methane emissions from abnormal events. The EPA continues to work through its stakeholder process to review new data from the EPA’s Greenhouse Gas Reporting Program (‘‘GHGRP’’) petroleum and natural gas systems source category (40 CFR part 98, subpart W, also referred to as ‘‘GHGRP subpart W’’) and research studies to assess how emissions estimates can be improved. Because lost gas, whether through fugitive emissions, unintentional gas carry through, or intentional releases, represents lost earning potential, the industry benefits from capturing and selling emissions of natural gas (and methane). Limiting super-emitters through actions included in this rule such as reducing fugitive emissions, using lower emitting equipment where feasible, and employing best management practices will not only reduce emissions but reduce the loss of revenue from this valuable commodity. Below we provide estimated emissions of methane, VOC, and SO2 from Oil and Natural Gas Industry operation sources. Methane emissions in the U.S. and from the Oil and Natural Gas industry. Official U.S. estimates of national level GHG emissions and sinks are developed by the EPA for the GHGI in fulfillment of commitments under the United Nations Framework Convention on Climate Change. The GHGI, which includes recent trends, is organized by industrial sector. The oil and natural gas production, natural gas processing, and natural gas transmission and storage sectors emit 28 percent of U.S. anthropogenic methane. Table 7 below presents total U.S. anthropogenic methane emissions for the years 1990, 2010, and 2019. In accordance with the practice of the EPA GHGI, the EPA GHGRP, and international reporting standards under the UN Framework Convention on Climate Change, the 2007 IPCC Fourth Assessment Report value of the methane 100-year GWP is used for weighting emissions in the following tables. The 100-year GWP value of 25 for methane indicates that one ton of methane has approximately as much climate impact over a 100-year period as 25 tons of carbon dioxide. The most recent IPCC AR6 assessment has estimated a slightly larger 100-year GWP of methane of almost 30 (specifically, either 27.2 or 29.8 depending on whether the value includes the carbon dioxide produced by the oxidation of methane in the atmosphere). As mentioned earlier, because methane has a shorter lifetime than carbon dioxide, the emissions of a ton of methane will have more impact earlier in the 100-year timespan and less impact later in the 100-year timespan relative to the emissions of a 100-year GWP-equivalent quantity of carbon dioxide: When using the AR6 20-year GWP of 81, which only looks at impacts over the next 20 years, the total US emissions of methane in 2019 would be equivalent to about 2140 MMT CO2. TABLE 7—U.S. METHANE EMISSIONS BY SECTOR [Million metric tons carbon dioxide equivalent (MMT CO2 EQ.)] Sector 1990 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Oil and Natural Gas Production, and Natural Gas Processing and Transmission and Storage Landfills ........................................................................................................................................ Enteric Fermentation ................................................................................................................... 78 Pandey et al. (2019). Satellite observations reveal extreme methane leakage from a natural gas well blowout. PNAS December 26, 2019 116 (52) 26376–26381. 79 See for example, Brandt, A., Heath, G., Cooley, D. (2016) Methane leaks from natural gas systems follow extreme distributions. Environ. Sci. Technol., DOI: 10.1021/acs.est.6b04303; Zavala-Araiza, D., Alvarez, R.A., Lyon, D.R., Allen, D.T., Marchese, A.J., Zimmerle, D.J., & Hamburg, S.P. (2017). Superemitters in natural gas infrastructure are caused by abnormal process conditions. Nature communications, 8, 14012; Mitchell, A., et al. (2015), Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results. Environmental Science & Technology, 49(5), 3219–3227; Allen, D., et al. (2014), Methane Emissions from Process VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers. Environmental Science & Technology. 80 Caulton et al. (2019). Importance of Superemitter Natural Gas Well Pads in the Marcellus Shale. Environ. Sci. Technol. 2019, 53, 4747–4754; Zavala-Araiza, D., Alvarez, R., Lyon, D, et al. (2016). Super-emitters in natural gas infrastructure are caused by abnormal process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/ articles/ncomms14012; Lyon, et al. (2016). Aerial Surveys of Elevated Hydrocarbon Emissions from Oil and Gas Production Sites. Environ. Sci. Technol. 2016, 50, 4877–4886. https://pubs.acs.org/ doi/10.1021/acs.est.6b00705; and Zavala-Araiza D, et al. (2015). Toward a functional definition of methane superemitters: Application to natural gas production sites. 49 ENVTL. SCI. & TECH. 8167, PO 00000 Frm 00022 Fmt 4701 Sfmt 4702 2010 189 177 165 2019 176 124 172 182 114 179 8168 (2015). https://pubs.acs.org/doi/10.1021/ acs.est.5b00133. 81 The EPA’s emission estimates in the GHGI are developed with the best data available at the time of their development, including data from the Greenhouse Gas Reporting Program (GHGRP) in 40 CFR part 98, subpart W, and from recent research studies. GHGRP subpart W emissions data used in the GHGI are quantified by reporters using direct measurements, engineering calculations, or emission factors, as specified by the regulation. The EPA has a multi-step data verification process for GHGRP subpart W data, including automatic checks during data-entry, statistical analyses on completed reports, and staff review of the reported data. Based on the results of the verification process, the EPA follows up with facilities to resolve mistakes that may have occurred. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules 63131 TABLE 7—U.S. METHANE EMISSIONS BY SECTOR—Continued [Million metric tons carbon dioxide equivalent (MMT CO2 EQ.)] Sector 1990 2010 2019 Coal Mining .................................................................................................................................. Manure Management ................................................................................................................... Other Oil and Gas Sources ......................................................................................................... Wastewater Treatment ................................................................................................................ Other Methane Sources 82 ........................................................................................................... 96 37 46 20 46 82 55 17 19 47 47 62 15 18 42 Total Methane Emissions ..................................................................................................... 777 692 660 Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990–2019 (published April 14, 2021), calculated using GWP of 25. Note: Totals may not sum due to rounding. Table 8 below presents total methane emissions from natural gas production through transmission and storage and petroleum production, for years 1990, 2010, and 2019, in MMT CO2 Eq. (or million metric tons CO2 Eq.) of methane. TABLE 8—U.S. METHANE EMISSIONS FROM NATURAL GAS AND PETROLEUM SYSTEMS [MMT CO2 EQ.] Sector 1990 Natural Gas Production ............................................................................................................... Natural Gas Processing ............................................................................................................... Natural Gas Transmission and Storage ...................................................................................... Petroleum Production .................................................................................................................. 2010 63 21 57 48 2019 97 10 30 39 94 12 37 38 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990–2019 (published April 14, 2021), calculated using GWP of 25. Note: Totals may not sum due to rounding. Global GHG Emissions. For additional background information and context, we used 2018 World Resources Institute Climate Watch data to make comparisons between U.S. oil and natural gas production and natural gas processing and transmission and storage emissions and the emissions inventories of entire countries and regions.83 The U.S. methane emissions from oil and natural gas production and natural gas processing and transmission and storage constitute 0.4 percent of total global emissions of all GHGs (48,601 MMT CO2 Eq.) from all sources.84 Ranking U.S. emissions of methane from oil and natural gas production and natural gas processing and transmission and storage against total GHG emissions for entire countries (using 2018 Climate Watch data), shows that these emissions are comparatively large as they exceed the national-level emissions totals for all GHGs and all anthropogenic sources for Colombia, the Czech Republic, Chile, Belgium, and over 160 other countries. What that means is that the U.S. emits more of a single GHG—methane—from a single sector—the oil and gas sector— than the total combined GHGs emitted by 164 out of 194 total countries. Furthermore, U.S. emissions of methane from oil and natural gas production and natural gas processing and transmission and storage are greater than the sum of total emissions of 64 of the lowestemitting countries and territories, using the 2018 Climate Watch data set. As illustrated by the domestic and global GHGs comparison data summarized above, the collective GHG emissions from the Crude Oil and Natural Gas source category are significant, whether the comparison is domestic (where this sector is the largest source of methane emissions, accounting for 28 percent of U.S. methane and 3 percent of total U.S. emissions of all GHGs), global (where this sector, accounting for 0.4 percent of all global GHG emissions, emits more than the total national emissions of over 160 countries, and combined emissions of over 60 countries), or when both the domestic and global GHG emissions comparisons are viewed in combination. Consideration of the global context is important. GHG emissions from U.S. Oil and Natural Gas production and natural gas processing and transmission and storage will become globally well-mixed in the atmosphere, and thus will have an effect on the U.S. regional climate, as well as the global climate as a whole for years and indeed many decades to come. No single GHG source category dominates on the global scale. While the Crude Oil and Natural Gas source category, like many (if not all) individual GHG source categories, could appear small in comparison to total emissions, in fact, it is a very important contributor in terms of both absolute emissions, and in comparison to other source categories globally or within the U.S. The IPCC AR6 assessment determined that ‘‘From a physical science perspective, limiting human-induced global warming to a specific level requires limiting cumulative CO2 emissions, reaching at least net zero CO2 emissions, along with strong reductions in other GHG emissions.’’ The report also singled out the importance of ‘‘strong and sustained CH4 emission reductions’’ in part due to the short lifetime of methane leading to the nearterm cooling from reductions in methane emissions, which can offset the warming that will result due to reductions in emissions of cooling aerosols such as SO2. Therefore, reducing methane emissions globally is an important facet in any strategy to limit warming. In the oil and gas sector, 82 Other sources include rice cultivation, forest land, stationary combustion, abandoned oil and natural gas wells, abandoned coal mines, mobile combustion, composting, and several sources emitting less than 1 MMT CO2 Eq. in 2019. 83 The Climate Watch figures presented here come from the PIK PRIMAP-hist dataset included on Climate Watch. The PIK PRIMAP-hist dataset combines the United Nations Framework Convention on Climate Change (UNFCCC) reported data where available and fills gaps with other sources. It does not include land use change and forestry but covers all other sectors. https:// www.climatewatchdata.org/ghg-emissions?end_ year=2018&source=PIK&start_year=1990. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 PO 00000 Frm 00023 Fmt 4701 Sfmt 4702 E:\FR\FM\15NOP2.SGM 15NOP2 63132 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules National Emissions Inventory (NEI), for which States are required to submit information under 40 CFR part 51, subpart A. Data in the NEI may be organized by various data points, including sector, NAICS code, and Source Classification Code. Tables 9 and 10 below present total U.S. VOC and SO2 emissions by sector, respectively, for the year 2017, in kilotons (kt) (or methane reductions are highly achievable and cost-effective using existing and well-known solutions and technologies that actually result in recovery of saleable product. VOC and SO2 emissions in the U.S. and from the oil and natural gas industry. Official U.S. estimates of national level VOC and SO2 emissions are developed by the EPA for the thousand metric tons). The oil and natural gas sector represents the top anthropogenic U.S. sector for VOC emissions after removing the biogenics and wildfire sectors in Table 9 (about 20% of the total VOC emitting by anthropogenic sources). About 2.5 percent of the total U.S. anthropogenic SO2 comes from the oil and natural gas sector. TABLE 9—U.S. VOC EMISSIONS BY SECTOR [kt] Sector 2017 Biogenics—Vegetation and Soil .......................................................................................................................................................... Fires—Wildfires .................................................................................................................................................................................... Oil and Natural Gas Production, and Natural Gas Processing and Transmission ............................................................................. Fires—Prescribed Fires ....................................................................................................................................................................... Solvent—Consumer and Commercial Solvent Use ............................................................................................................................ Mobile—On-Road non-Diesel Light Duty Vehicles ............................................................................................................................. Mobile—Non-Road Equipment—Gasoline .......................................................................................................................................... Other VOC Sources 85 ......................................................................................................................................................................... 25,823 4,578 2,504 2,042 1,610 1,507 1,009 4,045 Total VOC Emissions ................................................................................................................................................................... 43,118 Emissions from the 2017 NEI (released April 2020). Note: Totals may not sum due to rounding. TABLE 10—U.S. SO2 EMISSIONS BY SECTOR [kt] Sector 2017 Fuel Combustion—Electric Generation—Coal .................................................................................................................................... Fuel Combustion—Industrial Boilers, Internal Combustion Engines—Coal ....................................................................................... Mobile—Commercial Marine Vessels .................................................................................................................................................. Industrial Processes—Not Elsewhere Classified ................................................................................................................................ Fires—Wildfires .................................................................................................................................................................................... Industrial Processes—Chemical Manufacturing .................................................................................................................................. Oil and Natural Gas Production and Natural Gas Processing and Transmission .............................................................................. Other SO2 Sources 86 .......................................................................................................................................................................... 1,319 212 183 138 135 123 65 551 Total SO2 Emissions .................................................................................................................................................................... 2,726 Emissions from the 2017 NEI (released April 2020). Note: Totals may not sum due to rounding. Table 11 below presents total VOC and SO2 emissions from oil and natural gas production through transmission and storage, for the year 2017, in kt. The contribution to the total anthropogenic VOC emissions budget from the oil and gas sector has been increasing in recent NEI cycles. In the 2017 NEI, the oil and gas sector makes up about 25 percent of the total VOC emissions from anthropogenic sources. The SO2 emissions have been declining in just about every anthropogenic sector, but the oil and gas sector is an exception where SO2 emissions have been slightly increasing or remaining steady in some cases in recent years. TABLE 11—U.S. VOC AND SO2 EMISSIONS FROM NATURAL GAS AND PETROLEUM SYSTEMS [kt] khammond on DSKJM1Z7X2PROD with PROPOSALS2 Sector VOC Oil and Natural Gas Production .............................................................................................................................. Natural Gas Processing ........................................................................................................................................... Natural Gas Transmission and Storage .................................................................................................................. 2,478 12 14 Emissions from the 2017 NEI, (published April 2020), in kt (or thousand metric tons). Note: Totals may not sum due to rounding. 85 Other sources include remaining sources emitting less than 1,000 kt VOC in 2017. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 86 Other sources include remaining sources emitting less than 100 kt SO2 in 2017. PO 00000 Frm 00024 Fmt 4701 Sfmt 4702 E:\FR\FM\15NOP2.SGM 15NOP2 SO2 41 23 1 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 IV. Statutory Background and Regulatory History A. Statutory Background of CAA Sections 111(b), 111(d) and General Implementing Regulations The EPA’s authority for this rule is CAA section 111, which governs the establishment of standards of performance for stationary sources. This section requires the EPA to list source categories to be regulated, establish standards of performance for air pollutants emitted by new sources in that source category, and establish EG for States to establish standards of performance for certain pollutants emitted by existing sources in that source category. Specifically, CAA section 111(b)(1)(A) requires that a source category be included on the list for regulation if, ‘‘in [the EPA Administrator’s] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.’’ This determination is commonly referred to as an ‘‘endangerment finding’’ and that phrase encompasses both of the ‘‘causes or contributes significantly to’’ component and the ‘‘endanger public health or welfare’’ component of the determination. Once a source category is listed, CAA section 111(b)(1)(B) requires that the EPA propose and then promulgate ‘‘standards of performance’’ for new sources in such source category. CAA section 111(a)(1) defines a ‘‘standard of performance’’ as ‘‘a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.’’ As long recognized by the D.C. Circuit, ‘‘[b]ecause Congress did not assign the specific weight the Administrator should accord each of these factors, the Administrator is free to exercise his discretion in this area.’’ New York v. Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992). See also Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) (‘‘Lignite Energy Council’’) (‘‘Because section 111 does not set forth the weight that be [sic] should assigned to each of these factors, we have granted the agency a great degree of discretion in balancing them’’). In determining whether a given system of emission reduction qualifies as ‘‘the best system of emission reduction . . . adequately VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 demonstrated,’’ or ‘‘BSER,’’ CAA section 111(a)(1) requires that the EPA take into account, among other factors, ‘‘the cost of achieving such reduction.’’ As described in the proposal 87 for the 2016 Rule (85 FR 35824, June 3, 2016), the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) has stated that in light of this provision, the EPA may not adopt a standard the cost of which would be ‘‘exorbitant,’’ 88 ‘‘greater than the industry could bear and survive,’’ 89 ‘‘excessive,’’ 90 or ‘‘unreasonable.’’ 91 These formulations appear to be synonymous, and for convenience, in this rulemaking, as in previous rulemakings, we will use reasonableness as the standard, so that a control technology may be considered the ‘‘best system of emission reduction . . . adequately demonstrated’’ if its costs are reasonable, but cannot be considered the BSER if its costs are unreasonable. See 80 FR 64662, 64720– 21 (October 23, 2015). CAA section 111(a) does not provide specific direction regarding what metric or metrics to use in considering costs, affording the EPA considerable discretion in choosing a means of cost consideration.92 In this rulemaking, we evaluated whether a control cost is reasonable under a number of approaches that we find appropriate for assessing the types of controls at issue. For example, in evaluating controls for reducing VOC and methane emissions from new sources, we considered a control’s cost effectiveness under both a ‘‘single pollutant cost-effectiveness’’ approach and a ‘‘multipollutant costeffectiveness’’ approach, in order to appropriately take into account that the systems of emission reduction considered in this rule typically achieve reductions in multiple pollutants at once and secure a multiplicity of climate and public health benefits.93 We also evaluated costs at a sector level by 87 80 FR 56593, 56616 (September 18, 2015). Energy Council, 198 F.3d at 933. 89 Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975). 90 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). 91 Id. 92 See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C. Cir. 2001) (where CAA section 213 does not mandate a specific method of cost analysis, the EPA may make a reasoned choice as to how to analyze costs). 93 We believe that both the single and multipollutant approaches are appropriate for assessing the reasonableness of the multipollutant controls considered in this action. The EPA has considered similar approaches in the past when considering multiple pollutants that are controlled by a given control option. See e.g., 80 FR 56616– 56617; 73 FR 64079–64083 and EPA Document ID Nos. EPA–HQ–OAR–2004–0022–0622, EPA–HQ– OAR–2004–0022–0447, EPA–HQ–OAR–2004– 0022–0448. 88 Lignite PO 00000 Frm 00025 Fmt 4701 Sfmt 4702 63133 assessing the projected new capital expenditures required under the proposal (compared to overall new capital expenditures by the sector) and the projected compliance costs (compared to overall annual revenue for the sector) if the rule were to require such controls. For a detailed discussion of these cost approaches, please see section IX of the proposal preamble. As defined in CAA section 111(a), the ‘‘standard of performance’’ that the EPA develops, based on the BSER, is expressed as a performance level (typically, a rate-based standard). CAA section 111(b)(5) precludes the EPA from prescribing a particular technological system that must be used to comply with a standard of performance. Rather, sources can select any measure or combination of measures that will achieve the standard. CAA section 111(h)(1) authorizes the Administrator to promulgate ‘‘a design, equipment, work practice, or operational standard, or combination thereof’’ if in his or her judgment, ‘‘it is not feasible to prescribe or enforce a standard of performance.’’ CAA section 111(h)(2) provides the circumstances under which prescribing or enforcing a standard of performance is ‘‘not feasible,’’ such as, when the pollutant cannot be emitted through a conveyance designed to emit or capture the pollutant, or when there is no practicable measurement methodology for the particular class of sources.94 CAA section 111(b)(1)(B) requires the EPA to ‘‘at least every 8 years review and, if appropriate, revise’’ performance standards unless the ‘‘Administrator determines that such review is not appropriate in light of readily available information on the efficacy’’ of the standard. As mentioned above, once the EPA lists a source category under CAA section 111(b)(1)(A), CAA section 111(b)(1)(B) provides the EPA discretion to determine the pollutants and sources to be regulated. In addition, concurrent with the 8-year review (and though not a mandatory part of the 8-year review), the EPA may examine whether to add standards for pollutants or emission 94 The EPA notes that design, equipment, work practice or operational standards established under CAA section 111(h) (commonly referred to as ‘‘work practice standards’’) reflect the ‘‘best technological system of continuous emission reduction’’ and that this phrasing differs from the ‘‘best system of emission reduction’’ phrase in the definition of ‘‘standard of performance’’ in CAA section 111(a)(1). Although the differences in these phrases may be meaningful in other contexts, for purposes of evaluating the sources and systems of emission reduction at issue in this rulemaking, the EPA has applied these concepts in an essentially comparable manner. E:\FR\FM\15NOP2.SGM 15NOP2 63134 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 sources not currently regulated for that source category. Once the EPA establishes NSPS in a particular source category, the EPA is required in certain circumstances to issue EG to reduce emissions from existing sources in that same source category. Specifically, CAA section 111(d) requires that the EPA prescribe regulations to establish procedures under which States submit plans to establish, implement, and enforce standards of performance for existing sources for certain air pollutants to which a Federal NSPS would apply if such existing source were a new source. The EPA addresses this CAA requirement both through its promulgation of general implementing regulations for section 111(d) as well as specific EG. The EPA first published general implementing regulations in 1975, 40 FR 53340 (November 17, 1975) (codified at 40 CFR part 60, subpart B), and has revised its section 111(d) implementing regulations several times, most recently on July 8, 2019, 84 FR 32520 (codified at 40 CFR part 60, subpart Ba).95 In accordance with CAA section 111(d), States are required to submit plans pursuant to these regulations to establish standards of performance for existing sources for any air pollutant: (1) The emission of which is subject to a Federal NSPS; and (2) which is neither a pollutant regulated under CAA section 108(a) (i.e., criteria pollutants such as ground-level ozone and particulate matter, and their precursors, like VOC) 96 or a HAP regulated under CAA section 112. See also definition of ‘‘designated pollutant’’ in 40 CFR 60.21a(a). The EPA’s general implementing regulations use the term ‘‘designated facility’’ to identify those existing sources that may be subject to regulation under this provision of CAA section 111(d). See 40 CFR 60.21a(b). While States are authorized to establish standards of performance for designated facilities, there is a 95 Subpart Ba provides for the applicability of its provisions upon final publication of an EG if such EG is published after July 8, 2019. § 60.20a(a). The EPA acknowledges that the D.C. Circuit has vacated certain timing provisions within subpart Ba. Am. Lung Assoc. v. EPA, 985 F.3d 914 (D.C. Cir. 2021), petition for cert. pending, No. 20–1778 (filed June 23, 2001) (Am. Lung Assoc.). However, the court did not vacate the applicability provision, therefore subpart Ba applies to any EG finalized from this proposal. The Agency plans to undertake rulemaking to address the provisions vacated under the court’s decision in the near future. 96 VOC are not listed as CAA section 108(a) pollutants, but they are regulated precursors to photochemical oxidants (e.g., ozone) and particulate matter (PM), both of which are listed CAA section 108(a) pollutants, and VOC therefore fall within the CAA 108(a) exclusion. Accordingly, promulgation of NSPS for VOC does not trigger the application of CAA section 111(d). VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 fundamental obligation under CAA section 111(d) that such standards of performance reflect the degree of emission limitation achievable through the application of the BSER, as determined by the Administrator. This obligation derives from the definition of ‘‘standard of performance’’ under CAA section 111(a)(1), which makes no distinction between new-source and existing-source standards. The EPA identifies the degree of emission limitation achievable through application of the BSER as part of its EG. See 40 CFR 60.22a(b)(5). While standards of performance must generally reflect the degree of emission limitation achievable through application of the BSER, CAA section 111(d)(1) also requires that the EPA regulations permit the States, in applying a standard of performance to a particular source, to take into account the source’s remaining useful life and other factors. After the EPA issues final EG per the requirements under CAA section 111(d) and 40 CFR part 60, subpart Ba, States are required to submit plans that establish standards of performance for the designated facilities as defined in the EPA’s guidelines and that contain other measures to implement and enforce those standards. The EPA’s final EG issued under CAA section 111(d) do not impose binding requirements directly on sources, but instead provide requirements for States in developing their plans and criteria for assisting the EPA when judging the adequacy of such plans. Under CAA section 111(d), and the EPA’s implementing regulations, a State must submit its plan to the EPA for approval, the EPA will evaluate the plan for completeness in accordance with enumerated criteria, and then will act on that plan via a rulemaking process to either approve or disapprove the plan in whole or in part. If a State does not submit a plan, or if the EPA does not approve a State’s plan because it is not ‘‘satisfactory,’’ then the EPA must establish a Federal plan for that State.97 If EPA approves a State’s plan, the provisions in the state plan become federally enforceable against the designated facility responsible for compliance in the same manner as the provisions of an approved State implementation plan under CAA section 110. If no designated facility is located within a State, the State must submit to the EPA a letter certifying to that effect in lieu of submitting a State plan. See 40 CFR 60.23a(b). Designated facilities located in Indian country would not be addressed by a 97 CAA PO 00000 section 111(d)(2)(A). Frm 00026 Fmt 4701 Sfmt 4702 State’s CAA section 111(d) plan. Instead, an eligible Tribe that has one or more designated facilities located in its area of Indian country 98 would have the opportunity, but not the obligation, to seek authority and submit a plan that establishes standards of performance for those facilities on its Tribal lands.99 If a Tribe does not submit a plan, or if the EPA does not approve a Tribe’s plan, then the EPA has the authority to establish a Federal plan for that Tribe.100 B. What is the regulatory history and litigation background of NSPS and EG for the oil and natural gas industry? 1. 1979 Listing of Source Category Subsequent to the enactment of the CAA of 1970, the EPA took action to develop standards of performance for new stationary sources as directed by Congress in CAA section 111. By 1977, the EPA had promulgated NSPS for a total of 27 source categories, while NSPS for an additional 25 source categories were then under development.101 However, in amending the CAA that year, Congress expressed dissatisfaction that the EPA’s pace was too slow. Accordingly, the 1977 CAA Amendments included a new subsection (f) in section 111, which specified a schedule for the EPA to list additional source categories under CAA section 111(b)(1)(A) and prioritize them for regulation under CAA section 111(b)(1)(B). In 1979, as required by CAA section 111(f), the EPA published a list of source categories, which included ‘‘Crude Oil and Natural Gas Production,’’ for which the EPA would promulgate standards of performance under CAA section 111(b). See Priority List and Additions to the List of Categories of Stationary Sources, 44 FR 49222 (August 21, 1979) (‘‘1979 Priority List’’). That list included, in the order of priority for promulgating standards, source categories that the EPA Administrator had determined, pursuant to CAA section 111(b)(1)(A), contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. See 44 FR 49223 (August 21, 1979); see also 49 FR 2636–37 (January 20, 1984). 98 The EPA is aware of many oil and natural gas operations located in Indian Country. 99 See 40 CFR part 49, subpart A. 100 CAA section 111(d)(2)(A). 101 See 44 FR 49222 (August 21, 1979). E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules 2. 1985 NSPS for VOC and SO2 Emissions From Natural Gas Processing Units On June 24, 1985 (50 FR 26122), the EPA promulgated NSPS for the Crude Oil and Natural Gas source category that addressed VOC emissions from equipment leaks at onshore natural gas processing plants (40 CFR part 60, subpart KKK). On October 1, 1985 (50 FR 40158), the EPA promulgated additional NSPS for the source category to regulate SO2 emissions from onshore natural gas processing plants (40 CFR part 60, subpart LLL). khammond on DSKJM1Z7X2PROD with PROPOSALS2 3. 2012 NSPS OOOO Rule and Related Amendments In 2012, pursuant to its duty under CAA section 111(b)(1)(B) to review and, if appropriate, revise the 1985 NSPS, the EPA published the final rule, ‘‘Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution,’’ 77 FR 49490 (August 16, 2012) (40 CFR part 60, subpart OOOO) (‘‘2012 NSPS OOOO’’). The 2012 rule updated the SO2 standards for sweetening units and the VOC standards for equipment leaks at onshore natural gas processing plants. In addition, it established VOC standards for several oil and natural gasrelated operations emission sources not covered by 40 CFR part 60, subparts KKK and LLL, including natural gas well completions, centrifugal and reciprocating compressors, certain natural gas operated pneumatic controllers in the production and processing segments of the industry, and storage vessels in the production, processing, and transmission and storage segments. In 2013, 2014, and 2015 the EPA amended the 2012 NSPS OOOO rule in order to address implementation of the standards. ‘‘Oil and Natural Gas Sector: Reconsideration of Certain Provisions of New Source Performance Standards,’’ 78 FR 58416 (September 23, 2013) (‘‘2013 NSPS OOOO’’) (concerning storage vessel implementation); ‘‘Oil and Natural Gas Sector: Reconsideration of Additional Provisions of New Source Performance Standards,’’ 79 FR 79018 (December 31, 2014) (‘‘2014 NSPS OOOO’’) (concerning well completion); ‘‘Oil and Natural Gas Sector: Definitions of Low Pressure Gas Well and Storage Vessel,’’ 80 FR 48262 (August 12, 2015) (‘‘2015 NSPS OOOO’’) (concerning low pressure gas wells and storage vessels). The EPA received petitions for both judicial review and administrative reconsiderations for the 2012, 2013, and 2014 NSPS OOOO rules. The EPA denied reconsideration for some issues, VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 see ‘‘Reconsideration of the Oil and Natural Gas Sector: New Source Performance Standards; Final Action,’’ 81 FR 52778 (August 10, 2016), and, as noted below, granted reconsideration for other issues. As explained below, all litigation related to NSPS OOOO is currently in abeyance. 4. 2016 NSPS OOOOa Rule and Related Amendments Regulatory action. On June 3, 2016, the EPA published a final rule titled ‘‘Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources; Final Rule,’’ at 81 FR 35824 (40 CFR part 60, subpart OOOOa) (‘‘2016 Rule’’ or ‘‘2016 NSPS OOOOa’’).102 103 The 2016 NSPS OOOOa rule established NSPS for sources of GHGs and VOC emissions for certain equipment, processes, and operations across the Oil and Natural Gas Industry, including in the transmission and storage segment. 81 FR at 35832. The EPA explained that the 1979 listing identified the source category broadly enough to include that segment and, in the alternative, if the listing had limited the source category to the production and processing segments, the EPA affirmatively expanded the source category to include the transmission and storage segment on grounds that operations in those segments are a sequence of functions that are interrelated and necessary for getting the recovered gas ready for distribution. 81 FR at 35832. In addition, because this rule was the first time that the EPA had promulgated NSPS for GHG emissions from the Crude Oil and Natural Gas source category, the EPA predicated those NSPS on a determination that it had a rational basis to regulate GHG emissions from the source category. 81 FR at 35843. In response to comments, the EPA explained that it was not required to make an additional pollutant-specific finding that GHG emissions from the source category contribute significantly to dangerous air pollution, but in the alternative, the 102 The June 3, 2016, rulemaking also included certain final amendments to 40 CFR part 60, subpart OOOO, to address issues on which the EPA had granted reconsideration. 103 The EPA review which resulted in the 2016 NSPS OOOOa rule was instigated by a series of directives from then-President Obama targeted at reducing GHGs, including methane: The President’s Climate Action Plan (June 2013); the President’s Climate Action Plan: Strategy to Reduce Methane Emissions (‘‘Methane Strategy’’) (March 2014); and the President’s goal to address, propose and set standards for methane and ozone-forming emissions from new and modified sources in the sector (January 2015, https:// obamawhitehouse.archives.gov/the-press-office/ 2015/01/14/fact-sheet-Administration-takes-stepsforward-climate-action-plan-anno-1). PO 00000 Frm 00027 Fmt 4701 Sfmt 4702 63135 EPA did make such a finding, relying on the same information that it relied on when determining that it had a rational basis to promulgate a GHGs NSPS. 81 FR at 35843. Specifically, the 2016 NSPS OOOOa addresses the following emission sources: • Sources that were unregulated under the 2012 NSPS OOOO (hydraulically fractured oil well completions, pneumatic pumps, and fugitive emissions from well sites and compressor stations); • Sources that were regulated under the 2012 NSPS OOOO for VOC emissions, but not for GHG emissions (hydraulically fractured gas well completions and equipment leaks at natural gas processing plants); and • Certain equipment that is used across the source category, of which the 2012 NSPS OOOO regulated emissions of VOC from only a subset (pneumatic controllers, centrifugal compressors, and reciprocating compressors, with the exception of those compressors located at well sites). On March 12, 2018 (83 FR 10628), the EPA finalized amendments to certain aspects of the 2016 NSPS OOOOa requirements for the collection of fugitive emission components at well sites and compressor stations, specifically (1) the requirement that components on a delay of repair must conduct repairs during unscheduled or emergency vent blowdowns, and (2) the monitoring survey requirements for well sites located on the Alaska North Slope. Petitions for judicial review and to reconsider. Following promulgation of the 2016 NSPS OOOOa rule, several states and industry associations challenged the rule in the D.C. Circuit. The Administrator also received five petitions for reconsideration of several provisions of the final rule. Copies of the petitions are posted in Docket ID No. EPA–HQ–OAR–2010–0505.104 As noted below, the EPA granted reconsideration as to several issues raised with respect to the 2016 NSPS OOOOa rule and finalized certain modifications discussed in the next section. As explained below, all litigation challenging the 2016 NSPS OOOOa rule is currently stayed. 5. 2020 Policy and Technical Rules Regulatory action. In September 2020, the EPA published two final rules to amend 2012 NSPS OOOO and 2016 NSPS OOOOa. The first is titled, ‘‘Oil 104 See Docket ID Item Nos.: EPA–HQ–OAR– 2010–0505–7682, EPA–HQ–OAR–2010–0505–7683, EPA–HQ–OAR–2010–0505–7684, EPA–HQ–OAR– 2010–0505–7685, EPA–HQ–OAR–2010–0505–7686. E:\FR\FM\15NOP2.SGM 15NOP2 63136 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review.’’ 85 FR 57018 (September 14, 2020). Commonly referred to as the 2020 Policy Rule, it first rescinded the regulations applicable to the transmission and storage segment on the basis that the 1979 listing limited the source category to the production and processing segments and that the transmission and storage segment is not ‘‘sufficiently related’’ to the production and processing segments, and therefore cannot be part of the same source category. 85 FR at 57027, 57029. In addition, the 2020 Policy Rule rescinded methane requirements for the industry’s production and processing segments on two separate bases. The first was that such standards are redundant to VOC standards for these segments. 85 FR at 57030. The second was that the rule interpreted section 111 to require, or at least authorize the Administrator to require, a pollutantspecific ‘‘significant contribution finding’’ (SCF) as a prerequisite to a NSPS for a pollutant, and to require that such finding be supported by some identified standard or established set of criteria for determining which contributions are ‘‘significant.’’ 85 FR at 57034. The rule went on to conclude that the alternative significantcontribution finding that the EPA made in the 2016 Rule for GHG emissions was flawed because it accounted for emissions from the transmission and storage segment and because it was not supported by criteria or a threshold. 85 FR at 57038.105 Published on September 15, 2020, the second of the two rules is titled, ‘‘Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Reconsideration.’’ Commonly referred to as the 2020 Technical Rule, this second rule made further amendments to the 2016 NSPS OOOOa following the 2020 Policy Rule to eliminate or reduce certain monitoring obligations and to address a range of issues in response to administrative petitions for reconsideration and other technical and implementation issues brought to the khammond on DSKJM1Z7X2PROD with PROPOSALS2 105 Following the promulgation of the 2020 Policy Rule, the EPA promulgated a final rule that identified a standard or criteria for determining which contributions are ‘‘significant,’’ which the D.C. Circuit vacated. ‘‘Pollutant-Specific Significant Contribution Finding for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units, and Process for Determining Significance of Other New Source Performance Standards Source Categories.’’ 86 FR 2542 (Jan. 13, 2021), vacated by California v. EPA, No. 21–1035 (D.C. Cir.) (Order, April 5, 2021, Doc. #1893155). VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 EPA’s attention since the 2016 NSPS OOOOa rulemaking. Specifically, the 2020 Technical Rule exempted lowproduction well sites from fugitives monitoring (previously required semiannually), required semiannual monitoring at gathering and boosting compressor stations (previously quarterly), streamlined recordkeeping and reporting requirements, allowed compliance with certain equivalent State requirements as an alternative to NSPS fugitive requirements, streamlined the application process to request the use of new technologies to monitor for fugitive emissions, addressed storage tank batteries for applicability determination purposes and finalized several technical corrections. Because the 2020 Technical Rule was issued the day after the EPA’s rescission of methane regulations in the 2020 Policy Rule, the amendments made in the 2020 Technical Rule applied only to the requirements to regulate VOC emissions from this source category. The 2020 Policy Rule amended 40 CFR part 60, subparts OOOO and OOOOa, as finalized in 2016. The 2020 Technical Rule amended the 40 CFR part 60, subpart OOOOa, as amended by the 2020 Policy Rule. Petitions to reconsider. The EPA received three petitions for reconsideration of the 2020 rulemakings. Two of the petitions sought reconsideration of the 2020 Policy Rule. As discussed below, on June 30, 2021, the President signed into law S.J. Res. 14, a joint resolution under the CRA disapproving the 2020 Policy Rule, and as a result, the petitions for reconsideration on the 2020 Policy Rule are now moot. All three petitions sought reconsideration of certain elements of the 2020 Technical Rule. Litigation. Several States and nongovernmental organizations challenged the 2020 Policy Rule as well as the 2020 Technical Rule. All petitions for review regarding the 2020 Policy Rule were consolidated into one case in the D.C. Circuit. State of California, et al. v. EPA, No. 20–1357. On August 25, 2021, after the enactment of the joint resolution of Congress disapproving the 2020 Policy Rule (explained in section VIII below), the court granted petitioners motion to voluntarily dismiss their cases. Id. ECF Dkt #1911437. All petitions for review regarding the 2020 Technical Rule were consolidated into a different case in the D.C. Circuit. Environmental Defense Fund, et al. v. EPA, No. 20–1360 (D.C. Cir.). On February 19, 2021, the court issued an order granting a motion by the EPA to hold in abeyance the consolidated litigation over the 2020 PO 00000 Frm 00028 Fmt 4701 Sfmt 4702 Technical Rule pending EPA’s rulemaking actions in response to E.O. 13990 and pending the conclusion of EPA’s potential reconsideration of the 2020 Technical Rule. Id. ECF Dkt #1886335. As mentioned above, the EPA received petitions for judicial review regarding the 2012, 2013, and 2014 NSPS OOOO rules as well as the 2016 NSPS OOOOa rule. The challenges to the 2012 NSPS OOOO rule (as amended by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) were consolidated. American Petroleum Institute v. EPA, No. 13–1108 (D.C. Cir.). The majority of those cases were further consolidated with the consolidated challenges to the 2016 NSPS OOOOa rule. West Virginia v. EPA, No. 16–1264 (D.C. Cir.), see specifically ECF Dkt #1654072. As such, West Virginia v. EPA includes challenges to the 2012 NSPS OOOO rule (as amended by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) as well as challenges to the 2016 NSPS OOOOa rule.106 On December 10, 2020, the court granted a joint motion of the parties in West Virginia v. EPA to hold that case in abeyance until after the mandate has issued in the case regarding challenges to the 2020 Technical Rule. West Virginia v. EPA, ECF Dkt #1875192. C. Congressional Review Act (CRA) Joint Resolution of Disapproval On June 30, 2021, the President signed into law a joint resolution of Congress, S.J. Res. 14, adopted under the CRA,107 disapproving the 2020 Policy Rule.108 By the terms of the CRA, the signing into law of the CRA joint resolution of disapproval means that the 2020 Policy Rule is ‘‘treated as though [it] had never taken effect.’’ 5 U.S.C. 801(f). As a result, the VOC and methane standards for the transmission and storage segment, as well as the methane standards for the production and processing segments—all of which had been rescinded in the 2020 Policy Rule—remain in effect. In addition, the EPA’s authority and obligation to require the States to regulate existing sources of methane in the Crude Oil and 106 When the EPA issued the 2016 NSPS OOOOa rule, a challenge to the 2012 NSPS OOOO rule for failing to regulate methane was severed and assigned to a separate case, NRDC v. EPA, No. 16– 1425 (D.C. Cir.), pending judicial review of the 2016 NSPS OOOOa in American Petroleum Institute v. EPA, No. 13–1108 (D.C. Cir.). 107 The Congressional Review Act was adopted in Subtitle E of the Small Business Regulatory Enforcement Fairness Act of 1996. 108 ‘‘Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review,’’ 85 FR 57018 (Sept. 14, 2020) (‘‘2020 Policy Rule’’). E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules Natural Gas source category under section 111(d) of the CAA also remains in effect. The CRA resolution did not address the 2020 Technical Rule; therefore, those amendments remain in effect with respect to the VOC standards for the production and processing segments in effect at the time of its enactment. As part of this rulemaking, in sections VIII and X the EPA discusses the impact of the CRA resolution, and identifies and proposes appropriate changes to reinstate the regulatory text that had been rescinded by the 2020 Policy Rule and to resolve any discrepancies in the regulatory text between the 2016 NSPS OOOOa Rule and 2020 Technical Rule. khammond on DSKJM1Z7X2PROD with PROPOSALS2 V. Related Emissions Reduction Efforts This section summarizes related State actions and other Federal actions regulating oil and natural gas emissions sources and summarizes industry and voluntary efforts to reduce climate change. The proposed NSPS OOOOb and EG OOOOc include specific measures that build on the experience and knowledge the Agency and industry have gained through voluntary programs, as well as the leadership of the States in pioneering new regulatory programs. The proposed NSPS OOOOb and EG OOOOc consists of reasonable, proven, cost-effective technologies and practices that reflect the evolutionary nature of the Oil and Natural Gas Industry and proactive regulatory and voluntary efforts. The EPA intends that the requirements proposed in this document will spur all industry stakeholders in all parts of the country to apply these readily available and cost-effective measures. A. Related State Actions and Other Federal Actions Regulating Oil and Natural Gas Sources The EPA recognizes that several States and other Federal agencies currently regulate the Oil and Natural Gas Industry. The EPA also recognizes that these State and other Federal agency regulatory programs have matured since the EPA began implementing its 2012 NSPS and subsequent 2016 NSPS. The EPA further acknowledges the technical innovations that the Oil and Natural Gas Industry has made during the past decade; this industry is fast-paced and constantly changing based on the latest technology. The EPA commends these efforts and recognizes States for their innovative standards, alternative compliance options, and implementation strategies. The EPA recognizes that any one effort will not be enough to address the increasingly dangerous impacts of VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 climate change on public health and welfare and believes that consistent Federal regulation of the Crude Oil and Natural Gas source category plays an important role. To have a meaningful impact on climate change and its impact to human health and the environment, a multifaceted approach needs to be taken to ensure methane reductions will be realized. The EPA also recognizes that States and other Federal agencies regulate in accordance with their own authorities and within their own respective jurisdictions, and collectively do not fully address the range of sources and emission reduction measures contained in this proposal. Direct Federal regulation of methane from new sources combined with the approved State plans that are consistent with the EPA’s EG for existing sources will bring national consistency to level the regulatory playing field, help promote technological innovation, and reduce both climate- and other health-harming pollution from a large number of sources that are either currently unregulated or where additional costeffective reductions can be obtained. The EPA is committed to working within its authority to provide opportunities to align its programs with other existing State and Federal programs to reduce unnecessary regulatory redundancy where appropriate. Among assessing various studies and emissions data, the EPA reviewed many current and proposed State regulatory programs to identify potential regulatory options that could be considered for BSER.109 For example, the EPA reviewed California, Colorado, and Canadian regulations, as well as a pending proposed rule in New Mexico, that require non-emitting pneumatic devices at certain facilities and in certain circumstances. The EPA also examined California, Colorado, New Mexico (proposed), Pennsylvania, Wyoming, and the Bureau of Land Management (BLM) standards for liquids unloading events. Some of these States have led the way in regulating emissions sources that were not yet subject to requirements under the NSPS OOOOa. For example, Colorado requires the use of best management practices to minimize hydrocarbon emissions and the need for well venting associated with downhole well maintenance and liquids unloading, unless venting is necessary for safety. Other States, such as New Mexico, are evaluating similar requirements. Other States have 109 The NSPS OOOOb and EG TSD provides a high-level summary of the state programs that the agency assessed for purposes of this proposal. PO 00000 Frm 00029 Fmt 4701 Sfmt 4702 63137 requirements for emission sources currently regulated under NSPS OOOOa that are more stringent. For example, California and Colorado require continuous bleed natural gas-driven pneumatic controllers be non-emitting, with specified exceptions. We recognize that, in some cases, the EPA’s proposed NSPS and/or EG may be more stringent than existing programs and, in other cases, may be less stringent than existing programs. After careful review and consideration of State regulatory programs in place and proposed State regulations, we are proposing NSPS and EG that, when implemented, will reduce emissions of harmful air pollutants, promote gas capture and beneficial use, and provide opportunity for flexibility and expanded transparency in order to yield a consistent and accountable national program that provides a clear path for States and other Federal agencies to further partner to ensure their programs work in conjunction with each other. As an example of how the EPA strives to work with sources in States that have overlapping regulations for the Oil and Natural Gas Industry, the 2020 Technical Rule included approval of certain State programs as alternatives to certain requirements in the Federal NSPS. Subject to certain caveats, the EPA deemed certain fugitive emissions standards for well sites and compressor stations located in specific States equivalent to the NSPS in an effort to reduce any regulatory burden imposed by duplicative State and Federal regulations. See 40 CFR 60.5399a. The EPA worked extensively with States and reviewed many details of many State programs in this effort. Further, the 2020 Technical Rule amended 40 CFR part 60, subpart OOOOa, to incorporate a process that allows other States not already listed in 40 CFR 60.5399a to request approval of their fugitive monitoring program as an alternative to the NSPS. The EPA is proposing to include a similar request and approval process in NSPS OOOOb. Further, the EPA plans to work closely with States as they develop their State plans pursuant to the EG to look for opportunities to reduce unnecessary administrative burden imposed by redundant and duplicative regulatory requirements and help States that want to establish more stringent standards. In addition to States, certain Federal agencies also regulate aspects of the oil and natural gas industry pursuant to their own authorities and have other established programs affecting the industry. The EPA believes that Federal regulatory actions and efforts will provide other environmental co- E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63138 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules benefits, but the EPA recognizes itself to be the Federal agency that has primary responsibility to protect human health and the environment and has been given the unique responsibility and authority by Congress to address the suite of harmful air pollutants associated with this source category. The EPA further believes that to have a meaningful impact to address the dangers of climate change, it is going to require an ‘‘all hands-on deck’’ effort across all States and all Federal agencies. The EPA has maintained an ongoing dialogue with its Federal partners during the development of this proposed rule to minimize any potential regulatory conflicts and to minimize confusion and regulatory burden on the part of owners and operators. The below description summarizes other agencies’ regulations and other established Federal programs. The U.S. Department of the Interior (DOI) regulates the extraction of oil and gas from Federal lands. Bureaus within the DOI include BLM and the Bureau of Ocean Energy Management (BOEM). The BLM manages the Federal Government’s onshore subsurface mineral estate—about 700 million acres (30 percent of the U.S.)—for the benefit of the American public. The BLM maintains an oil and gas leasing program pursuant to the Mineral Leasing Act, the Mineral Leasing Act for Acquired Lands, the Federal Land Management and Policy Act, and the Federal Oil and Gas Royalty Management Act. Pursuant to a delegation of Secretarial authority, the BLM also oversees oil and gas operations on many Indian/Tribal leases. The BLM’s oil and gas operating regulations are found in 43 CFR part 3160. An oil and gas operator’s general environmental and safety obligations are found at 43 CFR 3162.5. The BLM does not directly regulate emissions for the purposes of air quality. However, BLM does regulate venting and flaring of natural gas for the purposes of preventing waste. The governing Resource Management Plan may require lessees to follow State and the EPA emissions regulations. An operator may be required to control/mitigate emissions as a condition of approval (COA) on a drilling permit. The need for such a COA is determined by the environmental review process. The BLM’s rules governing the venting and flaring of gas are contained in NTL–4A, which was issued in 1980. Under NTL– 4A, limitations on royalty-free venting and flaring constitute the primary mechanism for addressing the surface waste of gas. In 2016, the BLM replaced NTL–4A with a new rule governing VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 venting and flaring (‘‘Waste Prevention Rule’’). In addition to restricting royaltyfree flaring, the rule set emissions standards for tanks and pneumatic equipment and established LDAR requirements. In 2020, a U.S. District Court of Wyoming largely vacated that rule, thereby reinstating NTL–4A. More detailed information can be found at the BLM’s website: https://www.blm.gov/ programs/energy-and-minerals/oil-andgas/operations-and-production/ methane-and-waste-prevention-rule. The BOEM manages the development of U.S. Outer Continental Shelf (offshore) energy and mineral resources. BOEM has air quality jurisdiction in the Gulf of Mexico 110 and the North Slope Borough of Alaska.111 BOEM also has air jurisdiction in Federal waters on the Outer Continental Shelf 3–9 miles offshore (depending on State) and beyond. The Outer Continental Shelf Lands Act (OCSLA) section 5(a)(8) states, ‘‘The Secretary of the Interior is authorized to prescribe regulations ‘for compliance with the national ambient air quality standards pursuant to the CAA . . . to the extent that activities authorized under [the Outer Continental Shelf Lands Act] significantly affect the air quality of any State.’ ’’ The EPA and States have the air jurisdiction onshore and in State waters, and the EPA has air jurisdiction offshore in certain areas. More detailed information can be found at BOEM’s website: https:// www.boem.gov/. The U.S. Department of Transportation (DOT) manages the U.S. transportation system. Within DOT, the Pipeline and Hazardous Materials Safety Administration (PHMSA) is responsible for regulating and ensuring the safe and secure transport of energy and other hazardous materials to industry and consumers by all modes of transportation, including pipelines. While PHMSA regulatory requirements for gas pipeline facilities have focused on human safety, which has attendant environmental co-benefits, the ‘‘Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020’’ (Pub. L. 116–260, Division R; ‘‘PIPES Act of 2020’’), which was signed into law on December 27, 2020, revised PHMSA organic statutes to emphasize the centrality of environmental safety and protection of the environment in PHMSA decision making. For example, the PHMSA’s Office of Pipeline Safety ensures safety in the design, 110 The CAA gave BOEM air jurisdiction west of 87.5° longitude in the Gulf of Mexico region. 111 The Consolidated Appropriations Act of 2012 gave BOEM air jurisdiction in the North Slope Borough of Alaska. PO 00000 Frm 00030 Fmt 4701 Sfmt 4702 construction, operation, maintenance, and incident response of the U.S.’ approximately 2.6 million miles of natural gas and hazardous liquid transportation pipelines. When pipelines are maintained, the likelihood of environmental releases like leaks are reduced.112 In addition, the PIPES Act of 2020 contains several provisions that specifically address the minimization of releases of natural gas from pipeline facilities, such as a mandate that the Secretary of Transportation promulgate regulations related to gas pipeline LDAR programs. More detailed information can be found at PHMSA’s website: https://www.phmsa.dot.gov/. The U.S. Department of Energy (DOE) develops oil and natural gas policies and funds research on advanced fuels and monitoring and measurement technologies. Specifically, the Advanced Research Projects AgencyEnergy (ARPA–E) program advances high-potential, high-impact energy technologies that are too early for private-sector investment. APRA–E awardees are unique because they are developing entirely new technologies. More detailed information can be found at ARPA–E’s website: https://arpae.energy.gov/. Also, the U.S. Energy Information Administration (EIA) compiles data on energy consumption, prices, including natural gas, and coal. More detailed information can be found at the EIA’s website: https:// www.eia.gov/. The U.S. Federal Energy Regulatory Commission (FERC) is an independent agency that regulates the interstate transmission of electricity, natural gas,113 and oil.114 FERC also reviews proposals to build liquefied natural gas terminals and interstate natural gas pipelines as well as licensing hydropower projects. The Commission’s responsibilities for the crude oil industry include the following: Regulation of rates and practices of oil pipeline companies engaged in interstate transportation; establishment of equal service conditions to provide shippers with equal access to pipeline transportation; and establishment of reasonable rates for transporting petroleum and petroleum products by pipeline. The Commission’s responsibilities for the natural gas industry include the following: Regulation of pipeline, storage, and 112 See Final Report on Leak Detection Study to PHMSA. December 10, 2012. https:// www.phmsa.dot.gov/sites/phmsa.dot.gov/files/ docs/technical-resources/pipeline/16691/leakdetection-study.pdf. 113 https://www.ferc.gov/industries-data/naturalgas. 114 https://www.ferc.gov/industries-data/oil. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules liquefied natural gas facility construction; regulation of natural gas transportation in interstate commerce; issuance of certificates of public convenience and necessity to prospective companies providing energy services or constructing and operating interstate pipelines and storage facilities; regulation of facility abandonment, establishment of rates for services; regulation of the transportation of natural gas as authorized by the Natural Gas Policy Act and OCSLA; and oversight of the construction and operation of pipeline facilities at U.S. points of entry for the import or export of natural gas. FERC has no jurisdiction over construction or maintenance of production wells, oil pipelines, refineries, or storage facilities. More detailed information can be found at FERC’s website: https://www.ferc.gov/. B. Industry and Voluntary Actions To Address Climate Change khammond on DSKJM1Z7X2PROD with PROPOSALS2 Separate from regulatory requirements, some owners or operators of facilities in the Oil and Natural Gas Industry choose to participate in voluntary initiatives. Specifically, over 100 oil and natural gas companies participate in the EPA Natural Gas STAR and Methane Challenge partnership programs. Owners or operators also participate in a growing number of voluntary programs unaffiliated with the EPA voluntary programs. The EPA is aware of at least 19 such initiatives.115 Firms might participate in voluntary environmental programs for a variety of reasons, including attracting customers, employees, and investors who value more environmental-responsible goods and services; finding approaches to improve efficiency and reduce costs; and preparing for or helping inform future regulations.116 117 The EPA’s Natural Gas STAR Program started in 1993 and seeks to achieve methane emission reductions through implementation of cost-effective best practices and technologies. Partner companies document their voluntary emission reduction activities and can 115 Highwood Emissions Management (2021). ‘‘Voluntary Emissions Reduction Initiatives for Responsibly Sourced Oil and Gas.’’ Available for download at: https://highwoodemissions.com/ research/. 116 Borck, J.C. and C. Coglianese (2009). ‘‘Voluntary Environmental Programs: Assessing Their Effectiveness.’’ Annual Review of Environment and Resources 34(1): 305–324. 117 Brouhle, K., C. Griffiths, and A. Wolverton. (2009). ‘‘Evaluating the role of EPA policy levers: An examination of a voluntary program and regulatory threat in the metal-finishing industry.’’ Journal of Environmental Economics and Management. 57(2): 166–181. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 report their accomplishments to the EPA annually. Natural Gas STAR includes over 90 partners across the natural gas value chain. Through 2019 partner companies report having eliminated nearly 1.7 trillion cubic feet of methane emissions since 1993. The EPA’s Methane Challenge Program was launched in 2016 and expands on the Natural Gas STAR Program with ambitious, quantifiable commitments and detailed, transparent reporting and partner recognition. Annually Methane Challenge partners submit facility-level reports that characterize the methane emission sources at their facilities and detail voluntary actions taken to reduce methane emissions. The EPA emphasizes the importance of transparency with the publication of these facility-level data. Although this program includes nearly 70 companies from all segments of the industry, most partners operate in the transmission and distribution segments. Other voluntary programs for the oil and natural gas industry are administered by diverse organizations, including trade associations and nonprofits. While the field of voluntary initiatives continues to grow, it is difficult to understand the present, and potential future, impact these initiatives will have on reducing methane emissions as the majority of these initiatives publish aggregated programlevel data. The EPA recognizes the voluntary efforts of industry in reducing methane emissions beyond what is required by current regulations and in significantly expanding the understanding of methane mitigation measures. While progress has been made, there is still considerable remaining need to further reduce methane emissions from the Industry. VI. Environmental Justice Considerations, Implications, and Stakeholder Outreach To better inform this proposed rulemaking, the EPA assessed the characteristics of populations living near sources affected by the rule and conducted extensive outreach to overburdened and underserved communities and to environmental justice organizations. During our engagement with communities, concerns were raised regarding health effects of air pollutants, implications of climate change on lifestyle changes, water quality, or extreme heat events, and accessibility to data and information regarding sources near their homes. The EPA then considered this input along with other stakeholder input in designing the proposed rule. PO 00000 Frm 00031 Fmt 4701 Sfmt 4702 63139 For example, one key issue identified through stakeholder input is the use of cutting-edge technologies for methane detection that can allow for rapid detection of high-emitting sources. As described below, the EPA is proposing to allow the use of such technologies in this rule, alongside a rigorous fugitive emissions monitoring program that is based on traditional OGI technology. Another key concern the Agency heard is addressing large emission sources faster, which, in addition to seeking more information on new detection technologies, the EPA is proposing to address with more frequent monitoring at sites with more emissions. The EPA also heard that adjacent communities are concerned about health impacts, and the EPA is proposing rigorous guidelines for pollution sources at existing facilities, methane standards for storage vessels, strengthened and expanded standards for pneumatic controllers, and standards for liquids unloading events that will further reduce emissions of those pollutants. These are just a few examples of how this proposed rule provides benefits to communities; section XII provides a full explanation and rationale of the proposed actions. E.O. 12898 directs the EPA to identify the populations of concern who are most likely to experience unequal burdens from environmental harms; specifically, minority populations, lowincome populations, and indigenous peoples. 59 FR 7629 (February 16, 1994). Additionally, E.O. 13985 was signed in 2021 to advance racial equity and support underserved communities—including people of color and others who have been historically underserved, marginalized, and adversely affected by persistent poverty and inequality—through Federal Government actions. 86 FR 7009 (January 20, 2021). With respect to climate change, E.O. 14008, titled ‘‘Tackling Climate Change at Home and Abroad,’’ was signed on January 27, 2021, stating that climate considerations shall be an essential element of United States foreign policy and national security, working in partnership with foreign governments, States, territories, and local governments, and communities potentially impacted by climate change. The EPA defines environmental justice (EJ) as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA further defines the term fair treatment to E:\FR\FM\15NOP2.SGM 15NOP2 63140 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules mean that ‘‘no group of people should bear a disproportionate burden of environmental harms and risks, including those resulting from the negative environmental consequences of industrial, governmental, and commercial operations or programs and policies’’ (https://www.epa.gov/ environmentaljustice). In recognizing that minority and low-income populations often bear an unequal burden of environmental harms and risks, the EPA continues to consider ways of protecting them from adverse public health and environmental effects of air pollution emitted from sources within the Oil and Natural Gas Industry that are addressed in this proposed rulemaking. A. Environmental Justice and the Impacts of Climate Change khammond on DSKJM1Z7X2PROD with PROPOSALS2 In 2009, under the Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (‘‘Endangerment Finding’’, 74 FR 66496), the Administrator considered how climate change threatens the health and welfare of the U.S. population.118 As part of that consideration, she also considered risks to minority and low-income individuals and communities, finding that certain parts of the U.S. population may be especially vulnerable based on their characteristics or circumstances. These groups include economically and socially disadvantaged communities, including those that have been historically marginalized or overburdened; individuals at vulnerable lifestages, such as the elderly, the very young, and pregnant or nursing women; those already in poor health or with comorbidities; the disabled; those experiencing homelessness, mental illness, or substance abuse; and/or Indigenous or minority populations dependent on one or limited resources for subsistence due to factors including but not limited to geography, access, and mobility. Scientific assessment reports produced over the past decade by the 118 Earlier studies and reports can be found at https://www.epa.gov/cira/social-vulnerabilityreport. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 USGCRP,119 120 the IPCC,121 122 123 124 the National Academies of Science, Engineering, and Medicine,125 126 and 119 USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018. 120 USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change Research Program, Washington, DC, 312 pp. https:// dx.doi.org/10.7930/J0R49NQX. 121 Oppenheimer, M., M. Campos, R. Warren, J. Birkmann, G. Luber, B. O’Neill, and K. Takahashi, 2014: Emergent risks and key vulnerabilities. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 1039–1099. 122 Porter, J.R., L. Xie, A.J. Challinor, K. Cochrane, S.M. Howden, M.M. Iqbal, D.B. Lobell, and M.I. Travasso, 2014: Food security and food production systems. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 485–533. 123 Smith, K.R., A. Woodward, D. CampbellLendrum, D.D. Chadee, Y. Honda, Q. Liu, J.M. Olwoch, B. Revich, and R. Sauerborn, 2014: Human health: impacts, adaptation, and co-benefits. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 709–754. 124 IPCC, 2018: Global Warming of 1.5 °C. An IPCC Special Report on the impacts of global warming of 1.5 °C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Po¨rtner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Pe´an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)]. In Press. 125 National Research Council. 2011. America’s Climate Choices. Washington, DC: The National Academies Press. https://doi.org/10.17226/12781. 126 National Academies of Sciences, Engineering, and Medicine. 2017. Communities in Action: Pathways to Health Equity. Washington, DC: The National Academies Press. https://doi.org/ 10.17226/24624. PO 00000 Frm 00032 Fmt 4701 Sfmt 4702 the EPA 127 add more evidence that the impacts of climate change raise potential EJ concerns. These reports conclude that less-affluent, traditionally marginalized and predominantly nonWhite communities can be especially vulnerable to climate change impacts because they tend to have limited resources for adaptation, are more dependent on climate-sensitive resources such as local water and food supplies, or have less access to social and information resources. Some communities of color, specifically populations defined jointly by ethnic/ racial characteristics and geographic location (e.g., African-American, Black, and Hispanic/Latino communities; Native Americans, particularly those living on Tribal lands and Alaska Natives), may be uniquely vulnerable to climate change health impacts in the U.S., as discussed below. In particular, the 2016 scientific assessment on the Impacts of Climate Change on Human Health 128 found with high confidence that vulnerabilities are place- and timespecific, lifestages and ages are linked to immediate and future health impacts, and social determinants of health are linked to greater extent and severity of climate change-related health impacts. Per the NCA4, ‘‘Climate change affects human health by altering exposures to heat waves, floods, droughts, and other extreme events; vector-, food- and waterborne infectious diseases; changes in the quality and safety of air, food, and water; and stresses to mental health and well-being.’’ 129 Many health conditions such as cardiopulmonary or respiratory illness and other health impacts are associated with and exacerbated by an increase in GHGs and climate change outcomes, which is problematic as these diseases occur at higher rates within vulnerable communities. Importantly, negative public health outcomes include those that are physical in nature, as well as mental, emotional, social, and economic. The scientific assessment literature, including the aforementioned reports, demonstrates that there are myriad ways 127 EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430–R–21–003. 128 USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. 129 Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 2018: Human Health. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 539–571. doi: 10.7930/NCA4.2018.CH14. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules in which these populations may be affected at the individual and community levels. Outdoor workers, such as construction or utility workers and agricultural laborers, who are frequently part of already at-risk groups, are exposed to poor air quality and extreme temperatures without relief. Furthermore, individuals within EJ populations of concern face greater housing and clean water insecurity and bear disproportionate economic impacts and health burdens associated with climate change effects. They also have less or limited access to healthcare and affordable, adequate health or homeowner insurance. The urban heat island effect can add additional stress to vulnerable populations in densely populated cities who do not have access to air conditioning.130 Finally, resiliency and adaptation are more difficult for economically disadvantaged communities: They tend to have less liquidity, individually and collectively, to move or to make the types of infrastructure or policy changes necessary to limit or reduce the hazards they face. They frequently face systemic, institutional challenges that limit their power to advocate for and receive resources that would otherwise aid in resiliency and hazard reduction and mitigation. The assessment literature cited in the EPA’s 2009 Endangerment Finding, as well as Impacts of Climate Change on Human Health, also concluded that certain populations and people in particular stages of life, including children, are most vulnerable to climaterelated health effects. The assessment literature produced from 2016 to the present strengthens these conclusions by providing more detailed findings regarding related vulnerabilities and the projected impacts youth may experience. These assessments— including the NCA4 (2018) and The Impacts of Climate Change on Human Health in the United States (2016)— describe how children’s unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to allergens, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low-income households, especially those with children, if climate change reduces food availability and increases 130 USGCRP, VerDate Sep<11>2014 2016. 17:06 Nov 12, 2021 Jkt 256001 prices, leading to food insecurity within households. More generally, these reports note that extreme weather and flooding can cause or exacerbate poor health outcomes by affecting mental health because of stress; contributing to or worsening existing conditions, again due to stress or also as a consequence of exposures to water and air pollutants; or by impacting hospital and emergency services operations.131 Further, in urban areas in particular, flooding can have significant economic consequences due to effects on infrastructure, pollutant exposures, and drowning dangers. The ability to withstand and recover from flooding is dependent in part on the social vulnerability of the affected population and individuals experiencing an event.132 The Impacts of Climate Change on Human Health (USGCRP, 2016) also found that some communities of color, low-income groups, people with limited English proficiency, and certain immigrant groups (especially those who are undocumented) live with many of the factors that contribute to their vulnerability to the health impacts of climate change. While difficult to isolate from related socioeconomic factors, race appears to be an important factor in vulnerability to climate-related stress, with elevated risks for mortality from high temperatures reported for Black or African-American individuals compared to White individuals after controlling for factors such as air conditioning use. Moreover, people of color are disproportionately exposed to air pollution based on where they live, and disproportionately vulnerable due to higher baseline prevalence of underlying diseases such as asthma, so climate exacerbations of air pollution are expected to have disproportionate effects on these communities. Locations with greater health threats include urban areas (due to, among other factors, the ‘‘heat island’’ effect where built infrastructure and lack of green spaces increases local temperatures), areas where airborne allergens and other air pollutants already occur at higher levels, and communities experienced 131 Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 2018: Human Health. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 539–571. doi: 10.7930/NCA4.2018.CH14. 132 National Academies of Sciences, Engineering, and Medicine 2019. Framing the Challenge of Urban Flooding in the United States. Washington, DC: The National Academies Press. https://doi.org/ 10.17226/25381. PO 00000 Frm 00033 Fmt 4701 Sfmt 4702 63141 depleted water supplies or vulnerable energy and transportation infrastructure. The recent EPA report on climate change and social vulnerability 133 examined four socially vulnerable groups (individuals who are low income, minority, without high school diplomas, and/or 65 years and older) and their exposure to several different climate impacts (air quality, coastal flooding, extreme temperatures, and inland flooding). This report found that Black and African-American individuals were 40% more likely to currently live in areas with the highest projected increases in mortality rates due to climate-driven changes in extreme temperatures, and 34% more likely to live in areas with the highest projected increases in childhood asthma diagnoses due to climate-driven changes in particulate air pollution. The report found that Hispanic and Latino individuals are 43% more likely to live in areas with the highest projected labor hour losses in weather-exposed industries due to climate-driven warming, and 50% more likely to live in coastal areas with the highest projected increases in traffic delays due to increases in high-tide flooding. The report found that American Indian and Alaska Native individuals are 48% more likely to live in areas where the highest percentage of land is projected to be inundated due to sea level rise, and 37% more likely to live in areas with high projected labor hour losses. Asian individuals were found to be 23% more likely to live in coastal areas with projected increases in traffic delays from high-tide flooding. Those with low income or no high school diploma are about 25% more likely to live in areas with high projected losses of labor hours, and 15% more likely to live in areas with the highest projected increases in asthma due to climatedriven increases in particulate air pollution, and in areas with high projected inundation due to sea level rise. Impacts of Climate Change on Indigenous Communities. Indigenous communities face disproportionate risks from the impacts of climate change, particularly those communities impacted by degradation of natural and cultural resources within established reservation boundaries and threats to traditional subsistence lifestyles. Indigenous communities whose health, economic well-being, and cultural traditions depend upon the natural 133 EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430–R–21–003. E:\FR\FM\15NOP2.SGM 15NOP2 63142 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. The IPCC indicates that losses of customs and historical knowledge may cause communities to be less resilient or adaptable.134 The NCA4 (2018) noted that while indigenous peoples are diverse and will be impacted by the climate changes universal to all Americans, there are several ways in which climate change uniquely threatens indigenous peoples’ livelihoods and economies.135 In addition, there can be institutional barriers (including policy-based limitations and restrictions) to their management of water, land, and other natural resources that could impede adaptive measures. For example, indigenous agriculture in the Southwest is already being adversely affected by changing patterns of flooding, drought, dust storms, and rising temperatures leading to increased soil erosion, irrigation water demand, and decreased crop quality and herd sizes. The Confederated Tribes of the Umatilla Indian Reservation in the Northwest have identified climate risks to salmon, elk, deer, roots, and huckleberry habitat. Housing and sanitary water supply infrastructure are vulnerable to disruption from extreme precipitation events. Confounding general Native American response to natural hazards are limitations imposed by policies such as the Dawes Act of 1887 and the Indian Reorganization Act of 1934, which ultimately restrict Indigenous peoples’ autonomy regarding land-management decisions through Federal trusteeship of certain Tribal lands and mandated Federal oversight of management decisions. Additionally, NCA4 noted that Indigenous peoples are subjected to institutional racism effects, such as poor infrastructure, diminished access to quality healthcare, and greater risk of exposure to pollutants. Consequently, 134 Porter et al., 2014: Food security and food production systems. 135 Jantarasami, L.C., R. Novak, R. Delgado, E. Marino, S. McNeeley, C. Narducci, J. RaymondYakoubian, L. Singletary, and K. Powys Whyte, 2018: Tribes and Indigenous Peoples. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 572–603. doi: 10.7930/NCA4. 2018. CH15. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 Based on analyses of exposed populations, the EPA has determined that this action, if finalized in a manner similar to what is proposed in this document, is likely to help reduce adverse effects of air pollution on minority populations, and/or lowincome populations that have the potential for disproportionate impacts, as specified in E.O. 12898 (59 FR 7629, February 16, 1994) and referenced in E.O. 13985 (86 FR 7009, January 20, 2021). The EPA remains committed to engaging with communities and stakeholders throughout the development of this rulemaking and continues to invite comments on how the Agency can better achieve these goals through this action. For this proposed rule, we assessed emissions of HAP, criteria pollutants, and pollutants that cause climate change. For HAP emissions, we estimated cancer risks and the demographic breakdown of people living in areas with potentially elevated risk levels by performing dispersion modeling of the most recent NEI data from 2017, which indicates nationwide emissions of approximately 110,000 tpy of over 40 HAP (including benzene, toluene, ethylbenzene, xylenes, and formaldehyde) from the Oil and Natural Gas Industry. Table 12 gives the risk and demographic results for the Oil and Natural Gas Industry from this screening-level assessment. We estimate there are 39,000 people with cancer risk greater than or equal to 100-in-1 million attributable to oil and natural gas sources, with a maximum estimated risk of 200-in-1 million occurring in three census blocks (10 people). We estimate there are about 143,000 people with estimated risk greater than or equal to 50-in-1 million, and about 6.8 million people with estimated cancer risk greater than 1-in-1 million. It is important to note that these estimates are subject to various types of uncertainty related to input parameters and assumptions, including emissions datasets, exposure modeling and the dose-response relationships.137 As shown in Table 12, Hispanic and Latino populations and young people (ages 0–17) are disproportionately represented in communities exposed to elevated cancer risks from oil and natural gas sources, while the proportion of people in other demographic groups with estimated risks above the specified levels is at or below the national average. The overall percent minority is about the same as the national average, but the percentage of people exposed to cancer risks greater than or equal to the 100-in-1 million and 50-in-1 million thresholds who are Hispanic or Latino is about 10 percentage points higher than the national average. The overall minority percentage is not elevated compared to the national average because the African-American percentage is much lower than the national average. The demographic group of people aged 0–17 is slightly higher than the national average. 136 Porter et al., 2014: Food security and food production systems. 137 See ‘Risk Report Template’ at Docket ID No. EPA–HQ–OAR–2021–0317. Native Americans often have disproportionately higher rates of asthma, cardiovascular disease, Alzheimer’s disease, diabetes, and obesity. These health conditions and related effects (e.g., disorientation, heightened exposure to PM2.5, etc.) can all contribute to increased vulnerability to climate-driven extreme heat and air pollution events, which also may be exacerbated by stressful situations, such as extreme weather events, wildfires, and other circumstances. NCA4 and IPCC’s Fifth Assessment Report 136 also highlighted several impacts specific to Alaskan Indigenous Peoples. Coastal erosion and permafrost thaw will lead to more coastal erosion, rendering winter travel riskier and exacerbating damage to buildings, roads, and other infrastructure—impacts on archaeological sites, structures, and objects that will lead to a loss of cultural heritage for Alaska’s indigenous people. In terms of food security, the NCA4 discussed reductions in suitable ice conditions for hunting, warmer temperatures impairing the use of traditional ice cellars for food storage, and declining shellfish populations due to warming and acidification. While the NCA4 also noted that climate change provided more opportunity to hunt from boats later in the fall season or earlier in the spring, the assessment found that the net impact was an overall decrease in food security. B. Impacted Stakeholders PO 00000 Frm 00034 Fmt 4701 Sfmt 4702 E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules 63143 TABLE 12—CANCER RISK AND DEMOGRAPHIC POPULATION ESTIMATES FOR 2017 NEI NONPOINT OIL AND NATURAL GAS EMISSIONS Total Population Risks ≥100-in-1 million Risks ≥50-in-1 million Risks >1-in-1 million 39,000 143,000 6,805,000 Population khammond on DSKJM1Z7X2PROD with PROPOSALS2 Minority ......................... African American .......... Native American ........... Other and Multiracial .... Hispanic or Latino ........ Age 0–17 ...................... Age ≥65 ........................ Below the Poverty Level ......................... Over 25 Without a High School Diploma ........ Linguistically Isolated ... % Population % % 34.1 0.4 0.2 3.7 29.9 27.5 11.0 52,154 1,434 465 5,148 45,107 37,487 17,188 36.5 1.0 0.3 3.6 31.6 26.2 12.0 2,010,161 535,055 59,087 323,397 1,092,621 1,463,907 1,085,067 29.5 7.9 0.9 4.8 16.1 21.5 15.9 39.9 12.2 0.7 8.2 18.8 22.6 15.7 2,000 5.1 13,455 9.4 902,472 13.2 13.4 2,788 808 7.2 2.1 11,320 4,418 7.9 3.1 488,372 179,739 7.2 2.6 12.1 5.4 138 For this analysis, oil and natural gas intensive communities are defined as the top 20% of communities with respect to the proportion of oil and natural gas workers. 17:06 Nov 12, 2021 % 13,268 140 77 1,443 11,608 10,679 4,272 For criteria pollutants, we assessed exposures to ozone from Oil and Natural Gas Industry VOC emissions across races/ethnicities, ages, and sexes in a recent baseline (pre-control) air quality scenario. Annual air quality was simulated using a photochemical model for the year 2017, based on emissions from the most recent NEI. The analysis shows that the distribution of exposures for all demographic groups except Hispanic and Asian populations are similar to or below the national average or a reference population. Differences between exposures in Hispanic and Asian populations versus White or all populations are modest, and the results are subject to various types of uncertainty related to input parameters and assumptions. In addition to climate and air quality impacts, the EPA also conducted analyses to characterize potential impacts on domestic oil and natural gas production and prices and to describe the baseline distribution of employment and energy burdens. Section XVI.d describes the results for our analysis of prices and production. For the distribution of baseline employment, we assessed the demographic characteristics of (1) workers in the oil and gas sector and (2) people living in oil and natural gas intensive communities.138 Comparing workers in the oil and natural gas sector to workers in other sectors, oil and natural gas workers may have higher than average incomes, be more likely to have completed high school, and be disproportionately Hispanic. People in some oil and gas intensive communities VerDate Sep<11>2014 Population Nationwide Jkt 256001 concentrated in Texas, Oklahoma, and Louisiana have lower average income levels, lower rates of high school completion, and higher likelihood of being non-Whites or hispanic than people living in communities that are not oil and gas intensive. Regarding household energy burden, low-income households, Hispanic, and Black households’ energy expenditures may comprise a disproportionate share of their total expenditures and income as compared to higher income, nonHispanic, and non-Black households, respectively. Results are presented in detail in the RIA accompanying this proposal. In a proximity analysis of Tribes living within 50 miles of affected sources, we found 112 unique Tribal lands (Federally recognized Reservations, Off-Reservation Trust Lands, and Census Oklahoma Tribal Statistical Areas (OTSA)) located within 50 miles of a source with 32 Tribes having one or more sources located on Tribal land. Finally, the EPA has also analyzed prior enforcement actions related to air pollution from storage vessels, and identified improvements in air quality resulting from these actions as particularly important in communities with EJ concerns (identified using EJSCREEN).139 In a 2021 analysis of resolved enforcement matters, the EPA determined that communities with EJ concerns experience a disproportionate level of air pollution burden from storage vessel emissions. Although only about 25 percent of storage vessels were 139 See Memorandum ‘‘Analysis of Environmental Justice Impacts of EPA’s Historical Oil and Gas Storage Vessel Enforcement Resolutions (40 CFR part 60 subpart OOOO and OOOOa),’’ located at Docket ID No. EPA–HQ–OAR–2021–0317. PO 00000 Frm 00035 Fmt 4701 Sfmt 4702 located in these communities with EJ concerns, 67 percent of the total emission reductions of VOCs, methane, PM, and NOX (about 95 million pounds) achieved through these enforcement resolutions occurred in communities with EJ concerns. This analysis suggests that the provisions of this proposed rule requiring installation of controls at storage vessels and monitoring and mitigation of fugitive emissions and malfunctions at storage vessels, would have particular benefits for these communities. C. Outreach and Engagement The EPA identified stakeholder groups likely to be interested in this action and engaged with them in several ways including through meetings, training webinars, and public listening sessions to share information with stakeholders about this action, on how stakeholders may comment on the proposed rule, and to hear their input about the industry and its impacts as we were developing this proposal. Specifically, on May 27, 2021, the EPA held a webinar-based training designed for communities affected by this rule.140 This training provided an overview of the Crude Oil and Natural Gas Industry and how it is regulated and offered information on how to participate in the rulemaking process. The EPA also held virtual public listening sessions June 15 through June 17, 2021, and heard various community and health related themes from speakers who participated.141 142 Community themes 140 https://www.epa.gov/sites/default/files/202105/documents/us_epa_training_webinar_on_oil_ and_natural_gas_for_communities.5.27.2021.pdf. 141 June 15, 2021 session: https://youtu.be/ T8XwDbf-B8g; June 16, 2021 session: https:// www.youtube.com/watch?v=l23bKPF-5oc; June 17, E:\FR\FM\15NOP2.SGM Continued 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63144 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules included concerns about protecting communities adjacent to oil and gas activities, providing monitoring and data so communities know what is in the air they are breathing, and upholding Tribal trust responsibilities. Community speakers urged the EPA to adopt stringent measures to reduce oil and natural gas pollution, and frequently cited an analysis suggesting such measures could achieve reductions of 65 percent below 2012 levels by 2025. Community Access to Emissions Information. Several stakeholders requested that the rule include requirements that provide communities with information, including fence line monitoring or ‘‘better monitoring so people will know the air they are breathing.’’ A few speakers expressed concerned about the correct placement of existing air monitors. Speakers from Texas described local air monitors monitoring meteorology and ozone, but not hazardous air pollutants, and called on the EPA to consider alternative monitoring for oil and natural gas sources such as fence-line monitors, along with guidance from the EPA to require monitors of oil and natural gas facilities in close proximity to parks, schools, and playgrounds. Health Concerns in Adjacent Communities. Speakers raised concerns about impacts on frontline communities and those communities adjacent to oil and natural gas operations. These stakeholders called on the EPA to propose and promulgate stricter standards or alternative requirements for sources adjacent to urban communities and close to where people live and work. Several speakers used the term ‘‘energy sacrifice zone’’ when discussing the disproportionate impacts of oil and natural gas operations on frontline communities. Speakers advocated that when developing this regulatory effort, consultation with frontline communities is essential, and some speakers cited a Center for Investigative Reporting report stating that 30,000 children in Arlington, Texas, attend school within half a mile of active oil and gas sites. Speakers discussed concerns about methane as a formaldehyde precursor and related health effects and cited examples of health effects including hydraulic fracturing chemicals being measured in blood or urine; increases in nosebleeds in people in areas of oil and natural gas development; headaches and cancer. 2021 session: https://www.youtube.com/ watch?v=R2AZrmfuAXQ. 142 Full transcripts for the listening sessions are posted at EPA Docket ID No. EPA–HQ–OAR–2021– 0295. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 These speakers included teenagers from Pennsylvania, who said they live within 1 mile of 33 wellheads and 500 feet of a pipeline. Several people cited a February 2018 blowout and explosion in Belmont County, Ohio, that was reported to release 60,000 tons of methane in 20 days and said that is more than some countries emit in a year. Speakers also expressed related environmental concerns such as water contamination and fresh drinking water being diverted for hydraulic fracturing. One speaker urged that information on local water use be provided in languages other than English, stating that in Big Spring (Howard County), Texas, the local government only provided information to use tap water ‘‘at your own risk’’ in English. Additional concerns raised by communities included: Local compressor stations having numerous planned and unplanned releases into adjacent communities, which appear to be during startup; whether the EPA will use a robust cost analysis to address the economic impacts of labor loss and gas costs resulting from any regulation; if plugged and abandoned wells included in this action, will this regulation apply to BLM land; will States be required to use the same emissions calculation used by the EPA for methane GWP; will there be disclosure of necessary data collection or technology to be used by the Oil and Natural Gas Industry to track and reduce methane emissions; and will the EPA consider the necessity of venting and flaring from a safety standpoint. Communities also discussed concerns about excess emissions from storage vessels and the need for clarifying the applicability of the standard in addition to improving enforceability and compliance at this type of facility. In addition to the trainings and listening sessions, the EPA engaged with community leaders potentially impacted by this proposed action by hosting a meeting with EJ community leaders on May 14, 2021. As noted above, the EPA provided the public with factual information to help them understand the issues addressed by this action. We obtained input from the public, including communities, about their concerns about air pollution from the oil and gas industry, including receiving stakeholder perspectives on alternatives. The EPA considered and weighed information from communities as the agency developed this proposed action. In addition to the engagement conducted prior to this proposal, the EPA is providing the public, including those communities disproportionately PO 00000 Frm 00036 Fmt 4701 Sfmt 4702 impacted by the burdens of pollution, opportunities to engage in the EPA’s public comment period for this proposal, including by hosting public hearings. This public hearing will occur according to the schedule identified in the DATES and SUPPLEMENTARY INFORMATION section of this preamble to discuss: • What impacts they are experiencing (i.e., health, noise, smells, economic), • How the community would like the EPA to address their concerns, • How the EPA is addressing those concerns in the rulemaking, and • Any other topics, issues, concerns, etc. that the public may have regarding this proposal. For more information about the EPA’s pre-proposal outreach activities, please see EPA Docket ID No. EPA–HQ–OAR– 2021–0295. Please refer to EPA Docket ID No. EPA–HQ–OAR–2021–0317 for submitting public comments on this proposed rulemaking. For public input to be considered during the formal rulemaking, please submit comments on this proposed action to the formal regulatory docket at EPA Docket ID No. EPA–HQ–OAR–2021–0317 so that the EPA may consider those comments during the development of the final rule. D. Environmental Justice Considerations The EPA considered EJ implications in the development of this proposed rulemaking process, including the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income. As part of this process, the EPA engaged and consulted with frontline communities through interactions such as webinars, listening sessions and meetings. These opportunities gave the EPA a chance to hear directly from the public, especially overburdened and underserved communities, on the development of the proposed rule. The EPA considered these community concerns throughout our internal development process that resulted in this proposal which, if finalized in a manner similar to what is being proposed, will reduce emissions of harmful air pollutants, promote gas capture and beneficial use, and provide opportunity for flexibility and expanded transparency in order to yield a consistent and accountable national program. The EPA’s proposed NSPS and EG are summarized in sections XI and XII below. Anticipated impacts of this action are discussed further in section XVI of this preamble. In recognizing that minority and lowincome populations often bear an unequal burden of environmental harms and risks, the EPA continues to consider E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules ways to protect them from adverse public health and environmental effects of air pollution emitted from sources within the Oil and Natural Gas Industry that are addressed in this proposed rulemaking. For these reasons, in section XIV.C the EPA is proposing to include an additional requirement associated with the adoption and submittal of State plans pursuant to EG OOOOc (in addition to the current requirements of Subpart Ba) by requiring States to meaningfully engage with members of the public, including overburdened and underserved communities, during the plan development process and prior to adoption and submission of the plan to the EPA. The EPA is proposing this specific meaningful engagement requirement to ensure that the State plan development process is inclusive, effective, and accessible to all. Details of the EPA’s assessment of EJ considerations can be found in the RIA for this action. The EPA seeks input on the EJ analyses contained in the RIA, as well as broader input on other health and environmental risks the Agency should assess in the comprehensive development of this proposed action. In particular, the EPA is soliciting comment on key assumptions underlying the EJ analysis as well as data and information that would enable the Agency to conduct a more nuanced analysis of HAP and criteria pollutant exposure and risk, given the inherent uncertainty regarding risk assessment. More broadly, the EPA seeks information, analysis, and comment on how the provisions of this proposed action would affect air pollution and health in communities with environmental justice concerns, and whether there are further provisions that EPA should consider as part of a supplemental proposal or a final rule that would enhance the health and environmental benefits of this rule for these communities. VII. Other Stakeholder Outreach khammond on DSKJM1Z7X2PROD with PROPOSALS2 A. Educating the Public, Listening Sessions, and Stakeholder Outreach The EPA began the development of this proposed action to reduce methane and other harmful pollutants from new and existing sources in the Crude Oil and Natural Gas source category with a public outreach effort to gather a broad range of stakeholder input. This effort included: Opening a public docket for pre-proposal input; 143 holding training sessions providing overviews of the 143 EPA Docket ID No. EPA–HQ–OAR–2021– 0295. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 industry, the EPA’s rulemaking process and how to participate in it; and convening listening sessions for the public, including a wide range of stakeholders. The EPA additionally held roundtables with State environmental commissioners through the Environmental Council of the States, and oil and gas commissioners and staff through the Interstate Oil and Gas Compact Commission (IOGCC), and met with non-governmental organizations (NGOs), industry, and the U.S. Climate Alliance, among others.144 In addition to the trainings and listening sessions noted in section VI above, on May 25 and 26, 2021, the EPA held webinar-based trainings designed for small business stakeholders 145 and Tribal nations.146 The training provided an overview of the Oil and Natural Gas Industry and how it is regulated and offered information on how to participate in the rulemaking process. A combined total of more than 100 small business stakeholders and Tribal nations participated. During the training, small business stakeholders expressed interest in learning more about the EPA’s plan to either modify the 2016 NSPS OOOOa or take more substantial action in this proposal. For Tribal nations, the EPA has assessed potential impacts on Tribal nations and populations and has engaged with Tribal stakeholders to hear concerns associated with air pollution emitted from sources within the Oil and Natural Gas Industry that are addressed in this proposed rulemaking. Tribal members mentioned the need for the EPA to uphold its trust responsibilities, propose and promulgate rules that protect disproportionately impacted communities, and asked that the EPA allocate resources for Tribal governments to implement regulations through Tribal air quality programs. As noted above, the EPA also heard from a broad range of stakeholders during virtual public listening sessions held from June 15 through June 17, 2021,147 which featured a total of 173 speakers.148 Many speakers stressed the 144 A full list of pre-proposal meetings the EPA participated in is included at EPA Docket ID No. EPA–HQ–OAR–2021–0317. 145 https://www.epa.gov/sites/default/files/202105/documents/oil_and_gas_training_webinar_ small_businesses_05.25.21.pdf. 146 https://www.epa.gov/sites/default/files/202105/documents/usepa_training_webinar_on_oil_ and_natural_gas_for_tribes.5.26.2021.pdf. 147 June 15, 2021 session: https://youtu.be/ T8XwDbf-B8g; June 16, 2021 session: https:// www.youtube.com/watch?v=l23bKPF-5oc; June 17, 2021 session: https://www.youtube.com/ watch?v=R2AZrmfuAXQ. 148 Full transcripts for the listening sessions are posted in at EPA Docket ID No. EPA–HQ–OAR– 2021–0295. PO 00000 Frm 00037 Fmt 4701 Sfmt 4702 63145 urgent need to address climate change and the importance of reducing methane pollution as part of the nation’s overall response to climate change. In addition to the community perspectives described above, the Agency also heard from industry speakers who were generally supportive of the regulation and stressed the need to provide compliance flexibility and allow industry the ability to use cutting-edge tools, including measurement tools, to implement requirements. Technical comments from other speakers also focused on a need for robust methane monitoring and fugitive emissions monitoring, a need to strengthen standards for flares as a control for associated gas, and suggestions to improve compliance. The sections below provide additional details on the information presented by stakeholders during these listening sessions. 1. Technical Themes Measurement and Monitoring. Stakeholders advocated that the EPA modernize the rule by employing nextgeneration tools for methane identification and quantification, particularly for large emission or ‘‘super-emissions’’ events. Stakeholders particularly focused on allowing the use of remote sensing to help industry more easily comply with monitoring requirements at well pads, which are numerous and geographically spread out in some States. Stakeholders specified the desire to use innovative remote sensing technologies to monitor fugitive emissions and large emission events, including aerial, truck-based, satellite, and continuous monitoring. Several speakers focused on the need for regular monitoring, repair, and reporting, including ambient air monitoring in oil and natural gas development areas, as well as suggesting that the EPA pursue more robust methane monitoring for fugitive emissions, ensure that repair is completed, and pursue robust monitoring and reporting to verify the efficacy of the regulations. Implementation, Compliance, and Enforcement. Numerous stakeholders raised concerns about flaring of associated gas and advocated for more stringent standards to ensure that flares used as control devices perform effectively. One speaker, an OGI expert, noted seeing many flares that were not operating the way they were intended to and that were not adequately designed (e.g., unlit flares and ignition gas not being close enough to the waste gas stream to properly ignite). The speaker suggested that the EPA consider the concept of ‘thermal tuning’ of flares by E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63146 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules using OGI to see if a plume of unburned hydrocarbons extends downwind from the flare, to ensure that flares are actually operating effectively; the speaker suggested that this use of OGI could be done in conjunction with fugitive emissions monitoring to make sure controls are working. Stakeholders further emphasized the need for recordkeeping of any inspections that are made (e.g., looking for flare damage from burned tips, lightning strikes). Some stakeholders also requested that the EPA consider reducing or eliminating flaring of associated gas and incentivizing capture. Lastly, one speaker raised concerns about flaring of associated gas in Texas and how flaring is permitted by the State. In response to these concerns, the EPA is proposing to reduce venting and flaring of associated gas and to require monitoring of flares to detect malfunctions. Further, the EPA is soliciting comment on whether to adopt additional measures to assure proper design and operation of control devices, including flares, as discussed in section XIII. Stakeholders raised other implementation, compliance, and enforcement concerns, including calls for the EPA to develop rules that are easy to apply and implement given States’ limited budgets. Stakeholders cautioned that ‘‘flexibility’’ in a rule can be interpreted as a ‘‘loophole,’’ and opined that a rule that sets clear and uniform expectations will help avoid confusion. At the same time, speakers stated that a ‘‘prescriptive checklist’’ does not work in today’s environment and recommended that the EPA modernize the regulatory approach. Several speakers, including speakers from Texas and North Dakota, raised concerns about the limited enforcement capacity of local and State governments, as well as the EPA and its regional officials and stated that this may result in implementation gaps. Speakers called on the EPA to have a third-party verification or audit requirements for fugitive emissions and cited to Texas’s requirement for third-party audits to evaluate operator LDAR programs for highly reactive VOC. Speakers also cited to the public-facing Environmental Defense Fund (EDF) methane map 149 with geotags of sources with observed hydrocarbon emissions, which provides operators an opportunity to respond to posted leak videos and measurements. Lastly, one speaker requested that the EPA not allow exemptions for start-up and shutdown emissions events. The EPA is soliciting comment on ways to utilize credible emissions information 149 https://www.permianmap.org. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 obtained from communities and others, as discussed in section XI.A.1. Wells and Storage. Some stakeholders requested that the EPA consider a program for capping abandoned wells to ensure those wells are properly closed and not leaking. Speakers called on the EPA to consider abandoned and unplugged wells in the context of EJ communities adjacent to affected facilities and requested that the EPA incentivize appropriate well closure. In response to this input and to gather information that will be needed to inform possible future actions, the EPA is soliciting comment on ways to address abandoned wells, including potential closure requirements. See section XIII.B. Stakeholders also focused on marginal wells and asked that the EPA consider system-wide reductions be allowed, for example, at the basin level, and expressed challenges of retrofitting existing well sites and low production well sites where addition of control devices or closed vent systems would be necessary. Some speakers raised concern about ensuring that facilities are engineered for the basin or target formation from which they produce. Job Creation. Some speakers stated that this rulemaking is a job creation rule and encouraged a ‘‘next generation’’ approach to methane standards, such as incentivizing continuous monitoring. Other speakers cited a study about job creation in the methane mitigation industry.150 Inventory, Loss Rates, and Methane Global Warming Potential. Several speakers criticized the EPA’s emission inventories stating that the EPA is not using the correct data in its inventory, that the GHGI data is inaccurate because it relies on facility reporting of emissions from calculations and estimation methods rather than measurement and monitoring, and suggested that the EPA rely on monitoring and measurement of actual emissions and subsequently make the monitoring data publicly available. Speakers raised issues with differences in inventories across Federal agencies, contrasting DOE’s Environmental Impact Statements and EPA’s NEI. Stakeholders suggested that the EPA use data collected by EDF and other researchers, which calculated methane emissions to be 60 percent higher than the EPA’s estimates.151 Speakers also 150 Stakeholders submitted the following studies to the pre-proposal docket: https:// www.regulations.gov/comment/EPA-HQ-OAR-20210295-0016 and https://www.regulations.gov/ comment/EPA-HQ-OAR-2021-0295-0017. 151 Alvarez et al. 2018. Assessment of methane emissions from the U.S. oil and gas supply chain. PO 00000 Frm 00038 Fmt 4701 Sfmt 4702 mentioned the amount of methane that is lost from wells each year, providing varying estimates of these emissions. Lastly, stakeholders called on the EPA to use the 20-year GWP for methane, instead of the 100-year value the agency uses. 2. Climate and Other Themes Several speakers mentioned the effects of climate change from oil and natural gas methane emissions, such as impacts on farmland, wildfires, and transmission of tick-borne pathogens. Many speakers pointed out the extreme heat and drought that currently are affecting the western U.S. Stakeholders asked that the EPA examine the impacts of the Oil and Natural Gas Industry on small businesses that are not part of the regulated community, such as businesses that rely on outdoor recreation or water flow that could be affected by oil and natural gas operations. A speaker raised concerns about the impact of the industry on tourism, saying that 30 percent of their local economy relies on tourism and outdoor recreation. Lastly, a speaker discussed pipeline weatherization needs and suggested that the EPA and other Federal agencies account for seasonal variability. In addition to the public listening sessions, on June 29, 2021, the EPA met with environmental commissioners and staff through the Environmental Council of the States (ECOS). Subsequently, on July 12, 2021, the EPA participated in a roundtable with members of the IOGCC. The discussions in both roundtables included air emissions monitoring technologies and interactions between the EPA’s requirements and State rules. For the ECOS roundtable, the EPA also sought feedback on and implementation of the EPA’s current NSPS; for the IOGCC roundtable, the EPA also requested feedback on compliance with the rules. Key themes from both roundtables included the following: Allowing for the use of broad types of methane detection technologies; improving and streamlining the EPA’s AMEL process, such as by structuring it so it could apply broadly rather than on a site-bysite basis; requests that expanded aspects of States’ rules be deemed equivalent to the EPA’s rule, and requests that the EPA’s rule complement State regulations in a way that would not interrupt the work of State agencies requiring them to request State legislative approvals. Other common themes were requests that the rule Science 13 Jul 2018: Vol. 361, Issue 6398, pp. 186– 188. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 provide flexibility and be easy to implement, particularly for marginal or low production wells owned by independent small businesses, and that the EPA coordinate its rules with those of other Federal agencies, notably the DOI’s BLM. Other input included the need to fill gaps by addressing additional opportunities to reduce emissions beyond the 2016 NSPS OOOOa, concerns about the complexity of the calculation for the potential to emit for storage vessels, a desire that the EPA’s rule not slow momentum of voluntary efforts to reduce emissions, and a desire for regulations that recognize geographic differences. B. EPA Methane Detection Technology Workshop The EPA held a virtual public workshop on August 23 and 24, 2021, to hear perspectives on innovative technologies that could be used to detect methane emissions from the Oil and Natural Gas Industry.152 The workshop focused on methane-sensing technologies that are not currently approved for use in the NSPS for the Oil and Natural Gas Industry, and how those technologies could be applied in the Crude Oil and Natural Gas sector. Panelists provided twenty-four live presentations during the workshop. The panelists all had firsthand experience evaluating innovative methane-sensing technologies or had used these technologies to identify methane emissions and presented about their experience. The live presentations were broken into six panel sessions, each focused on a particular topic, e.g., satellite measurements, methane sensors, aerial technologies. At the end of each panel session, the set of panelists participated in a question-andanswer session. In addition to the live presentations, the workshop included a virtual exhibit hall for technology vendors to provide video presentations on their innovative technologies, with a focus on technology capability, applicability, and data quality. Fortytwo vendors participated in the virtual vendor hall. Nine hundred sixty stakeholders registered to participate in the workshop. The workshop was also livestreamed, so stakeholders who could not attend could watch the recorded livestream later at their convenience. The registrants included a wide range of stakeholders including, academics, methane detection technology end-user 152 https://www.epa.gov/controlling-air-pollutionoil-and-natural-gas-industry/epa-methanedetection-technology-workshop. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 and vendors, governmental employees (local, State, and Federal), and NGOs. C. How is this information being considered in this proposal? The EPA’s pre-proposal outreach effort was intended to gather stakeholder input to assist the Agency with developing this proposal.153 The EPA recognizes that tackling the dangers of climate change will require an ‘‘allhands-on deck’’ approach through regulatory, voluntary, and community programs and initiatives. Throughout the development of this proposed rule, the EPA considered the stakeholders’ experiences and lessons learned to help inform how to better structure this proposal and consider ongoing challenges that will require continued collaboration with stakeholders. The EPA will continue to consider the information obtained in developing this proposal as we take the next steps on the proposed regulations. With this proposal, the EPA seeks further input from the public and from all stakeholders affected by this rule. Throughout this action, unless noted otherwise, the EPA is requesting comments on all aspects of this proposal, including on several themes raised in the pre-proposal outreach (e.g., innovative technologies for methane detection and quantification). Please see section XI.A.1 of this preamble for specific solicitations for comment regarding advanced measurement technologies and section XIII for solicitations for comments on additional emission sources. For public input to be considered on this proposal,154 please submit comments on this proposed action to the regulatory docket at EPA Docket ID No. EPA–HQ–OAR–2021– 0317 so that the EPA may consider those comments during the development of the final rule. VIII. Legal Basis for Proposal Scope The EPA proposes in this rulemaking to revise certain NSPS and to promulgate additional NSPS for both methane and VOC emissions from new oil and gas sources in the production, processing, transmission and storage segments of the industry; and to promulgate EG to require States to regulate methane emissions from 153 The EPA opened a non-regulatory docket for stakeholder to submit early input. That early input can be found at EPA Docket I.D. Number EPA–HQ– OAR–2021–0295. 154 Information submitted to the pre-proposal non-regulatory docket at Docket ID No. EPA–HQ– OAR–2021–0295 is not automatically part of the proposal record. For information and materials to be considered in the proposed rulemaking record, it must be resubmitted in the rulemaking docket at EPA Docket ID No. EPA–HQ–OAR–2021–0317. PO 00000 Frm 00039 Fmt 4701 Sfmt 4702 63147 existing sources in those segments. The large amount of methane emissions from the Oil and Natural Gas Industry—by far, the largest methane-emitting industry in the nation—coupled with the adverse effects of methane on the global climate compel immediate regulatory action. This section explains EPA’s legal justification for proceeding with this proposed action, including regulating methane and VOCs from sources in all segments of the source category. The EPA first describes the history of our regulatory actions for oil and gas sources in 2016 and 2020— including the key legal interpretations and factual determinations made—as well as Congress’s action in 2021 in response. The EPA then explains the implications of Congress’s action and why we would come to the same conclusion even if Congress had not acted. This proposal is in line with our 2016 NSPS OOOOa rule, which likewise regulated methane and VOCs from all three segments of the industry. The 2016 NSPS OOOOa rule explained that these three segments should be regulated as part of the same source category because they are an interrelated sequence of functions in which pollution is produced from the same types of sources that can be controlled by the same techniques and technologies. That rule further explained that the large amount of methane emissions, coupled with the adverse effects of GHG air pollution, met the applicable statutory standard for regulating methane emissions from new sources through NSPS. Furthermore, the rule explained, this regulation of methane emissions from new sources triggered the EPA’s authority and obligation to set guidelines for States to develop standards to regulate the overwhelming majority of oil and gas sources, which the CAA categorizes as ‘‘existing’’ sources. In the 2020 Policy Rule, the Agency reversed course, concluding based upon new legal interpretations that the rule concluded the EPA had not made the proper determinations necessary to issue such regulations. This action eliminated the Agency’s authority and obligation to issue EG for existing sources. In 2021, Congress adopted a joint resolution to disapprove the EPA’s 2020 Policy Rule under the CRA. According to the terms of CRA, the 2020 Policy Rule is ‘‘treated as though [it] had never taken effect,’’ 5 U.S.C. 801(f), and as a result, the 2016 Rule is reinstated. In disapproving the 2020 Policy Rule under the CRA, Congress explicitly rejected the 2020 Policy Rule interpretations and embraced EPA’s E:\FR\FM\15NOP2.SGM 15NOP2 63148 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 rationales for the 2016 NSPS OOOOa rule. The House Committee on Energy & Commerce emphasized in its report that the source category ‘‘is the largest industrial emitter of methane in the U.S.,’’ and directed that ‘‘regulation of emissions from new and existing oil and gas sources, including those located in the production, processing, and transmission and storage segments, is necessary to protect human health and welfare, including through combatting climate change, and to promote environmental justice.’’ H.R. Rep. No. 117–64, 3–5 (2021) (House Report). A statement from the Senate cosponsors likewise underscored that ‘‘methane is a leading contributing cause of climate change,’’ whose ‘‘emissions come from all segments of the Oil and Gas Industry,’’ and stated that ‘‘we encourage EPA to strengthen the standards we reinstate and aggressively regulate methane and other pollution emissions from new, modified, and existing sources throughout the production, processing, transmission and storage segments of the Oil and Gas Industry under section 111 of the CAA.’’ 167 Cong. Rec. S2282 (April 28, 2021) (statement by Sen. Heinrich) (Senate Statement).155 The Senators concluded with a stark statement: ‘‘The welfare of our planet and of our communities depends on it.’’ Id. at S2283. This proposal comports with the EPA’s CAA section 111 obligation to reduce dangerous pollution and responds to the urgency expressed by the current Congress. With this proposal, the EPA is taking additional steps in the regulation of the Crude Oil and Natural Gas source category to protect human health and the environment. Specifically, the agency is proposing to revise certain of those NSPS, to add NSPS for additional sources, and to propose EG that, if finalized, would impose a requirement on States to regulate methane emissions from existing sources. As the EPA explained in the 2016 Rule, this source category collectively emits massive quantities of the methane emissions that 155 Sen. Heinrich stated that he made this statement on behalf of ‘‘[Majority [l]eader Chuck Schumer, Chairman Tom Carper of the Committee on Environment and Public Works, Senator Angus King, Senator Edward Markey and [himself],’’ who he described as ‘‘leading supporters and sponsors of S.J. Res. 14. . . .’’ Senate Statement at S. 2282. Thus, the Senate Statement should be considered an authoritative piece of the legislative history. It should be noted that the Joint Resolution was referred to the Senate Committee on Environment and Public Works and discharged from the committee by petition pursuant to 5 U.S.C. 802(c), https://www.congress.gov/bill/117th-congress/ senate-joint-resolution/14/all-actions. As a result, the resolution was not accompanied by a report from the Senate committee. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 are among those driving the grave and growing threat of climate change, particularly in the near term. 81 FR 35834, June 3, 2016. As discussed in section III above, since that time, the science has repeatedly confirmed that climate change is already causing dire health, environmental, and economic impacts in communities across the United States. Because the 2021 CRA resolution automatically reinstated the 2016 Rule, which itself determined that the Crude Oil and Natural Gas Source Category included the transmission and storage segment and that regulation of methane emissions was justified, the EPA is authorized to take the regulatory actions proposed in this rule. As explained below, we are reaffirming those determinations as clearly authorized under any reasonable interpretation of section 111. Because the reinstatement of the 2016 Rule provides the only necessary predicate for this rule, and because, as described, the interpretations underlying this rule are sound, the EPA is not reopening them here. A. Recent History of the EPA’s Regulation of Oil and Gas Sources and Congress’s Response 1. 2016 NSPS OOOOa Rule As described above, the 2016 NSPS OOOOa rule extended the NSPS for VOCs for new sources in the Crude Oil and Natural Gas source category and also promulgated NSPS for methane emissions from new sources. This rule contained several interpretations that were the bases for these actions, and that are important for present purposes. First, the EPA confirmed its position in the 2012 NSPS OOOO rule that the scope of the oil and gas source category included the transmission and storage segment, in addition to the production and processing segments that the EPA had regulated since 1984. The agency stated that it believed these segments were included in the initial listing of the source category, and to the extent they were not, the agency determined to add them as appropriately encompassed within the regulated source category. The EPA based this latter conclusion on the structure of the industry. In particular, the EPA emphasized that ‘‘[o]perations at production, processing, transmission, and storage facilities are a sequence of functions that are interrelated and necessary for getting the recovered gas ready for distribution,’’ and further explained, ‘‘[b]ecause they are interrelated, segments that follow others are faced with increases in throughput caused by PO 00000 Frm 00040 Fmt 4701 Sfmt 4702 growth in throughput of the segments preceding (i.e., feeding) them.’’ 81 FR 35832, June 3, 2016. The EPA also recognized ‘‘that some equipment (e.g., storage vessels, pneumatic pumps and compressors) are used across the oil and natural gas industry.’’ Id. Having made clear that the Crude Oil and Natural Gas source category includes the transmission and storage segment, the EPA proceeded to promulgate NSPS for sources in that segment. Id. at 35826. Second, in promulgating NSPS for methane emissions for new sources in the source category, the EPA explained its decision to regulate GHGs for the first time from the source category. Noting that the plain language of CAA section 111 requires a significantcontribution analysis only when EPA regulates a new source category, not a new pollutant, the Agency stated that it ‘‘interprets CAA section 111(b)(1)(B) to provide authority to establish a standard for performance for any pollutant emitted by that source category as long as the EPA has a rational basis for setting a standard for the pollutant.’’ 81 FR 35842, June 3, 2016. In the alternative, if a rational-basis analysis were deemed insufficient, the EPA explained that it also concluded that GHG emissions, in the form of methane emissions, from the regulated Crude Oil and Natural Gas source category significantly contribute to dangerous pollution. Id. at 81 FR 35843, and 35877. In making the rational basis and alternative significant contribution findings, the EPA focused on ‘‘the high quantities of methane emissions from the Crude Oil and Natural Gas source category.’’ Id. The EPA emphasized, among other things, that ‘‘[t]he Oil and Natural Gas source category is the largest emitter of methane in the U.S., contributing about 29 percent of total U.S. methane emissions.’’ Id. The EPA added that ‘‘[t]he methane that this source category emits accounts for 3 percent of all U.S. GHG emissions . . . [and] GWP-weighted emissions of methane from these sources are larger than emissions of all GHGs from about 150 countries.’’ Id. The EPA concluded that ‘‘the[se] facts . . . along with prior EPA analysis’’ concerning the effect of GHG air pollution on public health and welfare, ‘‘including that found in the 2009 Endangerment Finding, provide a rational basis for regulating GHG emissions from affected oil and gas sources . . .’’ as well as for concluding in the alternative that oil and gas methane significantly contributes to dangerous pollution. Id. at 35843. In addition, in the 2016 NSPS OOOOa Rule, EPA recognized that promulgation of NSPS for methane emissions under E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 section 111(b)(1)(B) triggered the requirement that EPA promulgate EG to require States to regulate methane emissions from existing sources under section 111(d)(1), and described the steps it was taking to lay the groundwork for that regulation. 81 FR at 35831. 2. 2020 Policy Rule The 2020 Policy Rule rescinded key elements of the 2016 NSPS OOOOa rule based on different factual assertions and statutory interpretations than in the 2016 Rule. Specifically, the 2020 Policy Rule stated that it ‘‘contains two main actions,’’ 85 FR 57019, September 14, 2020 which it identified as follows: ‘‘First, the EPA is finalizing a determination that the source category includes only the production and processing segments of the industry and is rescinding the standards applicable to the transmission and storage segment of the industry. . . .’’ Id. The rule justified this first action in part on the grounds that ‘‘the processes and operations found in the transmission and storage segment are distinct from those found in the production and processing segments,’’ because ‘‘the purposes of the operations are different’’ and because ‘‘the natural gas that enters the transmission and storage segment has different composition and characteristics than the natural gas that enters the production and processing segments.’’ Id. at 57028. ‘‘Second, the EPA is separately rescinding the methane requirements of the NSPS applicable to sources in the production and processing segments.’’ Id. EPA justified the rescission of the methane NSPS on two grounds. One was the EPA’s ‘‘conclu[sion] that those methane requirements are redundant with the existing NSPS for VOC and, thus, establish no additional health protections.’’ Id. at 57019. The second was a statutory interpretation: the EPA rejected the rational basis interpretation of the 2016 Rule, and stated that instead, ‘‘[t]he EPA interprets [the relevant provisions in CAA section 111] . . . to require, or at least to authorize the Administrator to require, a pollutant-specific SCF as a predicate for promulgating a standard of performance for that air pollutant.’’ Id. at 57035. The rule went on to ‘‘determine that the SCF for methane that the EPA made in the alternative in the 2016 [NSPS OOOOa] Rule was invalid and did not meet this statutory standard,’’ for two reasons: (i) ‘‘[t]he EPA made that finding on the basis of methane emissions from the production, processing, and transmission and storage segments, instead of just the production and VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 processing segments’’; and (ii) ‘‘the EPA failed to support that finding with either established criteria or some type of reasonably explained and intelligible standard or threshold for determining when an air pollutant contributes significantly to dangerous air pollution.’’ Id. at 57019. The rule recognized that ‘‘by rescinding the applicability of the NSPS . . . to methane emissions for [oil and gas] sources . . . existing sources . . . will not be subject to regulation under CAA section 111(d).’’ Id. at 57040. 3. CRA Resolution Disapproving the 2020 Policy Rule and Reinstating the 2016 NSPS OOOOa Rule On June 30, 2021, the President signed into law a joint resolution adopted by Congress under the CRA disapproving the 2020 Policy Rule. By the terms of the CRA, this disapproval means that the 2020 Policy Rule is ‘‘treated as though [it] had never taken effect.’’ 5 U.S.C. 801(f). As a result, upon the disapproval, by operation of law, the 2016 NSPS OOOOa rule was reinstated, including the inclusion of the transmission and storage segment in the source category, the VOC NSPS for sources in that segment, and the methane NSPS for sources across the source category. And with the reinstatement of the methane NSPS, the EPA’s obligation to issue EG to require States to regulate existing sources for methane emissions was reinstated as well. Moreover, the CRA bars an agency from promulgating ‘‘a new rule that is substantially the same as’’ a disapproved rule. 5 U.S.C. 801(b)(2). The accompanying legislative history, specifically a House Committee report (H.R. Rep. 117–64) and a statement on the Senate floor by the sponsors of the CRA resolution (Senate Statement at S2282–83), provides additional specificity regarding Congress’s intent in disapproving 2020 Policy Rule and reinstating the 2016 Rule with regard to the scope of the source category and the regulation of methane. a. Regulation of Transmission and Storage Sources The House Report rejected the 2020 Policy Rule’s removal of the transmission and storage segment from the Crude Oil and Natural Gas Source Category, and its rescission of the VOC and methane NSPS promulgated in the 2012 NSPS OOOO and 2016 NSPS OOOOa rules for transmission and storage sources. House Report at 7; 85 FR 57029, September 14, 2020 (2020 Policy Rule). The Report recognized that in authorizing the EPA to list for regulation ‘‘categories of sources’’ under PO 00000 Frm 00041 Fmt 4701 Sfmt 4702 63149 section 111(b)(1)(A) of the CAA, Congress ‘‘provided the EPA with wide latitude to determine the scope of a source category . . . and to expand the scope of an already-listed source category if the agency later determines that it is reasonable to do so.’’ House Report at 7. The Report stated that in the 2016 NSPS OOOOa, ‘‘EPA correctly determined that the equipment and operations at production, processing, and transmission and storage facilities are a sequence of functions that are interrelated and necessary for the overall purpose of extracting, processing, and transporting natural gas for distribution.’’ Id.; see 81 FR 35832, June 3, 2016 (2016 Rule). The Report added that the 2016 NSPS OOOOa also ‘‘correctly determined that the types of equipment used and the emissions profile of the natural gas in the transmission and storage segments do not so distinctly differ from the types of equipment used and the emissions profile of the natural gas in the production and processing segments as to require that the EPA create a separate source category listing.’’ House Report at 7; see 81 FR 35832, June 3, 2016. The Report went on to reject the 2020 Policy Rule’s basis for excluding the transmission and storage segment, finding that the functions of the various segments in the Crude Oil and Natural Gas sector are all ‘‘interrelated and necessary for the overall purpose’’ of the industry, House Report at 7, and that EPA correctly determined in 2016 that the source types and emissions found in the transmission and storage segment are sufficiently similar to production and processing as to justify regulating these segments in a single source category. Id. The Senate Statement was also explicit that the 2020 Policy Rule erred in rescinding NSPS for sources in the transmission and storage segment: [T]he resolution clarifies our intent that EPA should regulate methane and other pollution emissions from all oil and gas sources, including production, processing, transmission, and storage segments under the authority of section 111 of the CAA. In addition, we intend that section 111 . . . obligates and provides EPA with the legal authority to regulate existing sources of methane emissions in all of these segments. Senate Statement at S2283 (paragraphing revised). b. Regulation of Methane—Redundancy The House Report and Senate Statement made clear Congress’s view that in light of the large amount of methane emissions from oil and gas sources and their impact on global climate, the EPA must regulate those E:\FR\FM\15NOP2.SGM 15NOP2 63150 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules emissions under section 111. House Report at 5; Senate Statement at S2283. Both pieces of legislative history specifically rejected the 2020 Policy Rule’s rescission of the methane NSPS. House Report at 7; Senate Statement at S2283. Moreover, the legislative history specifically rejected the statutory interpretations of section 111 that formed the bases of EPA’s 2020 rationales for rescinding the methane NSPS. House Report at 7–10; see Senate Statement at S2283; see 85 FR 57033, 57035–38 (September 14, 2020). The House Report began by recognizing the critical importance of regulating methane emissions from oil and gas sources, emphasizing both the potency of methane in driving global warming, and the massive amounts of methane emitted each year by the oil and gas industry. House Report at 3–4. The House Report was clear that the amount of these emissions and their impact compelled regulatory action. Id. at 5. The Senate Statement was equally clear: khammond on DSKJM1Z7X2PROD with PROPOSALS2 [M]ethane is a leading contributing cause of climate change. It is 28 to 36 times more powerful than carbon dioxide in raising the Earth’s surface temperature when measured over a 100–year time scale and about 84 times more powerful when measured over a 20–year timeframe. Industrial sources emit GHG in great quantities, and methane emissions from all segments of the Oil and Gas Industry are especially significant in their contribution to overall emissions levels and surface temperature rise. . . . In fact, with the congressional adoption of this resolution, we encourage EPA to strengthen the standards we reinstate and aggressively regulate methane and other pollution emissions from new, modified, and existing sources throughout the production, processing, transmission, and storage segments of the Oil and Gas Industry under section 111 of the Clean Air Act. The welfare of our planet and of our communities depend on it. Senate Statement at S2283. Turning to the 2020 Policy Rule, the House Report rejected the rule’s position that the methane NSPS were redundant to the VOC NSPS, and therefore unnecessary. House Report at 7. The House Report rejected the 2020 Policy Rule’s ‘‘redundancy’’ rationale, explaining that in the 2016 NSPS OOOOa, the EPA had consciously ‘‘formulated [the two sets of NSPS so as] to impose the same requirements for the same types of equipment,’’ and that the co-extensive nature of the NSPS mean that ‘‘sources could comply with them in an efficient manner,’’ not that the NSPS were redundant. Id. The House report further rejected the 2020 Policy Rule’s assertion that it need not take VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 into account the implications of regulating methane for existing sources, calling it a ‘‘fundamental misinterpretation of section 111, and the critical importance of section 111(d) in Congress [sic: Congress’s] scheme.’’ House Report at 8 & n. 27 (The EPA’s 2020 ‘‘misinterpretation . . . was glaring and enormously consequential’’ because it precluded regulation of methane from existing sources). The House Report emphasized that ‘‘existing sources emit the vast majority of methane in the oil and gas sector,’’ id. and pointed out that while the 2016 NSPS ‘‘covered roughly 60,000 wells constructed since 2015[, t]here are more than 800,000 existing wells in operation. . . .’’Id. n.28. The Senate Statement also made clear that the resolution of disapproval ‘‘reaffirms that the CAA requires EPA to act to protect Americans from sources of . . . methane,’’ ‘‘reject[s] the [2020 Policy Rule’s] misguided legal interpretations,’’ and ‘‘clarifies our intent that EPA should regulate methane . . . from all oil and gas sources. . . .’’ Senate Statement at 2283. c. Regulation of Methane—Significant Contribution Finding The legislative history was explicit that, contrary to the EPA’s statutory interpretation in the 2020 Policy Rule, section 111 of the CAA, by its plain language, does not require, or authorize the EPA to require, as a prerequisite for promulgating NSPS for a particular air pollutant from a listed source category, a separate finding by the EPA that emissions of the pollutant from the source category contribute significantly to dangerous air pollution. House Report at 9–10; Senate Statement at S2283. The House Report rejected this interpretation. It made clear that instead, consistent with the EPA’s statements in the 2016 NSPS OOOOa and the plain language of the CAA, section 111 requires that the agency must make a SCF only at ‘‘the first step of the process, the listing of the source category,’’ and further requires that this finding ‘‘must apply to the impact of the ‘category of sources’ on ‘air pollution’ ’’ as opposed to individual pollutants. House Report at 9. The House Report went on to explain that this provision ‘‘does not require the EPA to make a SCF for individual air pollutants emitted from the source category, nor does it even mention individual air pollutants,’’ id. at 9. The House Report went on to explain in some detail the meaning that the EPA should give to section 111, which, consistent with the 2016 Rule, is that section 111 authorizes the agency to promulgate NSPS for PO 00000 Frm 00042 Fmt 4701 Sfmt 4702 particular pollutants as long as it has a rational basis for doing so. House Report at 8–9. The report explained that after the EPA lists a source category for regulation under section 111(b)(1)(A), it is required to determine for which pollutants to promulgate NSPS, and this determination is subject to CAA section 307(d)(9)(A) (‘‘In the case of review of any [EPA] action . . . to which [section 307(d)] applies, the court may reverse any such action found to be arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law’’).156 The Report further noted that the U.S. Supreme Court affirmed this interpretation in American Electric Power Co. Inc. v. Connecticut, 564 U.S. 410, 427 (2011) (American Electric Power) (‘‘EPA may not decline to regulate carbon-dioxide emissions from powerplants if refusal to act would be ‘arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law’’ (citing section 307(d)(9)(A)). The Report went on to note that the 2016 NSPS OOOOa had stated that the EPA was authorized to promulgate a NSPS for a particular pollutant if it had a ‘‘rational basis’’ for doing so, and the Report emphasized that this ‘‘rational basis’’ standard is ‘‘fully consistent with’’ the arbitrary and capricious standard under section 307(d)(9)(A) of the CAA. House Report at 9.157 The House Report further explained that, in contrast, the 2020 Policy Rule’s statutory interpretation of section 111 to require a pollutant-specific SCF as a predicate for promulgating NSPS was foreclosed by ‘‘the plain language of’’ section 111—noting that this interpretation ignored the distinction between the text of section 111 and that of other CAA provisions which do explicitly require a pollutant-specific cause-or-contribution finding. Id. at 10. Moreover, the Report added, ‘‘[g]iven that the statute is not ambiguous, the EPA cannot interpret section 111 to authorize the EPA to exercise discretion to require . . . a pollutant-specific SCF as a predicate for promulgating a [NSPS] for the pollutant.’’ Id. at 10. The Report went on to note several other supports for its statutory interpretation, including the legislative history of section 111. Id. at 10–11. The Senate Statement took the same approach, stating: ‘‘we do not intend that section 111 of [the] CAA requires EPA to make a pollutant-specific 156 Section 307(d) applies to the promulgation of NSPS, under section 307(d)(1)(C). 157 The House Report dismissed the 2020 Policy Rule’s criticism of the rational basis test as unduly vague by noting that a court could enforce it. House Report at 11. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 significant contribution finding before regulating emissions of a new pollutant from a listed source category. . . .’’ Senate Statement at S2283.158 The House Report also expressly disapproved of the 2020 Policy Rule’s interpretation of section 111 to require that the SCF must be based on some ‘‘identif[ied] standard or established set of criteria,’’ and not the facts-andcircumstances approach that EPA has used in making that finding for the source category. House Report at 10–11; see 2020 Policy Rule at 57038. The Report stated, ‘‘[i]t is fully appropriate for EPA to exercise its discretion to employ a facts-and-circumstances approach, particularly in light of the wide range of source categories and the air pollutants they emit that EPA must regulate under section 111.’’ House Report at 11. Finally, in reinstating the methane regulations, the legislative history for the CRA resolution clearly expressed the intent that the EPA proceed with regulation of existing sources. The House Report was explicit in this regard, stating that ‘‘[p]assage of the resolution of disapproval indicates Congress’ support and desire to immediately reinstate . . . EPA’s statutory obligation to regulate existing oil and natural gas sources under [CAA] section 111(d).’’ House Report at 3; see id. at 11–12. The report added that upon enactment of the resolution of disapproval, ‘‘the Committee strongly encourages the EPA to take swift action to . . . fulfill its statutory obligation to issue existing source guidelines under [CAA] section 111(d).’’ Id. The Senate Statement was substantially similar. Senate Statement at S2283 (‘‘By adopting this resolution of disapproval, it is our view that Congress reaffirms that the CAA requires EPA to act to protect Americans from sources of climate pollution like methane, which endangers the public’s health and welfare. . . . [W]e intend that [CAA] section 111 . . . obligates and provides EPA with the legal authority to regulate existing sources of methane emissions in [the Crude Oil and Natural Gas source category].’’). 158 Both the House Report and the Senate Statement recognized that EPA could, if it chose to, make a finding that a particular pollutant contributes significantly to dangerous air pollution, in order, for example, to inform the public about the risks of a pollutant. House Report at 10, Senate Statement at S2283. However, the House Report made clear that ‘‘it is the rational basis determination as to the risk a pollutant poses to endangerment of human health or welfare [and not any such SCF] that remains the statutory basis for the EPA’s action.’’ House Report at 10. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 B. Effect of Congress’s Disapproval of the 2020 Policy Rule Under the CRA, the disapproved 2020 Policy Rule is ‘‘treated as though [it] had never taken effect.’’ 5 U.S.C. 801(f). As a result, the preceding regulation, the 2016 NSPS OOOOa rule, was automatically reinstated, and treated as though it had never been revised by the 2020 Policy Rule. Moreover, the CRA bars EPA from promulgating ‘‘a new rule that is substantially the same as’’ a disapproved rule. 5 U.S.C. 801(b)(2), for example, a rule that deregulates methane emissions from the production and processing sectors or deregulates the transmission and storage sector entirely. The legislative history of the CRA gives further content to Congress’s disapproval and the bar on substantially similar rulemaking. The legislative history rejected the EPA’s statutory interpretations of section 111 in the 2020 Policy Rule and endorsed the legal interpretations contained in the 2016 NSPS OOOOa rule. Specifically, Congress expressed its intent that the transmission and storage segment be included in the source category, that sources in that segment remain subject to NSPS, and that all oil and gas sources be subject to NSPS for methane emissions.159 The EPA is now proceeding to propose additional requirements to reduce emissions from oil and gas sources, consistent with the statutory factors the EPA is required to consider under section 111 and with section 111’s overarching purpose of protecting against pollution that endangers health and welfare. While the reinstatement of the 2016 Rule through the CRA joint resolution of disapproval provides the predicate for this action, the EPA notes that, for the reasons discussed next, the EPA would reject the positions concerning legal interpretations taken in the 2020 Policy Rule and reaffirm the positions the Agency took in the 2016 Rule even absent the CRA resolution. The EPA provides this information for the purposes of informing the public and is not re-opening these positions for comment. C. Affirming the Legal Interpretations in the 2016 NSPS OOOOa Rule The Agency has reviewed all of the information and analyses in the 2016 159 See generally ‘‘Federal-State Unemployment Compensation Program; Establishing Appropriate Occupations for Drug Testing of Unemployment Compensation Applicants Under the Middle-Class Tax Relief and Job Creation Act of 2012: Final Rule,’’ 84 FR 53037, 53083 (Oct. 4, 2019) (citing legislative history of CRA resolution disapproving prior rule in explaining scope of new rule). PO 00000 Frm 00043 Fmt 4701 Sfmt 4702 63151 NSPS OOOOa and 2020 Policy Rule, and fully reaffirms the positions it took in the 2016 Rule and rejects the positions taken in the 2020 Policy Rule.160 For this rulemaking, the EPA has reviewed its prior actions, along with newly available information, including recent information concerning the dangers posed by climate change and the impact of methane emissions, as described in section III above. Based on this review, the EPA affirms the statutory interpretations underlying the 2016 Rule and rejects the different interpretations informing the congressionally voided 2020 Policy Rule. This section explains the EPA’s views. These views are confirmed by Congress’s reasoning in the legislative history of the CRA resolution and so, for convenience, this section occasionally refers to that legislative history. In particular, the EPA reaffirms that the Crude Oil and Natural Gas Source Category appropriately includes the transmission and storage segment, along with the production and processing segments. The EPA has broad discretion in determining the scope of the source category, and the 2016 Rule correctly identified the most important aspect of the industry, which is the interrelatedness of the segments and their common purpose in completing the multi-step process to prepare natural gas for marketing. 81 FR 35832, June 3, 2016. The 2020 Policy Rule’s objection that the chemical composition of natural gas changes as it moves from the production and processing segments to the transmission and storage segment, 85 FR 57028, September 14, 2020, misses the mark because in every segment methane predominates and the refining of natural gas in the processing segment, which is what changes its chemical composition, is appropriately viewed simply as one of the steps in the marketing of the gas. Further, while it is true that some of the equipment in each segment differs from the equipment in the other segments, as the 2020 Policy Rule pointed out, 85 FR 57029 (September 14, 2020), that too simply results from the fact that the segments represent different steps in the process of preparing natural gas for marketing. The more salient fact is that most of the polluting equipment, such as storage 160 Under F.C.C. v. Fox Television Stations, Inc., 556 U.S. 502 (2009), an agency may revise its policy, but must demonstrate that the new policy is permissible under the statute and is supported by good reasons, taking into account the record of the previous rule. To the extent that this standard applies in this action—where Congress has disapproved the 2020 Policy Rule—the EPA believes the explanations provided here satisfy the standard. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63152 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules vessels, pneumatic pumps, and compressors, are found throughout the segments and emit the same pollutants that can be controlled by the same techniques and technologies, 81 FR 35832 (June 3, 2016), underscoring the interrelated functionality of the segments and the appropriateness of regulating them together as part of a single source category. The scope of the source category as defined in 2016, and proposed to be affirmed in this rule, is well within the reasonable bounds of the EPA’s past practice in defining source categories, which sometimes even contain sources that are located in multiple distinct industries. See 40 CFR part 60, subpart Db (industrialcommercial-institutional steam generating units), 40 CFR part 60, subpart IIII (stationary compression ignition internal combustion engines). In this regard, the House Report correctly noted that ‘‘even the presence of large distinctions in equipment type and emissions profile across two segments would not necessarily preclude EPA from regulating those segments as a single source category, so long as the EPA could identify some meaningful relationship between them,’’ House Report at 7, as the EPA did in the 2016 Rule. Thus, the 2020 Policy Rule failed to articulate appropriate reasons to change the scope of the source category from what the EPA determined in the 2016 Rule. Having properly identified the scope of the source category as including the transmission and storage segment in the 2016 Rule, the EPA lawfully promulgated NSPS for sources in that segment. The EPA also affirms that the 2016 Rule established an appropriate basis for promulgating methane NSPS from oil and gas sources, and that the 2020 Policy Rule erred on all grounds in rescinding the methane NSPS. The importance of taking action at this time, in accordance with the requirements of CAA section 111, to reduce the enormous amount of methane emissions from oil and gas sources, in light of the impacts on the climate of this pollution, cannot be overstated. As stated in section I, the Oil and Natural Gas Industry is the largest industrial emitter of methane in the U.S. Human emissions of methane, a potent GHG, are responsible for about one third of the warming due to well-mixed GHGs, the second most important human warming agent after carbon dioxide. According to the IPCC, strong, rapid, and sustained methane reductions are critical to reducing near-term disruption of the climate system and a vital complement to CO2 reductions critical in limiting the VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 long-term extent of climate change and its destructive impacts.161 The EPA previously determined, in the 2016 NSPS OOOOa rule, both that it had a rational basis to regulate methane emissions from the source category, and, in the alternative, that methane emissions from the Crude Oil and Natural Gas Source Category, contribute significantly to dangerous air pollution. 81 FR 35842–43, (June 3, 2016). The EPA is not reopening those determinations for comment in the present rulemaking. Contrary to the statements in the 2020 Policy Rule, the methane NSPS promulgated in the 2016 Rule cannot be said to be redundant with the VOC NSPS and therefore unnecessary. The large contribution of methane emissions from the source category to dangerous air pollution driving the grave and growing threat of climate change means that, in the agency’s judgment, it would be highly irresponsible and also arbitrary and capricious under CAA section 307(d)(9)(A) for the EPA to decline to promulgate NSPS for methane emissions from the source category. See American Electric Power, 564 U.S. at 426–27. The fact that the EPA designed the methane NSPS so that sources could comply with them efficiently, through the same actions that the sources needed to take to comply with the VOC NSPS, did not thereby create redundancy. Further, the fact that methane NSPS but not the VOC NSPS trigger the regulatory requirements for existing sources makes clear that the two sets of requirements are not redundant. Indeed, if EPA had only regulated VOCs, it would only have been authorized to regulate new and modified sources, which comprise a small subset of polluting sources. By contrast, because the 2016 Rule also regulated methane, EPA was authorized and obligated to regulate hundreds of thousands of additional ‘‘existing’’ sources that comprise the vast majority of polluting sources. Accordingly, methane regulation was not ‘‘redundant’’ of VOC regulation. The 2020 Policy Rule’s contrary position was based on a misinterpretation of CAA section 111 which overlooked that the provision integrates requirements for new and existing sources. See Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433 n.48 (D.C. Cir. 1980) (CAA section 111(b)(1)(A) listing of a source category 161 See preamble section III for further discussion on the Crude Oil and Natural Gas Emissions and Climate Change, including discussion of the GHGs, VOCs and SO2 Emissions on Public Health and Welfare. PO 00000 Frm 00044 Fmt 4701 Sfmt 4702 is based on emissions from new and existing sources). The EPA also reaffirms the 2016 Rule’s statutory interpretation that the EPA is authorized to promulgate a NSPS for an air pollutant under CAA section 111(b)(1)(B) in a situation in which the EPA has previously determined that the source category causes or contributes significantly to dangerous air pollution and where the EPA has a rational basis for regulating the particular air pollutant in question that is emitted by the source category. 81 FR 35842 (June 3, 2016). The 2016 Rule noted the precedent in prior agency actions for the position that—following the listing of a source category—the EPA need provide only a rational basis for its exercise of discretion for which pollutants to regulate under section 111(b)(1)(B). See id. (citing National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) (court discussed, but did not review, the EPA’s reasons for not promulgating standards for NOX, SO2, and CO from lime plants). In addition, the Supreme Court in American Electric Power provided support for the rational basis statutory interpretation. 564 U.S. at 426–27 (‘‘EPA [could] decline to regulate carbon-dioxide emissions altogether at the conclusion of its . . . [CAA section 111] rulemaking,’’ and such a decision ‘‘would not escape judicial review,’’ under the ‘‘arbitrary and capricious’’ standard of section 307(d)(9)(A)). As the House Report noted, the EPA’s rational basis interpretation ‘‘is fully consistent with the provision[s] of section 111 and the section 307(d)(9) ‘arbitrary and capricious’ standard.’’ House Report at 9. The 2020 Policy Rule correctly noted that the CAA section 111(b)(1)(B) requirement that the EPA ‘‘shall promulgate . . . standards [of performance]’’ for air pollutants, coupled with the CAA section 111(a)(1) definition for ‘‘standard of performance’’ as, in relevant part, a ‘‘standard for emissions of air pollutants,’’ does not by its terms require that EPA promulgate NSPS for every air pollutant from the source category. But the rule erred in seeking to graft the CAA section 111(b)(1)(A) requirement for a SCF into CAA section 111(b)(1)(B). The language of CAA section 111(b)(1)(A) is clear: It requires the EPA Administrator to ‘‘include a category of sources in [the list for regulation] if in his judgment it causes, or contributes to, air pollution which may reasonably be anticipated to endanger public health or welfare.’’ (Emphasis added.) Congress thus specified that the required SCF is made E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules on a category basis, not a pollutantspecific basis, and that once that finding is made (as it was for the Crude Oil and Natural Gas source category in 1979), the EPA may establish standards for pollutants emitted by the source category. In determining for which air pollutants to promulgate standards of performance, the EPA must act rationally, which, as noted above, essentially must ensure that the action does not fail the ‘‘arbitrary and capricious’’ standard under CAA section 307(d)(9)(A). The 2020 Policy Rule’s objections to the rational basis standard on grounds that is ‘‘vague and not guided by any statutory criteria,’’ 85 FR 57034 (September 14, 2020), is incorrect. In making a rational basis determination, the EPA has considered the amount of the air pollutant emitted by the source category, both in absolute terms and by drawing comparisons, as well as the availability of control technologies. See National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) (discussing EPA’s reasons for not promulgating standards for NOX, SO2 and CO from lime plants); 80 FR 64510, 64530 (October 23, 2015) (rational basis determination for GHGs from fossil fuel-fired electricity generating power plants); 73 FR 35838, 35859–60 (June 24, 2008) (providing reasons why the EPA was not promulgating GHG standards for petroleum refineries). Courts routinely review rules under the ‘‘arbitrary and capricious’’ standard, as noted in the House Report, at 11. When the EPA is required to make an endangerment finding, the EPA also affirms that that finding should be made in consideration of the particular facts and circumstances, not a predetermined threshold. Accordingly, the EPA rejects the 2020 Policy Rule’s position to the contrary. Section 111(b)(1)(A) of the CAA does not require that the SCF for the source category be based on ‘‘established criteria’’ or ‘‘standard or threshold.’’ See Coal. for Responsible Regulation, Inc. v. EPA, 684 F.3d 102, 122–23 (D.C. Cir. 2012) (‘‘the inquiry [into whether an air pollutant endangers] necessarily entails a case-bycase, sliding-scale approach. . . . EPA need not establish a minimum threshold of risk or harm before determining whether an air pollutant endangers’’). During the 50 years that it has made listing decisions, the EPA has always relied on the individual facts and circumstances. See Alaska Dep’t of Envtl. Conservation, 540 U.S. 461, 487 (2004) (explaining, in a case under the CAA, ‘‘[w]e normally accord particular deference to an agency interpretation of VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 longstanding duration’’ (internal quotation marks omitted) (citing Barnhart v. Walton, 535 U.S. 212, 220 (2002)). This approach is appropriate because Congress intended that CAA section 111 apply to a wide range of source categories and pollutants, from wood heaters to emergency backup engines to petroleum refineries. In that context, it reasonable to interpret section 111 to allow EPA the discretion to determine how best to assess significant contribution and endangerment based on the individual circumstances of each source category. On this point, as well, the EPA is in full agreement with the statements in the House Report. House Report at 9–10. Finally, under CAA section 111(d)(1), once the EPA promulgates NSPS for certain air pollutants, including GHGs, the EPA is required to promulgate regulations, which the EPA terms EG, 40 CFR 60.22a, that in turn require States to promulgate standards of performance for existing sources of those air pollutants. The EPA agrees with the House Report and Senate statement that it is imperative to regulate methane emissions from the existing oil and gas sources that comprise the vast majority of polluting sources expeditiously under the authority of CAA section 111(d) and is proceeding with the process to do so in this rulemaking by publishing proposed EG. See section III.B.2. In 2019, the GHGI estimates for oil and natural gas production, and natural gas processing and transmission and storage segments that methane emissions equate to 182 MMT CO2 Eq.162 In the U.S. the EPA has identified over 15,000 oil and gas owners and operators, around 1 million producing onshore oil and gas wells, about 5,000 gathering and boosting facilities, over 650 natural gas processing facilities, and about 1,400 transmission compression facilities. Some stakeholders have raised issues concerning the scope of pollutants subject to CAA section 111(d) by arguing that the exclusion in CAA 162 The 100-year GWP value of 25 for methane indicates that one ton of methane has approximately as much climate impact over a 100year period as 25 tons of CO2. The most recent IPCC AR6 assessment has estimated a slightly larger 100year GWP of methane of almost 30 (specifically, either 27.2 or 29.8 depending on whether the value includes the CO2 produced by the oxidation of methane in the atmosphere). As mentioned earlier, because methane has a shorter lifetime than CO2, the emissions of a ton of methane will have more impact earlier in the 100-year timespan and less impact later in the 100-year timespan relative to the emissions of a 100-year GWP-equivalent quantity of CO2. See preamble section III for further discussion on the Crude Oil and Natural Gas Emissions and Climate Change, including discussion of the GHGs, VOCs and SO2 Emissions on Public Health and Welfare. PO 00000 Frm 00045 Fmt 4701 Sfmt 4702 63153 section 111(d) for HAP covers not only those pollutants listed for regulation under CAA section 112, but also precludes the EPA from regulating a source category under CAA section 111(d) for any pollutant if that source category has been regulated under CAA section 112. The EPA agrees with its longstanding legal interpretation spanning multiple Administrations that the 111(d) exclusion does not preclude the agency from regulating a non-HAP pollutant from a source category under section 111(d) even if that source category is regulated under section 112. See American Lung Ass’n v. EPA, 980 F.3d 914, 980 (D.C. Cir. 2019) (referring to ‘‘EPA’s three-decade-old . . . reading of the statutory amendments’’), petition for cert. pending No. 20–1530 (filed April 29, 2021); 70 FR 15994, 16029 (March 29, 2005) (Clean Air Mercury Rule); 80 FR 64662, 64710 (Oct. 23, 2015) (Clean Power Plan); 84 FR 32520 (July 8, 2019) (Affordable Clean Energy Rule). The House Report agreed with this interpretation, noting that the contrary position is flawed because it ignores the overall statutory structure that Congress created in the CAA and would create regulatory gaps in which the EPA would not be able to regulate existing sources for some pollutants (such as methane) under CAA section 111(d) if those sources (but not pollutants) were already regulated for different pollutants under CAA section 112. House Report at 11–12. Moreover, the D.C. Circuit recently considered this precise issue and held that the EPA may both regulate a source category for HAP under CAA section 112 and regulate that same source category for different pollutants under CAA section 111(d). Am. Lung Assoc., 985 F.3d at 977–988. Accordingly, both Congress and the court have come to the same conclusion after reviewing the statutory language, a conclusion that is aligned with the EPA’s longstanding position. We therefore proceed in the proposal to propose EGs for existing sources in the oil and gas source category. IX. Overview of Control and Control Costs A. Control of Methane and VOC Emissions in the Crude Oil and Natural Gas Source Category—Overview As described in this action, the EPA reviewed the standards in the 2016 NSPS OOOOa pursuant to CAA section 111(b)(1)(B). Based on this review, the EPA is proposing revisions to the standards for a number of affected facilities to reflect the updated BSER for those affected facilities. Where our analyses show that the BSER for an E:\FR\FM\15NOP2.SGM 15NOP2 63154 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 affected facility remains the same, the EPA is proposing to retain the current standard for that affected facility. In addition to the actions on the standards in the 2016 NSPS OOOOa described in this section, the EPA is proposing standards for GHGs (in the form of limitation on methane) and VOCs for a number of new sources that are currently unregulated. The proposed NSPS OOOOb would apply to new, modified, and reconstructed emission sources across the Crude Oil and Natural Gas source category for which construction, reconstruction, or modification is commenced after November 15, 2021. Further, pursuant to CAA section 111(d), the EPA is proposing EG, which include presumptive standards for GHGs (in the form of limitations on methane) (designated pollutant), for certain existing emission sources across the Crude Oil and Natural Gas source category in the proposed EG OOOOc. While the proposed requirements in NSPS OOOOb would apply directly to new sources, the proposed requirements in EG OOOOc are for States to use in the development of plans that establish standards of performance that will apply to existing sources (designated facilities). B. How does EPA evaluate control costs in this action? Section 111 of the CAA requires that the EPA consider a number of factors, including cost, in determining ‘‘the best system of emission reduction . . . adequately demonstrated.’’ CAA section 111(a)(1). The D.C. Circuit has long recognized that ‘‘[CAA] section 111 does not set forth the weight that [ ] should [be] assigned to each of these factors;’’ therefore, ‘‘[the court has] granted the agency a great degree of discretion in balancing them.’’ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) (‘‘Lignite Energy Council’’). In Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973) (‘‘Essex Chemical’’), the court noted that ‘‘it is not unlikely that the industry and the EPA will disagree on the economic costs of various control techniques’’ and that it ‘‘has no desire or special ability to settle such a dispute.’’ Id. at 437. Rather, the court focused its review on ‘‘whether the standards as set are the result of reasoned decision-making.’’ Id. at 434. A standard that ‘‘is the result of the exercise of reasoned discretion by the Administrator [ ] cannot be upset by this Court.’’ Id. at 437. As noted, CAA section 111 requires that the EPA consider cost in determining such system (i.e., ‘‘BSER’’), but it does not prescribe any criteria for VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 such consideration. The courts have recognized that the EPA has ‘‘considerable discretion under [CAA] section 111,’’ Lignite Energy Council, 198 F.3d at 933, on how it considers cost under CAA section 111(a)(1). For example, in Essex Chemical, the D.C. Circuit stated that to be ‘‘adequately demonstrated,’’ the system must be ‘‘reasonably reliable, reasonably efficient, and . . . reasonably expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.’’ 486 F.2d at 433. The court has reiterated this limit in subsequent case law, including Lignite Energy Council, in which it stated: ‘‘EPA’s choice will be sustained unless the environmental or economic costs of using the technology are exorbitant.’’ 198 F.3d at 933. In Portland Cement Association v. Train, the court elaborated by explaining that the inquiry is whether the costs of the standard are ‘‘greater than the industry could bear and survive.’’ 163 513 F.2d 506, 508 (D.C. Cir. 1975). In Sierra Club v. Costle, the court provided a substantially similar formulation of the cost factor: ‘‘EPA concluded that the Electric Utilities’ forecasted cost was not excessive and did not make the cost of compliance with the standard unreasonable. This is a judgment call with which we are not inclined to quarrel.’’ 657 F.2d 298, 343 (D.C. Cir. 1981). We believe that these various formulations of the cost factor— ‘‘exorbitant,’’ ‘‘greater than the industry could bear and survive,’’ ‘‘excessive,’’ and ‘‘unreasonable’’—are synonymous; the D.C. Circuit has made no attempt to distinguish among them. For convenience, in this rulemaking, we will use the term ‘‘reasonable’’ to describe that our evaluation of costs is well within the boundaries established by this case law. In evaluating whether the cost of a control is reasonable, the EPA considers various costs associated with such control, including capital costs and operating costs, and the emission reductions that the control can achieve. As discussed further below, the agency considers these costs in the context of the industry’s overall capital expenditures and revenues. Costeffectiveness analysis is also a useful 163 The 1970 Senate Committee Report on the Clean Air Act stated: ‘‘The implicit consideration of economic factors in determining whether technology is ‘available’ should not affect the usefulness of this section. The overriding purpose of this section would be to prevent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach.’’ S. Comm. Rep. No. 91–1196 at 16. PO 00000 Frm 00046 Fmt 4701 Sfmt 4702 metric, and a means of evaluating whether a given control achieves emission reduction at a reasonable cost. A cost-effectiveness analysis also allows comparisons of relative costs and outcomes (effects) of two or more options. In general, cost-effectiveness is a measure of the outcomes produced by resources spent. In the context of air pollution control options, costeffectiveness typically refers to the annualized cost of implementing an air pollution control option divided by the amount of pollutant reductions realized annually. A cost-effectiveness analysis is not intended to constitute or approximate a benefit-cost analysis in which monetized benefits are compared to costs, but rather provides a metric to compare the relative cost and emissions impacts of various control options. The estimation and interpretation of cost-effectiveness values is relatively straightforward when an abatement measure is implemented for the purpose of controlling a single pollutant, such as for the controls included as presumptive standards in the proposed EG OOOOc to address methane emissions from existing sources in the Crude Oil and Natural Gas source category. In other circumstances, air pollution reduction programs require reductions in emissions of multiple pollutants, as with the NSPS for the Crude Oil and Natural Gas source category, which regulates both GHG and VOC. In such cases, multipollutant controls (controls that achieve reductions of both pollutants through the same techniques and technologies) may be employed, and consequently, there is a need for determining cost-effectiveness for a control option across multiple pollutants (or classes of multiple pollutants). During the rulemaking for NSPS OOOOa, we evaluated a number of approaches for considering the costeffectiveness of the available multipollutant controls for reducing both methane and VOC emissions. See 80 FR 56593, 56616 (September 18, 2015). In that rulemaking, we used two approaches for considering the costeffectiveness of control options that reduce both VOC and methane emissions; we are proposing to use these same two cost-effectiveness approaches, along with other factors discussed further below, in considering the cost of requiring control for the proposed NSPS OOOOb. One approach, which we refer to as the ‘‘single pollutant costeffectiveness approach,’’ assigns all costs to the emission reduction of one pollutant and zero to all other concurrent reductions. If the cost is reasonable for reducing any of the E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules targeted pollutants alone, the cost of such control is clearly reasonable for the concurrent emission reduction of all the other regulated pollutants because they are being reduced at no additional cost. While this approach assigns all costs to only a portion of the emission reduction and thus may overstate the cost for that assigned portion, it does not overstate the overall cost. Instead, it acknowledges that the reductions of the other regulated pollutant are intended as opposed to incidental. This approach is simple and straightforward in application: If the multipollutant control is cost effective for reducing emissions of either of the targeted pollutants, it is clearly cost effective for reducing all other targeted emissions that are being achieved simultaneously. A second approach, which we term for the purpose of this rulemaking a ‘‘multipollutant cost-effectiveness approach,’’ apportions the annualized cost across the pollutant reductions addressed by the control option in proportion to the relative percentage reduction of each pollutant controlled. In the case of the Crude Oil and Natural Gas source category, both methane and VOC are reduced in equal proportions, relative to their respective baselines by the multipollutant control option (i.e., where control is 95 percent reduction, methane and VOC are both simultaneously reduced by 95 percent by the multipollutant control). As a result, under the multipollutant costeffectiveness approach, half of the control costs are allocated to methane and the other half to VOC. Under this approach, control is cost effective if it is cost effective for both VOC and methane. We believe that both the single pollutant and multipollutant costeffectiveness approaches discussed above are appropriate for assessing the reasonableness of the multipollutant controls considered in this action for new sources. As such, in the individual BSER analyses in section XII below, if a device is cost-effective under either of these two approaches, we find it to be cost-effective. The EPA has considered similar approaches in the past when considering multiple pollutants that are controlled by a given control option.164 The EPA recognizes, however, not all situations where multipollutant controls are applied are the same, and that other types of approaches might be appropriate in other instances. 164 See, e.g., 73 FR 64079–64083 and EPA Document I.D. EPA–HQ–OAR–2004–0022–0622, EPA–HQ–OAR–2004–0022–0447, EPA–HQ–OAR– 2004–0022–0448. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 As mentioned above, as part of its consideration of control costs in the individual BSER analyses in Section XII, the EPA evaluated costeffectiveness using the single pollutant and multipollutant cost-effectiveness approaches. We estimated the costeffectiveness values of the proposed control options using available information, including various studies, information submitted in previous rulemakings from the affected industry, and information provided by small businesses. The EPA provides the cost effectiveness estimates for reducing VOC and methane emissions for various control options considered in section XII. As discussed in that section, the EPA finds cost-effectiveness values up to $5,540/ton of VOC reduction to be reasonable for controls that we have identified as BSER in this proposal. These VOC values are within the range of what the EPA has historically considered to represent cost effective controls for the reduction of VOC emissions, including in the 2016 NSPS, based on the Agency’s long history of regulating a wide range of industries. With respect to methane, the EPA finds the cost-effectiveness values up to $1,800/ton of methane reduction to be reasonable for controls that we have identified as BSER in this proposal. Unlike VOC, the EPA does not have a long regulatory history to draw upon in assessing the cost effectiveness of controlling methane, as the 2016 NSPS OOOOa was the first national standard for reducing methane emissions. However, as explained below, the EPA has previously determined that methane cost-effectiveness values for the controls identified as BSER for the 2016 NSPS OOOOa, which range up to $2,185/ton of methane reduction, represent reasonable costs for the industry as a whole to bear; and because the costeffectiveness estimates for the proposed standards in this action are comparable to the cost-effectiveness values estimated for the controls that served as the basis (i.e., BSER) for the standards in the 2016 NSPS OOOOa, we consider the proposed standards to also be cost effective and reasonable. The BSER determinations from the 2016 NSPS OOOOa also support the EPA’s conclusion that the costeffectiveness values associated with the proposed standards in this action are reasonable. As mentioned above, for 2016 NSPS OOOOa, the highest estimate that the EPA considered cost effective for methane reduction was $2,185/ton, which was the estimate for converting a natural gas driven diaphragm pump to an instrument air PO 00000 Frm 00047 Fmt 4701 Sfmt 4702 63155 pump at a gas processing plant. 165 166 80 FR 56627; see also, NSPS OOOOa Final TSD at 93, Table 6–7. The EPA estimated that the cost-effectiveness of this option, a common practice at gas processing plants, could be up to $2,185/ton of methane reduction under the single pollutant cost-effectiveness approach and $1,093/ton under the multipollutant cost effectiveness approach; the EPA found ‘‘the control to be cost effective under either approach.’’ Id. Accordingly, the EPA finalized requirements in the 2016 NSPS OOOOa that require zero emissions from diaphragm pumps at gas processing plants, consistent with the Agency’s BSER determination. The 2016 NSPS OOOOa also requires 95 percent methane and VOC emission reduction from wet-seal centrifugal compressors. The BSER for this standard was capturing and routing the emissions to a control combustion device, a widely used control in the oil and gas sector for reducing emissions from storage vessels and pumps, in addition to centrifugal compressors. 80 FR 56620. The EPA estimated costeffectiveness values of up to $1,093/ton of methane reduction for this option. See NSPS OOOOa Final TSD at 114, Table 7–9. With respect to other controls identified as BSER in the 2016 NSPS OOOOa, their cost-effectiveness estimates were comparable to or well below the estimates from the 2016 NSPS OOOOa rulemaking discussed above. In light of this, and because sources have been complying with the 2016 NSPS OOOOa for years, we believe that the cost-effectiveness values for the controls 165 As discussed in section X.A, the EPA incorrectly stated in the 2020 Technical Rule that $738/ton of methane reduction was the highest cost-effectiveness value that the EPA determined to be reasonable for methane reduction in the 2016 NSPS OOOOa. 166 While in that rulemaking the EPA found quarterly monitoring of fugitive emissions at well sites not cost effective at $1,960/ton of methane reduced using the single pollutant approach (and $980 using the multi-pollutant approach), the EPA emphasized that this conclusion was not intended to ‘‘preclude the EPA from taking a different approach in the future including requiring more frequent monitoring (e.g., quarterly).’’ 81 FR 35855– 6 referencing Background Technical Support Document for the New Source Performance Standards 40 CFR part 60 subpart OOOOa (May 2016), at 49, Table 4–11 and 52, Table 4–14. Further, several states have issued regulations and industry has voluntarily taken steps to reduce emissions. This combined with greater knowledge and understanding of the industry leads us to find these values cost-effective. As discussed in this section IX.B, cost-effectiveness is one—not the only—factor in EPA’s consideration of control costs. In fact, in this action, the EPA is proposing different monitoring frequencies based on well site baseline emissions, even though the EPA found quarterly monitoring to be cost effective for all well sites. Please see section XII.A for a detailed discussion on this proposal. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63156 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules identified as BSER for the 2016 NSPS OOOOa, which range up to $2,185/ton of methane reduction, represent reasonable, rather than excessive, costs for the industry as a whole to bear. As shown in the individual BSER analyses in Section XII and the NSPS OOOOb and EG OOOOc TSD for this proposal, the cost-effectiveness values for the proposed standards in this action are comparable to the cost-effectiveness values for the standards in NSPS OOOOa. We, therefore, similarly consider the cost-effectiveness values for the proposed standards to be reasonable. That the proposed standards reflect the kinds of controls that many companies and sources around the country are already implementing underscore the reasonableness of these control measures. In addition to evaluating the annual average cost-effectiveness of a control option, the EPA also considers the incremental costs associated with increasing the stringency of the standards from one level of control to another level of control that achieves more emission reductions. The incremental cost of control provides insight into how much it costs to achieve the next increment of emission reductions through application of each increasingly stringent control options, and thus is a useful tool for distinguishing among the effects of more and less stringent control options. For example, during the rulemaking for the 2012 NSPS OOOO, the EPA considered the incremental cost effectiveness of changing the originally promulgated standards for leaks at gas processing plants, which were based on NSPS subpart VV, to the more stringent NSPS subpart VVa-level program. See 76 FR 52738, 52755 (August 23, 2011). The EPA generally finds the incremental cost-effectiveness to be reasonable if it is consistent with the costs that the Agency considers reasonable in its evaluation of annual average costeffectiveness. As shown in the NSPS OOOOb and EG OOOOc TSD for this action, the EPA estimated control costs both with and without savings from recovered gas that would otherwise be emitted. When determining the overall costs of implementation of the control technology and the associated costeffectiveness, the EPA reasonably takes into account any expected revenues from the sale of natural gas product that would be realized as a result of avoided emissions that result from implementation of a control. Such a sale would offset regulatory costs and so should be included to accurately assess the overall costs and the cost- VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 effectiveness of the standard. In our analysis we consider any natural gas that is either recovered or that is not emitted as a result of a control option as being ‘‘saved.’’ We estimate that one thousand standard cubic feet (Mcf) of natural gas is valued at $3.13 per Mcf.167 Our cost analysis then applies the monetary value of the saved natural gas as an offset to the control cost.168 This offset applies where, in our estimation, the monetary savings of the natural gas saved can be realized by the affected facility owner or operator and not where the owner or operator does not own the gas and would not likely realize the monetary value of the natural gas saved (e.g., transmission stations and storage facilities). Detailed discussions of these assumptions are presented in section 2 of the RIA associated with this action, which is in the docket. We also completed two additional analyses to further inform our determination of whether the cost of control is reasonable, similar to compliance cost analyses we have completed for other NSPS.169 First, we compared the capital costs that would be incurred to comply with the proposed standards to the industry’s estimated new annual capital expenditures. This analysis allowed us to compare the capital costs that would be incurred to comply with the proposed standards to the level of new capital expenditures that the industry is incurring in the absence of the proposed standards. We then determined whether the capital costs appear reasonable in comparison to the industry’s current level of capital spending. Second, we compared the annualized costs that would be incurred to comply with the standards to the industry’s estimated annual revenues. This analysis allowed us to evaluate the annualized costs as a percentage of the revenues being generated by the industry. The EPA has evaluated incremental capital costs in a manner similar to the analyses described above in prior new source performance standards, and in those prior standards, the Agency’s 167 This value reflects the forecasted Henry Hub price for 2022 from: U.S. Energy Information Administration. Short-Term Energy Outlook. https://www.eia.gov/outlooks/steo/archives/ may21.pdf. Release Date: May 11, 2021. 168 While the EPA presents cost-effectiveness with and without cost savings, the BSER is determined based on the cost-effectiveness without cost savings in all cases. 169 For example, see our compliance cost analysis in ‘‘Regulatory Impact Analysis (RIA) for Residential Wood Heaters NSPS Revision. Final Report.’’ U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards. EPA– 452/R–15–001, February 2015. PO 00000 Frm 00048 Fmt 4701 Sfmt 4702 determinations that the costs were reasonable were upheld by the courts. For example, the EPA estimated that the costs for the 1971 NSPS for coal-fired electric utility generating units were $19 million for a 600 MW plant, consisting of $3.6 million for particulate matter controls, $14.4 million for sulfur dioxide controls, and $1 million for nitrogen oxides controls, representing a total 15.8 percent increase in capital costs above the $120 million cost of the plant.170 See 1972 Supplemental Statement, 37 FR 5767, 5769 (March 21, 1972). The D.C. Circuit upheld the EPA’s determination that the costs associated with the final 1971 standard were reasonable, concluding that the EPA had properly taken costs into consideration. Essex Chemical, 486 F. 2d at 440. Similarly, in Portland Cement Association v. Ruckelshaus, the D.C. Circuit upheld the EPA’s consideration of costs for a standard of performance that would increase capital costs by about 12 percent, although the rule was remanded due to an unrelated procedural issue. 486 F.2d 375, 387–88 (D.C. Cir. 1973). Reviewing the EPA’s final rule after remand, the court again upheld the standards and the EPA’s consideration of costs, noting that ‘‘[t]he industry has not shown inability to adjust itself in a healthy economic fashion to the end sought by the Act as represented by the standards prescribed.’’ Portland Cement Assn. v. Train, 513 F. 2d at 508. In this action, for the capital expenditures analysis, we divide the nationwide capital expenditures projected to be spent to comply with the proposed standards by an estimate of the total sector-level new capital expenditures for a representative year to determine the percentage that the nationwide capital cost requirements under the proposal represent of the total capital expenditures by the sector. We combine the compliance-related capital costs under the proposed standards for the NSPS and for the presumptive standards in the proposed EG to analyze the potential aggregate impact of the proposal. The EAV of the projected compliance-related capital expenditures over the 2023 to 2035 period is projected to be about $510 million in 2019 dollars. We obtained new capital 170 Assuming these costs were denominated in 1971 dollars, converting the costs from 1971 to 2019 dollars using the Gross Domestic Product-Implicit Price Deflator, the costs for the 1971 NSPS for coalfired electric utility generating units were $94 million for a 600 MW plant, consisting of $18 million for particulate matter controls, $71 million for sulfur dioxide controls, and $5 million for nitrogen oxides controls, representing a 15.8 percent increase in capital costs above the $590 million cost of the plant. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 expenditure data for relevant NAICS codes for 2018 from the U.S. Census 2019 Annual Capital Expenditures Survey.171 Estimates of new capital expenditures are available for 2019, but we chose to use 2018 because the 2019 new capital expenditure data for pipeline transportation of natural gas (NAICS 4862) are withheld to avoid disclosing data for individual enterprises, and the withholding of that NAICS causes the totals for 2019 to be lower than for 2018. According to these data, new capital expenditures for the sector in 2018 were about $155 billion in 2019 dollars. Comparing the EAV of the projected compliance-related capital expenditures under the proposal with the 2018 total sector-level new capital expenditures yields a percentage of about 0.3 percent, which is well below the percentage increase previously upheld by the courts, as discussed above. For the comparison of compliance costs to revenues, we use the EAV of the projected compliance costs without and with projected revenues from product recovery under the proposal for the 2023 to 2035 period then divided the nationwide annualized costs by the annual revenues for the appropriate NAICS code(s) for a representative year to determine the percentage that the nationwide annualized costs represent of annual revenues. Like we do for capital expenditures, we combine the costs projected to be expended to comply with the standards for NSPS and the presumptive standards in the proposed EG to analyze the potential aggregate impact of the proposal. The EAV of the associated increase in compliance cost over the 2023 to 2035 period is projected to be about $1.2 billion without revenues from product recovery and about $760 million with revenues from product recovery (in 2019 dollars). Revenue data for relevant NAICS codes were obtained from the U.S. Census 2017 County Business Patterns and Economic Census, the most recent revenue figures available.172 According to these data, 2018 receipts for the sector were about $358 billion in 2019 dollars. Comparing the EAV of the projected compliance costs under the proposal with the sector-level receipts 171 U.S. Census Bureau, 2019 Annual Capital Expenditures Survey, Table 4b. Capital Expenditures for Structures and Equipment for Companies With Employees by Industry: 2018 Revised, https://www.census.gov/econ/aces/ index.html, accessed September 4, 2021. 172 2017 County Business Patterns and Economic Census. The Number of Firms and Establishments, Employment, Annual Payroll, and Receipts by Industry and Enterprise Receipts Size: 2017, https:// www.census.gov/programs-surveys/susb/data/ tables.2017.html, accessed September 4. 2021. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 figure yields a percentage of about 0.3 percent without revenues from product recovery and about 0.2 percent with revenues from product recovery. More data and analysis supporting the comparison of capital expenditures and annualized costs projected to be incurred under the rule and the sectorlevel capital expenditures and receipts is presented in Chapter 15 of the TSD for this action, which is in the public docket. In considering the costs of the control options evaluated in this action, the EPA estimated the control costs under various approaches, including annual average cost-effectiveness and incremental cost-effectiveness of a given control. The EPA also performed two broad comparisons to consider the costs of control: First, we compared the projected compliance-related capital expenditures to recent sector-level capital expenditures; second, we compared the projected total compliance costs to recent sector-level annual revenues. In its costeffectiveness analyses, the EPA recognized and took into account that these multi-pollutant controls reduce both VOC and methane emissions in equal proportions, as reflected in the single-pollutant and multipollutant cost effectiveness approaches. The EPA also considered cost saving from the natural gas recovered instead of vented due to the proposed controls. Based on all of the considerations described above, the EPA concludes that the costs of the controls that serve as the basis of the standards proposed in this action are reasonable. The EPA solicits comment on its approaches for considering control costs, as well as the resulting analyses and conclusions. X. Summary of Proposed Action for NSPS OOOOa As described above in sections IV and VIII, the 2020 Policy Rule rescinded all NSPS regulating emissions of VOC and methane from sources in the natural gas transmission and storage segment of the Oil and Natural Gas Industry and NSPS regulating methane from sources in the industry’s production and processing segments. As a result, the 2020 Technical Rule only amended the VOC standards for the production and processing segments in the 2016 NSPS OOOOa, because those were the only standards that remained at the time that the 2020 Technical Rule was finalized. The 2020 Technical Rule included amendments to address a range of technical and implementation issues in response to administrative petitions for reconsideration and other issues brought to the EPA’s attention since PO 00000 Frm 00049 Fmt 4701 Sfmt 4702 63157 promulgating the 2016 NSPS. These included, among other issues, those associated with the implementation of the fugitive emissions requirements and pneumatic pump standards, provisions to apply for the use of an AMEL, provisions for determining applicability of the storage vessel standards, and modification to the engineer certifications. In 2018, the EPA proposed amendments to address these technical issues for both the methane and VOC standards in the 2016 NSPS OOOOa, and in some instances for sources in the transmission and storage segment. 83 FR 52056, October 15, 2018. However, because the methane standards and all standards for the transmission and storage segment were removed via the 2020 Policy Rule prior to the finalization of the 2020 Technical Rule, the final amendments in the 2020 Technical Rule apply only to the 2016 NSPS OOOOa VOC standards for the production and processing segments. Additionally, the 2020 Policy Rule amended the 2012 NSPS OOOO to remove the VOC requirements for sources in the transmission and storage segment, but the Technical Rule did not amend the 2012 NSPS OOOO. Under the CRA, a rule that is subject to a joint resolution of disapproval ‘‘shall be treated as though such rule had never taken effect.’’ 5 U.S.C. 801(f)(2). Thus, because it was disapproved under the CRA, the 2020 Policy Rule is treated as never having taken effect. As a result, the requirements in the 2012 NSPS OOOO and 2016 NSPS OOOOa that the 2020 Policy Rule repealed (i.e., the VOC and methane standards for the transmission and storage segment, as well as the methane standards for the production and processing segments) must be treated as being in effect immediately upon enactment of the joint resolution on June 30, 2021. Any new, reconstructed, or modified facility that would have been subject to the 2012 or 2016 NSPS (‘‘affected facility’’) but for the 2020 Policy Rule was subject to those NSPS as of that date. The CRA resolution did not address the 2020 Technical Rule; therefore, the amendments made in the 2020 Technical Rule, which apply only to the VOC standards for the production and processing segments in the 2016 NSPS OOOOa, remain in effect. As a result, sources in the production and processing segments are now subject to two different sets of standards:173 One 173 The only exception is storage vessels, for which the EPA did not promulgate methane standards in the 2016 NSPS OOOOa. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63158 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules for methane based on the 2016 NSPS OOOOa, and one for VOC that include the amendments to the 2016 NSPS OOOOa made in the 2020 Technical Rule. Sources in the transmission and storage segment are subject to the methane and VOC standards as promulgated in either the 2012 NSPS OOOO or the 2016 NSPS OOOOa, as applicable.174 The EPA recognizes that certain amendments made to the VOC standards in the 2016 NSPS OOOOa in the 2020 Technical Rule, which addressed technical and implementation issues in response to administrative petitions for reconsideration and other issues brought to the EPA’s attention since promulgating the 2016 NSPS OOOOa rule could also be appropriate to address similar implementation issues associated with the methane standards for the production and processing segments and the methane and VOC standards for the transmission and storage segment. In fact, as mentioned above, such revisions were proposed in 2018 but not finalized because these standards were removed by the 2020 Policy Rule prior to the EPA’s promulgation of the 2020 Technical Rule. In light of the above, the EPA is proposing to revise 40 CFR part 60, subpart OOOOa, to apply certain amendments made in the 2020 Technical Rule to the 2016 NSPS OOOOa for methane from the production and processing segments and/or the 2016 NSPS OOOOa for methane and VOC from the transmission and storage segment, as specified in this section. In this action, the EPA is proposing amendments to the 2016 NSPS OOOOa to (1) rescind the revisions to the VOC fugitive emissions monitoring frequencies at well sites and gathering and boosting compressor stations in the 2020 Technical Rule as those revisions were not supported by the record for that rule, or by our subsequent information and analysis, and (2) adjust other modifications made in the 2020 Technical Rule to address technical and implementation issues that result from the CRA disapproval of the 2020 Policy Rule. The EPA is not reopening any of these prior rulemakings for any other purpose in this proposed action. Specifically, the EPA is not reopening any of the determinations made in the 2012 NSPS OOOO. In the final rule for this action, the EPA will update the 174 For the EPA’s full explanation of its initial guidance to stakeholders on the impact of the CRA, please see https://www.epa.gov/system/files/ documents/2021-07/qa_cra_for_2020_oil_and_gas_ policy_rule.6.30.2021.pdf. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 NSPS OOOO and NSPS OOOOa regulatory text in the CFR to reflect the CRA resolution’s disapproval of the final 2020 Policy Rule, specifically, the reinstatement of the NSPS OOOO and NSPS OOOOa requirements that the 2020 Policy Rule repealed but that came back into effect immediately upon enactment of the CRA resolution. In accordance with 5 U.S.C. 553(b)(3)(B), the EPA is not soliciting comment on these updates. Moreover, the EPA is not reopening the methane standards as finalized in the 2016 NSPS OOOOa, except as to the specific issues discussed below, nor is the EPA reopening any other portions of the 2016 Rule. The EPA is also not reopening any determinations made in the 2020 Technical Rule, except as to the specific issues discussed below. Finally, the reopening of determinations made with respect to the VOC standards in the 2020 Technical Rule does not indicate any intent to also reopen the methane standards for the same affected facilities. A. Amendments to Fugitive Emissions Monitoring Frequency The EPA is proposing to repeal its amendments in the 2020 Technical Rule that (1) exempted low production well sites from monitoring fugitive emissions and (2) changed from quarterly to semiannual monitoring of VOC emissions at gathering and boosting compressor stations. The EPA has authority to reconsider a prior action ‘‘as long as ‘the new policy is permissible under the statute. . . , there are good reasons for it, and . . . the agency believes it to be better.’ ’’ FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515, 129 S. Ct. 1800, 173 L. Ed. 2d738 (2009). The 2016 NSPS OOOOa, as initially promulgated, required semiannual monitoring of VOC and methane emissions at all well sites, including low production well sites. It also required quarterly monitoring of compressor stations, including gathering and boosting compressor stations. After issuing the 2020 Policy Rule, which removed all methane standards applicable to the production and processing segments and all methane and VOC standards applicable to the transmission and storage segment, the EPA promulgated the 2020 Technical Rule that further amended the VOC standards in the production and processing segment. In particular, based on its revised cost analyses, the EPA exempted low production well sites from monitoring VOC fugitive emissions and changed the frequency of monitoring VOC fugitive emissions from PO 00000 Frm 00050 Fmt 4701 Sfmt 4702 quarterly to semiannually at gathering and boosting compressor stations. However, as a result of the CRA disapproval of the 2020 Policy Rule, the low production well sites and the gathering and boosting compressor stations continue to be subject to semiannual and quarterly monitoring of methane emissions respectively. While it is possible for these affected facilities to comply with both the VOC and methane monitoring standards that are now in effect, as compliance with the more stringent standard would be deemed compliance with the other, the EPA reviewed its decisions to amend the VOC monitoring frequencies for these affected facilities as well as the underlying record and, for the reasons explained below, no longer believe that the amendments are appropriate. Therefore, the EPA is proposing to repeal these amendments and restore the semiannual and quarterly monitoring requirements for low production well sites and gathering and boosting compressor stations, as originally promulgated in the 2016 NSPS OOOOa, for both methane and VOC. 1. Low Production Well Sites As mentioned above, low production well sites are subject to semiannual monitoring of fugitive methane emissions. The EPA is proposing to repeal the amendment in the 2020 Technical Rule exempting low production well sites from monitoring fugitive VOC emissions because the analysis for the 2020 Technical Rule supports retaining the semiannual monitoring requirement when regulating both VOC and methane emissions. While the 2020 Technical Rule amended only the VOC standards in the production and processing segments, the EPA evaluated both methane and VOC reductions in its final technical support document (TSD) (2020 TSD), including the costs associated with different monitoring frequencies under the multipollutant approach,175 which the EPA considers a reasonable approach when regulating multiple pollutants. As shown in the 2020 TSD, under the multipollutant approach, the cost of semiannual monitoring at low production well sites is $850 per ton of methane and $3,058 per ton of VOC reduced, both of which are well within the range of what the 175 For purposes of the multipollutant approach, we assume that emissions of methane and VOC are controlled at the same time, therefore, half of the cost is apportioned to the methane emission reductions and half of the cost is apportioned to VOC emission reductions. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 EPA considers to be cost effective.176 Nevertheless, the EPA stated in the 2020 Technical Rule that ‘‘even if we had not rescinded the methane standards in the 2020 Policy Rule, we would still conclude that fugitive emissions monitoring, at any of the frequencies evaluated, is not cost effective for low production well sites.’’ This statement, however, is inconsistent with the conclusions on what costs are reasonable for the control of methane emissions as discussed in this proposal in section IX. More importantly, as an initial matter, this statement was based on the EPA’s observation in the 2020 Technical Rule that the $850 per ton of methane reduced is ‘‘greater than the highest value for methane that the EPA determined to be reasonable in the 2016 NSPS subpart OOOOa,’’ which the EPA incorrectly identified as $738/ton; the record for the 2016 NSPS OOOOa shows that the EPA considered value as high as $2,185/ton to be cost effective for methane reduction. 80 FR 56627; see also, NSPS OOOOa Final TSD at 93, Table 6–7. Further, even with the incorrect observation, the EPA did not conclude in the 2020 Technical Rule that $850 per ton of methane reduced is therefore unreasonable. 85 FR 57420. In fact, the EPA reiterated its prior determination that ‘‘a cost of control of $738 per ton of methane reduced did not appear excessive,’’ and that value was only $112 less than the value that the EPA had incorrectly identified as the highest methane cost-effectiveness value from the 2016 NSPS OOOOa. As discussed above, in fact $738/ton is well within the costs that the EPA concludes to be reasonable in the 2016 NSPS OOOOa as well as in this document. Also, as explained in section XI.A.2, due to the wide variation in well characteristics, types of oil and gas products and production levels, gas composition, and types of equipment at well sites, there is considerable uncertainty regarding the relationship between the fugitive emissions and production levels. Accordingly, the EPA no longer believes that production levels provide an appropriate threshold for any exemption from fugitive monitoring. See section XI.A.2 for 176 See 2020 NSPS OOOOa Technical Rule TSD at Docket ID No. EPA–HQ–OAR–2017–0483–2291. See also section IX, which provides that the cost effectiveness values for the controls that we have identified as BSER in this action range from $2,200/ ton to $5,800/ton VOC reduction and $700/ton to $2,100/ton of methane reduction. As explained in that section, these controls reflect emission reduction technologies and methods that many owners and operators in the oil and gas industry have employed for years, either voluntarily or due to the 2012 and 2016 NSPS, as well as State or other requirements. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 additional discussion on the proposed emission thresholds for well site fugitive emissions in place of production-based model plants. In light of the above, the EPA is proposing to remove the exemption of low production well sites from fugitive VOC emissions monitoring, thereby restoring the semiannual monitoring requirement established in the 2016 NSPS OOOOa. 2. Gathering and Boosting Compressor Stations The EPA is proposing to repeal its amendment to the VOC monitoring frequency for gathering and boosting compressor stations in the 2020 Technical Rule because the EPA believes that amendment was made in error. In that rule, the EPA noted that, based on its revised cost analysis, quarterly monitoring has a cost effectiveness of $3,221/ton of VOC emissions and an incremental cost of $4,988/ton of additional VOC emissions reduced between the semiannual and quarterly monitoring frequencies. While the EPA observed that semiannual monitoring is more cost effective than quarterly, the EPA nevertheless acknowledged that ‘‘these values (total and incremental) are considered costeffective for VOC reduction based on past EPA decisions, including the 2016 rulemaking.’’ 85 FR 57421, September 15, 2020. The EPA instead identified two additional factors to support its decision to forgo quarterly monitoring. First, the EPA stated that the ‘‘Oil and Gas Industry is currently experiencing significant financial hardship that may weigh against the appropriateness of imposing the additional costs associated with more frequent monitoring.’’ However, the EPA did not offer any data regarding the financial hardship, significant or otherwise, the industry was experiencing. While the rule cited to several articles on the impact of COVID–19 on the industry, the EPA did not discuss any aspect of any of the cited articles that led to its conclusion of ‘‘significant financial hardship’’ on the industry. Nor did the EPA explain how reducing the frequency of a monitoring requirement that had been in effect since 2016 would meaningfully affect the industry’s economic circumstances in any way or weigh those considerations against the forgone emission reductions that would result from reducing monitoring frequency. Second, the EPA generally asserted that ‘‘there are potential efficiencies, and potential cost savings, with applying the same monitoring frequencies for well sites and compressor stations.’’ Again, the EPA did not describe what the potential PO 00000 Frm 00051 Fmt 4701 Sfmt 4702 63159 efficiencies are or the extent of cost savings that would justify forgoing quarterly monitoring, or weigh those efficiencies and cost savings against the forgone emission reductions that would result from reducing the monitoring frequency for compressor stations. Nor did we explain why the Agency’s 2016 BSER determination that quarterly monitoring was achievable and costeffective was incorrect in light of these asserted efficiencies. On the contrary, based on the compliance records for the 2016 NSPS OOOOa, there is no indication that compressor stations experienced hardship or difficulty in complying with the quarterly monitoring requirement. Further, as discussed in section XII.A.1.b, our analysis for NSPS OOOOb and EG OOOOc confirms that quarterly monitoring remains both achievable and cost-effective for compressor stations, and several State agencies also have rules that require quarterly monitoring at compressor stations. For the reasons stated above, the EPA concludes that it lacked justification and thus erred in revising the VOC monitoring frequency for gathering and boosting compressor stations from quarterly to semiannual. The EPA is therefore proposing to repeal that amendment, thereby restoring the quarterly monitoring requirement for gathering and boosting compressor stations, as established in the 2016 NSPS OOOOa. B. Technical and Implementation Amendments In the following sections, the EPA describes a series of proposed amendments to 2016 NSPS OOOOa for methane to align the 2016 methane standards with the current VOC standards (which were modified by the 2020 Technical Rule). We describe the supporting rationales that were provided in the 2020 Technical Rule for modifying the requirements applicable to the VOC standards, and explain why the amendments would also appropriately apply to the reinstated methane standards. 1. Well Completions In the 2020 Technical Rule, the EPA made certain amendments to the VOC standards for well completions in the 2016 NSPS OOOOa. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to apply the same amendments to the methane standards for well completions in the 2016 NSPS OOOOa. First, the EPA is proposing to amend the 2016 NSPS OOOOa methane standards for well completions to allow E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63160 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules the use of a separator at a nearby centralized facility or well pad that services the well affected facility during flowback, as long as the separator can be utilized as soon as it is technically feasible for the separator to function. The well completion requirements, as promulgated in 2016, had required that the owner or operator of a well affected facility have a separator on site during the entire flowback period. 81 FR 35901, June 3, 2016. In the 2020 Technical Rule, the EPA amended this provision to allow the separator to be at a nearby centralized facility or well pad that services the well affected facility during flowback as long as the separator can be utilized as soon as it is technically feasible for the separator to function. See 40 CFR 60.5375a(a)(1)(iii). As explained in that rulemaking (85 FR 57403) and previously in the 2016 NSPS OOOOa final rule preamble, ‘‘[w]e anticipate a subcategory 1 well to be producing or near other producing wells. We therefore anticipate reduced emission completion (REC) equipment (including separators) to be onsite or nearby, or that any separator brought onsite or nearby can be put to use.’’ 81 FR 35852, June 3, 2016. For the same reason, the EPA is proposing to make the same amendment to the methane standards for well completions. Additionally, the 2020 Technical Rule amended 40 CFR 60.5375a(a)(1)(i) to clarify that the separator that is required during the initial flowback stage may be a production separator as long as it is also designed to accommodate flowback. As explained in the preamble to the final 2020 Technical Rule, when a production separator is used for both well completions and production, the production separator is connected at the onset of the flowback and stays on after flowback and at the startup of production. 85 FR 57403, September 15, 2020. For the same reason, the EPA is proposing the same clarification apply to the methane standards for well completions. The 2020 Technical Rule also amended the definition of flowback. In 2016, the EPA defined ‘‘flowback’’ as the process of allowing fluids and entrained solids to flow from a well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production. Flowback also means the fluids and entrained solids that emerge from a well during the flowback process. The flowback period begins when material introduced into the well during the treatment returns to the surface following hydraulic fracturing or refracturing. The flowback period ends VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 when either the well is shut in and permanently disconnected from the flowback equipment or at the startup of production. The flowback period includes the initial flowback stage and the separation flowback stage. 81 FR 35934, June 3, 2016. The 2020 Technical Rule amended this definition by adding a clarifying statement that ‘‘[s]creenouts, coil tubing cleanouts, and plug drill-outs are not considered part of the flowback process.’’ 40 CFR 60.5430a. In the proposal for the 2020 Technical Rule, the EPA explained that screenouts, coil tubing cleanouts, and plug drill outs are functional processes that allow for flowback to begin; as such, they are not part of the flowback. 83 FR 52082, October 15, 2018. In conjunction with this amendment, the 2020 Technical Rule added definitions for screenouts, coil tubing cleanouts, and plug drill outs. See 40 CFR 60.5430a. Specifically, a screenout is an attempt to clear proppant from the wellbore in order to dislodge the proppant out of the well. A coil tubing cleanout is a process where an operator runs a string of coil tubing to the packed proppant within a well and jets the well to dislodge the proppant and provide sufficient lift energy to flow it to the surface. A plug drill-out is the removal of a plug (or plugs) that was used to isolate different sections of the well. For the reason stated above, the EPA is proposing to apply the definitions of flowback, screenouts, coil tubing cleanouts, and plug drill outs that were finalized in the 2020 Technical Rule to the methane standards for well completions in the 2016 NSPS OOOOa. Finally, the 2020 Technical Rule amended specific recordkeeping and reporting requirements for the VOC standards for well completions, and the EPA is proposing to apply these amendments to the methane standards for well completions in the 2016 NSPS OOOOa. For the reasons explained in 83 FR 52082, the 2020 Technical Rule requires that for each well site affected facility that routes flowback entirely through one or more production separators, owners and operators must record and report only the following data elements: • Well Completion ID; • Latitude and longitude of the well in decimal degrees to an accuracy and precision of five (5) decimals of a degree using North American Datum of 1983; • U.S. Well ID; • The date and time of the onset of flowback following hydraulic fracturing or refracturing or identification that the well immediately starts production; and PO 00000 Frm 00052 Fmt 4701 Sfmt 4702 • The date and time of the startup of production. While the 2020 Technical Rule removed certain reporting requirements (e.g., information about when a separator is hooked up or disconnected during flowback) as unnecessary or redundant, 85 FR 57403, the rule added a requirement that for periods where salable gas is unable to be separated, owners and operators must record and report the date and time of onset of flowback, the duration and disposition of recovery, the duration of combustion and venting (if applicable), reasons for venting (if applicable), and deviations. As explained in the preamble to the proposal for the 2020 Technical Rule, when a production separator is used for both well completions and production, the production separator is connected at the onset of the flowback and stays on after flowback and at the startup of production; in that event, certain reporting and recordkeeping requirements associated with well completions (e.g., information about when a separator is hooked up or disconnected during flowback) would be unnecessary. 83 FR 52082. Because these amendments to the recordkeeping and reporting requirements associated with well completion are independent of the specific pollutant being regulated, we are proposing these same amendments to the methane standards for well completions in the 2016 NSPS OOOOa. 2. Pneumatic Pumps In the 2020 Technical Rule, the EPA made certain amendments to the VOC standards for pneumatic pumps in the 2016 NSPS OOOOa. For the same reasons provided in the 2020 Technical Rule, along with further explanation provided below, the EPA is proposing to apply the same amendments to the methane standards for pneumatic pumps in the 2016 NSPS OOOOa. First, the EPA is proposing to amend the 2016 NSPS OOOOa methane standards for pneumatic pumps to expand the technical infeasibility provision to apply to pneumatic pumps at greenfield sites. Under the 2016 NSPS OOOOa, ‘‘emissions from new, modified, and reconstructed natural gasdriven diaphragm pumps located at well sites [must] be reduced by 95 percent if either a control device or the ability to route to a process is already available onsite, unless it is technically infeasible at sites other than new developments (i.e., greenfield sites).’’ 81 FR 35824 and 35844. For the 2016 NSPS OOOOa, the EPA concluded that circumstances that could otherwise make control of a pneumatic pump technically infeasible E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules at an existing location could be addressed in the design and construction of a greenfield site. 81 FR 35849 and 35850 (June 3, 2016). Concerns raised in petitions for reconsideration on the 2016 NSPS OOOOa explained that, even at greenfield sites, certain scenarios present circumstances where the control of a pneumatic pump may be technically infeasible despite the site being newly designed and constructed.177 These circumstances include, but are not limited to, site designs requiring high-pressure flares to which routing a low-pressure pump discharge is not feasible and use of small boilers or process heaters that are insufficient to control pneumatic pump emissions or that could result in safety trips and burner flame instability. The EPA proposed to extend the technical infeasibility exemption to greenfield sites in 2018 and sought comment on these circumstances that could preclude control of a pneumatic pump at greenfield sites. While the EPA received comments both in favor of and opposing the application of the technical infeasibility exemption to greenfield sites, the commenters did not identify a reasoned basis for the EPA to decline to extend the exemption. See Response to Comments (RTC) for 2020 Technical Rule at 5–1 to 5–4 at Docket ID No. EPA–HQ–OAR–2017–0483. Moreover, the EPA specifically sought information regarding the additional costs that would be incurred if owners and operators of greenfield sites were required to select a control that can accommodate pneumatic pump emissions in addition to the control’s primary purpose at a new construction site, but no such information was provided. The 2020 Technical Rule therefore expanded the technical infeasibility provision to apply to pneumatic pumps at all well sites, including new developments (greenfield sites), concluding that the extension was appropriate because the EPA identified circumstances where it may not be technically feasible to control pneumatic pumps at a greenfield site. The 2020 Technical Rule removed the reference to greenfield site in 40 CFR 60.5393a(b) and the associated definition of greenfield site at 40 CFR 60.5430a. In the final rule preamble for the 2016 NSPS OOOOa, the EPA stated we did not intend to require the installation of a control device at a well site for the sole purpose of controlling emissions 177 See proposal for 2020 Technical Rule at 83 FR 52061. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 from a pneumatic pump, but rather only required control of pneumatic pumps to the extent a control device or process would already be available on site. It is not the EPA’s intent to require a greenfield site to install a control device specifically for controlling emissions from a pneumatic pump. It is our understanding that sites are designed to maximize operation and safety. This includes the placement of equipment, such as control devices. Because vented gas from pneumatic pumps is at low pressure, it may not be feasible to move collected gas through a closed vent system to a control device, depending on site design. Therefore, the EPA continues to conclude that, when determining technical feasibility at any site, such a determination should consider the routing of pneumatic pump emissions to the controls which are needed for the other processes at the site (i.e., not the pneumatic pump). The owner or operator must justify and provide professional or in-house engineering certification for any site where the control of pneumatic pump emissions is technically infeasible. As explained in the RTC for the 2020 Technical Rule, ‘‘[t]he EPA believes that the requirement to certify an engineering assessment to demonstrate technical infeasibility provides protection against an owner or operator purposely designing a new site just to avoid routing emissions from a pneumatic pump to an onsite control device or to a process.’’ 178 For the reasons explained above, the EPA is proposing to align the methane standards in the 2016 NSPS OOOOa for controlling pneumatic pump emissions with the amendments made to the VOC standards in the 2020 Technical Rule to allow for a well-justified determination of technical infeasibility at all well sites, including greenfield sites. Second, the 2020 Technical Rule amended the 2016 NSPS OOOOa to specify that boilers and process heaters are not considered control devices for the purposes of the pneumatic pump standards. It is the EPA’s understanding, based on information provided in 178 See Docket ID No. EPA–HQ–OAR–2017– 0483–2291. ‘‘For example, consider the example provided by one commenter where a new site design requires only a high-pressure flare to control emergency and maintenance blowdowns and it is not feasible for a low-pressure pneumatic pump discharge to be routed to such a flare. The infeasibility determination would need not only demonstrate that it is not feasible for a low-pressure pneumatic pump discharge to be directly routed to the flare, it would also need to demonstrate that it is infeasible to design and install a low-pressure header to allow routing this discharge to such a flare system.’’ RTC at 5–4. PO 00000 Frm 00053 Fmt 4701 Sfmt 4702 63161 reconsideration petitions 179 submitted regarding the 2016 NSPS OOOOa and comments received on the proposal for the 2020 Technical Rule, that some boilers and process heaters located at well sites are not inherently designed for the control of emissions. While it is true that for some other sources (not pneumatic pumps), boilers and process heaters may be designed as control devices, that is generally not the operational purpose of this equipment at a well site. Instead, it is the EPA’s understanding that boilers and process heaters operate seasonally, episodically, or otherwise intermittently as process devices, thus making the use of these devices as controls inefficient and noncompliant with the continuous control requirements at 40 CFR 60.5415a.180 Further, as explained in the 2020 Technical Rule, the fact that some boilers and process heaters located at well sites are not inherently designed to control emissions means that ‘‘routing pneumatic pump emissions to these devices may result in frequent safety trips and burner flame instability (e.g., high temperature limit shutdowns and loss of flame signal).’’ Id. The EPA determined that ‘‘requiring the technical infeasibility evaluation for every boiler and process heater located at a wellsite would result in unnecessary administrative burden since each such evaluation would be raising the[se] same concerns.’’ 85 FR 57404 (September 15, 2020). Further, as described above, the EPA did not intend to require the installation of a control device for the sole purpose of controlling emissions from pneumatic pumps. Based on the EPA’s understanding that boilers and process heaters located at well sites are designed and operated as process equipment (meaning they are not inherently designed for the control of emissions), the EPA also does not intend to require their continuous operation solely to control emissions from pneumatic pumps either. Therefore, the EPA is proposing to align the methane standards for pneumatic pumps with the 2020 Technical Rule to specify that boilers and process heaters are not considered control devices for the purposes of controlling pneumatic pump emissions. The EPA solicits comment on this alignment, including whether there are specific examples where boilers and process heaters are 179 See Docket ID No. EPA–HQ–OAR–2017– 0483–0016. 180 See Docket ID No. EPA–HQ–OAR–2017– 0483–0016. E:\FR\FM\15NOP2.SGM 15NOP2 63162 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 currently used as control devices at well sites. Third, the EPA is proposing to align the certification requirements for the determination that it is technically infeasible to route emissions from a pneumatic pump to a control device or process. The 2016 NSPS OOOOa required certification of technical infeasibility by a qualified third-party Professional Engineer (PE); however, the 2020 Technical Rule allows this certification by either a PE or an inhouse engineer, because in-house engineers may be more knowledgeable about site design and control than a third-party PE. The EPA continues to believe that certification by an in-house engineer is appropriate for this purpose. We are, therefore, proposing to align the methane standards in the 2016 NSPS OOOOa with the 2020 Technical Rule to allow certification of technical infeasibility by either a PE or an inhouse engineer with expertise on the design and operation of the pneumatic pump. We are soliciting comment on this proposed alignment. 3. Closed Vent Systems (CVS) As in the 2020 Technical Rule, the EPA is proposing to allow multiple options for demonstrating that there are no detectable methane emissions from CVS. Additionally, the EPA is proposing to allow either a PE or an in-house engineer with expertise on the design and operation of the CVS to certify the design and operation will meet the requirement to route all vapors to the control device or back to the process. The methane standards in the 2016 NSPS OOOOa require that CVS be operated with no detectable emissions, as demonstrated through specific monitoring requirements associated with the specific affected facilities (i.e., pneumatic pumps, centrifugal compressors, reciprocating compressors, and storage vessels). Relevant here, the 2016 NSPS OOOOa required this demonstration for both VOC and methane emissions through annual inspections using EPA Method 21 for CVS associated with pneumatic pumps, while requiring storage vessels to conduct monthly audio, visual, olfactory (AVO) monitoring. The 2020 Technical Rule amended the VOC requirements for CVS for pneumatic pumps to align the requirements for pneumatic pumps and storage vessels by incorporating provisions allowing the option to demonstrate the pneumatic pump CVS is operated with no detectable emissions by either an annual inspection using EPA Method 21, monthly AVO monitoring, or OGI monitoring at the frequencies specified VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 for fugitive emissions monitoring. The EPA is proposing to amend the methane standards to allow pneumatic pump affected facilities to permit these same options to demonstrate no detectable methane emissions from CVS either using annual Method 21 monitoring, as currently required by the 2016 NSPS OOOOa, or using either monthly AVO monitoring or OGI monitoring at the fugitive monitoring frequency. The EPA considers these detection options appropriate for CVS associated with pneumatic pumps because any of the three would detect methane as well as VOC emissions. We incorporated the option for monthly AVO monitoring in the 2020 Technical Rule because pneumatic pumps and controlled storage vessels are commonly located at the same site and having separate monitoring requirements for a potentially shared CVS is overly burdensome and duplicative. 83 FR 52083 (October 15, 2018). We further incorporated the option for OGI monitoring because OGI is already being used for those sites that are subject to fugitive emissions monitoring and the CVS can readily be monitored during the fugitive emissions survey at no extra cost. 85 FR 57405. The EPA believes it is appropriate to maintain these options because not all well sites with controlled pneumatic pumps will be subject to fugitive emissions monitoring (e.g., pneumatic pumps located at existing well sites that have not triggered the fugitive monitoring requirements for new or modified well sites) and requiring either OGI or EPA Method 21 survey of the CVS for the pneumatic pump in the absence of fugitive emissions surveys would be unreasonable. It is possible for a new pneumatic pump to be subject to control at an existing well site that is not subject to the fugitive emissions requirements. Requiring either EPA Method 21 or OGI for the sole purpose of monitoring the CVS associated with the pneumatic pump would be too costly,181 therefore we continue to believe monthly AVO is an appropriate option for pneumatic pumps subject to the 2016 NSPS OOOOa. Additionally, the 2020 Technical Rule amended the 2016 NSPS OOOOa to 181 Both OGI and EPA Method 21 have significant capital and annual costs, including the cost of specialized equipment and trained operators of that equipment. While the costs of these programs are justified for well site fugitive emission monitoring based on the assumption of a high component count from which emissions would be controlled, the CVS is only one of those many components. Thus, where well site fugitive monitoring is not otherwise required, the cost-effectiveness of OGI or EPA Method 21 would be significantly higher for the CVS alone. PO 00000 Frm 00054 Fmt 4701 Sfmt 4702 allow certification of the design and operation of CVS by an in-house engineer with expertise on the design and operation of the CVS in lieu of a PE. This certification is necessary to ensure the design and operation of the CVS will meet the requirement to route all vapors to the control device or back to the process. As explained in the proposal for the 2020 Technical Rule, 83 FR 52079, the EPA allows CVS certification by either a PE or an in-house engineer because in-house engineers may be more knowledgeable about site design and control than a third-party PE. For the same reason, the EPA is proposing to amend the CVS requirements associated with methane emissions in the production and processing segments, and methane and VOC emissions in the transmission and storage segment, to allow certification of the design and operation of CVS by either a PE or an in-house engineer with expertise on the design and operation of the CVS. 4. Fugitive Emissions at Well Sites and Compressor Stations a. Well Sites The EPA is proposing to exclude from fugitive emissions monitoring a well site that is or later becomes a ‘‘wellhead only well site,’’ which the 2020 Technical Rule defines as ‘‘a well site that contains one or more wellheads and no major production and processing equipment.’’ The 2016 NSPS OOOOa excludes well sites that contain only one or more wellheads from the fugitive emissions requirements because fugitive emissions at such well sites are extremely low. 80 FR 56611. As explained in that rulemaking, ‘‘[s]ome well sites, especially in areas with very dry gas or where centralized gathering facilities are used, consist only of one or more wellheads, or ‘Christmas trees,’ and have no ancillary equipment such as storage vessels, closed vent systems, control devices, compressors, separators and pneumatic controllers. Because the magnitude of fugitive emissions depends on how many of each type of component (e.g., valves, connectors, and pumps) are present, fugitive emissions from these well sites are extremely low.’’ 80 FR 56611. The 2020 Technical Rule amended the 2016 NSPS OOOOa to exclude from fugitive emissions monitoring a well site that is or later becomes a ‘‘wellhead only well site,’’ which the 2020 Technical Rule defines as ‘‘a well site that contains one or more wellheads and no major production and processing equipment.’’ The 2020 Technical Rule defined ‘‘major production and processing equipment’’ E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 as including reciprocating or centrifugal compressors, glycol dehydrators, heater/ treaters, separators, and storage vessels collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water. We continue to believe that available information, including various studies,182 supports an exemption for well sites that do not have this major production and processing equipment. The 2020 Technical Rule allows certain small ancillary equipment, such as chemical injection pumps, pneumatic controllers used to control well emergency shutdown valves, and pumpjacks, that are associated with, or attached to, the wellhead and ‘‘Christmas tree’’ to remain at a ‘‘wellhead only well site’’ without being subject to the fugitive emissions monitoring requirements because they have very few fugitive emissions components that would leak, and therefore have limited potential for fugitive emissions. The emission reduction benefits of continuing monitoring at that point would be relatively low, and thus would not be cost-effective. For the reason stated above, the EPA is proposing to amend the 2016 NSPS OOOOa to allow monitoring of methane fugitive emissions to stop when a wellsite contains only wellhead(s) and no major production and processing equipment, as provided in the 2020 Technical Rule. b. Compressor Stations As discussed above, the 2016 NSPS OOOOa required quarterly monitoring of compressor stations for both VOC and methane emissions, and it also permitted waiver from one quarterly monitoring event when the average temperature is below 0 °F for two consecutive months because it is technically infeasible for the OGI camera (and EPA Method 21 instruments) to operate below this temperature. After the 2020 Policy Rule rescinded the methane standards, the 2020 Technical Rule reduced the monitoring requirements for the VOC standards to require only semiannual monitoring and, in doing so, removed the waiver. Upon enactment of the CRA resolution, compressor stations again became subject to quarterly monitoring pursuant to the reinstated 2016 NSPS OOOOa methane standards, and the waiver as it applied to the methane standards was also reinstated. Consistent with our proposal to align 182 See https://pubs.acs.org/doi/10.1021/ acs.est.0c02927, https://data.permianmap.org/ pages/flaring, and https://www.edf.org/sites/ default/files/documents/PermianMapMethodology_ 1.pdf. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 the monitoring requirements for VOCs with the monitoring requirements for methane, the EPA is also proposing to reinstate the waiver for the VOC standards as specified in the 2016 NSPS OOOOa. c. Well Sites and Compressor Stations on the Alaska North Slope The EPA is proposing to amend the 2016 NSPS OOOOa to require that new, reconstructed, and modified compressor stations located on the Alaska North Slope that startup (initially, or after reconstruction or modification) between September and March to conduct initial monitoring of methane emissions within 6 months of startup, or by June 30, whichever is later. The EPA made a similar amendment to the initial monitoring of methane and VOC emissions at well sites located on the Alaska North Slope in the March 12, 2018 amendments to the 2016 NSPS OOOOa (‘‘2018 NSPS OOOOa Rule’’).183 As explained in that action, such separate requirements were warranted due to the area’s extreme cold temperatures, which for approximately half of the year are below the temperatures at which the monitoring instruments are designed to operate. The 2020 Technical Rule made this amendment for VOC emissions from gathering and boosting compressor stations located in the Alaska North Slope for this same reason. The EPA is also proposing to amend the 2016 NSPS OOOOa to require annual monitoring of methane and VOC emissions at all compressor stations located on the Alaska North Slope, with subsequent annual monitoring at least 9 months apart but no more than 13 months apart. In the 2018 NSPS OOOOa Rule, the EPA similarly amended the monitoring frequency for well sites located on the Alaska North Slope to annual monitoring to accommodate the extreme cold temperature. 83 FR 10628 (March 12, 2018). For the same reason, in the 2020 Technical Rule, the EPA amended the 2016 NSPS OOOOa to require annual VOC monitoring at gathering and boosting compressor stations located on the Alaska North Slope because extreme cold temperatures make it technically infeasible to conduct OGI monitoring for over half of a year.184 Because the same 183 83 FR 10628 (March 12, 2018). Docket ID Nos. EPA–HQ–OAR–2010– 0505–7682 and EPA–HQ–OAR–2010–0505–12434. See also FLIR Systems, Inc. product specifications for GF300/320 model OGI cameras at https:// www.flir.com/ogi/display/?id=55671 and Thermo Fisher Scientific product specification for TVA– 2020 at https://assets.thermofisher.com/TFS-Assets/ LSG/Specification-Sheets/EPM-TVA2020.pdf. 184 See PO 00000 Frm 00055 Fmt 4701 Sfmt 4702 63163 difficulties would arise with respect to monitoring for fugitive methane emissions from gathering and boosting compressor stations or to monitoring of methane and VOC emissions from compressor stations in the transmission and storage segment, the EPA is proposing to amend the 2016 NSPS OOOOa to require that all compressor stations located on the Alaska North Slope conduct annual monitoring of both methane and VOC emissions. Further, the EPA is proposing to extend the deadline for conducting initial monitoring of both VOC and methane emissions from 60 days to 90 days for all well sites and compressor stations located on the Alaska North Slope that startup or are modified between April and August. In the 2020 Technical Rule, the EPA made this amendment for initial VOC monitoring to allow the well site or gathering and boosting compressor station to reach normal operating conditions. 85 FR 57406. For the same reason, we are proposing to further amend the 2016 NSPS OOOOa to apply this same 90-day initial monitoring requirement to initial monitoring of fugitive methane and VOC emissions from all well sites and compressor stations located on the Alaska North Slope that startup or are modified between April and August. d. Modification The 2016 NSPS OOOOa, as originally promulgated, provided that ‘‘[f]or purposes of the fugitive emissions standards at 40 CFR 60.5397a, [a] well site also means a separate tank battery surface site collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water from wells not located at the well site (e.g., centralized tank batteries).’’ 40 CFR 60.5430a. However, the original 2016 NSPS OOOOa defined ‘‘modification’’ only with respect to a well site and was silent on what constitutes modification to a well site that is a separate tank battery surface site. Specifically, 40 CFR 60.5365a(i), as promulgated in 2016, specified that, for the purposes of fugitive emissions components at a well site, a modification occurs when (1) a new well is drilled at an existing well site, (2) a well is hydraulically fractured at an existing well site, or (3) a well is hydraulically refractured at an existing well site. See 40 CFR 60.5365a(i). Because this provision was silent on when modification occurs at a well site that is a separate tank battery surface site, the 2020 Technical Rule added language to clarify that a modification of a well site that is a separate tank battery surface site occurs when (1) any of the actions listed above for well sites occurs E:\FR\FM\15NOP2.SGM 15NOP2 63164 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 at an existing separate tank battery surface site, (2) a well modified as described above sends production to an existing separate tank battery surface site, or (3) a well site subject to the fugitive emissions requirements removes all major production and processing equipment such that it becomes a wellhead-only well site and sends production to an existing separate tank battery surface site. Because the 2020 Technical Rule amended only the VOC standards in the 2016 NSPS OOOOa, and since this definition of modification equally applies to fugitive methane emissions from a separate tank battery surface site, the EPA is proposing to apply this definition of modification for purposes of determining when modification occurs at a separate tank battery surface site triggering the methane standards for fugitive emissions at well sites. e. Initial Monitoring for Well Sites and Compressor Stations The 2016 NSPS OOOOa, as originally promulgated, had required monitoring of methane and VOC fugitive emissions at well sites and compressor stations to begin within 60 days of startup (of production in the case of well sites) or modification. The 2020 Technical Rule extended this time frame to 90 days for well sites and gathering and boosting compressor stations in response to comments stating that well sites and compressor stations do not achieve normal operating conditions within the first 60 days of startup and suggesting that the EPA allow 90 days to 180 days. The EPA agreed that additional time to allow the well site or compressor station to reach normal operating conditions is warranted, considering the purpose of the initial monitoring is to identify any issues associated with installation and startup of the well site or compressor station. By providing sufficient time to allow owners and operators to conduct the initial monitoring survey during normal operating conditions, the EPA expects that there will be more opportunity to identify and repair sources of fugitive emissions, whereas a partially operating site may result in missed emissions that remain unrepaired for a longer period of time. 85 FR 57406. These same reasons apply regardless of pollutant or the location of the compressor station; therefore, the EPA is proposing to further amend the 2016 NSPS OOOOa to extend the deadline for conducting initial monitoring from 60 to 90 days for monitoring both VOC and methane fugitive emissions at all well sites and compressor stations (except those on the Alaska North Slope which are VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 separately regulated as discussed in section X.B.4.c). f. Repair Requirements The 2020 Technical Rule made certain amendments to the 2016 NSPS OOOOa repair requirements associated with monitoring of fugitive VOC emissions at well sites and gathering and boosting compressor stations. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly amend the 2016 NSPS OOOOa repair requirements associated with monitoring of methane emissions at well sites and gathering and boosting compressor stations and monitoring of VOC and methane fugitive emissions at compressor stations in the transmission and storage segment. Specifically, the EPA is proposing to require a first attempt at repair within 30 days of identifying fugitive emissions and final repair, including the resurvey to verify repair, within 30 days of the first attempt at repair. The 2016 NSPS OOOOa, as originally promulgated, required repair within 30 days of identifying fugitive emissions and a resurvey to verify that the repair was successful within 30 days of the repair. Stakeholders raised questions regarding whether emissions identified during the resurvey would result in noncompliance with the repair requirement. In the 2020 Technical Rule, the EPA clarified that repairs should be verified as successful prior to the repair deadline and added definitions for the terms ‘‘first attempt at repair’’ and ‘‘repaired.’’ Specifically, the definition of ‘‘repaired’’ includes the verification of successful repair through a resurvey of the fugitive emissions component. The EPA is similarly proposing to apply these amendments to the repair requirements made in the 2020 Technical Rule to the repair requirements associated with monitoring of methane emissions at well sites and gathering and boosting compressor stations as well as monitoring of VOC and methane fugitive emissions at compressor stations in the transmission and storage segment and monitoring. In addition, the EPA is proposing that delayed repairs be completed during the ‘‘next scheduled compressor station shutdown for maintenance, scheduled well shutdown, scheduled well shut-in, after a scheduled vent blowdown, or within 2 years, whichever is earliest.’’ The proposed amendment would clarify that completion of delayed repairs is required during scheduled shutdown for maintenance, and not just any shutdown. PO 00000 Frm 00056 Fmt 4701 Sfmt 4702 In 2018 NSPS OOOOa Rule the EPA amended the 2016 NSPS OOOOa to specify that, where the repair of a fugitive emissions component is ‘‘technically infeasible, would require a vent blowdown, a compressor station shutdown, a well shutdown or well shut-in, or would be unsafe to repair during operation of the unit, the repair must be completed during the next scheduled compressor station shutdown, well shutdown, well shut-in, after a planned vent blowdown, or within 2 years, whichever is earlier.’’ 185 During the rulemaking for the 2020 Technical Rule, the EPA received comments expressing concerns with requiring repairs during the next scheduled compressor station shutdown, without regard to whether the shutdown is for maintenance purposes. The commenters stated that repairs must be scheduled and that where a planned shutdown is for reasons other than scheduled maintenance, completion of the repairs during that shutdown may be difficult and disrupt gas transmission. The EPA agrees that requiring the completion of delayed repairs only during those scheduled compressor station shutdowns where maintenance activities are scheduled is reasonable and anticipates that these maintenance shutdowns occur on a regular schedule. Accordingly, in the 2020 Technical Rule the EPA further amended this provision by adding the term ‘‘for maintenance’’ to clarify that repair must be completed during the ‘‘next scheduled compressor station shutdown for maintenance’’ or other specified scheduled events, or within 2 years, whichever is the earliest. For the same reason, the EPA is proposing the same clarifying amendment to the delay of repair requirements for fugitive methane emissions at well sites and gathering and boosting compressor stations and fugitive VOC and methane fugitive emissions at compressor stations in the transmission and storage segment. g. Definitions Related to Fugitive Emissions at Well Sites and Compressor Stations The 2020 Technical Rule made certain amendments to the definition of a well site and the definition for startup of production as they relate to fugitive VOC emissions requirements at well sites. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly amend these definitions as they relate to the fugitive methane emissions requirements at well sites. 185 83 E:\FR\FM\15NOP2.SGM FR 10638, 40 CFR 60.5397a(h)(2). 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules The 2020 Technical Rule amended the definition of well site, for purposes of VOC fugitive emissions monitoring, to exclude equipment owned by third parties and oilfield solid waste and wastewater disposal wells. The amended definition for ‘‘well site’’ excludes third party equipment from the fugitive emissions requirements by excluding ‘‘the flange immediately upstream of the custody meter assembly and equipment, including fugitive emissions components located downstream of this flange.’’ To clarify this exclusion, the 2020 Technical Rule defines ‘‘custody meter’’ as ‘‘the meter where natural gas or hydrocarbon liquids are measured for sales, transfers, and/or royalty determination,’’ and the ‘‘custody meter assembly’’ as ‘‘an assembly of fugitive emissions components, including the custody meter, valves, flanges, and connectors necessary for the proper operation of the custody meter.’’ This exclusion was added for several reasons, including consideration that owners and operators may not have access or authority to repair this third-party equipment and because the custody meter ‘‘is used effectively as the cash register for the well site and provides a clear separation for the equipment associated with production of the well site, and the equipment associated with putting the gas into the gas gathering system.’’ 83 FR 52077 (October 15, 2018). The definition of a well site was also amended in the 2020 Technical Rule to exclude Underground Injection Control (UIC) Class I oilfield disposal wells and UIC Class II oilfield wastewater disposal wells. The EPA had proposed to exclude UIC Class II oilfield wastewater disposal wells because of our understanding that they have negligible fugitive VOC and methane emissions. 83 FR 52077. Comments received on the 2020 Technical rulemaking effort further suggested, and the EPA agreed, that we also should exclude UIC Class I oilfield disposal wells because of their low VOC and methane emissions. Both types of disposal wells are permitted through UIC programs under the Safe Drinking Water Act for protection of underground sources of drinking water. For consistency, the 2020 Technical Rule adopted the definitions for UIC Class I oil field disposal wells and UIC Class II oilfield wastewater disposal wells under the Safe Drinking Water Act definitions in excluding them from the definition of a well site in the 2016 NSPS OOOOa. Specifically, the 2020 Technical Rule defined a UIC Class I oilfield disposal well as ‘‘a well with a UIC Class I permit that meets the definition in 40 CFR VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 144.6(a)(2) and receives eligible fluids from oil and natural gas exploration and production operations.’’ Additionally, the 2020 Technical Rule defines a UIC Class II oilfield wastewater disposal well as ‘‘a well with a UIC Class II permit where wastewater resulting from oil and natural gas production operations is injected into underground porous rock formations not productive of oil or gas, and sealed above and below by unbroken, impermeable strata.’’ As amended, UIC Class I and UIC Class II disposal wells are not considered well sites for the purposes of VOC fugitive emissions requirements. Because the 2020 Technical Rule, as finalized, addressed only VOC emissions in the production and processing segment, the EPA is proposing the same exclusion and definition of ‘‘well site’’ for the purposes of fugitive emissions monitoring of methane emissions at well sites. The EPA is also proposing to apply the definition for ‘‘startup of production’’ for purposes of well site fugitive emissions requirements for VOC to these requirements as they relate to methane. The 2016 NSPS OOOOa initially contained a definition for ‘‘startup of production’’ as it relates to the well completion standards that reduce emissions from hydraulically fractured wells. For that purpose, the term was defined as ‘‘the beginning of initial flow following the end of flowback when there is continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate or produced water.’’ 81 FR 25936 (June 3, 2016). The 2020 Technical Rule amended the definition of ‘‘startup of production’’ to separately define the term as it relates to fugitive VOC emissions requirements at well sites. Specifically, ‘‘. . .[f]or the purposes of the fugitive monitoring requirements of 40 CFR 60.5397a, startup of production means the beginning of the continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate or produced water’’ 85 FR 57459 (September 15, 2020). This separate definition clarifies that fugitive emissions monitoring applies to both conventional and unconventional (hydraulically fractured) wells. For this same reason, the EPA is proposing to apply this same definition of ‘‘startup of production’’ to fugitive emissions monitoring of methane emissions at well sites. h. Monitoring Plan The 2016 NSPS OOOOa, as originally promulgated, required that each fugitive PO 00000 Frm 00057 Fmt 4701 Sfmt 4702 63165 emissions monitoring plan include a site map and a defined observation path to ensure that the OGI operator visualizes all of the components that must be monitored during each survey. The 2020 Technical Rule amended this requirement to allow the company to specify procedures that would meet this same goal of ensuring every component is monitored during each survey. While the site map and observation path are one way to achieve this, other options can also ensure monitoring, such as an inventory or narrative of the location of each fugitive emissions component. The EPA stated in the 2020 Technical Rule that ‘‘these company-defined procedures are consistent with other requirements for procedures in the monitoring plan, such as the requirement for procedures for determining the maximum viewing distance and maintaining this viewing distance during a survey.’’ 85 FR 57416 (September 15, 2020). Because the same monitoring device is used to monitor both methane and VOC emissions, the same company-defined procedures for ensuring each component is monitored are appropriate. Therefore, the EPA is proposing to similarly amend the monitoring plan requirements for methane and for compressor stations to allow company procedures in lieu of a sitemap and an observation path. i. Recordkeeping and Reporting The 2020 Technical Rule amended the 2016 NSPS OOOOa to streamline the recordkeeping and reporting requirements for the VOC fugitive emissions standards. The amendments removed the requirement to report or keep certain records that the EPA determined were redundant or unnecessary; in some instances, the rule replaced those requirements or added new requirements that could better demonstrate and ensure compliance, in particular where the underlying requirement was also amended (e.g., repair requirements). These amendments reflect consideration of the public comments received on the proposal for that rulemaking. The purpose and function of the recordkeeping and reporting requirements are equally applicable to methane and VOCs, and therefore, are not pollutant specific. For the same reasons the EPA streamlined these requirements in the 2020 Technical Rule,186 the EPA is proposing to apply these streamlined recordkeeping and reporting requirements for methane 186 See E:\FR\FM\15NOP2.SGM 85 FR 57415 (September 15, 2020). 15NOP2 63166 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 emissions from sources subject to NSPS OOOOa. For each collection of fugitive emissions components located at a well site or compressor station, the following amendments were made to the recordkeeping and reporting requirements in the 2020 Technical Rule: • Revised the requirements in 40 CFR 60.5397a(d)(1) to require inclusion of procedures that ensure all fugitive emissions components are monitored during each survey within the monitoring plan. • Removed the requirement to maintain records of a digital photo of each monitoring survey performed, captured from the OGI instrument used for monitoring when leaks are identified during the survey because the records of the leaks provide proof of the survey taking place. • Removed the requirement to maintain records of the number and type of fugitive emissions components or digital photo of fugitive emissions components that are not repaired during the monitoring survey once repair is completed and verified with a resurvey. • Required records of the date of first attempt at repair and date of successful repair. • Revised reporting to specify the type of site (i.e., well site or compressor station) and when the well site changes status to a wellhead-only well site. • Removed requirement to report the name or ID of operator performing the monitoring survey. • Removed requirement to report the number and type of difficult-to-monitor and unsafe-to-monitor components that are monitored during each monitoring survey. • Removed requirement to report the ambient temperature, sky conditions, and maximum wind speed. • Removed requirement to report the date of successful repair. • Removed requirement to report the type of instrument used for resurvey. 5. AMEL The 2020 Technical Rule made the following amendments to the provisions associated with applications for use of an AMEL for VOC work practice standards for well completions, reciprocating compressors, and the collection of fugitive emissions components located at well sites and gathering and boosting compressor stations. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly amend the 2016 NSPS OOOOa provisions associated with applications for use of an AMEL for VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 methane work practice standards at well sites and gathering and boosting compressor stations and VOC and methane work practice standards at compressor stations in the transmission and storage segment. The 2020 Technical Rule amended the AMEL application requirements to help streamline the process for evaluation and possible approval of advanced measurement technologies. The amendments included allowing submission of applications by, among others, owners and operators of affected facilities, manufacturers or vendors of leak detection technologies, or trade associations. The 2020 Technical Rule ‘‘allows any person to submit an application for an AMEL under this provision.’’ 85 FR 57422 (September 15, 2020). However, the 2020 Technical Rule, like the 2016 NSPS OOOOa still requires that the application include sufficient information to demonstrate that the AMEL achieves emission reductions at least equivalent to the work practice standards in the rule. To that end, the 2020 Technical Rule ‘‘requires applications for these AMEL to include site-specific information to demonstrate equivalent emissions reductions, as well as site-specific procedures for ensuring continuous compliance.’’ Id. At a minimum, the application should include field data that encompass seasonal variations, which may be supplemented with modeling analyses, test data, and/or other documentation. The specific work practice(s), including performance methods, quality assurance, the threshold that triggers action, and the mitigation thresholds are also required as part of the AMEL application. For example, for a technology designed to detect fugitive emissions, information such as the detection criteria that indicate fugitive emissions requiring repair, the time to complete repairs, and any methods used to verify successful repair would be required. Since the 2020 Technical Rule changes to the AMEL provisions in the 2016 NSPS OOOOa are procedural in the sense that they mostly speak to the ‘‘minimum information that must be included in each application in order for the EPA to make a determination of equivalency and, thus, be able to approve an alternative’’ the EPA believes that it is appropriate to retain those amendments. 85 FR 57422 (September 15, 2020). If finalized, the application must demonstrate equivalence as explained above for both the reduction of methane and VOC emissions. Because the 2020 Technical Rule amended only the VOC standards in the 2016 NSPS OOOOa, and since PO 00000 Frm 00058 Fmt 4701 Sfmt 4702 EPA believes that basis for promulgation of this provision for AMEL applications equally applies to work practices standards for methane emissions at facilities in the production and processing segments and VOC and methane emissions at facilities in the transmission and storage segment, the EPA is proposing to apply these application requirements for all applicants seeking an AMEL for the methane and VOC work practice standards in NSPS OOOOa. 6. Alternative Fugitive Emissions Standards Based on Equivalent State Programs The 2020 Technical Rule added a new section (at 40 CFR 60.5399a) which served two purposes. First, the new section outlined procedures for State, local, and Tribal authorities to seek the EPA’s approval of their VOC fugitive emissions standards at well sites and gathering and boosting compressor stations as an alternative to the Federal standards. Second, the new section approved specific voluntary alternative standards for six States. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly allow this new section to apply to fugitive emissions standards for methane fugitive emissions at well sites and gathering and boosting compressor stations, and VOC and methane fugitive emissions at compressor stations in the transmission and storage segment. The 2020 Technical Rule added this new section in part to allow the use of specific alternative fugitive emissions standards for VOC emissions for six State fugitive emissions programs that the EPA had concluded were at least equivalent to the fugitive emissions monitoring and repair requirements at 40 CFR 60.5397a(e), (f), (g), and (h) as amended in that rule.187 These approved alternative fugitive emissions standards may be used for certain individual well sites or gathering and boosting compressor stations that are subject to VOC fugitive emissions monitoring and repair so long as the source complies with specified Federal requirements applicable to each approved alternative State program and included in 40 CFR 60.5399a(f) through (n). For example, a well site that is subject to the requirements of Pennsylvania General Permit 5A, section G, effective August 8, 2018, could choose to comply with those 187 See memorandum, ‘‘Equivalency of State Fugitive Emissions Programs for Well Sites and Compressor Stations to Final Standards at 40 CFR part 60, subpart OOOOa,’’ located at Docket ID No. EPA–HQ–OAR–2017–0483. January 17, 2020. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules standards in lieu of the monitoring, repair, recordkeeping, and reporting requirements in the NSPS for fugitive emissions at well sites. However, in that example, the owner or operator must develop and maintain a fugitive emissions monitoring plan, as required in 40 CFR 60.5397a(c) and (d), and must monitor all of the fugitive emissions components, as defined in 40 CFR 60.5430a, regardless of the components that must be monitored under the alternative standard (i.e., under Pennsylvania General Permit 5A, Section G in the example). Additionally, the facility choosing to use the EPAapproved alternative standard must submit, as an attachment to its annual report for NSPS OOOOa, the report that is submitted to its State in the format submitted to the State, or the information required in the report for NSPS OOOOa if the State report does not include site-level monitoring and repair information. If a well site is located in the State but is not subject to the State requirements for monitoring and repair (i.e., not obligated to monitor or repair fugitive emissions), then the well site must continue to comply with the Federal requirements of the NSPS at 40 CFR 60.5397a in its entirety. In addition to providing the EPAapproved voluntary alternative fugitive emissions standards for well sites and gathering and boosting compressor stations located in California, Colorado, Ohio, Pennsylvania, and Texas, and well sites in Utah, the amendments in the 2020 Technical Rule provide application requirements to request the EPA approval of an alternative fugitive emissions standards as State, local, and Tribal programs continue to develop. Applications for the EPA approval of alternative fugitive emissions standards based on State, local, or Tribal programs may be submitted by any interested person, including individuals, corporations, partnerships, associations, States, or municipalities. Similar to the application process for AMEL for advanced measurement technologies, the application must include sufficient information to demonstrate that the alternative fugitive emissions standards achieve emissions reductions at least equivalent to the fugitive emissions monitoring and repair requirements in the Federal NSPS. At a minimum, the application must include the monitoring instrument, monitoring procedures, monitoring frequency, definition of fugitive emissions requiring repair, repair requirements, recordkeeping, and reporting requirements. If any of the sections of the State regulations or permits approved as alternative fugitive VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 emissions standards are changed at a later date, the State must follow the procedures outlined in 40 CFR 60.5399a to apply for a new evaluation of equivalency. As part of the 2018 proposed rule (83 FR 52056, October 15, 2018) that resulted in the 2020 Technical Rule, the EPA evaluated the specific State programs for both methane and VOC emissions at well sites, gathering and boosting compressor stations, and compressor stations in the transmission and storage segment as discussed in detail in a memorandum to that docket evaluating the equivalency of State fugitive emissions programs.188 The EPA is now proposing that all well sites and compressor stations located in and subject to the specified State regulations in 40 CFR 60.5399a may utilize these alternative fugitive emissions standards for both methane and VOC fugitive emissions. In the 2020 Technical Rule the EPA concluded that these monitoring, repair, recordkeeping, and reporting requirements were equivalent to the same types of requirements in the 2016 NSPS OOOOa for VOC at well sites and gathering and boosting compressor stations. See 85 FR 57424. The monitoring instrument (i.e., OGI or EPA Method 21) will detect, at the same time, both methane and VOC emissions without speciating these emissions. Therefore, detection of one of these pollutants is also detection of the other pollutant. For the same reasons provided in the 2020 Technical Rule, and explained in the associated State equivalency memos, the EPA proposes to find these same State fugitive emissions standards (as specified in 40 CFR 60.5399a(f) through (n)) equivalent to the specified Federal methane fugitive emissions standards for well sites and gathering and boosting stations, and the methane and VOC fugitive emissions standards for compressor stations in the transmission and storage segment. The EPA is also proposing to allow State, local, and Tribal agencies to apply for the EPA approval of their fugitives monitoring program as an alternative to the Federal NSPS for methane. Put another way, the EPA is proposing to include methane throughout 40 CFR 60.5399a. The EPA recognizes that the determinations of equivalence included in the 2020 Technical Rule were based on the fugitive emissions monitoring requirements that existed at that time for the 2016 NSPS OOOOa which, based on other changes in the 2020 Technical Rule, included an exemption from 188 See Docket ID Nos. EPA–HQ–OAR–2017– 0483–0041 and EPA–HQ–OAR–2017–0483–2277. PO 00000 Frm 00059 Fmt 4701 Sfmt 4702 63167 monitoring for low production well sites and required semiannual monitoring at gathering and boosting compressor stations. As explained above, the EPA is proposing to repeal both of those changes, and require semiannual monitoring at all well sites, including those with low production, and quarterly monitoring at gathering and boosting compressor stations. These proposed changes to the 2016 NSPS OOOOa fugitive emissions requirements do not impact the EPA’s conclusion that the six previously approved alternative State programs are equivalent to the Federal standards. Even so, the EPA is proposing regulatory changes within the alternative State program provisions in 2016 NSPS OOOOa to account for these proposed changes to the Federal standards. See the redline version of regulatory text in the docket at Docket ID No. EPA–HQ–OAR–2021–0317. These changes are intended to ensure that the previously approved alternative State programs continue to maintain equivalency with the Federal standards if NSPS OOOOa is revised as proposed here. With these changes, the EPA continues to find that the alternative State programs that were previously approved are still equivalent with, if not better than, the Federal requirements. 7. Onshore Natural Gas Processing Plants a. Capital Expenditure The 2020 Technical Rule made certain amendments to the 2016 NSPS OOOOa definition of capital expenditure as it relates to modifications for VOC LDAR requirements at onshore natural gas processing plants. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly amend this definition as it relates to the methane LDAR requirements at onshore natural gas processing plants. The 2020 Technical Rule amended the definition of ‘‘capital expenditure’’ at 40 CFR 50.5430a by replacing the equation used to determine the percent of replacement cost, ‘‘Y.’’ This amendment was necessary because, as originally promulgated, the equation for determining ‘‘Y’’ would result in an error, thus, making it difficult to determine whether a capital expenditure had occurred using the NSPS OOOOa equation. The 2020 Technical Rule replaced the equation with an equation that utilizes the consumer price indices, ‘‘CPI’’ because it more appropriately reflects inflation than the original equation. Specifically, the equation for ‘‘Y’’ as amended in the E:\FR\FM\15NOP2.SGM 15NOP2 63168 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 2020 Technical Rule, is based on the CPI, where ‘‘Y’’ equals the CPI of the date of construction divided by the most recently available CPI of the date of the project, or ‘‘CPIN/CPIPD.’’ Further, the 2020 Technical Rule specifies that the ‘‘annual average of the CPI for all urban consumers (CPI–U), U.S. city average, all items’’ must be used for determining the CPI of the year of construction, and the ‘‘CPI–U, U.S. city average, all items’’ must be used for determining the CPI of the date of the project. This amendment clarified that the comparison of costs is between the original date of construction of the process unit (the affected facility) and the date of the project which adds equipment to the process unit. For these same reasons, the EPA is proposing that the definition of ‘‘capital expenditure,’’ as amended by the 2020 Technical Rule, also be used to determine whether modification had occurred and thus triggers the applicability of the methane LDAR requirements at onshore natural gas processing plants in the 2016 NSPS OOOOa. b. Initial Compliance Period The 2020 Technical Rule amended the VOC standards for onshore natural gas processing plants to specify that the initial compliance deadline for the equipment leak standards is 180 days. The EPA is proposing to apply this clarification to the initial compliance deadline with the methane standards for equipment leaks at onshore natural gas processing plants. As explained in the 2020 Technical Rule, the EPA added a provision requiring compliance ‘‘as soon as practicable, but no later than 180 days after initial startup’’ because that provision was in the NSPS for equipment leaks of VOC at onshore natural gas processing plants when it was first promulgated, specifically at 40 CFR 60.632(a) of part 60, subpart KKK (NSPS KKK). 85 FR 57408. This provision at 40 CFR 60.632(a) provides up to 180 days to come into compliance with NSPS KKK. In 2012, the EPA revised the standards in NSPS KKK with the promulgation of NSPS OOOO 189 by lowering the leak definition for valves from 10,000 ppm to 500 ppm and requiring the monitoring of connectors. 77 FR 49490, 49498. While the EPA did not mention that it was also amending the 180-day compliance deadline in NSPS OOOO, this provision at 40 CFR 60.632(a) was 189 ‘‘Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution for Which Construction, Modification or Reconstruction Commenced After August 23, 2011, and on or before September 18, 2015.’’ VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 not included in NSPS OOOO and, in turn, was not included in NSPS OOOOa. During the rulemaking for NSPS OOOOa, the EPA declined a request to include this provision at 40 CFR 60.632(a) in NSPS OOOOa, explaining that such inclusion was not necessary because NSPS OOOOa already includes by reference a similar provision (i.e., 40 CFR 60.482–1a(a)) which requires each owner or operator to ‘‘demonstrate compliance . . . within 180 days of initial startup,’’ 80 FR 56593, 56647–8. However, in reassessing the issue during the rulemaking for the 2020 Technical Rule, the EPA noted that NSPS KKK includes both the provision in 40 CFR 60.632(a) and 40 CFR 60.482–1(a), which contains a provision that is the same as the one described above at 40 CFR 60.482–1a(a), thus suggesting that 40 CFR 60.632(a) is not redundant or unnecessary. In fact, the absence of this provision in NSPS OOOO/OOOOa raised a question as to whether compliance is required within 30 days for equipment that is required to be monitored monthly. To clarify this confusion and remain consistent with NSPS KKK, the 2020 Technical Rule amended NSPS OOOOa to reinstate this provision at 40 CFR 60.632(a). For the same reasons explained above, the EPA is proposing to similarly apply this provision to compliance with methane standards for the equipment leaks at onshore natural gas processing plants. This provision clarifies that monitoring must begin as soon as practicable, but no later than 180 days after the initial startup of a new, modified, or reconstructed process unit at an onshore natural gas processing plant. Once started, monitoring must continue with the required schedule. For example, if pumps are monitored by month 3 of the initial startup period, then monthly monitoring is required from that point forward. This initial compliance period is different than the compliance requirements for newly added pumps and valves within a process unit that is already subject to a LDAR program. Initial monitoring for those newly added pumps and valves is required within 30 days of the startup of the pump or valve (i.e., when the equipment is first in VOC service). 8. Technical Corrections and Clarifications The 2020 Technical Rule also revised the 2016 NSPS OOOOa for VOC emissions to include certain additional technical corrections and clarifications. In this action, the EPA is proposing to apply these same technical corrections and clarifications to the methane standards for production and processing PO 00000 Frm 00060 Fmt 4701 Sfmt 4702 segments and/or the methane and VOC standards for the transmission and storage segment in the 2016 NSPS OOOOa, as appropriate. Specifically, the EPA is proposing to: • Revise 40 CFR 60.5385a(a)(1), 60.5410a(c)(1), 60.5415a(c)(1), and 60.5420a(b)(4)(i) and (c)(3)(i) to clarify that hours or months of operation at reciprocating compressor facilities must be measured beginning with the date of initial startup, the effective date of the requirement (August 2, 2016), or the last rod packing replacement, whichever is latest. • Revise 40 CFR 60.5393a(b)(3)(ii) to correctly cross-reference paragraph (b)(3)(i) of that section. • Revise 40 CFR 60.5397a(c)(8) to clarify the calibration requirements when Method 21 of appendix A–7 to part 60 is used for fugitive emissions monitoring. • Revise 40 CFR 60.5397a(d)(3) to correctly cross-reference paragraphs (g)(3) and (4) of that section. • Revise 40 CFR 60.5401a(e) to remove the word ‘‘routine’’ to clarify that pumps in light liquid service, valves in gas/vapor service and light liquid service, and pressure relief devices (PRDs) in gas/vapor service within a process unit at an onshore natural gas processing plant located on the Alaska North Slope are not subject to any monitoring requirements, whether the monitoring is routine or nonroutine. • Revise 40 CFR 60.5410a(e) to correctly reference pneumatic pump affected facilities located at a well site as opposed to pneumatic pump affected facilities not located at a natural gas processing plant (which would include those not at a well site). This correction reflects that the 2016 NSPS OOOOa do not contain standards for pneumatic pumps at gathering and boosting compressor stations. 81 FR 35850. • Revise 40 CFR 60.5411a(a)(1) to remove the reference to paragraphs (a) and (c) of 40 CFR 60.5412a for reciprocating compressor affected facilities. • Revise 40 CFR 60.5411a(d)(1) to remove the reference to storage vessels, as this paragraph applies to all the sources listed in 40 CFR 60.5411a(d), not only storage vessels. • Revise 40 CFR 60.5412a(a)(1) and (d)(1)(iv) to clarify that all boilers and process heaters used as control devices on centrifugal compressors and storage vessels must introduce the vent stream into the flame zone. Additionally, revise 40 CFR 60.5412a(a)(1)(iv) and (d)(1)(iv)(D) to clarify that the vent stream must be introduced with the primary fuel or as the primary fuel to E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules meet the performance requirement option. This is consistent with the performance testing exemption in 40 CFR 60.5413a and continuous monitoring exemption in 40 CFR 60.5417a for boilers and process heaters that introduce the vent stream with the primary fuel or as the primary fuel. • Revise 40 CFR 60.5412a(c) to correctly reference both paragraphs (c)(1) and (2) of that section, for managing carbon in a carbon adsorption system. • Revise 40 CFR 60.5413a(d)(5)(i) to reference fused silica-coated stainless steel evacuated canisters instead of a specific name brand product. • Revise 40 CFR 60.5413a(d)(9)(iii) to clarify the basis for the total hydrocarbon span for the alternative range is propane, just as the basis for the recommended total hydrocarbon span is propane. • Revise 40 CFR 60.5413a(d)(12) to clarify that all data elements must be submitted for each test run. • Revise 40 CFR 60.5415a(b)(3) to reference all applicable reporting and recordkeeping requirements. • Revise 40 CFR 60.5416a(a)(4) to correctly cross-reference 40 CFR 60.5411a(a)(3)(ii). • Revise 40 CFR 60.5417a(a) to clarify requirements for controls not specifically listed in paragraph (d) of that section. • Revise 40 CFR 60.5422a(b) to correctly cross-reference 40 CFR 60.487a(b)(1) through (3) and (b)(5). • Revise 40 CFR 60.5422a(c) to correctly cross-reference 40 CFR 60.487a(c)(2)(i) through (iv) and (c)(2)(vii) through (viii). • Revise 40 CFR 60.5423a(b) to simplify the reporting language and clarify what data are required in the report of excess emissions for sweetening unit affected facilities. • Revise 40 CFR 60.5430a to remove the phrase ‘‘including but not limited to’’ from the ‘‘fugitive emissions component’’ definition. During the 2016 NSPS OOOOa rulemaking, the EPA stated in a response to comment that this phrase is being removed,190 but did not do so in that rulemaking. • Revise 40 CFR 60.5430a to remove the phrase ‘‘at the sales meter’’ from the ‘‘low pressure well’’ definition to clarify that when determining the low-pressure status of a well, pressure is measured within the flow line, rather than at the sales meter. • Revise Table 3 of 40 CFR part 60, subpart OOOOa, to correctly indicate that the performance tests in 40 CFR 190 See Docket ID Item No. EPA–HQ–OAR–2010– 0505–7632, Chapter 4, page 4–319. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 60.8 do not apply to pneumatic pump affected facilities. • Revise Table 3 of 40 CFR part 60, subpart OOOOa, to include the collection of fugitive emissions components at a well site and the collection of fugitive emissions components at a compressor station in the list of exclusions for notification of reconstruction. • Revise 40 CFR 60.5393a(f), 60.5410a(e)(8), 60.5411a(e), 60.5415a(b) introductory text and (b)(4), 60.5416a(d), and 60.5420a(b) introductory text and (b)(13), and introductory text in 40 CFR 60.5411a and 60.5416a, to remove language associated with the administrative stay we issued under section 307(d)(7)(B) of the CAA in ‘‘Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources; Grant of Reconsideration and Partial Stay’’ (82 FR 25730, June 5, 2017). The administrative stay was vacated by the D.C. Circuit on July 3, 2017. XI. Summary of Proposed NSPS OOOOb and EG OOOOc This section presents a summary of the specific NSPS standards and EG presumptive standards the EPA is proposing for various types of equipment and emission points. More details of the rationale for these standards and requirements, including alternative compliance options and exemptions to the standards, are provided in section XII of this preamble and the TSD for this action in the public docket. As stated in section I, the EPA intends to provide draft regulatory text for the proposed NSPS OOOOb and EG OOOOc in a supplemental proposal. A. Fugitive Emissions From Well Sites and Compressor Stations Fugitive emissions are unintended emissions that can occur from a range of equipment at any time. The magnitude of these emissions can also vary widely. The EPA has historically targeted fugitive emissions from the Crude Oil and Natural Gas source category through ground-based component level monitoring using OGI, or alternatively, EPA Method 21. The EPA is proposing the following monitoring requirements and presumptive standards for the collection of fugitive emissions components located at well sites and compressor stations. Additional details for the proposed standards and proposed presumptive standards are included in the following subsections. Information received through the various solicitations in this section may be used to evaluate if a change in the BSER is PO 00000 Frm 00061 Fmt 4701 Sfmt 4702 63169 appropriate from the proposed requirements below, specifically consideration of alternative measurement technologies as the BSER. Any potential changes would be addressed through a supplemental proposal. • Well sites with total site-level baseline methane emissions less than 3 tpy: Demonstration, based on a sitespecific survey, that actual emissions are reflected in the baseline methane emissions calculation, • Well sites with total site-level baseline methane emissions of 3 tpy or greater: Quarterly OGI or EPA Method 21 monitoring, • (Co-proposal) Well sites with total site-level baseline methane emissions of 3 tpy or greater and less than 8 tpy: Semiannual OGI or EPA Method 21 monitoring, • (Co-proposal) Well sites with total site-level baseline methane emissions of 8 tpy or greater: Quarterly OGI or EPA Method 21 monitoring, • Compressor stations: Quarterly OGI or EPA Method 21 monitoring, • Well sites and compressor stations located on the Alaska North Slope: Annual monitoring, with separate initial monitoring requirements, and • Alternative screening approach for all well sites and compressor stations: Bimonthly screening surveys using advanced measurement technology and annual OGI or EPA Method 21 monitoring at each individual well site or compressor station. 1. Definition of Fugitive Emissions Component A key factor in evaluating how to target fugitive emissions is clearly identifying the emissions of concern and the sources of those emissions. In the 2016 NSPS OOOOa, the EPA defined ‘‘fugitive emissions component’’ as ‘‘any component with the potential to emit methane and VOCs’’ and included several specific component types, ranging from valves and connectors, to openings on controlled storage vessels that were not regulated under NSPS OOOOa. However, data shows that the universe of components with potential for fugitive emissions is broader than the illustrative list included in the 2016 NSPS OOOOa, and that the majority of the largest emissions events occur from a subset of components that may not have been clearly included in the definition. Therefore, the EPA is proposing a new definition for ‘‘fugitive emissions component’’ to provide clarity that these sources of large emission events are covered. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63170 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules ‘‘Fugitive emissions component’’ is proposed to be any component that has the potential to emit fugitive emissions of methane and VOC at a well site or compressor station, including valves, connectors, PRDs, open-ended lines, flanges, all covers and closed vent systems, all thief hatches or other openings on a controlled storage vessel, compressors, instruments, meters, natural gas-driven pneumatic controllers or natural gas-driven pumps. However, natural gas discharged from natural gas-driven pneumatic controllers or natural gas-driven pumps are not considered fugitive emissions if the device is operating properly and in accordance with manufacturers specifications. Control devices, including flares, with emissions resulting from the device operating in a manner that is not in full compliance with any Federal rule, State rule, or permit, are also considered fugitive emissions components. This proposed definition includes the same components that were included in the 2016 NSPS OOOOa and adds sources of large emissions, such as malfunctioning controllers or control devices. The inclusion of specific component types in this proposed definition would allow the use of OGI, EPA Method 21, or an alternative screening technology to identify emissions that would either be repaired (i.e., leaks) or have a root cause analysis with corrective action (e.g., malfunctioning control device, unintentional gas carry through, venting from covers and openings on a controlled storage vessel, or malfunctioning natural gas-driven pneumatic controllers). Further, we are proposing that where a CVS is used to route emissions from an affected facility (i.e., centrifugal or reciprocating compressor, pneumatic pump, or storage vessel), the owner or operator would demonstrate there are no detectable emissions from the covers and CVS through the OGI (or EPA Method 21) monitoring conducted during the fugitive emissions survey. Where emissions are detected, corrective actions to complete all necessary repairs as soon as practicable would be required, and the emissions would be considered a potential violation of the no detectable emissions standard. In the case of a malfunction or operational upset of a control device or the equipment itself, where emissions are not expected to occur if the equipment is operating in compliance with the standards of the rule, this proposal would require the owner or operator to conduct a root cause analysis to determine why the emissions VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 are present, take corrective action to complete all necessary repairs as soon as practicable and prevent reoccurrence of emissions, and report the malfunction or operational upset as a potential violation of the underlying standards for the source of the emissions. We are soliciting comment on whether to include the option to continue utilizing monthly AVO surveys as demonstrations of no detectable emissions from a CVS but are not proposing that option specifically. Because the EPA is proposing both NSPS and EG in this action, we anticipate that CVS associated with controlled pneumatic pumps will be located at well sites subject to fugitive emissions monitoring. Therefore, we do not believe the monthly AVO option is necessary. However, we are soliciting comment on whether there are circumstances where a CVS associated with a controlled pneumatic pump is located at a well site not otherwise subject to fugitive emissions monitoring and where OGI (or EPA Method 21) would be an additional burden. The EPA is soliciting comment on this proposed definition of ‘‘fugitive emissions component,’’ including any additional components or characterization of components that should be included. Further, we are soliciting comment on the use of the fugitive emissions survey to identify malfunctions and other large emission sources where the equipment is not operating in compliance with the underlying standards, including the proposed requirement to perform a root cause analysis and to take corrective action to mitigate and prevent future malfunctions. 2. Fugitive Emissions From Well Sites The current NSPS for reducing fugitive VOC and methane emissions at well sites requires semiannual monitoring, except that a low production well site (one that produces at or below 15 barrels of oil equivalent (boe) per day) is exempt from VOC monitoring. As explained in section X.A.1, we are proposing to remove that exemption from NSPS OOOOa, as we have concluded that exemption was not justified by the underlying record and does not represent BSER. Further, based on our revised BSER analysis, which is summarized in section XII.A.1.a, the EPA is proposing updated standards for reducing fugitive VOC and methane emissions from the collection of fugitive emissions components located at new, modified, or reconstructed well sites (under the newly proposed NSPS OOOOb). Also, for the reasons discussed in section XII.A.2, the EPA is PO 00000 Frm 00062 Fmt 4701 Sfmt 4702 proposing to determine that the BSER analysis supports a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing well sites (under the newly proposed EG OOOOc) that is the same as what we are proposing for the NSPS (for NSPS OOOOb). Provided below is a summary of the proposed updated NSPS and the proposed EG. a. NSPS OOOOb For new, modified, or reconstructed sources, we are proposing a fugitive emissions monitoring and repair program that includes monitoring for fugitive emissions with OGI in accordance with the proposed 40 CFR part 60, appendix K (‘‘appendix K’’), which is included in this action and outlines the proposed procedures that must be followed to identify emissions using OGI.191 We are also proposing that EPA Method 21 may be used as an alternative to OGI monitoring. We are further proposing that monitoring must begin within 90 days of startup of production (or startup of production after modification). Unlike in NSPS OOOOa which, as amended by the 2020 Technical Rule, set VOC monitoring frequency based on production level, the EPA is proposing that the OGI monitoring frequency be based on the site-level methane baseline emissions,192 as determined, in part, through equipment/component count emission factors. The EPA is proposing the calculation of the total site-wide methane emissions, including fugitive emissions from components, emissions from natural gas-driven pneumatic controllers, natural gas-driven pneumatic pumps, storage vessels, as well as other regulated and nonregulated emission sources. Specifically, we are proposing that owners or operators would calculate the site-level baseline methane emissions using a combination of population-based emission factors and storage vessel emissions. Further, the EPA proposes this calculation would be repeated every time equipment is added to or removed from the site. For each natural gasdriven pneumatic pump, continuous bleed natural gas-driven pneumatic 191 ‘‘Determination of Volatile Organic Compound and Greenhouse Gas Leaks Using Optical Gas Imaging’’ located at Docket ID No. EPA–HQ–OAR– 2021–0317. 192 As shown in the TSD, the EPA analyzed the monitoring frequency for both methane and VOC under both the single pollutant approach and the multipollutant approach. Because the composition of gas at a well site is predominantly methane (approximately 70 percent), a methane threshold represents the lowest threshold that is cost effective to control both VOC and methane emissions. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules controller, and intermittent bleed natural gas-driven pneumatic controller located at the well site, the owner or operator would apply the population emission factors for all components found in Table W–1A of GHGRP subpart W. For each piece of major production and processing equipment and each wellhead located at the well site, the owner or operator would first apply the default average component counts for major equipment found in Table W–1B and Table W–1C of GHGRP subpart W, and then apply the component-type emission factors for the population of valves, connectors, open-ended lines, and PRVs found in Table 2–8 of the 1995 Emissions Protocol.193 Finally, the owner or operator would use the calculated potential methane emissions after applying control (if applicable) for each storage vessel tank battery located at the well site. The sum of the emissions estimated for all equipment at the site would be used as the baseline methane emissions for determining the applicable monitoring frequency. The EPA proposes to use the default population emission factors found in Table W–1A of GHGRP subpart W and the default average component counts for major equipment found in Tables W–1B and W–1C of GHGRP subpart W because they are well-vetted emission and activity factors used by the Agency. The EPA is not incorporating these emission factors directly into the proposed NSPS OOOOb or EG OOOOc because they could be the subject of future GHGRP subpart W revisions, and if revised, those revisions would be relevant to this calculation. For the individual components (e.g., valves and connectors), the EPA proposes to rely on the component-type emission factors found in Table 2–8 of the 1995 Emissions Protocol for purposes of quantifying emissions from major production and processing equipment and each wellhead located at the well site because these data have been relied upon in previous rulemakings for this sector, have been the subject of extensive public comment, and the EPA has determined that they are appropriate to use for purposes of this action. The EPA requests comment on whether the proposed methodologies for calculating site-level baseline methane emissions are appropriate for these emission sources, and if not, what methodologies would be more appropriate. Specifically, the EPA recognizes the proposed calculation methodology assumes all equipment is 193 EPA, Protocol for Equipment Leak Emission Estimates, EPA–453/R–95–017, November 1995. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 operating as designed (e.g., controlled storage vessels with all vapors routed to a control that is actually achieving 95 percent reduction or greater). Therefore, we are soliciting comment on whether sites should use the uncontrolled PTE calculation for their storage vessels in their site-level baseline estimate to account for times when these vessels are not operating as designed, which is a known cause of large emission events of concern. Further, to that point, the EPA is soliciting comment on how to develop a factor that could be applied to the site-level baseline calculation that would account for large emission events, or any specific data that would provide a factor for these events. As we state throughout this preamble, large emission events are of specific concern and fugitive emissions monitoring is an effective tool for detecting these emissions, therefore, we acknowledge there is considerable interest from various stakeholders that these emission events are accounted for in our analyses. At this time, the EPA does not have enough information to develop a factor or determine how to best apply that factor. Information provided through this solicitation would allow us to consider additional revisions to this calculation methodology through a supplemental proposal. The EPA is also soliciting comment on whether providing direct major equipment population emission factors that can be combined with site-specific gas compositions would provide a more transparent and less burdensome means to develop the site-specific emissions estimates than using a combination of major equipment counts, specific component counts per major equipment, and component-level population emission factors. Furthermore, the EPA requests comment on whether site-level baseline methane emissions should be determined using a baseline emissions survey instead of the proposed methodology, and if so, what methodologies should be used to quantify emissions from the survey such as measurement or emission factors based on leaking component emission factors. The EPA also solicits comment on specific methodologies to support commenters’ positions. The EPA also requests comment on whether there are additional production and processing equipment or emission sources that should be included in the site-level baseline methane emissions. For example, the EPA is aware that there could be emission sources such as engines, dehydrator venting, compressor venting, associated gas venting, and migration of gas outside of the wellbore PO 00000 Frm 00063 Fmt 4701 Sfmt 4702 63171 at a well site. If such equipment or emission sources should be included in the site-level baseline, the EPA requests comment on methodologies for quantifying emissions for purposes of the baseline. Based on the analysis described in section XII.A.1, the potential for fugitive emissions is impacted more by the number and type of equipment at the site, and not by the volume of production. Therefore, the EPA believes it is more appropriate to use sitespecific emissions estimates based on the number and type of equipment located at the individual site to determine the monitoring frequency. Table 13 summarizes the proposed sitelevel baseline methane thresholds for the proposed monitoring frequencies, which according to our analysis would achieve the greatest cost-effective emission reductions. As noted below, the EPA solicits comment on all aspects of the proposed tiered approach to monitoring that is summarized in Table 13. Although we are proposing no routine OGI monitoring where site-level baseline methane emissions are below 3 tpy, the EPA is proposing to require these sites to demonstrate the actual emissions are accounted for in the calculation. This demonstration would include a survey, such as OGI, EPA Method 21 (including provisions for the use of a soap solution), or advanced measurement technologies. Given that this demonstration is designed to show actual emissions are below 3 tpy, and most survey techniques are not quantitative, the EPA anticipates that sources finding emissions will make repairs on equipment/components identified as leaking during the demonstration survey. The EPA acknowledges that the 2016 NSPS OOOOa and this proposal allow the use of EPA Method 21 as an alternative to OGI monitoring to detect fugitive emissions from the collection of fugitive emissions components under the proposed tiered approach to monitoring. However, as discussed in section XI.A.5, EPA Method 21 is not proposed as an alternative for follow-up OGI surveys under the proposed alternative screening approach using advanced measurement technologies when screening detects emissions. This is because EPA Method 21 is not able to find all sources of leaks and is therefore not an appropriate method for detection in these cases where large emissions events have been identified. Given this limitation, the EPA is soliciting comment on whether EPA Method 21 remains an appropriate E:\FR\FM\15NOP2.SGM 15NOP2 63172 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules alternative to OGI for routine OGI surveys. TABLE 13—PROPOSED WELL SITE MONITORING FREQUENCIES BASED ON SITE–LEVEL BASELINE METHANE EMISSIONS Site-level baseline methane emissions threshold Proposed OGI monitoring frequency >0 and <3 tpy ....................... ≥3 and <8 tpy ....................... ≥8 tpy ................................... No routine monitoring required ....................................... Quarterly .......................................................................... Quarterly .......................................................................... khammond on DSKJM1Z7X2PROD with PROPOSALS2 Where quarterly monitoring is proposed, subsequent quarterly monitoring would occur at least 60 days apart. Where semiannual monitoring is co-proposed, subsequent semiannual monitoring would occur at least 4 months apart and no more than 7 months apart. We are proposing to retain the provision in the 2016 NSPS OOOOa that the quarterly monitoring may be waived when temperatures are below 0 °F for two of three consecutive calendar months of a quarterly monitoring period. The EPA has previously required the use of OGI technology to detect fugitive emissions of methane and VOC from the oil and gas sector (i.e., well sites and compressor stations). However, the EPA had not developed a protocol for its use even though the EPA has previously mentioned the need for an OGI protocol during other rulemakings where OGI has been proposed for leak detection.194 In this document, the EPA is proposing a draft protocol for the use of OGI as appendix K to 40 CFR part 60. The EPA notes that while this protocol is being proposed for use in the oil and gas sector, the applicability of the protocol is broader. The protocol is applicable to surveys of process equipment using OGI cameras in the entire oil and gas upstream and downstream sectors from production to refining to distribution where a subpart in those sectors references its use. As part of the development of appendix K, the EPA conducted an extensive literature review on the technology development as well as observations on current application of OGI technology. Approximately 150 references identify the technology, applications, and limitations of OGI. The EPA also commissioned multiple 194 The development of appendix K to 40 CFR part 60 was previously mentioned in both the proposal for the National Uniform Emission Standards for Storage Vessel and Transfer Operations, Equipment Leaks, and Closed Vent Systems and Control Devices; and Revisions to the National Uniform Emission Standards General Provisions (77 FR 17897, March 26, 2012) and the Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards (79 FR 36880, June 30, 2014). VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 Co-proposed OGI monitoring frequency No routine monitoring required. Semiannual. Quarterly. laboratory studies and OGI technology evaluations. Additionally, on November 9 and 10, 2020, the EPA held a virtual stakeholder workshop to gather input on development of a protocol for the use of OGI. The information obtained from these efforts was used to develop the TSD for appendix K, which provides technical analyses, experimental results, and other supplemental information used to evaluate and develop standardized procedures for the use of OGI technology in monitoring for fugitive emissions of VOCs, HAP, and methane from industrial environments.195 Appendix K outlines the proposed procedures that instrument operators must follow to identify leaks or fugitive emissions using a hand-held, field portable infrared camera. Additionally, appendix K contains proposed specifications relating to the required performance of qualifying infrared cameras, required operator training and verification, determination of an operating window for performing surveys, and requirements for a monitoring plan and recordkeeping. The EPA is requesting comment on all aspects of the draft OGI protocol being proposed as appendix K to 40 CFR part 60.196 As mentioned in section X.B.4.f, we are proposing that, once fugitive methane emissions are detected during the OGI survey, a first attempt at repair must be made within 30 days of detecting the fugitive emissions, with final repair, including resurvey to verify repair, completed within 30 days after the first attempt. These proposed repair requirements with respect to methane fugitive emissions are the same as those made in the 2020 Technical Rule for VOC fugitive emissions (and proposed in section X.B.4.f for methane in this action). Because large emission events contribute disproportionately to emissions, the EPA is soliciting comment on how to structure a 195 Technical Support Document—Optical Gas Imaging Protocol (40 CFR part 60, Appendix K), available in the docket for this action. 196 See appendix K in Docket ID No. EPA–HQ– OAR–2021–0317. PO 00000 Frm 00064 Fmt 4701 Sfmt 4702 requirement that would tier repair deadlines based on the severity of the fugitive emissions identified during the OGI (or EPA Method 21) surveys. In order for such a structure to work, there would need to be a way to qualify which fugitive emissions are smaller and which are larger, as the initial monitoring with OGI will not provide this information. One approach could be to define broad categories of leaks and make assumptions about the magnitude of emissions for those broad categories. For example, an open thief hatch would be considered a very large leak due to the surface opening size, and it would need to be remedied on the tightest timeframe, whereas a leaking connector would be considered a small leak based on historical emissions factors and could be repaired on a more lenient timeframe. The EPA is soliciting comments on how this approach could be structured, particularly the types of leaks that would fall into each broad category and the appropriate repair timeframes for each of the categories. The EPA is also soliciting comment on other approaches that could also be implemented for repairing fugitive emissions in a tiered structure. Finally, we are proposing to retain the requirement for owners and operators to develop a fugitive emissions monitoring plan that covers all the applicable requirements for the collection of fugitive emissions components located at a well site and includes the elements specified in the proposed appendix K when using OGI. The affected facilities include well sites with major production and processing equipment, and centralized tank batteries. As in the 2020 Technical Rule, the EPA is proposing to not include ‘‘wellhead only well sites,’’ as affected facilities when the well site is a wellhead only well site at the date it becomes subject to the rule. Based on the proposed site-level baseline methane emissions calculation methodology, wellhead only sites would only calculate emissions from fugitive components (e.g., valves, connectors, flanges, and open-ended lines) that are located on the wellhead. We believe E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules these sites would not exceed the 3 tpy threshold to require routine monitoring. However, unlike the 2020 Technical Rule, the EPA is proposing that when a well site later removes all major production and processing equipment such that it becomes a wellhead only well site, it must recalculate the emissions in order to determine if a different frequency is then required. In this proposal, the definitions for ‘‘wellhead only well site’’ and ‘‘well site’’ would be the same as those finalized in the 2020 Technical Rule. Specifically, ‘‘wellhead only well site’’ means ‘‘for purposes of the fugitive emissions standards, a well site that contains one or more wellheads and no major production and processing equipment.’’ The term ‘‘major production and processing equipment’’ refers to ‘‘reciprocating or centrifugal compressors, glycol dehydrators, heater/ treaters, separators, and storage vessels collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water.’’ The EPA is soliciting comment on whether any other equipment not included in this definition should be added in order to clearly specify what well sites are considered wellhead only sites. Specifically, the EPA is soliciting comment on the inclusion of natural gas-driven pneumatic controllers, natural gas-driven pneumatic pumps, and pumpjack engines in the definition of ‘‘major production and processing equipment.’’ A ‘‘well site’’ means one or more surface sites that are constructed for the drilling and subsequent operation of any oil well, natural gas well, or injection well. For purposes of the fugitive emissions standards, a well site includes a centralized production facility. Also, for purposes of the fugitive emissions standards, a well site does not include: (1) UIC Class II oilfield disposal wells and disposal facilities; (2) UIC Class I oilfield disposal wells; and (3) the flange immediately upstream of the custody meter assembly and equipment, including fugitive emissions components, located downstream of this flange. In addition to retaining the above definitions, the EPA is also proposing a new definition for ‘‘centralized production facility’’ for purposes of fugitive emissions requirements for well sites, where a ‘‘centralized tank battery’’ is one or more permanent storage tanks and all equipment at a single stationary source used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 one or more offsite natural gas or oil production wells. This equipment includes, but is not limited to, equipment used for storage, separation, treating, dehydration, artificial lift, combustion, compression, pumping, metering, monitoring, and flowline. Process vessels and process tanks are not considered storage vessels or storage tanks. A centralized production facility is located upstream of the natural gas processing plant or the crude oil pipeline breakout station and is a part of producing operations. Additional discussion on centralized production facilities is included in section XI.L. The EPA is not proposing any change to the current definition of modification as it relates to fugitive emissions requirements at well sites or centralized production facilities. Specifically, modification occurs at a well site when: (1) A new well is drilled at an existing well site; (2) a well at an existing well site is hydraulically fractured; or (3) a well at an existing well site is hydraulically refractured. Similarly, modification occurs at a centralized production facility when (1) any of the actions above occur at an existing centralized production facility; (2) a well sending production to an existing centralized production facility is modified as defined above for well sites; or (3) a well site subject to the fugitive emissions standards for new sources removes all major production and processing equipment such that it becomes a wellhead only well site and sends production to an existing centralized production facility. b. EG OOOOc For existing well sites (for EG OOOOc), we are proposing a presumptive standard that follows the same fugitive monitoring and repair program as for new sources. For the reasons discussed in section XII.A.2, the BSER analysis for existing sources supports proposing a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing well sites that is the same as what the EPA is proposing for new, reconstructed, or modified sources (for NSPS OOOOb). The EPA did not identify any factors specific to existing sources that would alter the analysis performed for new sources to make that analysis different for existing well sites. The EPA determined that the OGI technology, methane emission reductions, costs, and cost effectiveness discussed above for the collection of fugitive emissions components at new well sites are also applicable for the collection of fugitive emissions PO 00000 Frm 00065 Fmt 4701 Sfmt 4702 63173 components at existing well sites. Further, the fugitive emissions requirements do not require the installation of controls on existing equipment or the retrofit of equipment, which can generally be an additional factor for consideration when determining the BSER for existing sources. Therefore, the EPA found is appropriate to use the analysis developed for the proposed NSPS OOOOb to also develop the BSER and proposed presumptive standards for the EG OOOOc. Based on the information available at this time, the EPA thinks the large number of existing well sites, many of which are not complex warrants soliciting comment on whether existing well sites (or a subcategory thereof) could have different emission profiles due to certain site characteristics or other factors that would suggest a different presumptive standard is appropriate. Further, we remain concerned about the burden of fugitive emissions monitoring requirements on small businesses. Therefore, we are requesting comment on regulatory alternatives for well sites that accomplish the stated objectives of the CAA and which minimize any significant economic impact of the proposed rule on small entities, including any information or data that pertain to the emissions impacts and costs of our proposal to remove the exemption from fugitive monitoring for well sites with low emissions, or would support alternative fugitive monitoring requirements for these sites. We are soliciting data that assess the emissions from low production well sites, and information on any factors that could make certain well sites less likely to emit VOC and methane, including geologic features, equipment onsite, production levels, and any other factors that could establish the basis for appropriate regulatory alternatives for these sites. Further, the EPA is aware there are a subset of existing well sites that are owned by individual homeowners, farmers, or companies with very few employees (well below the threshold defining a small business). For these owners, the EPA is concerned our analysis underestimates the actual burden imposed by these proposed standards. As an example, ownership may be limited to 1 or 2 wells located on an individual’s property, for which the production is used for heating the home. The cost burden of conducting fugitive emissions surveys in this type of scenario has not fully be analyzed. Therefore, the EPA solicits comment and information that would allow us to E:\FR\FM\15NOP2.SGM 15NOP2 63174 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules further evaluate the burden on the smallest companies to further propose appropriate standards at this subset (or other similar subsets) of well sites through a supplemental proposal. Finally, we are soliciting comment on all aspects of the proposed fugitive emissions requirements for both new and existing well sites, including whether we should use the tiering approach, whether the tiers we have defined are appropriate, and the monitoring requirements for each tier, including whether it would be costeffective to monitor at more frequent intervals than proposed. The EPA may include revisions to this proposal for ground-based OGI monitoring at well sites if information is received that would warrant consideration of a different approach to establishing monitoring frequencies at well sites. khammond on DSKJM1Z7X2PROD with PROPOSALS2 3. Fugitive Emissions from Compressor Stations The current NSPS for reducing fugitive emissions from the collection of fugitive emissions components located at a compressor station is a fugitive emissions monitoring and repair program requiring quarterly OGI monitoring.197 Based on our analysis, which is summarized in section XII.A.1.b, the EPA is proposing quarterly OGI monitoring requirement for both methane and VOC as it continues to reflect the BSER for reducing both emissions from fugitive components at new, modified, and reconstructed compressor stations. Likewise, the EPA is also proposing quarterly monitoring as a presumptive GHG standard (in the form of limitation on methane emissions) for the collection of fugitive emissions components located at existing compressor stations. The affected compressor stations include gathering and boosting, transmission, and storage compressor stations. a. NSPS OOOOb We are proposing that the quarterly monitoring using OGI be conducted in accordance with the proposed appendix K described above in section XI.A.2, which outlines procedures that must be followed to identify leaks using OGI. We are proposing to retain the current requirements that monitoring must begin within 90 days of startup of the station (or startup after modification), with subsequent quarterly monitoring 197 Note that for gathering and boosting compressor stations, the EPA is proposing to rescind the 2020 Technical Rule amendment that changed the monitoring frequency to semiannual for VOC emissions. See section X.A.2 for more information. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 occurring at least 60 days apart. Also, quarterly monitoring may be waived when temperatures are below 0 °F for two of three consecutive calendar months of a quarterly monitoring period. We are also not proposing any change to the following repair-related requirements: Specifically, a first attempt at repair must be made within 30 days of detecting the fugitive emissions, with final repair, including resurvey to verify repair, completed within 30 days after the first attempt. In addition, owners and operators must develop a fugitive emissions monitoring plan that covers all the applicable requirements for the collection of fugitive emissions components located at a compressor station. In conjunction with the proposed requirement that monitoring be conducted in accordance with the proposed appendix K, we are proposing to require that the monitoring plan also include elements specified in the proposed appendix K when using OGI. b. EG OOOOc For existing sources, we are proposing a presumptive standard that includes the same fugitive emissions monitoring and repair program as for new sources. For the reasons discussed in section XII.A.2, the BSER analysis for existing sources supports proposing a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing compressor stations that is the same as what the EPA is proposing for new, modified, or reconstructed sources (for NSPS OOOOb). Similar to well sites, we are soliciting comment on all aspects of the proposed quarterly monitoring for both new and existing compressor stations, including whether more frequent monitoring would be appropriate. We are also soliciting information on several additional topics. First, the EPA is soliciting comment and data to assess whether compressor stations should be subcategorized for the NSPS and/or the EG, which the EPA could consider through a supplemental proposal. For example, some industry stakeholders have asserted that station throughput directly correlates to the operating pressures, equipment counts, and condensate production, which would influence fugitive emissions at the station. They suggested that subcategorization based on design throughput capacity for the compressor station may be appropriate. We are specifically seeking information related to throughputs where fugitive emissions of methane are demonstrated to be PO 00000 Frm 00066 Fmt 4701 Sfmt 4702 minimal below a certain capacity. While this specific example was raised in the context of existing sources only, the EPA is also soliciting comment on whether new, modified, or reconstructed compressor stations could encounter the same issue and therefore warrant similar subcategorization. Next, for compressor stations, we are soliciting comment on delayed repairs by existing sources when parts are not readily available and must be special ordered. In comments submitted to the EPA as part of the stakeholder outreach conducted prior to this proposal, industry stakeholders stated that the EPA ‘‘should acknowledge that existing sources are older pieces of equipment so there is a higher likelihood that replacement parts will not be readily available; therefore, a lack of available parts should be an appropriate cause to delay a repair.’’ 198 Industry stakeholders further explained that operators will need to special order replacement parts. Further, they stated in their comments that operators should be afforded 30 days to schedule the repair once they have received the replacement part. The EPA is soliciting comment and data to better understand the breadth of this issue with replacement parts for existing compressor stations. Additionally, we are soliciting comment on whether 30 days following receipt of the replacement part is appropriate for completing delayed repairs at existing compressor stations, whether there should be any limit on delays in repairs under these circumstances, and whether this compliance flexibility should be limited or disallowed based on the severity of the leak to be repaired. We are also soliciting comment on the specific records that should be maintained and/or reported to justify delayed repairs as a result of part availability issues. Depending on the additional information received, the EPA may consider proposing changes to the proposed EG for compressor stations through a supplemental proposal. Finally, as discussed in section XI.A.2, the EPA is soliciting comment on whether the scheduling of repairs at compressor stations should be tiered based on severity of the emissions found. Please refer to section XI.A.3 for additional details on this solicitation for comment. 4. Well Sites and Compressor Stations on the Alaska North Slope For new, reconstructed, and modified well sites and compressor stations 198 Document ID No. EPA–HQ–OAR–2021–0295– 0033. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules 5. Alternative Screening Using Advanced Measurement Technologies For new, modified, or reconstructed sources (i.e., collection of fugitive emissions components located at well sites and compressor stations), the EPA is proposing an alternative fugitive emissions monitoring and repair program that includes bimonthly screening for large emission events using advanced measurement technologies followed with at least annual OGI in accordance with the proposed 40 CFR part 60, appendix K (‘‘appendix K’’), which is included in this action and outlines the proposed procedures that must be followed to identify emissions using OGI.199 Additionally, we are proposing this same alternative screening using advanced measurement technologies as an alternative presumptive standard for existing sources. Specifically, the EPA is proposing to allow owners and operators the option to comply with this alternative fugitive emissions standard instead of the proposed ground based OGI surveys summarized in sections XI.A.2 and XI.A.3. The EPA proposes to require owners and operators choosing this alternative standard to do so for all affected well sites and compressor stations within a company-defined area. This company-defined area could be a county, sub-basin, or other appropriate geographic area. Under this proposed alternative, the EPA proposes to require a screening survey on a bimonthly basis using a methane detection technology that has been demonstrated to achieve a minimum detection threshold of 10 kg/ hr. This screening survey would be used to identify individual sites (i.e., well sites and compressor stations) where a follow-up ground-based OGI survey of all fugitive emissions components at the site is needed because fugitive emissions have been detected. Given the proposed minimum detection threshold of 10 kg/hr, which would constitute a significant emissions event, the EPA believes this follow-up OGI survey should be completed in an expeditious timeframe, therefore we are proposing to require this follow-up OGI survey of all fugitive emissions components at the site within 14 days of the screening survey. However, additional information is needed to fully evaluate the appropriateness of this deadline. Therefore, the EPA is soliciting comment on the proposed 14-day deadline for a follow-up OGI survey and information that would allow further evaluation of other potential deadlines to require. Next, for sites with emissions identified during screening and subject to this follow-up OGI survey, the EPA proposes that any fugitive emissions identified must be repaired, including those emissions identified during the screening survey. For purposes of this proposal, the EPA is proposing the same repair deadlines as those for the ground based OGI requirements discussed in sections XI.A.2 and XI.A.3, which are a first attempt at repair within 30 days of the OGI survey and final repair completed within 30 days of the first attempt. As noted in section XI.A.1, some equipment types with large emissions warrant a requirement for 199 ‘‘Determination of Volatile Organic Compound and Greenhouse Gas Leaks Using Optical Gas Imaging’’ located at Docket ID No. EPA–HQ–OAR– 2021–0317. khammond on DSKJM1Z7X2PROD with PROPOSALS2 located on the Alaska North Slope, based on the rationale provided in section X.B.4.c of this preamble, the EPA is proposing the same monitoring requirements as those in NSPS OOOOa (under newly proposed OOOOb). Also, the EPA is proposing to determine that the same technical infeasibility issues with weather conditions exist for existing well sites and compressor stations located on the Alaska North Slope. Therefore, the EPA is proposing a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing well sites and compressor stations located on the Alaska North Slope (under the newly proposed EG OOOOc) that is the same as what we are proposing for NSPS OOOOb. Specifically, the EPA is proposing to require annual monitoring of methane and VOC emissions at all well sites and compressor stations located on the Alaska North Slope, with subsequent annual monitoring at least 9 months apart but no more than 13 months apart. The EPA is also proposing to require that new, reconstructed, and modified well sites and compressor stations located on the Alaska North Slope that startup (initially, or after reconstruction or modification) between September and March to conduct initial monitoring of methane and VOC fugitive emissions within 6 months of startup, or by June 30, whichever is later. Finally, the EPA is proposing to require that new, reconstructed, and modified well sites and compressor stations located on the Alaska North Slope that startup (initially, or after reconstruction or modification) between April and August to conduct initial monitoring of methane and VOC fugitive emissions within 90 days of startup. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 PO 00000 Frm 00067 Fmt 4701 Sfmt 4702 63175 root cause analysis rather than simply repairing the emission source. The EPA solicits comment on how that root cause analysis with corrective action approach could be applied in this proposed alternative screening approach. Further, because large emission events, especially those identified during the screening surveys, contribute disproportionately to emissions, the EPA is also soliciting comment on how to structure a requirement that would tier repair deadlines based on the severity of the fugitive emissions when using this proposed alternative standard. See section XI.A.2 for additional discussion of this solicitation on tiered repairs. In addition to the bimonthly screening surveys proposed above, the EPA recognizes that component-level fugitive emissions may still be present at sites where the screening survey does not detect emissions. Therefore, in conjunction with these bimonthly screenings performed with the advanced measurement technology, the EPA is proposing to require a full OGI (or EPA Method 21) survey at least annually at each individual site utilizing the alternative screening standard. If the owner or operator performs an OGI survey in response to emissions found during the bimonthly screening survey, that OGI survey would count as the annual OGI survey; a second survey would not be required to comply with the annual OGI survey requirement and the clock would restart with the next annual survey due within 12 calendar months. The overall purpose of this annual OGI survey is to ensure that each individual site is surveyed with OGI at least annually, even where large emissions are not detected during the screening surveys using advanced measurement technology. The EPA is not allowing EPA Method 21 for use during the proposed follow-up OGI surveys when screening detects emissions because EPA Method 21 is not appropriate for detecting the sources of large emission events, such as malfunctioning control devices. Finally, the EPA is proposing to require that owners and operators include information specific to the alternative standard within their fugitive emissions monitoring plan. Since the 2016 NSPS OOOOa, owners and operators have been required to develop and maintain a fugitive emissions monitoring plan for all sites subject to the fugitive emissions requirements. This monitoring plan includes information regarding which sites are covered under the plan, which technology is being used (e.g., OGI or EPA Method 21), and site or company- E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63176 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules specific procedures that are employed to ensure compliant surveys. The EPA is proposing to add a requirement that the monitoring plan also address sites that are utilizing the proposed alternative standard. Specifically, the EPA is proposing a requirement to include the following information when the alternative standard is applied: • Identification of the sites opting to comply with the alternative screening approach; • General description of each site to be monitored, including latitude and longitude coordinates of the asset in decimal degrees to an accuracy and precision of five decimals of a degree using the North American Datum of 1983; • Description of the measurement technology; • Verification that the technology meets the 10 kg/hr methane detection threshold, including supporting data to demonstrate the sensitivity of the measurement technology as applied; • Procedures for a daily verification check of the measurement sensitivity under field conditions (e.g., controlled releases); • Standard operating procedures consistent with EPA’s guidance 200 and to include safety considerations, measurement limitations, personnel qualification/responsibilities, equipment and supplies, data and record management, and quality assurance/quality control (i.e., initial and ongoing calibration procedures, data quality indicators, and data quality objectives); and • Procedures for conducting the screening. In the event that an owner or operator uses multiple technologies covered by one monitoring plan, the owner or operator would identify which technology is to be used on which site within the monitoring plan. In addition to the proposed requirements within the monitoring plan, the EPA is also proposing specific recordkeeping and reporting requirements associated with the follow-up OGI surveys that are consistent with the recordkeeping and reporting required for OGI surveys in NSPS OOOOa as amended in the 2020 Technical Rule. See section X.B.1.h and X.B.1.i. The EPA is soliciting comment on when notifications would be required for sites where the alternative standard is applied. Further, the EPA is soliciting comment on whether 200 Guidance for Preparing Standard Operating Procedures (SOPs), EPA/600/B–07/001, April 2007, https://www.epa.gov/sites/default/files/2015-06/ documents/g6-final.pdf. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 submission of the monitoring plan, and/ or Agency approval before utilizing the alternative standard is necessary to ensure consistency in screening survey procedures in the absence of finalized methods or procedures. While the EPA is proposing the above alternative screening requirements, additional information is necessary to further refine the specific alternative work practice as it relates to the available technologies. Specific information is requested in the following paragraphs, and, if received, would allow the EPA to better analyze the BSER for fugitive emissions at well sites and compressor stations through a supplemental proposal. First, the EPA solicits comment on the use of 10 kg/hr as the minimum detection threshold for the advanced measurement technologies used in the alternative screening approach, including data that would support consideration of another detection threshold. The EPA also solicits comment on whether a matrix approach should be developed, instead of prescribing one detection threshold and screening frequency, and what that matrix should look like. In the matrix approach, the frequency of the screening surveys and regular OGI (or EPA Method 21) surveys would be based on the sensitivity of the technology, with the most sensitive detection thresholds having the least frequent screening and survey requirements and the least sensitive detection thresholds having the most frequent screening and survey requirements. For example, sites that are screened using a technology with a detection threshold of 1 kg/hr may require less frequent screening and may require an OGI survey less frequently than sites screened using a technology with a detection threshold of 50 kg/hr. We are also soliciting comment on the detection sensitivity of commercially available methane detection technologies based on conditions expected in the field, as well as factors that affect the detection sensitivity and how the detection sensitivity would change with these factors. Next, the EPA is soliciting comment on the standard operating procedures being used for commercially available technologies, including any manufacturer recommended data quality indicators and data quality objectives in use to validate these measurements. Additionally, for those commercially available technologies that quantify methane emissions rather than just detect methane, we are soliciting comment on the range of quantification based on conditions one would expect in the field. PO 00000 Frm 00068 Fmt 4701 Sfmt 4702 The EPA is seeking information that would allow us to further evaluate the potential costs and assumed emission reductions achieved through an alternative screening program. Therefore, the EPA is seeking information on the cost of screening surveys using different types of advanced measurement technologies, singularly or in combination, and factors that affect that cost (e.g., is it influenced by the number of sites and length of survey). Additionally, we are interested in understanding whether there would be opportunities for costsharing among operators and whether any aspect of regulation would be beneficial or required to facilitate such cost-sharing opportunities. We also solicit comment on whether these technologies and cost-sharing opportunities would allow for costeffective monitoring at all sites owned or operated by the same company within a sub-basin or other discrete geographic area. Further, we seek comment on the current and expected availability of these advanced measurement technologies and the supporting personnel and infrastructure required to deploy them, how their cost and availability might be affected if demand for these technologies were to increase, and how quickly the use of these technologies could expand if they were integrated into this regulatory program either as a required element of fugitive monitoring or as this proposed alternative work practice. The EPA recognizes that the approach outlined above may not be suited to continuous monitoring technologies, such as network sensors or open-path technology. While these systems typically have the ability to meet the 10 kg/hr methane threshold discussed above 201 the emissions from these well sites can be intermittent or tied to process events (e.g., pigging operations). We are concerned that the proposed alternative screening approach would trigger an OGI survey for every emission event, regardless of type, duration, or size, if a continuous monitoring technology is installed. This would disincentivize the use of continuous monitoring systems, which could be valuable tools in finding large emission sources sooner. While we believe that a framework for advanced measurement technologies that monitor sites continuously should be developed, we do not currently have all of the information that is necessary to develop 201 Alden et al., Single-Blind Quantification of Natural Gas Leaks from 1 km Distance Using Frequency Combs, Environmental Science and Technology, 2019, 53, 2908–2917. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 an equivalence demonstration for these monitors or to ensure the technology works appropriately over time. Therefore, we are soliciting comment on how an equivalence demonstration can be made for these continuous monitoring technologies. The framework for a continuous monitoring technology would need to cover the following items at a minimum: The number of monitors needed and the placement of the monitors; minimum response factor to methane; minimum detection level; frequency of data readings; how to interpret the monitor data to determine what emissions are a detection versus baseline emissions; how to determine allowable emissions versus leaks; the meteorological data criteria; measurement systems data quality indicators; calibration requirements and frequency of calibration checks; how downtime should be handled; and how to handle situations where the source of emissions cannot be identified even when the monitor registers a leak. We are soliciting comment on how to develop a framework that is flexible for multiple technologies while still ensuring that emissions are adequately detected and the monitors respond appropriately over time. Additionally, we are soliciting comment on whether these continuous monitors need to respond to other compounds as well as methane; how close a meteorological station must be to the monitored site; and whether OGI or EPA Method 21 surveys should still be required, and if so, at what frequency. At this time, the EPA does not have enough information to determine how this proposed alternative standard using advanced measurement technologies compares to the proposed BSER of OGI monitoring at well sites at a frequency that is based on the site baseline methane emissions as described in section XI.A.3.a, or to quarterly OGI monitoring at compressor stations. Information provided through this solicitation may be used to reevaluate BSER through a supplemental proposal. 6. Use of Information From Communities and Others As the EPA learned during the Methane Detection Technology Workshop, industry, researchers, and NGOs have utilized advanced methane detection systems to quickly identify large emission sources and target ground based OGI surveys. State and local governments, industry, researchers, and NGOs have been utilizing advanced technologies to better understand the detection of, source of, and factors that lead to large emission events. The EPA anticipates that the use VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 of these techniques by a variety of parties, including communities located near oil and gas facilities or affected by oil and gas pollution, will continue to grow as these technologies become more widely available and decline in cost. The EPA is seeking comment on how to take advantage of the opportunities presented by the increasing use of these technologies to help identify and remediate large emission events (commonly known as ‘‘super-emitters’’). Specifically, the EPA seeks comment on how to evaluate, design, and implement a program whereby communities and others could identify large emission events and, where there is credible information of such a large emission event, provide that information to owners and operators for subsequent investigation and remediation of the event. The EPA understands that these large emission events are often attributable to malfunctions or abnormal process conditions that should not be occurring at a well-operating, wellmaintained, and well-controlled facility that has implemented the various BSER measures identified in this proposal. We generally envision a program for finding large emission events that consists of a requirement that, if emissions are detected above a defined threshold by a community, a Federal or State agency, or any other third party, the owner or operator would be required to investigate the event, do a root cause analysis, and take appropriate action to mitigate the emissions, and maintain records and report on such events. We seek comment on all aspects of this concept, which would be developed further as part of a supplemental proposal. Among other things, the EPA is soliciting comment on an emissions threshold that could be used to define these large emission events, and which types of technologies would be suitable for identification of large emissions events. For example, there are some satellite systems capable of generally identifying emissions above 100 kg/hr with a spatial resolution which could allow identification of emission events from an individual site.202 Additionally there are other satellites systems available which have wider spatial resolution that can identify large methane emission events, and when combined with finer resolution platforms, could allow identification of emission events from an individual site. The EPA believes that any emissions 202 D.J. Varon, J. McKeever, D. Jervis, J.D. Maasakkers, S. Pandey, S. Houweling, I. Aben, T. Scarpelli, D.J. Jacob, Satellite Discovery of anomalously Large Methane Point Sources from Oil/Gas Production, available at https://doi.org/ 10.1029/2019GL083798, October 25, 2019. PO 00000 Frm 00069 Fmt 4701 Sfmt 4702 63177 visible by satellites should qualify as large emission events. However, the EPA solicits comment on whether the threshold for a large emission should be lower than what is visible by satellite. Second, in order to make this approach viable, the EPA would need to specify what actions an owner or operator must take when notified of a large emission event, including deadlines for taking such actions. These elements could include the specific steps the company would take to investigate the notification and mitigate the event, such as verifying the location of the emissions, conducting ground investigations to identify the specific emission source, conducting a root cause analysis, performing corrective action within a specific timeframe to mitigate the emissions, and preventing ongoing and future chronic or intermittent large emissions from that source. These steps could be incorporated into a fugitive emissions monitoring plan maintained by the owner or operator, and failure to take the actions specified by the owner or operator in the plan could be considered noncompliance. We seek comment on what specific follow-up actions or other procedures would be appropriate to require once a large emission event is identified, as well as appropriate deadlines for these actions. Third, the EPA would need to define guidelines for credible and actionable data. The EPA is soliciting comment on what these guidelines should entail and whether specific protocols (e.g., permissible detection technologies, data analytics, operator training, data reporting, public access, and data preservation) should govern the collection of such data and whether such data should conform to any type of certification. If specific certification or protocols are necessary, the EPA is soliciting comment on how that certification should be obtained. Fourth, we are also soliciting comment on best practices for the identification of the correct owner or operator of a facility responsible for such large emissions, since such information is necessary to halt such large-volume emission events, and how the community or other third-party should notify the owner or operator, as well as how the delegated authority should be made aware of such notification. Finally, we are soliciting comment on whether the EPA should develop a model plan for responding to notifications that companies could adopt instead of developing companyor site-specific plans, including what E:\FR\FM\15NOP2.SGM 15NOP2 63178 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules elements should be included in that model plan. khammond on DSKJM1Z7X2PROD with PROPOSALS2 B. Storage Vessels 1. NSPS OOOOb The current NSPS in subpart OOOOa for storage vessels is to reduce VOC emissions by 95 percent, and the standard applies to a single storage vessel with a potential for 6 or more tpy of VOC emissions. Based on our analysis, which is summarized in section XII.B.1, the EPA is proposing to retain the 95 percent reduction standard as it continues to reflect the BSER for reducing VOC emissions from new storage vessels. The EPA is also proposing to set GHG standards (in the form of limitations on methane emissions) for storage vessels in this action. Because the BSER for reducing VOC and methane emissions are the same, the proposed GHG standard is to reduce methane emissions by 95 percent. The EPA continues to support the capture of gas vapors from storage vessels rather than the combustion of what can be an energy-rich saleable product. We incentivize this by recognizing the use of vapor recovery as a part of the process, therefore the storage vessel emissions would not contribute to the site’s potential-to-emit. Under the current NSPS for storage vessels, an affected facility is a single storage vessel with potential VOC emissions of 6 tpy or greater. The EPA is proposing to include a tank battery as a storage vessel affected facility. The EPA proposes to define a tank battery as a group of storage vessels that are physically adjacent and that receive fluids from the same source (e.g., well, process unit, compressor station, or set of wells, process units, or compressor stations) or which are manifolded together for liquid or vapor transfer. To determine whether a single storage vessel is an affected facility, the owner or operator would compare the 6 tpy VOC threshold to the potential emissions from that individual storage vessel; to determine whether a tank battery is an affected facility, the owner or operator would compare the 6 tpy VOC threshold to the aggregate potential emissions from the group of storage vessels. For new, modified, or reconstructed sources, if the potential VOC emissions from a storage vessel or tank battery exceeds the 6 tpy threshold, then it is a storage vessel affected facility and controls would be required. This is consistent with the EPA’s initial determination in the 2012 NSPS OOOO that controlling VOC emissions as low as 6 tpy from storage vessels is costeffective. The proposed standard of 95 VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 percent reduction of methane and VOC emissions, which is the same as the current VOC standard in the 2012 NSPS OOOO and 2016 NSPS OOOOa, can be achieved by capturing and routing the emissions utilizing a cover and closed vent system that routes captured emissions to a control device that achieves an emission reduction of 95 percent, or that routes captured emissions to a process. Finally, we are proposing specific provisions to clarify what circumstances constitute a modification of an existing storage vessel affected facility (single storage vessel or tank battery), and thus subject it to the proposed NSPS instead of the EG. The EPA is proposing that a single storage vessel or tank battery is modified when physical or operational changes are made to the single storage vessel or tank battery that result in an increase in the potential methane or VOC emissions. Physical or operational changes would be defined to include: (1) The addition of a storage vessel to an existing tank battery; (2) replacement of a storage vessel such that the cumulative storage capacity of the existing tank battery increases; and/or (3) an existing tank battery or single storage vessel that receives additional crude oil, condensate, intermediate hydrocarbons, or produced water throughput (from actions such as refracturing a well or adding a new well that sends these liquids to the tank battery). The EPA is proposing to require that the owner or operator recalculate the potential VOC emissions when any of these actions occur on an existing tank battery to determine if a modification has occurred. The existing tank battery will only become subject to the proposed NSPS if it is modified pursuant to this definition of modification and its potential VOC emissions exceed the proposed 6 tpy VOC emissions threshold. 2. EG OOOOc Based on our analysis, which is summarized in section XII.B.2, the EPA is proposing EG for existing storage vessels which include a presumptive GHG standard (in the form of limitation on methane emissions). For existing sources under the EG, the EPA is proposing to define a designated facility as an existing tank battery with potential methane emissions of 20 tpy or greater. The proposed definition of a tank battery in the EG is the same as the definition proposed for new sources; however, since the designated pollutant in the context of the EG is methane, determination of whether a tank battery is a designated facility would be based on its potential methane emissions only. PO 00000 Frm 00070 Fmt 4701 Sfmt 4702 Our analysis shows that it is cost effective to control an existing tank battery with potential methane emissions 20 tpy or higher. Similar to the proposed NSPS, we are proposing a presumptive standard that includes a 95 percent reduction of the methane emissions from each existing tank battery that qualifies as a designated facility. Such a standard could be achieved by capturing and routing the emissions by utilizing a cover and closed vent system that routes captured emissions to a control device that achieves an emission reduction of 95 percent, or routes emission back to a process. C. Pneumatic Controllers 1. NSPS OOOOb The current NSPS OOOOa regulates certain continuous bleed natural gas driven pneumatic controllers, but includes different standards based on whether the pneumatic controller is located at an onshore natural gas processing plant. If the pneumatic controller is located at an onshore natural gas processing plant, then the current NSPS requires a zero bleed rate. If the pneumatic controller is located elsewhere, then the current NSPS requires the pneumatic controller to operate at a natural gas bleed rate no greater than 6 scfh. The current NSPS does not regulate intermittent vent natural gas driven pneumatic controllers at any location. Based on our analysis, which is summarized in section XII.C.1, the EPA is proposing pneumatic controller standards for NSPS OOOOb as follows. First, in addition to each single natural gas-driven continuous bleed pneumatic controller being an affected facility, the EPA proposes to define each natural gas-driven intermittent vent pneumatic controller as an affected facility. The EPA believes these pneumatic controllers should be covered by NSPS OOOOb because natural gas-driven intermittent devices represent a large majority of the overall population of pneumatic controllers and are responsible for the majority of emissions from these sources. We are proposing to define an intermittent vent natural gasdriven pneumatic controller as a pneumatic controller that is not designed to have a continuous bleed rate but is instead designed to only release natural gas to the atmosphere as part of the actuation cycle. This affected facility definition would apply at all sites, including natural gas processing plants. Second, we are proposing a requirement that all controllers E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules (continuous bleed and intermittent vent) must have a VOC and methane emission rate of zero. The proposed rule does not specify how this emission rate of zero must be achieved, but a variety of viable options are discussed in Section XII.C. including the use of pneumatic controllers that are not driven by natural gas such as air-driven pneumatic controllers and electric controllers, as well as natural gas driven controllers that are designed so that there are no emissions, such as self-contained pneumatic controllers. As noted above, the EPA is proposing that the definition of an affected facility would be each pneumatic controller that is driven by natural gas and that emits to the atmosphere. As such, pneumatic controllers that are not driven by natural gas would not be affected facilities, and thus would not be subject to the pneumatic controller requirements of NSPS OOOOb. Similarly, controllers that are driven by natural gas but that do not emit to the atmosphere would also not be affected facilities. In order to demonstrate that a particular pneumatic controller is not an affected facility, owners and operators should maintain documentation to show that such controllers are not natural gas driven such as documentation of the design of the system, and to ensure that they are operated in accordance with the design so that there are no emissions. In both NSPS OOOO and OOOOa, there is an exemption from the standards in cases where the use of a pneumatic controller affected facility with a bleed rate greater than the applicable standard is required based on functional needs, including but not limited to response time, safety, and positive actuation. The EPA is not maintaining this exemption in the proposed NSPS OOOOb, except for in very limited circumstances explained in section XII.C. As discussed in section XII.C., the reasons to allow for an exemption based on functional need in NSPS OOOO and OOOOa were based on the inability of a low-bleed controller to meet the functional requirements of an owner/operator such that a highbleed controller would be required in certain instances. Since we are now proposing that pneumatic controllers have a methane and VOC emission rate of zero, we do not believe that the reasons related to the use of low bleed controllers are still applicable. However, EPA is soliciting comment on whether owners/operators believe that maintaining such an exemption based on functional need is appropriate, and if so why. The proposed rule includes an exemption from the zero-emission VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 requirement for pneumatic controllers in Alaska at locations where power is not available. In these situations, the proposed standards require the use of a low-bleed controller instead of highbleed controller. Further, in these situations (controllers in Alaska at location without power) the proposed rule includes the exemption that would allow the use of high-bleed controllers instead of low-bleed based on functional needs. Lastly, in these situations owners/operators must inspect intermittent vent controllers to ensure they are not venting during idle periods. 2. EG OOOOc In this action, the EPA is proposing to define designated facilities (existing sources) analogous to the affected facility definitions described above for pneumatic controllers under the NSPS. For the reasons discussed in section XII.C.2, the BSER analysis for existing sources supports proposing presumptive standards for reducing methane emissions from existing pneumatic controllers that are the same as those the EPA is proposing for new, modified, or reconstructed sources (for NSPS OOOOb). D. Well Liquids Unloading Operations Well liquids unloading operations, which are currently unregulated under the NSPS OOOOa, refer to unloading of liquids that have accumulated over time in gas wells and are impeding or halting production. The EPA is proposing standards in the NSPS OOOOb to reduce methane and VOC emissions during liquids unloading operations. 1. NSPS OOOOb We are proposing standards to reduce VOC and methane emissions from each well that conducts a liquids unloading operation. Based on our analysis, which is summarized in section XII.D.1, we are proposing a standard under NSPS OOOOb that requires owners or operators to perform liquids unloading with zero methane or VOC emissions. In the event that it is technically infeasible or not safe to perform liquids unloading with zero emissions, the EPA is proposing to require that an owner or operator establish and follow BMPs to minimize methane and VOC emissions during liquids unloading events to the extent possible. The EPA is co-proposing two regulatory approach options to implement the rule requirements. For Option 1, the affected facility would be defined as every well that undergoes liquids unloading. This would mean that wells that utilize a non-emitting method for liquids PO 00000 Frm 00071 Fmt 4701 Sfmt 4702 63179 unloading would be affected facilities and subject to certain reporting and recordkeeping requirements. These requirements would include records of the number of unloadings that occur and the method used. A summary of this information would also be required to be reported in the annual report. The EPA also recognizes that under some circumstances venting could occur when a selected liquids unloading method that is designed to not vent to the atmosphere is not properly applied (e.g., a technology malfunction or operator error). Under the proposed rule Option 1 owners and operators in this situation would be required to record and report these instances, as well as document and report the length of venting, and what actions were taken to minimize venting to the maximum extent possible. For wells that utilize methods that vent to the atmosphere, the proposed rule would require that owners or operators (1) Document why it is infeasible to utilize a non-emitting method due to technical, safety, or economic reasons; (2) develop BMPs that ensure that emissions during liquids unloading are minimized including, at a minimum, having a person on-site during the liquids unloading event to expeditiously end the venting when the liquids have been removed; (3) follow the BMPs during each liquids unloading event and maintain records demonstrating they were followed; and (4) report the number of liquids unloading events in an annual report, as well as the unloading events when the BMP was not followed. While the proposed rule would not dictate all of the specific practices that must be included, it would specify minimum acceptance criteria required for the types and nature of the practices. Examples of the types and nature of the required practice elements are provided in XII.D.1.e. For Option 2, the affected facility would be defined as every well that undergoes liquids unloading using a method that is not designed to totally eliminate venting. The significant difference in this option is that wells that utilize non-venting methods would not be affected facilities that are subject to the NSPS OOOOb. Therefore, they would not have requirements other than to maintain records to document that they used non-venting liquids unloading methods. The requirements for wells that use methods that vent would be the same as described above under Option 1. The EPA solicits comment on including information such as where the well stream was directed during unloading and emissions E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63180 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules manifested and whether an estimate of the VOC and methane emissions generated should be included in the annual report. There are several techniques owners and operators can choose from to unload liquids, including manual unloading, velocity tubing or velocity strings, beam or rod pumps, electric submergence pumps, intermittent unloading, gas lift (e.g., use of a plunger lift), foam agents, wellhead compression, and routing the gas to a sales line or back to a process. Although the unloading method employed by an owner or operator can itself be a method that can be employed in such a way that mitigates/eliminates venting of emissions from a liquids unloading event, indicating a particular method to meet a particular well’s unloading needs is a production engineering decision. Based on available information, liquids unloading operations are often conducted in such a way that eliminates venting to the atmosphere and there are many options that include techniques and procedures that an owner or operator can choose from to achieve this standard (discussed in section XII.D.e of this preamble). However, the EPA recognizes that there may be reasons that a non-venting method is infeasible for a particular well, and the proposed rule would allow for the use of BMPs to reduce the emissions to the maximum extent possible for such cases (discussed in section XII.D of this preamble). BMPs include, but are not limited to, following specific steps that create a differential pressure to minimize the need to vent a well to unload liquids and reducing wellbore pressure as much as possible prior to opening to atmosphere via storage tank, unloading through the separator where feasible, and requiring an operator to remain onsite throughout the unloading, and closure of all well head vents to the atmosphere and return of the well to production as soon as practicable. For example, where a plunger lift is used, the plunger lift can be operated so that the plunger returns to the top and the liquids and gas flow to the separator. Under this scenario, venting of the gas can be minimized and the gas that flows through the separator can be routed to sales. In situations where production engineers select an unloading technique that vents emissions or has the potential to vent emissions to the atmosphere, owners and operators already often implement BMPs in order to increase gas sales and reduce emissions and waste during these (often manual) liquids unloading activities. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 2. EG OOOOc The EPA has determined that each well liquids unloading event represents a modification, which will make the well subject to new source standards under the NSPS for purposes of the liquids unloading standards.203 Therefore, after the effective date of NSPS OOOOb, the first time a well undergoes liquids unloading it will become subject to NSPS OOOOb. This will mean that there will never be a well that undergoes liquids unloading that will be existing. Therefore, we are not proposing presumptive standards under the subpart OOOOc EG. E. Reciprocating Compressors 1. NSPS OOOOb The current NSPS in subpart OOOOa for reducing VOC and methane emissions from reciprocating compressors is to replace the rod packing on or before 26,000 hours of operation or 36 calendar months, or to route emissions from the rod packing to a process through a closed vent system under negative pressure. The affected facility is each reciprocating compressor, with the exception of reciprocating compressors located at well sites. Based on the analysis in section XII.E.1, the proposed BSER for reducing GHGs and VOC from new reciprocating compressors is replacement of the rod packing based on an annual monitoring threshold. Under this proposal for the NSPS, we would continue to retain, as an alternative, the option of routing rod packing emissions to a process via a closed vent system under negative pressure. In this proposed updated standard, the owner or operator of a reciprocating compressor affected facility would be required to monitor the rod packing emissions annually using a flow measurement. When the measured leak rate exceeds 2 scfm (in pressurized mode), replacement of the rod packing would be required. As mentioned above, reciprocating compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because we found the cost of control to be unreasonable. 81 FR 35878 (June 3, 2016). Our current analysis, as summarized in section XII.E.1, continues to support this exclusion for a subset of well sites so this proposal for NSPS OOOOb includes that same 203 To clarify further, when a well liquids unloading event represents a modification, this does not make the whole well site a new source. Rather, the modification will make the well subject to NSPS for only the liquids unloading standards. PO 00000 Frm 00072 Fmt 4701 Sfmt 4702 exclusion for well sites that are not centralized production facilities. See section XI.L for additional details on centralized production facilities. As described in that section, the EPA is proposing to apply the proposed standards to reciprocating compressors located at centralized production facilities. 2. EG OOOOc Based on the analysis in section XII.E.2, the EPA is proposing EG that include a presumptive GHG standard (in the form of limitation on methane emissions) for existing reciprocating compressors that is the same as the proposed NSPS, including applying these presumptive standards to reciprocating compressors located at existing centralized tank batteries. F. Centrifugal Compressors 1. NSPS OOOOb The current NSPS in subpart OOOOa for wet seal centrifugal compressors is 95 percent reduction of GHGs and VOC emissions. The affected facility is each wet seal centrifugal compressor, with the exception of wet seal centrifugal compressors located at well sites. Based on the analysis in section XII.F.1, the BSER for reducing GHGs and VOC from new, reconstructed, or modified wet seal centrifugal compressors is the same as the current standard, which is 95 percent reduction of GHG and VOC emissions. The standard can be achieved by capturing and routing the emissions, using a cover and closed vent system, to a control device that achieves an emission reduction of 95 percent, or by routing captured emissions to a process. As discussed above, wet seal centrifugal compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because data available at the time did not suggest there were a large number of wet seal centrifugal compressors located at well sites. 81 FR 35878 (June 3, 2016). Our analysis continues to support this exemption for wet seal centrifugal compressors located at well sites that are not centralized production facilities. See section XI.L for additional details on centralized production facilities. As described in that section, the EPA is proposing to apply the proposed standards to centrifugal compressors located at centralized production facilities. 2. EG OOOOc Based on the analysis in section XII.F.2, the EPA is proposing EG that E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules include a presumptive GHG standard (in the form of limitation on methane emissions) for existing wet seal centrifugal compressors that is the same as the NSPS, including applying these presumptive standards to wet seal centrifugal compressors at existing centralized tank batteries. khammond on DSKJM1Z7X2PROD with PROPOSALS2 G. Pneumatic Pumps 1. NSPS OOOOb The current NSPS in subpart OOOOa regulates individual natural gas driven diaphragm pneumatic pumps at well sites and at onshore natural gas processing plants. The current NSPS for a natural gas driven diaphragm pneumatic pump at well sites requires 95 percent control of GHGs and VOCs if there is an existing control device or process on site where emissions can be routed. There are two exceptions to the 95 percent control requirement: (1) The existing control or process achieves less than 95 percent reduction; or (2) it is technically infeasible to route to the existing control device or process. In addition, the current NSPS in OOOOa specifies that boilers and process heaters are not considered control devices and that routing emissions from pneumatic pump discharges to boilers and process heaters is not considered routing to a process. For more discussion on the use of boilers and process heaters as control devices for pneumatic pump emissions, see section X.B.2 of this preamble. The current NSPS for a natural gas driven diaphragm pneumatic pump at an onshore natural gas processing plant is a natural gas emission rate of zero, based on natural gas as a surrogate for VOC and GHG, the two regulated pollutants. For NSPS OOOOb, we are proposing to expand the applicability of the standard currently in NSPS OOOOa in two ways. The first is by including all natural gas driven diaphragm pumps as affected facilities in the transmission and storage segment in addition to the production and natural gas processing segments. The second is that we are expanding the affected facility definition to include natural gas driven piston pumps in addition to diaphragm pumps. The proposed definition of an affected facility would continue to exclude lean glycol circulation pumps that rely on energy exchange with the rich glycol from the contractor. Based on our analysis, which is summarized in section XII.G.1, we are proposing to retain the current standard for a natural gas driven diaphragm pneumatic pump at well sites because the BSER for reducing VOC and VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 methane emissions from such pumps at a well site continues to be routing to a combustion device or process, but only if the control device or process is already available on site. As before, the current analysis continues to show that it is not cost-effective to require the owner or operator of a pneumatic pump to install a new control device or process onsite to capture emissions solely for this purpose. Moreover, even where a control device or process is available onsite that would achieve at least 95 percent control, the EPA is aware that it may not be technically feasible in some instances to route the pneumatic pump to the control device or process. In this situation, the proposed rule would exempt the owner and operator from this requirement provided that they document the technical infeasibility and submit it in an annual report. Another circumstance is that it may be feasible to route the emissions to a control device, but the control cannot achieve 95 percent control. In this instance, the proposed rule would exempt the owner or operator from the 95 percent requirement, provided that the owner or operator maintain records demonstrating the percentage reduction that the control device is designed to achieve. In this way, the standard would achieve emission reductions with regard to pneumatic pump affected facilities even if the only available control device cannot achieve a 95 percent reduction. For more discussion of the technical infeasibility aspects of the pneumatic pump requirements, see section X.B.2 of this preamble. We are proposing to expand these requirements to all diaphragm pumps at all sites in the production segment, as well as at all transmission and storage sites. In addition, we are proposing that these requirements would also include emissions from piston pneumatic pumps at all sites in the production segment. We are not proposing any change to the current standard of zero natural gas emission for natural gas driven diaphragm pneumatic pumps located at onshore natural gas processing plants, other than the expansion of the affected facility definition to include piston pumps. Our analysis discussed in section XII.G.1 demonstrates this standard is the BSER. 2. EG OOOOc The EPA is proposing EG that include presumptive methane standards that are the same as described above for the NSPS OOOOb for existing natural gas driven diaphragm pneumatic pumps located at well sites and all other sites PO 00000 Frm 00073 Fmt 4701 Sfmt 4702 63181 in the production segment (except processing plants) and transmission and storage segment where an existing control device exists. However, unlike the proposed methane standards in NSPS OOOOb for natural gas driven piston pneumatic pumps at sites in the production segment, the proposed presumptive standards under EG OOOOc exclude piston pumps from the 95 percent control requirements. The EPA’s proposed emissions guidelines also include a presumptive methane standard for pneumatic pumps located at onshore natural gas processing plants that is the same as the proposed NSPS described above. H. Equipment Leaks at Natural Gas Processing Plants Based on our analysis, which is summarized in section XII.H.1, the EPA is proposing to update the NSPS for reducing VOC and methane emissions from equipment leaks at onshore natural gas processing plants. Further, based on the same analysis in section XII.H.1 and the EPA’s understanding that it is appropriate to apply that same analysis to existing sources, the EPA is also proposing EG that include these same LDAR requirements as presumptive standards for reducing methane leaks from existing equipment at onshore natural gas processing plants. The EPA is proposing to expand the definition of an affected facility (referred to as a ‘‘equipment within a process unit’’) and establish a new standard for reducing equipment leaks of VOC and methane emissions from new, modified, and reconstructed process units at onshore natural gas processing plants. This proposed standard would require (1) the use of OGI monitoring to detect equipment leaks from pumps, valves, and connectors, and (2) retain the current requirements in the 2016 NSPS OOOOa (which adopts by reference specific provisions of 40 CFR part 60, subpart VVa (‘‘NSPS VVa’’)) for PRDs, openended valves or lines, and closed vent systems and equipment designated with no detectable emissions. First, we are proposing to remove a threshold that excludes certain equipment within a process unit from being subject to the equipment leaks standards for onshore natural gas processing plants. While the current definition of an affected facility includes all equipment, except compressors, that is in contact with a process fluid containing methane or VOCs (i.e., each pump, PRD, openended valve or line, valve, and flange or other connector), the standards apply only to equipment ‘‘in VOC service,’’ E:\FR\FM\15NOP2.SGM 15NOP2 63182 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 which ‘‘means the piece of equipment contains or contacts a process fluid that is at least 10 percent VOC by weight.’’ We are proposing to remove this VOC concentration threshold from the LDAR requirements for the following reasons. First, a VOC concentration threshold bears no relationship to the LDAR for methane and is therefore not an appropriate threshold for determining whether LDAR for methane applies. Second, since there would be no threshold for requiring LDAR for methane, any equipment not in VOC service would still be required to conduct LDAR for methane even if not for VOC, thus rendering this VOC concentration threshold irrelevant. Second, for all pumps, valves, and connectors located within an affected process unit at an onshore natural gas processing plant, we are proposing to require the use of OGI to identify leaks from this equipment on a bimonthly frequency (i.e., once every other month), which according to our analysis is the BSER for identifying and reducing leaks from this equipment. OGI monitoring would be conducted in accordance with the proposed appendix K,204 which is included in this action and outlines the proposed procedures that must be followed to identify leaks using OGI. As an alternative to bimonthly monitoring using OGI, we are proposing to allow affected facilities the option to comply with the requirements of NSPS VVa, which are the current requirements in the 2016 NSPS OOOOa.205 As explained in XII.A, our analysis shows that the proposed standards, which use OGI, achieve equivalent reduction of VOC and methane emissions as the current standards, which are based on EPA Method 21, but at a lower cost. While we no longer consider EPA Method 21 to be the BSER for reducing methane and VOC emissions from equipment leaks at onshore natural gas processing plants, we are retaining NSPS VVa as an alternative for owners and operators who prefer using EPA Method 21. Third, we are proposing to require a first attempt at repair for all leaks identified with OGI within 5 days of detection, and final repair completed within 15 days of detection. We are also 204 ‘‘Determination of Volatile Organic Compound and Greenhouse Gas Leaks Using Optical Gas Imaging’’ located at Docket ID No. EPA–HQ–OAR– 2021–0317. 205 It is important to note that the stay of the connector monitoring requirements in 40 CFR 60.482–11a does not apply to connectors located at onshore natural gas processing plants. Therefore, where sources choose to comply with the requirements of NSPS VVa in place of the proposed OGI requirements, the standards in 40 CFR 60.482– 11a are applicable to all connectors in the process unit. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 proposing definitions for ‘‘first attempt at repair’’ and ‘‘repaired.’’ The proposed definitions would apply to the equipment leaks standards at natural gas processing plants as well as to fugitive emissions requirements at well sites and compressor stations. The proposed definition of ‘‘first attempt at repair’’ is an action taken for the purpose of stopping or reducing fugitive emissions or equipment leaks to the atmosphere. First attempts at repair include, but are not limited to, the following practices where practicable and appropriate: Tightening bonnet bolts; replacing bonnet bolts; tightening packing gland nuts; or injecting lubricant into lubricated packing. The proposed definition for ‘‘repaired’’ is fugitive emissions components or equipment are adjusted, replaced, or otherwise altered, in order to eliminate fugitive emissions or equipment leaks as defined in the subpart and resurveyed to verify that emissions from the fugitive emissions components or equipment are below the applicable leak definition. Repairs can include replacement with lowemissions (‘‘low-e’’) valves or valve packing, where commercially available, as well as drill-and-tap with a low-e injectable. These low-e equipment meet the specifications of API 622 or 624. Generally, a low-e valve or valve packing product will include a manufacturer written warranty that it will not emit fugitive emissions at a concentration greater than 100 ppm within the first five years. Further, we are proposing to incorporate the delay of repair provisions that are in 40 CFR 60.482–9a of NSPS VVa (and incorporated into NSPS OOOOa). These provisions would allow the delay of repairs where it is technically infeasible to complete repairs within 15 days without a process unit shutdown and require repair completion before the end of the next process unit shutdown. Fourth, we are proposing to retain the current requirements in NSPS OOOOa for open-ended valves or lines, closed vent systems and equipment designated with no detectable emissions, and PRDs. For open-ended valves or lines, we propose to retain the requirements in 40 CFR 60.482–6a of NSPS VVa. Specifically, we are proposing that each open-ended valve or line in a new or existing process unit must be equipped with a closure device (i.e., cap, blind flange, plug, or a second valve) that seals the open end at all times except during operations requiring process fluid flow through the open-ended valve or line. The EPA is soliciting comment on requiring OGI monitoring (or EPA Method 21 monitoring for those opting PO 00000 Frm 00074 Fmt 4701 Sfmt 4702 for that alternative) on these open-ended valves or lines equipped with closure devices to ensure no emissions are going to the atmosphere. Specifically, the EPA is soliciting information that would aid in determining what additional costs would be incurred from either OGI or EPA Method 21 monitoring and repair of leaking open-ended valves or lines, and information on leak rates and concentrations of emissions, where monitoring has been performed. While the EPA is proposing to retain the no detectable emission requirement in NSPS OOOOa for closed vent systems and equipment designated as having no detectable emissions (e.g., valves or PRDs), the EPA is also soliciting comment on whether bimonthly OGI monitoring according to the proposed appendix K is appropriate to demonstrate compliance with this requirement. The current NSPS requires the closed vent systems 206 and the other equipment described above to operate with no detectable emissions, as demonstrated by an instrument reading of less than 500 ppm above background with EPA Method 21. On December 22, 2008, the EPA issued a final rule titled, ‘‘Alternative Work Practice to Detect Leaks from Equipment’’ (AWP).207 In that final rule, the EPA did not permit the use of OGI for this equipment, stating, ‘‘the AWP is not appropriate for monitoring closed vent system, leakless equipment, or equipment designated as non-leaking. While the AWP will identify leaks with larger mass emission rates, tests conducted with both the AWP and the current work practice indicate the AWP, at this time, does not identify very small leaks and may not be able to identify if non-leaking/leakless equipment are truly nonleaking because the detection sensitivity of the optical gas imaging instrument is not sufficient.’’ 73 FR 78204 (December 22, 2008). The EPA is soliciting information that would support the use of OGI for closed vent systems and equipment designated with no detectable emissions at new and existing process units, including comment on applying the proposed bimonthly OGI monitoring requirement on this equipment in place 206 For purposes of this standard, the EPA is referring to closed vent systems used equipment within process units at onshore natural gas processing plants. Closed vent systems associated with controlled storage vessels, wet seal centrifugal compressors, reciprocating compressors and pneumatic pumps are not included in this discussion and would demonstrate compliance with the no detectable emissions standard by EPA Method 21 (except for storage vessels), monthly AVO, or OGI monitoring during the fugitive emissions survey. 207 See 73 FR 78199 (December 22, 2008). E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules of the NSPS VVa annual EPA Method 21 monitoring. Finally, the EPA is proposing to retain the emission standards for PRDs found in 40 CFR 60.482–4a of NSPS VVa. This provision requires that PRDs be operated with no detectable emissions, except during pressure releases at new and existing process units. As stated above, the EPA is soliciting comment on the use of OGI to demonstrate that PRDs are meeting this operational emission standard. 2. EG OOOOc The EPA is proposing EG that include a presumptive methane standard that is the same as described above for the NSPS OOOOb for equipment leaks at existing onshore natural gas processing plants. Based on the analysis in section XII.H.2, the BSER for reducing GHGs from equipment leaks at new and existing onshore natural gas processing plants are the same. khammond on DSKJM1Z7X2PROD with PROPOSALS2 I. Well Completions Based on our understanding that there are no advances in technologies or practices, which is summarized in section XII.I, the EPA is proposing to retain the REC and completion combustion requirements for reducing methane and VOC emissions from well completions of hydraulically fractured or refractured oil and natural gas wells, as they continue to reflect the BSER. These proposed standards are the same as those for natural gas and oil wells regulated in the 2012 NSPS OOOO and 2016 NSPS OOOOa, as amended in the 2020 Technical Rule for VOC and proposed in section X.B.1 for methane.208 Because of the nature of well completions, any completion (or recompletion) is considered a new or modified well affected facility, therefore, the EPA does not believe there are existing well affected facilities to which a EG OOOOc presumptive standard for well completions would apply. J. Oil Wells With Associated Gas Associated gas originates at wellheads that also produce hydrocarbon liquids and occurs either in a discrete gaseous phase at the wellhead or is released from the liquid hydrocarbon phase by separation. There are no current NSPS requirements for this emission source. The EPA is proposing standards in the NSPS OOOOb to reduce methane and VOC emissions resulting from the venting of associated gas from oil wells. 208 See Docket ID No. EPA–HQ–OAR–2021–0317 for proposed redline regulatory text for 40 CFR 60.5375a as a reference for the specific well completion standards proposed for NSPS OOOOb. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 1. NSPS OOOOb We are proposing standards to reduce methane and VOC emissions from each oil well that produces associated gas. Based on our analysis, which is summarized in section XII.J, we are proposing a standard under NSPS OOOOb that requires owners or operators of oil wells to route associated gas to a sales line. In the event that access to a sales line is not available, we are proposing that the gas can be used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, or routed to a flare or other control device that achieves at least 95 percent reduction in methane and VOC emissions. As discussed in section XII.J, the EPA is soliciting comment on how ‘‘access to a sales line’’ should be defined. An affected facility would be defined as any oil well that produces associated gas. The proposed rule would require that when using a flare, the flare must meet the requirements in 40 CFR 60.18 and that monitoring, recordkeeping, and reporting be conducted to ensure that the flare is constantly achieving the required 95 percent reduction. As discussed in section XII.J, the EPA is soliciting comment on an alternative affected facility definition that would exclude oil wells that route all associated gas to a sales line. The EPA is also soliciting comment and information that would support requirements using other strategies to reduce venting and flaring of associated gas from oil wells. The EPA is specifically requesting comment on whether the proposed requirements will incentivize the sale or productive use of captured gas, and if not, other methods that the EPA could use to incentivize or require the sale or productive use instead of flaring. 2. EG OOOOc The EPA is proposing presumptive standards for existing oil wells in this action that are the same as discussed above for new sources. K. Sweetening Units Based on our understanding that no advances in technologies or practices are available to reduce SO2 emissions from sweetening units, as described in section XII.K, the EPA is proposing to retain the standards as it continues to reflect the BSER. These proposed standards are the same as those for sweetening units regulated in the 2016 NSPS OOOOa, and as amended in the 2020 Technical Rule.209 209 See Docket ID No. EPA–HQ–OAR–2021–0317 for proposed redline regulatory text for 40 CFR PO 00000 Frm 00075 Fmt 4701 Sfmt 4702 63183 L. Centralized Production Facilities The EPA is also proposing a new definition for ‘‘centralized production facility,’’ which is one or more permanent storage tanks and all equipment at a single stationary source used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from one or more offsite natural gas or oil production wells. This equipment includes, but is not limited to, equipment used for storage, separation, treating, dehydration, artificial lift, combustion, compression, pumping, metering, monitoring, and flowline. Process vessels and process tanks are not considered storage vessels or storage tanks. A centralized production facility is located upstream of the natural gas processing plant or the crude oil pipeline breakout station and is a part of producing operations. The EPA is proposing this definition to (1) specify how the fugitive emissions requirement apply to centralized production facilities, (2) specify how exemptions related to 40 CFR part 60, subpart K, Ka, or Kb (‘‘NSPS Kb) may apply, and (3) specify what standards would apply to reciprocating and centrifugal compressors located at these facilities. First, the EPA is proposing to specify how the fugitive emission requirements apply to centralized production facilities. The 2016 NSPS OOOOa, as originally promulgated, provided that ‘‘[f]or purposes of the fugitive emissions standards at 40 CFR 60.5397a, [a] well site also means a separate tank battery surface site collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water from wells not located at the well site (e.g., centralized tank batteries).’’ 40 CFR 60.5430a. The inclusion of centralized tank batteries in the definition of well site was used to clarify the boundary of a well site for purposes of the fugitive emissions requirements. Further, in the RTC 210 for the 2016 NSPS OOOOa we stated, ‘‘[o]ur intent is to limit the oil and gas production segment up to the point of custody transfer to an oil and natural gas mainline pipeline (including transmission pipelines) or a natural gas processing plant. Therefore, the collection of fugitive emissions components within this boundary are a part of the well site.’’ The EPA continues to define these facilities as a type of well site but is proposing a separate definition to provide further 60.5375a as a reference for the specific well completion standards proposed for NSPS OOOOb. 210 See Document ID No. EPA–HQ–OAR–2010– 0505–7632 at page 4–194. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63184 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules clarity, especially as it relates to when these facilities are modified, and thus become subject to the fugitive emissions requirements in NSPS OOOOb. The EPA has determined it is appropriate to rename this site as a centralized production facility and to provide the specific definition above to avoid confusion with the storage vessel affected facility, of which applicability is determined for a tank battery, and to better specify the facility name based on the basic function the site performs (i.e., production operations). Second, the EPA has received questions related to whether NSPS Kb would apply to the storage vessels at centralized production facilities. There is an exemption in NSPS Kb for storage vessels in the producing operations that are below a specific size. Specifically, 40 CFR 60.110(b)(4) exempts ‘‘vessels with a design capacity less than or equal to 1,589.874 m3 used for petroleum or condensate stored, processed, or treated prior to custody transfer.’’ This exemption is a revision of an exemption originally promulgated in 40 CFR part 60, subpart K (‘‘NSPS K’’). NSPS K ‘‘does not apply to storage vessels for the crude petroleum or condensate stored, processed, and/or treated at a drilling and production facility prior to custody transfer.’’ 40 CFR 60.110(b). In that final rule the EPA explained that, ‘‘[t]he storage of crude oil and condensate at producing fields is specifically exempted from the standard.’’ 39 FR 9312 (March 8, 1974). While ‘‘producing fields’’ were not explicitly defined, NSPS K defined the terms ‘‘custody transfer’’ and ‘‘drilling and production facility’’. For purposes of NSPS K, custody transfer means ‘‘the transfer of produced crude petroleum and/or condensate, after processing and/ or treating in the producing operations, from storage tanks or automatic transfer facilities to pipelines or any other forms of transportation.’’ 40 CFR 60.111(g). Drilling and production facility means ‘‘all drilling and servicing equipment, wells, flow lines, separators, equipment, gathering lines, and auxiliary nontransportation-related equipment used in the production of crude petroleum but does not include natural gasoline plants.’’ 40 CFR 60.111(h). The definition of ‘‘custody transfer’’ was later also incorporated into 40 CFR part 60, subpart Ka (‘‘NSPS Ka’’), NSPS Kb, and 40 CFR part 63, subpart HH (National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities). Instead of a categorical exemption for storage vessels located at drilling and production facilities, NSPS Ka, and subsequently NSPS Kb, adopted VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 threshold-based exemptions that are based on the capacity of an individual storage vessel used to store petroleum (crude oil) or condensate prior to custody transfer. In NSPS Ka, the EPA stated ‘‘[t]his exemption applies to storage between the time that the petroleum liquid is removed from the ground and the time that custody of the petroleum liquid is transferred from the well or producing operations to the transportation operations’’ 45 FR 23377 (April 4, 1980). In NSPS Kb, the EPA further stated that ‘‘[t]he promulgated standards for petroleum liquid storage vessels specifically exempted vessels with a capacity less than 420,000 gallons and storing petroleum (crude oil) and condensate prior to custody transfer (production vessels). The emission controls that are applicable to the storage vessels included in the standards being proposed are not applicable to production vessels.’’ 49 FR 29701. The EPA finds it inappropriate to use the controls required by NSPS K, Ka, and Kb on storage vessels located in the production segment, especially where flash emissions are prevalent. Specifically, the NSPS K, Ka, and Kb control requirements include provisions allowing the use of floating roofs to reduce emissions from storage tanks. Floating roofs are not designed to store liquid (or gases) under pressure. Pressurized liquid sent to a storage vessel from a well or separator or other process that operates above atmospheric pressure may contain dissolved gases. These gases will be released or ‘‘flash’’ from the liquid as the fluid comes to equilibrium with atmospheric pressure within the storage vessel. The flash gas will either be released from gaps in the seal system or from ‘‘rim vents’’ on the floating roof. The rim vent may be an open tube or may be fitted with a lowpressure relief valve, but it is specifically designed to allow any gas entrained or dissolved in the storage liquid to be released above the floating roof. That is, floating roofs are not designed to prevent the release of flash gas, they are only designed to limit the volatilization of a liquid that occurs when the storage liquid is directly exposed with unsaturated air. Since a significant portion of emissions from storage vessels at well sites or centralized production facilities are from flash gas, floating roofs are much less effective at reducing storage vessel emissions than venting these emissions through a CVS to a control or recovery device. Further, it is the EPA’s understanding that these centralized production facilities carry out the same operations PO 00000 Frm 00076 Fmt 4701 Sfmt 4702 that would be conducted at the individual well sites. Therefore, the EPA is proposing a definition of ‘‘centralized production facility’’ that clearly specifies these facilities are located within the producing operations. Therefore, if all other conditions are met (i.e., vessels with a design capacity less than or equal to 1,589.874 m3 used for petroleum or condensate stored, processed, or treated prior to custody transfer), storage vessels at these centralized facilities would meet the exemption criteria for NSPS Kb. Alternatively, the EPA is soliciting comment on whether it would be more appropriate to specify within the proposed NSPS OOOOb and EG OOOOc that storage vessels at well sites and centralized production facilities are subject to the requirements in NSPS OOOOb and EG OOOOc instead of NSPS K, Ka, or Kb. This alternative approach would eliminate the need for sources to determine if the storage vessel meets the exemption criteria specified in those subparts and instead focus on appropriate controls for the storage vessels based on the location and type of emissions likely present (e.g., flash emissions). Finally, the EPA is now proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of ‘‘centralized production facilities’’ above. In the 2016 NSPS OOOOa, the EPA exempted reciprocating and centrifugal compressors located at well sites from the applicable compressor standards. Reciprocating compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because we found the cost of control to be unreasonable. 81 FR 35878. However, as mentioned above, the EPA believes the definition of ‘‘well site’’ in NSPS OOOOa may cause confusion regarding whether reciprocating compressors located at centralized production facilities are also exempt from the standards. In our current analysis, described in section XII.E, we find it is appropriate to apply the same emission factors to reciprocating compressors located at centralized production facilities as those used for reciprocating compressors at gathering and boosting compressor stations. Given the results of that analysis, the EPA is proposing to apply the proposed NSPS OOOOb and presumptive standards in EG OOOOc to E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 reciprocating compressors located at centralized production facilities. The new definition above is intended to apply the results of the EPA’s analysis. We believe that this new definition is necessary in the context of reciprocating compressors to distinguish between these compressors at centralized production facilities where the EPA has determined that the standard should apply, and these compressors at standalone well sites where the EPA has determined that the standard should not apply. See section XII.E for more details of those proposed standards. Similarly, wet seal centrifugal compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because data available at the time did not suggest there were a large number of wet seal centrifugal compressors located at well sites. 81 FR 35878. In our current analysis, described in section XII.F, we find it is appropriate to apply the same emission factors to wet seal centrifugal compressors located at centralized production facilities as those used for these same compressors at gathering and boosting compressor stations. Given the results of that analysis, the EPA is proposing to apply the proposed NSPS OOOOb and presumptive standards in EG OOOOc to wet seal centrifugal compressors located at centralized production facilities. See section XII.F for more details of those proposed standards. M. Recordkeeping and Reporting The EPA is proposing to require electronic reporting of performance test reports, annual reports, and semiannual reports through the Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA’s Central Data Exchange (CDX) at https://cdx.epa.gov/ .) A description of the electronic data submission process is provided in the memorandum Electronic Reporting Requirements for New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) Rules, available in the docket for this action. Performance test results collected using test methods that are supported by the EPA’s Electronic Reporting Tool (ERT) as listed on the ERT website 211 at the time of the test would be required to be submitted in the format generated through the use of the ERT or an electronic file consistent with the xml schema on the ERT 211 https://www.epa.gov/electronic-reporting-airemissions/electronic-reporting-tool-ert. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 website, and other performance test results would be submitted in portable document format (PDF) using the attachment module of the ERT. For semiannual and annual reports, the owner or operator would be required to use the appropriate spreadsheet template to submit information to CEDRI. The EPA is also proposing to allow owners and operators the ability to seek extensions for submitting electronic reports for circumstances beyond the control of the facility, i.e., for a possible outage in CDX or CEDRI or for a force majeure event, in the time just prior to a report’s due date. The EPA is providing these potential extensions to protect owners and operators from noncompliance in cases where they cannot successfully submit a report by the reporting deadline for reasons outside of their control. The decision to accept the claim of needing additional time to report is within the discretion of the Administrator. Electronic reporting is required in the amended 2016 NSPS OOOOa, and the EPA believes that the electronic submittal of these reports in the proposed NSPS OOOOb will increase the usefulness of the data contained in those reports, is in keeping with current trends in data availability, will further assist in the protection of public health and the environment, and will ultimately result in less burden on the regulated community. Electronic reporting can also eliminate paperbased, manual processes, thereby saving time and resources, simplifying data entry, eliminating redundancies, minimizing data reporting errors, and providing data quickly and accurately to the affected facilities, air agencies, the EPA, and the public. Moreover, electronic reporting is consistent with the EPA’s plan 212 to implement E.O. 13563 and is in keeping with the EPA’s agency-wide policy 213 developed in response to the White House’s Digital Government Strategy.214 In addition to the annual and semiannual reporting requirement, the EPA is soliciting comment on what 212 EPA’s Final Plan for Periodic Retrospective Reviews, August 2011. Available at: https:// www.regulations.gov/document?D=EPA-HQ-OA2011-0156-0154. 213 E-Reporting Policy Statement for EPA Regulations, September 2013. Available at: https:// www.epa.gov/sites/production/files/2016-03/ documents/epa-ereporting-policy-statement-201309-30.pdf. 214 Digital Government: Building a 21st Century Platform to Better Serve the American People, May 2012. Available at: https:// obamawhitehouse.archives.gov/sites/default/files/ omb/egov/digital-government/digitalgovernment.html. PO 00000 Frm 00077 Fmt 4701 Sfmt 4702 63185 elements, if any, are appropriate for more frequent reporting, and what mechanism would be appropriate for the collection and public dissemination of this information. For example, it may be appropriate to make information related to large emission events public in a timelier manner than the annual reporting period. Therefore, the EPA is soliciting comment on the appropriate mechanism to use for this type of report, including how the data would be reported, who would manage that reporting system, the frequency at which the data should be reported, the potential benefits of more frequent reporting for reducing emissions, the associated burden with this type of reporting and ways to mitigate that burden, and other considerations that should be taken into account. N. Prevention of Significant Deterioration and Title V Permitting The pollutant we are proposing to regulate is GHGs, not methane as a separately regulated pollutant. As explained in section XV of this preamble, we are proposing to add provisions to NSPS OOOOb and EG OOOOc, analogous to what was included in the 2016 NSPS OOOOa and other rules regulating GHGs from electric utility generating units, to make clear in the regulatory text that the pollutant regulated by this rule is GHGs. The proposed addition of these and other provisions is intended to address some of the potential implications on the CAA Prevention of Significant Deterioration (PSD) preconstruction permit program and the CAA title V operating permit program. XII. Rationale for Proposed NSPS OOOOb and EG OOOOc The following sections provide the EPA’s BSER analyses and the resulting proposed NSPS to reduce methane and VOC emissions and the resulting proposed EG, which include presumptive standards, to reduce methane emissions from across the Crude Oil and Natural Gas source category. Our general process for evaluating BSER for the emission sources discussed below included: (1) Identification of available control measures; (2) evaluation of these measures to determine emission reductions achieved, associated costs, non-air environmental impacts, energy impacts and any limitations to their application; and (3) selection of the control techniques that represent E:\FR\FM\15NOP2.SGM 15NOP2 63186 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 BSER.215 As discussed in the 2016 NSPS OOOOa, the available control technologies will reduce both methane and VOC emissions at the same time. The revised BSER analysis we have undertaken for the sources addressed in the proposed NSPS OOOOb continues to support this conclusion. CAA Section 111 also requires the consideration of cost in determining BSER. Section IX describes how the EPA evaluates the cost of control for purposes of this rulemaking. Sections XII.A through XII.I provide the BSER analysis and the resulting proposed NSPS and EG for the individual emission sources contemplated in this action. Please note that there are minor differences in some values presented in various documents supporting this action. This is because some calculations have been performed independently (e.g., NSPS OOOOb and EG OOOOc TSD calculations for NSPS OOOOb and EG OOOOc focused on unit-level cost-effectiveness and RIA calculations focused on national impacts) and include slightly different rounding of intermediate values. For this proposed EG the EPA is proposing to translate the degree of emission limitation achievable through application of the BSER (i.e., level of stringency) into presumptive standards.216 As discussed in each of the EG-specific subsections below, the EPA’s evaluation of BSER in the context of existing sources utilized much of the same information as our BSER analysis for the NSPS. This is because within the oil and natural gas industry many of the control measures that are available to reduce emissions of methane from existing sources are the same as those control measures available to reduce VOC and methane emissions from new, modified, and reconstructed sources. By extension, many of the methane emission reductions achieved by the available control options, as well as the associated costs, non-air environmental impacts, energy impacts, and limitations to their application, are very similar if not the same for new and existing sources. Any relevant differences between new and existing sources in the context of available control measures or 215 In the context of developing the draft emissions guidelines contained herein, this general process also follows, and is intended to satisfy, certain requirements of EPA’s implementing regulations for CAA section 111(d), namely the specific listed component of a draft EG contained in 40 CFR 60.22a(b)(2), and some elements of paragraph (b)(3). 216 This is intended to satisfy certain elements of the requirements of EPA’s implementing regulations found at 40 CFR 60.22a(b)(3) and (5) with the exception of compliance times which the EPA discusses separately in section XVI. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 any other factors are discussed in the EG-specific subsections below. Where the EPA identified relevant distinctions between new and existing sources in the context of evaluating BSER, it was typically regarding the cost of control options. While many factors can cause differences in the cost of control between new and existing sources, the EPA would like to highlight two general concepts to illustrate how the oil and natural gas industry is unique. These concepts are the ‘‘size’’ of the affected facility and the type of standards. First, affected facilities defined in any given NSPS can range from entire process units to individual pieces of equipment. For affected facilities comprised of an entire process unit, or very large processes or equipment, there can be significant differences between the cost of construction or modification for a new source as compared to the cost of a retrofit required for implementation of a control at an existing source. In the case of a new sources, there can be cost savings associated with the up-front planning for the installation of controls which cannot be achieved at existing sources that must instead retrofit already existing processes or equipment. This is particularly true of controls involving equipment changes or add-on control devices. In contrast, most affected facilities for which the EPA is proposing standards in NSPS OOOOb are more narrowly defined. For example, a pneumatic controller affected facility is generally defined as a single natural gas-driven pneumatic controller, which is a discrete and relatively small piece of equipment in a larger process. Another example is the reciprocating compressor affected facility which is defined as a single reciprocating compressor. As such, the EPA did not identify the same type of cost savings associated with the up-front planning of controls in the oil and gas sector as we might in the context of larger affected facilities. We believe this is one factor that led to costs being very similar for new and existing sources. Second, with regard to the type of standards, many of the standards proposed for NSPS OOOOb, and the presumptive standards proposed for EG OOOOc, are non-numerical standards, such as work practice standards, that require limited or no significant physical modifications. The EPA found that costs for these non-numerical standards would typically not differ between new and existing sources because the work practice could be implemented in both contexts without the need to first install or retrofit any equipment. Put another way, a work PO 00000 Frm 00078 Fmt 4701 Sfmt 4702 practice tends to operate in the same manner regardless of whether the site is new or existing, and existing sites typically do not need to take any preliminary steps in order to implement the work practice. For these reasons, many of the proposed presumptive standards for EG OOOOc discussed in the following sections mirror the proposed standards identified based on the BSER analyses for NSPS OOOOb. A. Proposed Standards for Fugitive Emissions From Well Sites and Compressor Stations 1. NSPS OOOOb There are many potential sources of fugitive emissions throughout the Crude Oil and Natural Gas Production source category. Fugitive emissions occur when connection points are not fitted properly or when seals and gaskets start to deteriorate. Changes in pressure and mechanical stresses can also cause components or equipment to emit fugitive emissions. Poor maintenance or operating practices, such as improperly reseated pressure relief valves (PRVs) or worn gaskets and springs on thief hatches on controlled storage vessels are also potential causes of fugitive emissions. Additional sources of fugitive emissions include agitator seals, connectors, pump diaphragms, flanges, instruments, meters, open-ended lines, PRDs such as PRVs, pump seals, valves or controlled liquid storage tanks. In the 2021 GHGI, the methane emissions for 2019 from fugitive emissions in the Crude Oil and Natural Gas source category were 96,000 metric tons methane for petroleum systems and 351,500 metric tons for natural gas systems. These levels represent 6 percent of the total methane emissions estimated from all petroleum systems sources (i.e., exploration through refining) and 5 percent of all methane emissions from natural gas systems (i.e., exploration through distribution). In addition, fugitive emissions may be represented in other categories of the GHGI production segment; for example, a portion of fugitive emissions (as defined in this action) is also expected to be related to fugitive emissions from tank thief hatches, and thief hatches on controlled storage vessels, and those emissions are included in the emissions estimates for storage vessels in the GHGI. In the 2016 NSPS OOOOa, the EPA promulgated standards to control GHGs (in the form of limitations on methane emissions) and VOC emissions from fugitive emissions components located at well sites and compressor stations. These standards required a fugitive E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 emissions monitoring and repair program, where well sites and compressor stations had to be monitored semiannually and quarterly, respectively. a. Fugitive Emissions From Well Sites Oil and natural gas production practices and equipment vary from well site to well site. A well site can serve one well or multiple wells. Some production sites may include only a single wellhead that is extracting oil or natural gas from the ground, while other sites may include multiple wellheads with a number of operations such as production, extraction, recovery, lifting, stabilization, separation and/or treating of petroleum and/or natural gas (including condensate). In addition, the 2016 NSPS OOOOa definition of well site also includes centralized tank batteries for purposes of the fugitive emissions requirements because, like storage vessels at well sites, centralized tank batteries collect crude oil, condensate, intermediate hydrocarbon liquids, or produced water from wells; therefore, ‘‘excluding tank batteries not located at the well site could incentivize some owners or operators to place new tank batteries further away from well sites to make use of such an exemption.’’ 217 The equipment to perform these production operations (including piping and associated components, compressors, generators, separators, storage vessels, and other equipment) has components that may be sources of fugitive emissions. Therefore, the number of components with the potential for fugitive emissions can vary depending on the number of wells and the number of major production and processing equipment at the site. Another factor that impacts the operations at a well site, and the resulting fugitive emissions potential, is the nature of the oil and natural gas being extracted. This can range from well sites that only extract and handle ‘‘dry’’ natural gas to those that extract and handle heavy oil. In both the 2016 NSPS OOOOa and subsequent amendments in the 2020 Technical Rule, the EPA relied on a model plant approach to estimate emissions from well sites. Model plants were developed to provide a representation of well sites across the spectrum. Separate production-based model plants using component counts to determine baseline emissions were developed. The basic approach used was to assign a number of specific equipment types for each well site 217 See Document ID No. EPA–HQ–OAR–2010– 0505–7632 at page 4–221. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 model plant and then to estimate the number of components based on assigned numbers of components per equipment type. Primarily, the well site model plants utilized information from the DrillingInfo HPDI® database,218 the 1996 EPA/GRI Study,219 EPA’s GHG Inventory, and GHGRP subpart W. Fugitive model plants were originally developed for the 2015 NSPS OOOOa proposed rule (80 FR 56614, September 18, 2015) and evolved over time in response to new information and public comments. More information on the history of the model plant development can be found in the 2015 NSPS Proposal TSD,220 the 2016 NSPS Final TSD,221 the 2018 NSPS Proposal TSD,222 and the 2020 NSPS Final TSD.223 In this proposal, the EPA is shifting away from using model plants for well sites for the BSER analysis and is instead using an individual site-level emission-calculation approach in order to better characterize and take into account the differences at individual well sites that can lead to a vast range in the magnitude of fugitive emissions, which a model plant cannot do. Provided below is a more detailed explanation of the issues concerning the previous model plant approach, followed by a description of the sitespecific baseline emission calculation approach, which is similar to the State of Colorado’s LDAR program. In the 2020 Technical Rule, the EPA created separate model plants to represent fugitive emissions from low production well sites (those producing 15 boe or less per day) and non-low production well sites, as it was generally assumed that low producing sites would have fewer major production and processing equipment and thus lower fugitive emissions. This prior estimate of baseline emissions was calculated using model plant site designs with assumed populations of major production and processing equipment and fixed fugitive emissions component counts. While the estimated baseline emissions from the two model plants differ due to the difference in the assumed populations of major production and processing equipment and fixed fugitive emissions component counts, the estimated baseline emissions 218 Drilling Information, Inc. 2014. DI Desktop. 2014 Production Information Database. 219 Gas Research Institute (GRI)/U.S. EPA. Research and Development, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. June 1996 (EPA–600/R–96– 080h). 220 EPA–HQ–OAR–2010–0505–5021. 221 EPA–HQ–OAR–2010–0505–7631. 222 EPA–HQ–OAR–2017–0483–0040. 223 EPA–HQ–OAR–2017–0483–2290. PO 00000 Frm 00079 Fmt 4701 Sfmt 4702 63187 were intended to represent the baseline emissions for all well sites represented by each model plant. Since that rulemaking, further analysis of existing and new information indicates that there is significant variation in the well characteristics, type of oil and gas products and production levels, gas composition, operations, and types and quantity of equipment at well sites across the U.S. The TSD for this action further describes existing data and new information received since the 2020 Technical Rule that have been evaluated by the EPA to arrive at the conclusion that there is no one-size-fits-all approach to predicting emissions from well sites and that the emissions vary greatly, in ways that bear little correlation to production levels alone. For example, site-level methane emissions data from comprehensive studies sampled across several different regions at numerous well sites, shows a wide range of methane emissions (i.e., ranging from as low as 0 to as high as 1,200 tpy for marginal or low production wells). Additionally, recently obtained ICR data indicate that actual component counts at well sites with equipment could be higher than those estimated by model plants for low and non-low production, e.g., EPA’s non-low model plant could be underestimating number of wells, tanks and separators; and similar observations were made for low production based on this data. Contrary to previous general assumptions, information reviewed also shows that it is not necessarily the case that fugitive emissions from sites with lower production have lower emissions than sites with higher production. In fact, it is quite possible that the inverse can be true (i.e., lower producing sites could have higher emissions and inversely, higher producing sites could have lower emissions.) More information can be found in the NSPS OOOOb and EG TSD for this proposal. Therefore, the EPA has concluded that the previous model plant approach, which was based on two production levels (equal/above or below 15 boe per day) and the estimated equipment types and numbers associated with each of the two production levels, may not be reflective of the actual baseline fugitive emissions from well sites. Further, the potential for fugitive emissions at any given site is impacted more by the number and type of equipment at the site and maintenance practices, which can vary widely among well sites with low production.224 Given these 224 See https://pubs.acs.org/doi/10.1021/ acs.est.0c02927, https://data.permianmap.org/ E:\FR\FM\15NOP2.SGM Continued 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63188 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules limitations in utilizing model plants to analyze fugitive emission reduction programs at well sites with widely varying configurations, operations, and production levels, we find it appropriate to shift away from using model plants and instead rely on the potential fugitive emissions at the individual site in our BSER analysis and resulting proposed standards. Therefore, this new analysis, which is described below, is conducted on this basis. This site-specific baseline emissions calculation approach is similar to the State of Colorado’s LDAR program. The concept is that each site calculates its baseline methane emissions for all the equipment at the site, the number and type of equipment at the well site, the number of fugitive emissions components associated with each piece of equipment, and the site-specific gas composition. The fugitive monitoring frequency would be based on the baseline site-specific methane emissions level calculated based on this information. This calculation is described in detail in section XI.A.2. We believe that this approach will more accurately depict the emissions profile at each individual well site. As a result, the EPA is conducting the BSER analysis based on site-level baseline methane emissions, where the analysis is performed in increments of 1 tpy of site-level baseline methane emissions as discussed more below. During the rulemaking for the 2016 NSPS OOOOa, the EPA analyzed two options for reducing fugitive methane and VOC emissions at well sites: A fugitive emissions monitoring program based on individual component monitoring using EPA Method 21 for detection combined with repairs and a fugitive emissions monitoring program based on the use of OGI detection combined with repairs. Finding that both methods achieve comparable emission reduction but OGI was more cost effective, the EPA ultimately identified semiannual monitoring of well sites using OGI as the BSER. 81 FR 35856 (June 3, 2016). While there are several new fugitive emissions technologies under development, the EPA needs additional information to fully characterize the cost, availability, and capabilities of these technologies, and they are therefore not being evaluated as potential BSER at this time. However, we are proposing the use of these technologies as an alternative screening method as described in section XI.A.5. For this analysis for both pages/flaring, and https://www.edf.org/sites/ default/files/documents/PermianMapMethodology_ 1.pdf. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 the NSPS and the EG, we re-evaluated the use of OGI as BSER. In the discussion below, we evaluate OGI control options based on varying the frequency of conducting the survey and fugitive emissions repair threshold (i.e., the visible identification of methane or VOC when an OGI instrument is used). For this analysis, we considered biennial, annual, semiannual, quarterly, and monthly survey frequency for well sites. The regulatory concept for the proposed NSPS OOOOb is that the required frequency of fugitive monitoring would be based on total site baseline methane emissions. At well sites, the composition of gas is predominantly methane (approximately 70 percent on average). Therefore, as shown in our analysis, compared to VOC, methane better reflects the baseline emission level where it is cost effective to regulate both methane and VOC fugitive emissions at well sites. For this reason, we chose to use methane as the threshold for our determination. For the BSER analyses, we selected for evaluation total site-wide methane emissions increments of 1 tpy of sitelevel baseline methane emissions ranging from 1 tpy to 50 tpy. The EPA acknowledges that the site-level baseline methane emissions calculated may not account for the presence of large emission events when they occur. However, the EPA has found it inappropriate to apply a factor that assumes every site is experiencing a large emission event annually based on information suggesting that only a small percentage of sites experience these events at any given time.225 In 2015, we evaluated the potential emission reductions from the implementation of an OGI monitoring program where we assigned an emission reduction of 40, 60, and 80 percent to annual, semiannual, and quarterly monitoring survey frequencies, respectively. The EPA re-evaluated the control efficiencies under different monitoring frequencies for the 2020 Technical Rule based on comments received on the 2018 proposal and concluded that the assigned control efficiencies described above can be expected from the corresponding 225 Brandt, A.R., Heath, G.A., Cooley, D. (2016). Methane Leaks from Natural Gas Systems Follow Extreme Distributions. Environ. Sci. Technol. 50, 12512, https://pubs.acs.org/doi/abs/10.1021/ acs.est.6b04303; Zavala-Araiza, D., Alvarez, R., Lyon, D, et al. (2016). Super-emitters in natural gas infrastructure are caused by abnormal process conditions. Nat Commun 8, 14012 (2017). https:// www.nature.com/articles/ncomms14012; ZavalaAraiza, D., Lyon, D., Alvarez, R. et al. (2015). PNAS 112, 15597. https://www.pnas.org/content/112/51/ 15597. PO 00000 Frm 00080 Fmt 4701 Sfmt 4702 monitoring frequencies using OGI.226 No other information reviewed since that time indicates that the assigned reduction frequencies are different than previously established and the reduction efficiencies are consistent with what current information indicates. In addition, we also evaluated biennial survey frequency for well sites assuming an achievable reduction frequency of 30 percent, and monthly monitoring where information evaluated indicated monthly OGI monitoring has the potential of reducing emissions up towards 90 percent. It is worth noting that these calculations are based on the expected reductions from ‘‘typical’’ component equipment leaks that occur with wellmaintained sites. The EPA is aware of situations where equipment malfunctions related to equipment components can cause large emission events that are described in detail in section XII.A.5. In these cases, we expect the emission reductions associated with the different monitoring frequencies evaluated would be significantly higher than assumed above and is the reason we solicit comment on the proposed alternative screening program using advanced measurement technologies to identify and quantify large emission sources. Given the intermittent and stochastic nature of large emission events, it is difficult to apply emission factors that predict the probability of a site experiencing these events within any timeframe. As stated above, the EPA finds it inappropriate to apply a factor that assumes every site is experiencing a large emission event annually given the available data. However, we recognize that identifying and stopping these large emission events is a central purpose of the monitoring requirements proposed in this document, and that quantifying the pollution reduction benefits associated with addressing these large emission events is important to fully capture the benefits and cost-effectiveness of our proposed fugitive emissions monitoring requirements. We also acknowledge there is substantial ongoing research on large emission events that may further inform the EPA’s calculations, including the potential to develop factors that take into account a distribution of emissions across well sites and the associated emissions reductions achieved when large emission events are included in the calculation. We evaluated the costs of a monitoring and repair program under various monitoring frequencies. For 226 See 85 FR 57412 and section 2.4.1.1 of the 2020 TSD. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules well sites, the capital costs associated with the fugitives monitoring program were estimated to be $1,030 per well site. These capital costs include the cost of developing the fugitive emissions monitoring plan and purchasing or developing a recordkeeping data management system specific to fugitive emissions monitoring and repair. Consistent with the analyses used for the 2016 NSPS OOOOa and 2020 Technical Rule, the EPA assumes that each company will develop a monitoring plan and recordkeeping system that covers a company-defined area, which is assumed to include 22 well sites. This assumption is used because there are several elements of the fugitive monitoring program that are not site-specific. The total company-defined area (22 well site) capital costs are divided evenly to arrive at the $1,030 capital cost per well site estimate. When evaluating the annual costs of the fugitive emissions monitoring and repair requirements (i.e., monitoring, repair, repair verification, data management licensing fees, recordkeeping, and reporting), the EPA considers costs at the individual site level. Estimates for these costs were updated extensively as part of the 2020 Technical Rule, and the EPA has made further updates for this proposal based on more recent information. With these updates, the estimated annual costs of the fugitive emissions program at well sites are estimated to range from $2,490 for biennial monitoring to $8,140 for monthly monitoring.227 These total annual costs include annualization of the up-front cost at 7 percent interest rate over 8 years. We note these costs are representative of the average annual costs expected at well sites, where larger sites may have larger costs associated with longer surveys or potentially more repairs, while smaller sites may experience the opposite with shorter surveys or potentially less repairs. Therefore, we believe the costs developed for well sites are representative of OGI fugitives monitoring program costs and reflect the best information available at this time. The EPA requests comment on its range of cost estimates for an OGI fugitives monitoring program. The EPA believes that there will be sufficient supply of OGI equipment and available OGI camera operators for industry to conduct all required monitoring, upon 227 As a comparison, the annualized costs for fugitive emissions monitoring and repair at well sites were estimated to range from $1,900 to $3,500 for annual to quarterly monitoring, respectively, in the 2020 Technical Rule. See 2020 TSD, attachment 5 at Document ID No. EPA–HQ–OAR–2017–0483– 2290. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 the effective date of the NSPS OOOOb and the subsequent implementation of the EG OOOOc. However, the EPA requests additional information on this capacity and whether there is a likelihood of shortages in the early years of the program that might raise costs. The EPA is also requesting comment on the proposed appendix K and whether the proposed training, certification, and audit provisions are appropriate and do not place undue burden on the ability of industry to satisfy the regulatory requirements. At well sites, there are savings associated with the gas not being released. The value of the natural gas saved is assumed to be $3.13 per Mcf of recovered gas. Annual costs were also calculated considering these savings. As discussed in section XI.C, natural gas-driven intermittent pneumatic controllers are designed to vent during actuation only, but these devices are known to malfunction and operate incorrectly, which causes them to release natural gas to the atmosphere when idle. The EPA is proposing a zero VOC and methane emissions standard for natural gas-driven intermittent pneumatic controllers. However, for sites in Alaska located in the production segment (well sites, gathering and boosting stations, and centralized tank batteries) and in the transmission and storage segment that do not have electricity, the EPA is proposing a standard wherein intermittent natural gas-driven pneumatic controllers only vent during actuation and not when idle. See section XII.C on pneumatic controllers for a full explanation of this standard. While these intermittent controllers are their own separate affected facility, we are proposing that they be monitored in conjunction with the fugitive emissions components located at the same well site to verify proper actuation and that venting does not occur during idle times. We created a matrix that includes, for each site-wide methane emission level, the capital (up front) cost, annual costs (with and without the consideration of savings), emission reductions for methane and VOC, and cost effectiveness (dollar per tons of emission reduction). Cost effectiveness was calculated using two approaches; the single pollutant approach where all the costs are assigned to the reduction of one pollutant; and the multipollutant approach, where half the costs are assigned to the methane reduction and half to the VOC reduction, see discussion in preamble section IX. This was repeated for each site-wide methane emissions level for each monitoring frequency. There were several trends PO 00000 Frm 00081 Fmt 4701 Sfmt 4702 63189 shown in this matrix. As noted above, the annual cost for each individual monitoring frequency is applied to all site-wide emission levels when evaluating that frequency. Therefore, as the emissions (and potential emission reductions) increased, the fugitive emissions monitoring became more cost-effective. For example, for semiannual monitoring, the cost effectiveness ranged from $5,300 per ton of methane reduced (for a 1 tpy sitewide methane site) to $100 per ton (for a 50 tpy site-wide methane site). Also, because the emission reduction increase was greater than the cost increase with increasing monitoring frequency, the fugitive emissions monitoring became more cost-effective with increasing monitoring frequency. For example, for a 10 tpy site-wide methane site, the methane cost effectiveness for annual monitoring was $750 per ton, $530 per ton for semiannual monitoring, and $525 per ton for quarterly monitoring. This trend did not extend to monthly monitoring, as the cost of monthly monitoring increases significantly (almost double) compared to quarterly monitoring, while the emission reduction only increased by 10 percent. The complete matrix is available in the NSPS OOOOb and EG TSD for this rulemaking. The matrix shows that, on a multipollutant basis, both semiannual and quarterly monitoring at well sites with baseline emissions as low as 2 tpy is cost-effective, and that at 3 tpy, both semiannual and quarterly monitoring are cost-effective based on the methane emissions alone. Cost-effectiveness, however, is not the only relevant factor in setting the BSER, particularly for a source as numerous and diverse as well sites. We estimate that there will be approximately 21,000 new wells each year (and 410,000 existing wells) to which the proposed fugitive emissions requirements will apply.228 Various studies demonstrate that the vast majority of emissions come from a relatively small subset of wells.229 230 228 Estimated well counts are based on nonwellhead only sites. Based on information provided by API, we assume that 27% of sites are wellhead only; see Memoranda for Meetings with the American Petroleum Institute (API), September 23, 2021, located at Docket ID No. EPA–HQ– OAR– 2021–0317. Absent additional information, we also assume that 27% of wells are wellhead only. The estimated new well count reflects the arithmetic average of well counts over the analysis horizon in the RIA, 2023–2035. The estimated existing well count reflects the total in 2026, which is the first year that we estimate impacts for the emissions guidelines. 229 Brandt, A., Heath, G., Cooley, D. (2016) Methane leaks from natural gas systems follow E:\FR\FM\15NOP2.SGM Continued 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63190 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules The EPA would like to ensure that resources and effort are focused on those wells that emit the most methane and VOC. Moreover, given the diversity of ownership, while our cost assumption that distributes the costs of recordkeeping evenly across 22 sites within a company-defined area is a reasonable estimate for the population as a whole, it may underestimate the costs and therefore overestimate the cost-effectiveness for owners with fewer than 22 well sites (and conversely, underestimate cost-effectiveness for owners with more than 22 well sites). In order to best focus resources and effort on the well sites with the greatest emissions and more accurately capture costs, particularly for owners with fewer well sites, the EPA requests comment on the number of wells that likely emit at each baseline emissions level, and the baseline emissions level of wells generally owned by owners with few wells. The EPA anticipates that it may refine its BSER determination for well sites through its supplemental proposal based on the information gathered from commenters. Taking these factors into account, and as explained in more detail below, the EPA proposes to conclude that (1) BSER for well sites with a baseline site-wide emissions level of less than 3 tpy is no regular monitoring, but that to help ensure that these sites actually emit at less than 3 tpy, a one-time survey (following each calculation of site-level baseline methane emissions) would be required to ensure that any abnormalities are addressed; (2) BSER for well sites with a baseline site-wide emissions level of 3 tpy or greater is quarterly monitoring. Because of the uncertainties discussed above, and as explained in more detail below, the EPA further co-proposes to conclude that BSER for well sites with a baseline sitewide emissions level of 3 tpy or greater and less than 8 tpy is semiannual monitoring. Our co-proposal is the same as our main proposal with regard to well sites whose baseline site-wide emissions are less than 3 tpy (no regular monitoring, but a one-time survey) and whose emissions are 8 tpy or greater (quarterly monitoring). The EPA estimates that a majority of fugitive emissions (approximately 86%) can be attributed to wells with site-wide baseline emissions of 3 tpy or greater, where 54% can be attributed to wells extreme distributions. Environ. Sci. Technol., DOI: 10.1021/acs.est.6b04303. 230 Zavala-Araiza, D., Alvarez, R., Lyon, D, et al. (2016). Super-emitters in natural gas infrastructure are caused by abnormal process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/ articles/ncomms14012. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 with site-wide baseline emissions of 8 tpy or greater.231 Proposed BSER for Well Sites with Baseline Emissions Less Than 3 tpy. As noted, in both our main proposal and our co-proposal, we propose to conclude that BSER for well sites with baseline emissions of less than 3 tpy is no regular monitoring, but a one-time survey to help ensure that these sites actually emit at less than 3 tpy. Based on the matrix described above, the EPA determined that where total site baseline methane emissions are 2 tpy, semiannual and quarterly monitoring costs approximately $2,700/ton methane reduced, while biennial and annual monitoring costs approximately $4,000/ ton methane reduced. The costs for VOC reductions range from $10,000 to $15,000/ton VOC reduced for quarterly to biennial monitoring, respectively. These costs are outside the range of what we are proposing to consider cost effective on a single-pollutant basis for both methane and VOC. See Section IX.B. However, when considered on a multipollutant basis, the costs of semiannual and quarterly monitoring are approximately $1,350 per ton methane reduced, and approximately $5,000 per ton of VOC, which we do consider cost-effective. Thus, for sites with total baseline methane emissions of 2 tpy, we conclude that regular monitoring at semiannual or quarterly frequencies would be cost-effective.232 We do not propose to conclude that routine monitoring with OGI is the BSER for sites with baseline emissions of less than 3 tpy, however, for several reasons. While the estimates for semiannual and quarterly monitoring are within what we consider to be cost effective for well sites with baseline emissions of 2 tpy, in light of the large cohort of relatively lower-emitting sites, we are concerned that our cost effectiveness estimates may not accurately capture the costs, and therefore cost-effectiveness, of routine monitoring with OGI for businesses that own relatively few well sites. Throughout the development of the 2016 NSPS OOOOa, and in subsequent analyses and rulemaking actions, industry stakeholders have consistently stated that the fugitive monitoring requirements are particularly burdensome for smaller entities that 231 Percentages were estimated for the baseline scenario in the RIA for the 2030 analysis year by combining the bin percentages presented in RIA Table 2–4 with the projected well site activity data documented in the RIA. 232 The NSPS OOOOb and EG OOOOc TSD also provide costs for monitoring at 1 tpy, which is not considered cost-effective at any frequency evaluated. PO 00000 Frm 00082 Fmt 4701 Sfmt 4702 own fewer well sites. The EPA believes that many of these smaller entities are likely to own well sites with baseline emissions of less than 3 tpy, a category that tends to include smaller and less complex facilities with few or no major pieces of production and processing equipment.233 And as noted, the EPA would like to ensure that resources and effort are focused on well sites with significant emissions. Given the possibility that our cost-effectiveness analysis has overestimated the average number of sites, and therefore underestimated the cost-effectiveness, for this cohort of well sites, the EPA is proposing no regular monitoring at sites with baseline site-wide emissions of less than 3 tpy. While the EPA is proposing to conclude that BSER for well sites with total site-level baseline methane emissions less than 3 tpy is no regular monitoring, we believe it is essential to ensure that well sites in this monitoring tier are operating in a well-controlled manner, and are not experiencing leaks or malfunctions that would cause their emissions to exceed 3 tpy. Therefore, the EPA is proposing a requirement for owners and operators to conduct a survey, and perform repairs as needed, to demonstrate that the well site is free of leaks or malfunctions and is therefore operating in a manner consistent with the baseline methane emissions calculation.234 This survey could employ any method available that would demonstrate the actual emissions are consistent with the baseline calculation, including, but not limited to, the use of OGI, EPA Method 21 (which includes provisions for a soap bubble test), or alternative methane detection technologies like those discussed in the proposed screening alternative in section XI.A.5. The EPA seeks comment on all aspects of this proposed BSER determination, including information, data, and analysis that would shed further light on the factors and concerns just expressed and that would support the establishment of ongoing monitoring requirements at the cohort of sites with baseline methane emissions below 3 tpy. Among other things, the EPA seeks 233 Anna M. Robertson, Rachel Edie, Robert A. Field, David Lyon, Renee McVay, Mark Omara, Daniel Zavala-Araiza, and Shane M. Murphy. ‘‘New Mexico Permian Basin Measured Well Pad Methane Emissions Are a Factor of 5–9 Times Higher Than U.S. EPA Estimates.’’ Environmental Science & Technology 2020 54 (21), 13926–13934. DOI: 10.1021/acs.est.0c02927. 234 We anticipate that during the survey to confirm their baseline methane emissions and thus exemption status, sources would also repair the leaks found, consistent with our understanding of the standard industry practice. E:\FR\FM\15NOP2.SGM 15NOP2 63191 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules comment on the ownership profile of well sites with site-wide baseline emissions less than 3 tpy, the extent to which well sites in this cohort are owned by firms that own relatively few wells, and the relative economic costs associated with requiring regular OGI monitoring at these wells. The EPA also seeks information that would improve our understanding of the overall number of wells that would fall in this cohort of sites, and the contribution these wells make to overall fugitive emissions. And the EPA seeks comment on our estimates of the costs and emission reduction associated with OGI monitoring at this cohort of sites, or other data and analysis that would provide support for regular OGI monitoring at these sites. In addition, the EPA notes that the advanced measurement technologies that form the basis of our proposed alternative screening option in section XI.A.5 could be particularly well-suited for rapidly and cost-effectively detecting recurrences of large emitting events at sites with baseline emissions below 3 tpy. Accordingly, the EPA seeks comment that could inform whether to require the use of these technologies for ongoing monitoring at this cohort of sites, including information on the capabilities of these emerging technologies, methodologies for their use, and the costs and emission reductions associated with using these advanced measurement technologies as part of a mandatory monitoring regime. If appropriate, and based on input received during the comment period, the EPA may consider further addressing monitoring requirements for sites with baseline emissions below 3 tpy as part of a supplemental proposal. Additionally, the EPA is soliciting comment on different criteria, such as the number of well sites owned by a specific owner, that could better account for factors that may affect the costs of fugitive emissions monitoring. As noted, while the EPA has presented costs on an individual site-level, we have also distributed the costs of recordkeeping evenly across an assumed 22 sites within a company-defined area. While this may be appropriate for companies with larger ownership, it is likely underestimating the cost (and overestimating the cost-effectiveness) on owners with fewer sites. Information provided on small businesses, including ownership thresholds, could be used to further determine differences in OGI monitoring requirements at well sites through a supplemental proposal. Further, the EPA is soliciting comment on whether the presence of specific major production and processing equipment types at a well site warrants a separate monitoring frequency consideration even where the calculated total site-level baseline methane emissions are below 3 tpy. As mentioned throughout this preamble, the EPA is concerned about the presence of large emission events, which various studies have shown are most often attributed to specific equipment. This equipment includes separators paired with onsite storage vessels, combustion devices, and intermittent pneumatic controllers.235 236 237 Therefore, the EPA is soliciting comment on whether well sites with these specific types of equipment present must conduct at least semiannual monitoring, regardless of the total site-level baseline methane emissions calculated, including those sites calculated below 3 tpy. Finally, the EPA believes there is a subset of well sites (i.e., wellhead only well sites) that will never have baseline methane fugitive emissions of 3 tpy or greater. Therefore, the proposed rule would not define these sites as affected facilities, thus removing the need for these sites to determine baseline emissions. As defined in the 2020 Technical Rule, a ‘‘wellhead only well site’’ is ‘‘a well site that contains one or more wellheads and no major production and processing equipment.’’ The term ‘‘major production and processing equipment’’ is defined as including reciprocating or centrifugal compressors, glycol dehydrators, heater/ treaters, separators, and storage vessels collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water. As described earlier in this section, sites will calculate their baseline methane emissions using a combination of population-based emission factors and storage vessel emissions. The population-based emission factors include emissions from wellheads, reciprocating and centrifugal compressors, glycol dehydrators, heater/ treaters, separators, natural gas-driven pneumatic pumps, and natural gasdriven pneumatic controllers (both continuous and intermittent). By definition, a wellhead only well site would not have emissions associated with the major production and processing equipment, which includes storage vessels. Further, this proposed rule would not allow the use of natural gas-driven pneumatic controllers at any location (except on the Alaska North Slope), including wellhead only well sites. Therefore, the only emissions would be calculated based on the fugitive emissions components associated with the wellhead, which we believe would never be above 3 tpy. Proposed BSER for Sites with Baseline Emissions of 3 tpy or Greater. The EPA next evaluated what frequency of OGI monitoring is BSER for well sites where the total site-level baseline methane emissions are 3 tpy or greater. Table 14 summarizes the cost-effectiveness information for each monitoring frequency evaluated at this threshold. TABLE 14—SUMMARY OF EMISSION REDUCTIONS AND COST–EFFECTIVENESS FOR SITE–LEVEL BASELINE METHANE EMISSIONS OF 3 TPY Methane emission reduction (tpy/site) Annual cost ($/yr/site) Monitoring frequency Single-pollutant VOC emission reduction (tpy/site) Methane costeffectiveness ($/ton) Multipollutant VOC costeffectiveness ($/ton) Methane costeffectiveness ($/ton) VOC costeffectiveness ($/ton) khammond on DSKJM1Z7X2PROD with PROPOSALS2 3 tpy site-level baseline methaneemissions Biennial .......................................................... Annual ........................................................... Semiannual ................................................... Quarterly ........................................................ Monthly .......................................................... $2,500 3,000 3,200 4,200 8,100 235 Id. 236 Tyner, David R., Johnson, Matthew R., ‘‘Where the Methane Is—Insights from Novel Airborne LiDAR Measurements Combined with Ground Survey Data.’’ Environmental Science & Technology VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 0.90 1.20 1.80 2.40 2.70 0.25 0.33 0.50 0.67 0.75 $2,800 2,500 1,800 1,800 3,000 2021 55 (14), 9773–9783. DOI: 10.1021/ acs.est.1c01572. 237 Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al. Closing the methane gap in US oil and natural gas production emissions inventories. Nat PO 00000 Frm 00083 Fmt 4701 Sfmt 4702 $10,000 9,000 6,400 6,300 11,000 $1,400 1,250 900 900 1,500 $5,000 4,500 3,200 3,200 5,400 Commun 12, 4715 (2021). https://doi.org/10.1038/ s41467-021-25017-4. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63192 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules Based on the information summarized in Table 14, the average costs per ton reduced appear to be reasonable for either semiannual or quarterly monitoring when site-level baseline methane emissions are 3 tpy or greater under the single pollutant approach for methane (biennial, annual, or monthly are outside of what the EPA considers reasonable for VOCs in the single pollutant approach), or reasonable at any frequency under the multipollutant approach. In addition to considering the average costs per ton reduced for these sites, the EPA also evaluated the incremental cost associated with progressing to greater monitoring frequencies. To conduct this analysis, the EPA first considered semiannual monitoring for these sites as a baseline for comparison. Since 2016, owners and operators have been conducting semiannual monitoring pursuant to NSPS OOOOa, State requirements, or voluntarily, thus demonstrating the reasonableness of that frequency. Additionally, the cost is comparable to the costs found reasonable in the 2016 NSPS OOOOa 238 for both the single pollutant approach for methane or multipollutant approach for both methane and VOC. To determine if quarterly monitoring is reasonable for sites with total baseline methane emissions of 3 tpy, we evaluated the incremental costs of going from semiannual to quarterly monitoring. The incremental costs of semiannual to quarterly monitoring for an emissions baseline of 3 tpy methane is $1,700/ton methane and $6,000/ton VOC using the single pollutant approach (and $800/ton methane and $3,000/ton VOC using the multipollutant cost effectiveness approach). These incremental costs are within the range we find reasonable in this proposal under the single pollutant approach for methane and under the multipollutant approach. We next evaluated monthly monitoring for this cohort. As shown in Table 14, monthly monitoring appears reasonable under the multipollutant approach. Therefore, we evaluated the incremental costs of going from quarterly monitoring to monthly monitoring to determine if monthly monitoring is appropriate. Table 15 summarizes these incremental costs. As shown in Table 15, the incremental cost of going from quarterly to monthly monitoring when baseline emissions are 238 The 2020 Technical Rule amended only the VOC standards in the 2016 NSPS OOOOa and, as discussed in section X.A, incorrectly identified $738/ton as the highest value that the EPA found cost effective for methane reduction in the 2016 NSPS OOOOa. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 3 tpy is $13,000/ton methane and $47,000/ton VOC under the single pollutant approach ($6,500/ton methane and $23,500/ton VOC under the multipollutant approach). In both approaches, these costs are outside the range of what we are proposing to consider cost effective. See Section IX.B. Based on the analysis described above, we propose to find that quarterly monitoring at well sites with total sitelevel baseline methane emissions of 3 tpy or greater is the BSER. We note that California requires quarterly inspections for all well sites under its LDAR requirements in Code of Regulations, Title 17, Division 3, Chapter 1, Subchapter 10 Climate Change, Article 4, Article Subarticle 13: Greenhouse Gas Emission Standards for Crude Oil and Natural Gas Facilities, which supports a conclusion that quarterly monitoring at these sites is feasible and costeffective.239 Accordingly, the EPA’s primary proposal is to conclude that BSER for well sites with total site-level baseline emissions of less than 3 tpy is no regular monitoring (but a one-time survey) and that BSER for well sites with total sitelevel baseline emissions of 3 tpy or greater is quarterly monitoring and repair. While the EPA is proposing quarterly OGI monitoring for well sites with total site-level baseline methane emissions of 3 tpy or greater, we are concerned this cost-effectiveness analysis may not fully account for the numerosity and diversity of sites and their potential emission profiles. We further note that some States with established fugitive emissions monitoring programs have provided for more graduated frequencies that recognize this diversity among sites. For example, Colorado’s Regulation 7 Control of Ozone via Ozone Precursors and Control of Hydrocarbons via Oil and Gas Emissions 240 requires a tiered inspection frequency regime that provides for semiannual monitoring at site-wide baseline emissions thresholds that far exceed the EPA’s proposed 3 tpy threshold. Under the Colorado regulations, a semiannual inspection frequency is required for well production facilities with uncontrolled actual VOC emissions between 2 and 12 tpy (corresponding to approximately 7 to 43 tpy methane). Quarterly inspections are required for well sites without storage tanks and with uncontrolled actual VOC emissions between 12 and 20 tpy (corresponding 239 https://ww2.arb.ca.gov/sites/default/files/ classic/regact/2016/oilandgas2016/ogfro.pdf. 240 https://cdphe.colorado.gov/aqcc-regulations. PO 00000 Frm 00084 Fmt 4701 Sfmt 4702 to approximately 43 to 72 tpy methane), and for well sites with storage tanks and with uncontrolled actual VOC emissions between 12 and 50 tpy (corresponding to approximately 43 to 180 tpy methane). Colorado Regulation 7 also requires monthly inspections for well production facilities without storage tanks with uncontrolled actual VOC emissions above 20 tpy (and above 50 tpy for facilities with storage tanks). The proposed thresholds for quarterly monitoring in this action are more stringent than the Colorado regulations when compared using the gas composition ratio of 0.28 VOC to methane that is used in our BSER analysis. Specifically, the VOC emissions associated with a site-level baseline methane emission rate of 3 tpy are 0.83 tpy VOC, less than half the VOC threshold that requires semiannual monitoring and 14.5 times lower than the VOC threshold requiring quarterly monitoring in Colorado. Although Colorado’s regulations are most directly comparable to the EPA’s proposed approach, other States also provide for more graduated monitoring frequencies. For example, Ohio’s General Permits 12.1 and 12.2 initially require quarterly monitoring for well sites, followed by a reduced monitoring frequency of semiannual or annual monitoring depending on the fraction of equipment found to be leaking.241 When considering these State programs, particularly the comparison of our proposal to Colorado’s thresholds; the fact that our costeffectiveness calculation may not account for the diversity of emissions and sites; and the concerns we have raised regarding the cost-effectiveness for businesses with fewer well sites than are assumed in our cost-effectiveness analysis (many of whom we anticipate are small businesses), the EPA believes it is also appropriate to co-propose semiannual monitoring for well sites in a middle cohort—those with total sitelevel baseline emissions of 3 tpy or greater and less than 8 tpy. We seek comment on the number and ownership profile of wells that would fall into this category to better understand whether semiannual monitoring is an appropriate monitoring frequency for sites in this range. To inform this analysis, we evaluated methane emissions in 1 tpy increments starting at 3 tpy. Tables 15a and 15b summarize the total costs and incremental costs of semiannual to quarterly for baseline methane 241 https://epa.ohio.gov/dapc/genpermit/oil-andgas-well-site-production. E:\FR\FM\15NOP2.SGM 15NOP2 63193 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules emissions of 3 tpy or greater and less than 8 tpy. TABLE 15A—SUMMARY OF TOTAL COST–EFFECTIVENESS FOR FUGITIVE MONITORING AT WELL SITES Annual cost ($/yr/site) Site-level baseline methane emissions (tpy) Single pollutant cost-effectiveness Methane ($/ton) I Multipollutant cost-effectiveness VOC ($/ton) Methane ($/ton) I VOC ($/ton) Semiannual Monitoring 3 4 5 6 7 8 ........................................................................................... ........................................................................................... ........................................................................................... ........................................................................................... ........................................................................................... ........................................................................................... $3,200 3,200 3,200 3,200 3,200 3,200 $1,800 1,300 1,100 890 760 670 $6,400 4,800 3,800 3,200 2,700 2,400 $890 670 530 440 380 330 $3,200 2,400 1,900 1,600 1,400 1,200 1,800 1,300 1,000 880 750 660 6,300 4,700 3,800 3,200 2,700 2,400 880 660 530 440 380 330 3,200 2,400 1,900 1,600 1,400 1,200 Quarterly Monitoring 3 4 5 6 7 8 ........................................................................................... ........................................................................................... ........................................................................................... ........................................................................................... ........................................................................................... ........................................................................................... 4,200 4,200 4,200 4,200 4,200 4,200 TABLE 15B—SUMMARY OF INCREMENTAL COST–EFFECTIVENESS FOR FUGITIVE MONITORING AT WELL SITES Incremental annual cost ($/yr/site) Site-level baseline methane emissions (tpy) Incremental methane emission reduction (tpy/site) Incremental VOC emission reduction (tpy/site) Incremental cost-effectiveness Methane ($/ton) VOC ($/ton) Incremental for semiannual to quarterly khammond on DSKJM1Z7X2PROD with PROPOSALS2 3 4 5 6 7 8 ........................................................................................... ........................................................................................... ........................................................................................... ........................................................................................... ........................................................................................... ........................................................................................... While there is no obvious cutoff point, the EPA anticipates that well sites with calculated baseline emissions of 8 tpy or greater will generally consist of complex sites comprising multiple wellheads and/or one or more of the major pieces of production or processing equipment that are known to have a propensity for causing large emissions events. The EPA also believes it is possible that at 8 tpy and greater, well sites are both more likely to be owned by companies with a larger number of sites and that the owners of these wells are likely to be larger companies. Lastly, the EPA estimates that a large share of fugitive emissions (approximately 54%) can be attributed to wells with site-wide baseline emissions of 8 tpy or greater.242 For these reasons, the EPA believes that an 8 tpy threshold for quarterly monitoring 242 Percentage estimated using the analysis underpinning the baseline scenario in the RIA for the 2030 analysis year. VerDate Sep<11>2014 20:46 Nov 12, 2021 Jkt 256001 $1,000 1,000 1,000 1,000 1,000 1,000 0.60 0.80 1.00 1.20 1.40 1.60 would appropriately focus resources on the wells with the largest emissions profiles, and that concerns about on the costs for small owners or operators are most attenuated for this cohort of relatively large and high-emitting sites. As noted above, we seek comment on whether it is sensible to have a middle cohort with a semiannual monitoring requirement and, if so, what the bounds of that cohort should be. In making this determination, the EPA is particularly interested in comments regarding the number and ownership profiles of well sites that may fall into this middle cohort. As required by section 111, the EPA’s proposed BSER analysis for fugitive emissions from all well sites has considered nonair quality health and environmental impacts. No secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of fugitive emissions components. There are some PO 00000 Frm 00085 Fmt 4701 Sfmt 4702 0.17 0.22 0.27 0.33 0.39 0.45 $1,700 1,250 1,000 840 720 630 $6,000 4,500 3,600 3,000 2,600 2,250 emissions that would be generated by contractors conducting the OGI camera monitoring associated with driving to and from the site for the fugitive emissions survey. Using AP–42 mobile emission factors and assuming a distance of 70 miles to the well site, the emissions generated from semiannual monitoring at a well site (140 miles to and from the well site twice a year) is estimated to be 0.35 lb/yr of hydrocarbons, 6.0 lb/yr of CO and 0.40 lb/yr of NOx. No other secondary impacts are expected. We do not believe these secondary emissions are so significant as to affect the proposed determinations described above. In summary, based on the analysis described above, the EPA is proposing OGI monitoring based on tiered total site-wide baseline methane emission levels to represent thresholds that would determine the monitoring frequency. For well sites with total sitelevel methane emissions less than 3 tpy, E:\FR\FM\15NOP2.SGM 15NOP2 63194 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 the EPA is proposing to require a onetime survey to demonstrate that the well site is free of leaks or other abnormal conditions that are not accounted for in the baseline calculation. For well sites with total site-level methane emissions of 3 tpy or greater, the EPA is proposing quarterly monitoring at all sites. Lastly, the EPA is co-proposing semiannual monitoring for well sites with total sitelevel methane emissions of 3 tpy or greater and less than 8 tpy, and quarterly monitoring for all sites with baseline emissions of 8 tpy or greater. As noted earlier, site-level baseline emission levels would be calculated by owners and operators for each site based on prescribed population emission factors for components and equipment at the site, combined with an assessment of potential methane emission from storage vessels (after applying controls). b. Fugitive Emissions From Compressor Stations The EPA continues to utilize the model plant approach in estimating baseline fugitive emissions from compressor stations. Unlike well sites, we believe that compressor station designs are less variable and that model plants are an effective construct to analyze fugitive emission control programs. The EPA has evaluated feedback received from several industry stakeholders related to development of compressor station model plants over multiple years since the original 2015 NSPS OOOOa proposal were model plants for compressor stations (including those at gathering and boosting stations, transmission stations, and storage facilities) were first introduced. Consistent with this early approach for estimating emissions from compressor stations, the EPA still believes the model plant approach is the best way to assess fugitive emissions from compressor stations, in the absence of information indicating otherwise. Baseline model plant emissions for compressor stations can reasonably be calculated using equipment counts, fugitive emissions component counts, and emissions factors from the 1995 Emissions Protocol. The EPA has evaluated each specific model plant for gathering and boosting, transmission, and storage, based on information that has become available, and model plants were updated where information indicated an update was appropriate. For example, information from actual compressor stations in operation provided by GPA Midstream for several of their member companies representing numerous sites across the country, was used to refine the gathering and VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 boosting model plant in 2020. Refinements have also been made to the transmission and storage model plants based on information received from companies in these segments. The size and equipment located at compressor stations do not vary as widely as at well sites, and therefore emissions are expected to be less variable as well. Furthermore, stakeholders have not indicated that a model plant approach is not reasonable. For these reasons, the EPA retains a model plant approach for compressor stations which are representative in estimating fugitive emissions. There are three types of compressor stations in the Crude Oil and Natural Gas source category: (1) Gathering and boosting stations, (2) transmission stations, and (3) storage stations. The equipment associated with these compressor stations vary depending on the volume of natural gas that is transported and whether any treatment of the gas occurs, such as the removal of water or hydrocarbons. The model plants developed for these sites include all equipment (including piping and associated components, compressors, generators, separators, storage vessels, and other equipment) and associated components (e.g., valves and connectors) that may be sources of fugitive emissions associated with these operations. One model plant was developed for each of the three types of compressor stations described above, which are discussed in detail in the 2020 NSPS OOOOa TSD and in the NSPS OOOOb and EG TSD supporting this action. For gathering and boosting stations, the fugitive baseline emissions were estimated to be 16.6 tpy of methane and 4.6 tpy of VOC. For transmission stations, the fugitive baseline emissions were estimated to be 40.4 tpy of methane and 1.1 tpy of VOC. For storage stations, the fugitive baseline emissions were estimated to be 142.2 tpy of methane and 3.9 tpy of VOC. As with well sites, in the original BSER analysis for the 2016 NSPS OOOOa rulemaking, two options for reducing fugitive methane and VOC emissions at compressor stations were identified, which were (1) a fugitive emissions monitoring program based on individual component monitoring using EPA Method 21 for detection combined with repairs and (2) a fugitive emissions monitoring program based on the use of OGI detection combined with repairs. Finding that both methods achieve comparable emission reduction but OGI was more cost effective, the EPA ultimately identified quarterly monitoring of compressor stations using PO 00000 Frm 00086 Fmt 4701 Sfmt 4702 OGI as the BSER. 81 FR 35862. While there are several new fugitive emissions technologies under development, the EPA needs additional information and better understanding of these technologies, and they are therefore not being evaluated as potential BSER at this time. For this analysis for both the NSPS and the EG, we re-evaluated OGI as BSER. In the discussion below, we evaluate OGI control options based on varying the frequency of conducting the survey and fugitive emissions repair threshold (i.e., the visible identification of methane or VOC when an OGI instrument is used). For this analysis, we considered annual, semiannual, quarterly, and monthly survey frequency for compressor stations. In 2015, we evaluated the potential emission reductions from the implementation of an OGI monitoring program where an emission reduction of 40, 60 and 80 percent for annual, semiannual, and quarterly monitoring survey frequencies, respectively, were determined appropriate. No other information reviewed since 2015 indicates that the assigned reduction frequencies are different than previously established and the reduction efficiencies are consistent with what current information indicates. In addition, we also evaluated monthly monitoring for compressor stations where information evaluated indicated monthly OGI monitoring has the potential of reducing emissions up towards 90 percent. We evaluated the costs of monitoring and repair under various monitoring frequencies described above, including the cost of OGI monitoring via the camera survey, repair costs, resurvey costs, monitoring plan development and the cost of a recordkeeping system. For compressor stations, the capital cost associated with the fugitives monitoring program were estimated to be $3,090 for each gathering and boosting compressor station, which includes development of a fugitive emissions monitoring plan for a company-defined area (assumed to include 7 gathering and boosting compressor stations) and database management development or licensing for recordkeeping. These capital costs are divided evenly amongst the 7 gathering and boosting compressor stations in the company-defined area for purposes of the model plant analysis, consistent with the 2016 NSPS OOOOa and 2020 Technical Rule analyses. The capital cost associated with the fugitives monitoring program for transmission and storage compressor stations was estimated at $23,880, which is for a single transmission and storage compressor station. The annual costs E:\FR\FM\15NOP2.SGM 15NOP2 63195 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules include the capital recovery cost (calculated at a 7 percent interest rate for 10 years), survey and repair costs, database management fees, and recordkeeping and reporting costs. The annual costs estimated for compressor stations range from $6,350 for annual monitoring to $33,220 for monthly monitoring at gathering and boosting compressor stations. For transmission compressor stations, the annual costs estimated range from $12,900 for annual monitoring to $39,770 for monthly monitoring. For storage compressor stations, the annual costs estimated range from $17,000 for annual monitoring to $43,860 for monthly monitoring. As discussed above, the EPA is proposing that natural gas-driven intermittent vent controllers at production and natural gas transmission sites in Alaska without electricity would be subject to a standard that prohibits emissions when the controller is idle. Intermittent pneumatic controllers are designed to vent during actuation only, but these devices are known to malfunction and operate incorrectly which causes them to release natural gas to the atmosphere when idle. For sites in Alaska that do not have electricity located in the production segment (well sites, gathering and boosting stations, and centralized tank batteries) and in the transmission and storage segment, the EPA is proposing to define intermittent natural gas-driven pneumatic controllers as an affected facility and proposing to apply a standard that these controllers only vent during actuation and not when idle. See section XII.C on pneumatic controllers for a full explanation of this standard. We have determined that it would be efficient and reasonable to verify proper actuation and that venting does not occur during idle times by proposing that these devices are monitored along with fugitive emissions components at a site to ensure these devices are meeting the standard. We believe the cost of monitoring of intermittent pneumatic controllers will be absorbed by the cost of the fugitive emissions program, and that little to no additional cost would be associated with monitoring these devices on the fugitive emissions components monitoring schedule. If compressor stations have electricity, they would be required to have nonemitting controllers, and no additional costs are expected to be incurred relayed to repair and/or replacement of malfunctioning intermittent vent controllers. At gathering and boosting compressor stations there are savings associated with the gas not being released. The value of the natural gas saved is assumed to be $3.13 per Mcf of recovered gas. Transmission and storage compressor stations do not own the natural gas; therefore, revenues from reducing the amount of natural gas emitted/lost was not applied for this segment. The EPA evaluated the costeffectiveness of monitoring for each subtype of compressor station, starting with evaluating whether quarterly monitoring remains the BSER. The 2016 NSPS OOOOa requires a fugitive emissions monitoring and repair program, where compressor stations have to be monitored quarterly. Compressor stations have successfully met this standard. Further, several State agencies have rules that require quarterly monitoring at compressor stations. For example, Colorado’s Regulation 7 Control of Ozone via Ozone Precursors and Control of Hydrocarbons via Oil and Gas Emissions 243 requires a semiannual inspection frequency for compressor stations with uncontrolled actual VOC emissions between 2 and 12 tpy, a quarterly inspection frequency for compressor stations with uncontrolled actual VOC emissions between 12 and 50 tpy, and monthly inspections for compressor stations with uncontrolled actual VOC emissions above 50 tpy. California requires quarterly inspections under their LDAR requirements 244 and similarly, Ohio’s General Permit 18.1 also requires quarterly monitoring for compressor stations.245 These examples of State rules, where quarterly monitoring appears to be the lowest monitoring frequency required with one exception where the VOC baseline emissions were extraordinarily high, is a demonstration of the reasonableness of monitoring fugitive emissions components on a quarterly basis for compressor stations. Given the apparent reasonableness of quarterly monitoring as discussed above, the EPA evaluated whether it was reasonable to require monthly monitoring for compressor stations. Table 16 summarizes the cost, emission reductions, and cost-effectiveness of quarterly and monthly OGI monitoring at compressor stations for the single pollutant approach, while Table 17 summarizes the multi-pollutant approach. TABLE 16—SUMMARY OF THE SINGLE POLLUTANT COST OF CONTROL FOR COMPRESSOR STATION FUGITIVE EMISSIONS MONITORING Model plant I Capital cost ($) I Annual cost ($/yr) Emission reductions Annual cost w/savings ($/yr) I I Methane (tons/yr) I VOC (tons/yr) I Methane cost of control w/o savings ($/ton) I VOC cost of control w/o savings ($/ton) Quarterly Monitoring Gathering & Boosting .................................... Transmission ................................................. Storage .......................................................... Compressor Program Weighted Average ...................................................... $3,100 23,900 23,900 I ........................ $13,400 19,900 24,000 I ........................ $11,000 19,900 24,000 I ........................ 13.3 32.3 114.0 I ........................ 3.7 0.9 3.2 I ........................ $1,000 600 200 I 900 $3,600 22,300 7,600 I 4,400 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Monthly Monitoring Gathering & Boosting .................................... Transmission ................................................. Storage .......................................................... Compressor Program Weighted Average ...................................................... 3,100 23,900 23,900 I ........................ 243 https://cdphe.colorado.gov/aqcc-regulations. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 33,200 39,800 43,900 I ........................ 30,500 39,800 43,900 I ........................ 15.0 36.4 128.2 I ........................ 244 https://ww2.arb.ca.gov/sites/default/files/ classic/regact/2016/oilandgas2016/ogfro.pdf. PO 00000 Frm 00087 Fmt 4701 Sfmt 4702 4.2 1.0 3.5 I ........................ 2,200 1,100 340 I 1,800 8,000 39,500 12,400 I 9,300 245 https://www.epa.state.oh.us/dapc/genpermit/ ngcs/GP_181. E:\FR\FM\15NOP2.SGM 15NOP2 63196 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules TABLE 17—SUMMARY OF THE MULTI–POLLUTANT COST OF CONTROL FOR COMPRESSOR STATION FUGITIVE EMISSIONS MONITORING Capital cost ($) Model plant Emission reductions Annual cost w/savings ($/yr) Annual cost ($/yr) Methane (tons/yr) Methane cost of control w/o savings ($/ton) VOC (tons/yr) VOC Cost of control w/o savings ($/ton) Quarterly Monitoring Gathering & Boosting .................................... Transmission ................................................. Storage .......................................................... $3,100 23,900 23,900 $13,400 19,900 24,000 $11,000 19,900 24,000 13.3 32.3 114.0 3.7 0.9 3.2 $500 300 100 $1,800 11,100 3,800 Compressor Program Weighted Average ...................................................... ........................ ........................ ........................ ........................ ........................ 430 2,200 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Monthly Monitoring Gathering & Boosting .................................... Transmission ................................................. Storage .......................................................... 3,100 23,900 23,900 33,200 39,800 43,900 30,500 39,800 43,900 15.0 36.4 128.2 4.2 1.0 3.5 1,100 550 200 4,000 19,800 6,200 Compressor Program Weighted Average ...................................................... ........................ ........................ ........................ ........................ ........................ 900 4,600 Based on the single pollutant approach, both quarterly and monthly frequencies are reasonable for methane emissions, while only quarterly is reasonable for VOC emissions. Like described for well sites, owners and operators of compressor stations have been monitoring quarterly since 2016 pursuant to NSPS OOOOa, State requirements, or voluntarily, which suggests these costs are reasonable. These costs for quarterly monitoring are also comparable to those found reasonable in both the 2016 NSPS OOOOa and the 2020 Technical Rule. Further, both frequencies are reasonable under the multipollutant approach when considering the total costeffectiveness compared to a baseline of no OGI monitoring. The EPA then looked at the incremental costs of going from quarterly to monthly monitoring. Quarterly monitoring achieves an emission reduction ranging from 13.3 tpy at gathering and boosting compressor stations to 114 tpy at storage compressor stations. Monthly monitoring achieves additional reductions ranging from 1.7 tpy at gathering and boosting compressor stations to 14.2 tpy at storage compressor stations. However, these additional reductions are achieved at $9,400/ton methane (and nearly $50,000/ton VOC). The EPA finds that achieving these additional emissions reductions is not reasonable for the cost, given the only small fraction of additional reductions realized at monthly monitoring. Based on the cost analysis summarized above, we find that the cost effectiveness of quarterly monitoring for compressor stations is reasonable. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 Finally, no secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of fugitive emissions components. There are some emissions that would be generated by the OGI camera monitoring contractors with respect to driving to and from the site for the fugitive emissions survey. Using AP–42 mobile emission factors and assuming a distance of 70 miles to the compressor station, the emissions generated from quarterly monitoring at a compressor station (140 miles to and from the compressor station four times a year) is estimated to be 0.70 lb/yr of hydrocarbons, 12.0 lb/yr of CO and 0.80 lb/yr of NOX. No other secondary impacts are expected. In light of the above, we find that the BSER for reducing methane and VOC emissions from all compressor stations, including gathering and boosting stations, transmission stations, and storage stations is quarterly monitoring for this proposal. Therefore, for NSPS OOOOb, we are proposing to require quarterly monitoring for all compressor stations. 2. EG OOOOc The EPA also evaluated BSER for the control of fugitive emissions at existing well sites and compressor stations. The findings were that the controls evaluated for new sources for NSPS OOOOb are appropriate for consideration under the EG OOOOc. Further, the EPA finds that the OGI monitoring, methane emission reductions, costs, and cost effectiveness results discussed above for new sources are also applicable for existing sources. Therefore, for the EG OOOOc, the EPA is proposing presumptive standards to require quarterly PO 00000 Frm 00088 Fmt 4701 Sfmt 4702 monitoring for well sites with site-level baseline methane emissions greater than and equal to 3 tpy. Further, we are coproposing semiannual monitoring for well sites with site-level baseline methane emissions greater than and equal to 3 tpy and less than 8 tpy, and quarterly monitoring for well sites with site-level baseline methane emissions greater than and equal to 8 tpy. We find the costs reasonable for existing well sites with total site-level baseline methane emissions greater than or equal to 3 tpy to conduct quarterly OGI monitoring at an incremental cost of $1,700/ton methane reduced. We are aware that there is a large percentage of existing well sites that are likely owned and operated by small businesses. We continue to be concerned about the burden of frequent OGI monitoring on these small businesses and are requesting comment consistent with our solicitation for new sources. The EPA also finds, and is proposing, that the BSER for reducing methane emissions from all existing compressor stations, including gathering and boosting stations, transmission stations, and storage stations is quarterly monitoring. For compressor stations, we find that both quarterly (at $430/ton methane reduced) and monthly monitoring (at $900/ton methane reduced) are reasonable when looking at total cost-effectiveness against a baseline of no monitoring, however, at an incremental cost of $9,400/ton methane reduced, monthly monitoring is not reasonable. Therefore, for the EG OOOOc, we are proposing a presumptive standard of quarterly monitoring for all compressor stations. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules 3. Alternative Screening Using Advanced Measurement Technology As discussed throughout this preamble, the EPA recognizes the existence large emission events. In certain instances, these situations could be caused by severely and continuously leaking components that would be identified and corrected via the routine OGI-based periodic monitoring program, but only on a quarterly or semiannual basis. Moreover, some large emission events are intermittent and stochastic in nature and may not be identified via these OGI surveys. Since the 2016 NSPS OOOOa, significant strides have occurred in developing and deploying methane detection technologies that can detect fugitive emissions (especially large emission events) in a potentially faster and more cost-effective manner than traditional techniques such as OGI and EPA Method 21. The EPA has continued following the development of these technologies and their applications through various public programs, such as the DOE ARPA–E programs, which have focused on the development of cost-effective tools to locate and measure methane emissions. Additionally, the EPA has continued discussions with stakeholders, including academic researchers and private industry, as they develop and evaluate novel tools for the detection and quantification of methane emissions in the oil and gas sector. As noted in section VII.B, the EPA also held a twoday workshop in August 2021 to hear perspectives on these new technologies. Some of the promising technologies now emerging include, but are not limited to, fixed-base and open path sensor networks, unmanned aircraft systems (UAS) equipped with methane detection equipment, the use of highend instruments for mobile measurements on the ground and in the air, and satellite observations with advanced optical techniques. As the EPA learned during the Methane Detection Technology Workshop, industry has utilized these advanced measurement technologies to supplement existing fugitive emissions programs and to quickly identify unexpected emissions events (e.g., emissions from controlled storage vessels) in order to make repairs as quickly as possible.246 While most of these advanced measurement technologies are not sensitive enough to pin-point the exact same emission sources as the current fugitive emission detection programs, many can more 246 See summary report of the EPA’s Methane Detection Workshop located at Docket ID No. EPA– HQ–OAR–2021–0317. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 quickly detect the largest emissions sources (e.g., malfunctions and undersized or non-performing major equipment), and they can also find emissions that may be missed by fugitive emission surveys (e.g., component-level leaks on valves, connectors, and meters). Moreover, the EPA understands the stochastic nature, distribution, and frequency of these large emission events across sites and over time is uncertain, and that these events occur sporadically at an individual site in ways that may take longer to detect or might not be detected through a periodic fugitive emissions survey using traditional technologies. Integrating advanced emission detection technologies into this rule—whether deployed by owner-operators themselves or by third parties—could be a valuable way to reduce fugitive emissions more cost-effectively and rapidly detect and remedy ‘‘superemitting’’ events that make an outsize contribution to overall emissions from this source category. There are many other advantages to these advanced measurement technologies over technologies currently used for fugitive emissions detection (i.e., OGI and EPA Method 21 technologies). For instance, these advanced measurement technologies may be less susceptible to operator error or judgment than traditional methods of leak detection, thus making surveys more consistent and reliable. Many of these technologies can survey broader areas than can be effectively surveyed with field personnel, drastically reducing the driving time from site to site, which could have potential cost and safety benefits and allow for more frequent monitoring, which could allow for the identification and mitigation of large volume methane emissions sooner than OGI or EPA Method 21 surveys. As described in section XI.A.5, the EPA is proposing an alternative work practice for detecting fugitive emissions that incorporates these advanced measurement technologies. There were a number of presentations during the Methane Detection Technology Workshop that discussed the detection capabilities of various methane measurement technologies which could be used for a screening approach. Given the diverse array of advanced technologies that are now in use, and the rapid pace at which these technologies are being refined and new technologies are being developed, the EPA believes that it is appropriate to articulate a foundational set of performance criteria and documentation requirements for this alternative work practice that can be applied to multiple PO 00000 Frm 00089 Fmt 4701 Sfmt 4702 63197 existing and forthcoming technologies. Based on the information available to the Agency, including the information presented in the Methane Detection Technology Workshop, the EPA believes setting a minimum detection threshold of 10 kg/hr methane might be appropriate for use in determining what technologies and in what deployment platforms (e.g., fixed, ground and aerial) are appropriate for a potential screening alternative within the proposed NSPS OOOOb and EG OOOOc. Therefore, the specific alternative work practice that the EPA is proposing includes a provision that would allow the use of any technology with a minimum detection threshold of 10 kg/hr. Although we have focused this discussion on advanced measurement technologies, the EPA is also soliciting comment on whether there are ways to utilize existing technologies to screen for large emission events. For example, could gauges or meters be utilized to identify potential large losses between the wellhead and the custody meter assembly. Further, the EPA is seeking comment on very simple AVO checks that could be performed in conjunction with the periodic OGI monitoring surveys to help identify potential large emission events. For example, two often-cited causes of super-emitter sources are unlit flares and separator dump valves that are stuck open allowing unintentional gas carry-through to emit from storage vessels. The additional time and cost required to perform visual inspections to see if the flare pilot light is working, or to see if a dump valve is stuck open, would be minimal. Yet the benefits of simple AVO inspections could be significant. The EPA is soliciting comment on this concept, as well as comments on the common items that could be included on a checklist for such low-burden AVO inspections in conjunction with fugitive monitoring. B. Proposed Standards for Storage Vessels 1. NSPS OOOOb a. Background In the 2012 NSPS OOOO, the EPA established VOC standards for storage vessels. Based on our review of these standards, we are proposing to retain the current standard of 95 percent reduction. However, the EPA is proposing to redefine the affected facility to include a tank battery. Specifically, the EPA is proposing to define a storage vessel affected facility as a single storage vessel or a group of storage vessels that are physically adjacent and that receive fluids from the E:\FR\FM\15NOP2.SGM 15NOP2 63198 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 same source (e.g., well, process unit, or set of wells or process units) or manifolded together for the transfer of liquid or vapors. In this definition, we consider tanks to be physically adjacent when they are near or next to each other and may or may not be connected or piped together. In addition, the EPA is proposing methane standards for new, reconstructed, and modified storage vessels under the proposed NSPS OOOOb. Both the proposed revised VOC standards and the proposed methane standards would be the same (i.e., 95 percent reduction of emissions from storage vessel affected facilities as defined above in this proposal). These reductions can be achieved by utilizing a cover and closed vent system to capture and route the emissions to a control device that achieves an emission reduction of 95 percent, or by routing the captured emissions to a process. Both methane and VOC emissions from storage vessels are a result of working, breathing and flashing losses. Working losses occur when vapors are displaced due to the emptying and filling of storage vessels. Breathing losses are the release of gas associated with daily temperature fluctuations when the liquid level remains unchanged. Flashing losses occur when a liquid with dissolved gases is transferred from a vessel with higher pressure (e.g., separator) to a vessel with lower pressure (e.g., storage vessel), thus allowing dissolved gases and a portion of the liquid to vaporize or flash. In the Crude Oil and Natural Gas source category, flashing losses occur when crude oils or condensates flow into a storage vessel from a separator operated at a higher pressure. Typically, the higher the operating pressure of the upstream separator, the greater the flash emissions from the storage vessel. Temperature of the liquid may also influence the amount of flash emissions. Lighter crude oils and condensate generally flash more hydrocarbons than heavier crude oils. b. Definition of Affected Facility The current standards apply to single storage vessels with potential VOC emissions of 6 tpy or greater, although the EPA has long observed that these storage vessels are typically located as part of a tank battery. 76 FR 52738, 52763 (Aug. 23, 2011). Further, the 6 tpy applicability threshold was established by directly correlating VOC emissions to throughput, was based on the use of a single combustion control device, regardless of the number of storage vessels routing emissions to that control device, and control of 6 tpy VOC was cost effective using that single control VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 device. Id. at 52763–64. Over the years, there have been questions and issues raised regarding how to calculate the potential VOC emissions from individual storage vessels that are part of a tank battery. The EPA attempted to address this issue through various amendments to NSPS OOOO and NSPS OOOOa,247 most recently in the 2020 Technical Rule. In the 2020 Technical Rule, the EPA continued to recognize that tank batteries are more prevalent than individual storage vessels. While the 2020 Technical Rule included amendments to the calculation methodology for determining potential VOC emissions from storage vessels that are part of a tank battery, the EPA has now determined that it is more appropriate to evaluate the control of methane and VOC emissions from tank batteries 248 as a whole instead of each individual storage vessel within a tank battery.249 In this review the EPA evaluated regulatory options based on the use of a single control device to reduce both methane and VOC emissions from a tank battery, which is consistent with the 2012 NSPS OOOO, 2016 NSPS OOOOa, and subsequent amendments to each of those rules. The EPA believes that this approach will simplify applicability criteria for owners and operators of storage vessels, and more accurately aligns with the EPA’s original intent of how storage vessel affected facility status should be determined. c. Modification Section 60.14(a) of the general provisions to part 60 defines modification as follows: ‘‘Except as provided in paragraphs (e) and (f) of this section, any physical or operational change to an existing facility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies shall be considered a modification. . . .’’ We also note that 40 CFR 60.14(f) states that ‘‘Applicable provisions set forth under an applicable subpart of this part shall supersede any conflicting provisions of this section.’’ The EPA understands the difficulty assessing emissions from storage vessels and seeks to provide 247 See 79 FR 79018 and 80 FR 48262. purposes of this analysis and the resulting proposed standards, the term ‘‘tank battery’’ refers to a single storage vessel or a group of storage vessels that are physically adjacent and that receive fluids from the same source (e.g., well, process unit, or set of wells or process units) or which are manifolded together for liquid or vapor transfer. 249 This approach would no longer allow facilities to apply certain criteria and average the total potential VOC emissions of the tank battery across the number of storage vessels in the battery to determine a per-vessel potential for VOC emissions. 248 For PO 00000 Frm 00090 Fmt 4701 Sfmt 4702 clarity on actions that are considered modification of a tank battery by explicitly listing these in the proposed NSPS OOOOb. We evaluated circumstances that would lead to an increase in the VOC and methane emissions from a tank battery and therefore constitute a modification of an existing tank battery. A modification of an existing tank battery would then require the tank battery owner or operator to assess the potential emissions relative to the proposed NSPS instead of the EG. The EPA is proposing that a single storage vessel or tank battery is modified when any of the following physical or operational changes are made: (1) The addition of a storage vessel to an existing tank battery; (2) replacement of a storage vessel such that the cumulative storage capacity of the existing tank battery increases; and/or (3) an existing single storage vessel or tank battery that receives additional crude oil, condensate, intermediate hydrocarbons, or produced water throughput (from actions such as refracturing a well or adding a new well that sends these liquids to the tank battery). For both items 1 and 2, even if the type and quantity of fluid processed remains the same, the increased storage capacity will lead to higher breathing losses and thereby increase the VOC emissions from the tank battery relative to the VOC emissions prior to the vessel addition or replacement. Therefore, we conclude that these actions are a modification of the tank battery. However, we are soliciting comment to help us better understand the effect of the proposed definition number 1 and 2 on the number of new storage vessels or tank batteries that would be subject to the NSPS. Under the current definition of a storage vessel affected facility in NSPS OOOOa, which is each single storage vessel that meets the 6 tpy applicability threshold, a new storage vessel that is installed in an existing tank battery is an affected facility (assuming the 6 tpy applicability threshold is met for the single storage vessel) whether the new storage vessel is a replacement or an addition to the tank battery. However, under the proposed definition number 1 and 2 above, the NSPS OOOOb is triggered only if the new storage vessel is an addition to the tank battery or is of bigger capacity than the storage vessel it is replacing in a tank battery. We therefore solicit comment on how often a storage vessel in a tank battery is replaced with one that is of bigger capacity, or whether the need to increase a tank battery’s capacity is E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 generally accomplished by adding storage vessels as opposed to replacing an existing one with a bigger one. We further solicit comment on whether, under our proposed definition of a tank battery (i.e., a single storage vessel or a group of storage vessels that are physically adjacent and that receive fluids from the same source (e.g., well, process unit, or set of wells or process units)), the replacement of a storage vessel in a tank battery should also require the assessment of the potential VOC and methane emissions from the tank battery. Item 3 will increase the volumetric throughput of the tank battery relative to the throughput prior to storage of the additional fluid. This will increase the working losses and potentially increase the flashing losses from the tank battery, depending on the properties of the new fluid stream. In any event, adding a new fluid stream to an existing tank battery increases the VOC emissions from that tank battery relative to just prior to the addition of a new fluid stream and is therefore considered a modification of the tank battery. The EPA is proposing to require that the owner or operator recalculate the potential VOC emissions when any of these actions occur on an existing single storage vessel or tank battery to determine if the modification may require control of VOC emissions. The existing single storage vessel or tank battery will only become subject to the proposed NSPS if it is modified pursuant to this proposed definition of modification and its potential VOC emissions exceed the proposed 6 tpy VOC emissions threshold for the tank battery. d. Technology Review The available control techniques for reducing methane and VOC emissions from storage vessels include routing the emissions from the storage vessels to a combustion control device or a VRU, which would route the emission to a process (including a gas sales line). These are the same control systems that were evaluated under the 2012 NSPS OOOO. While floating roofs can also be used to reduce emissions from many storage vessel applications, including at natural gas processing plants and compressor stations, floating roofs are not effective at reducing emissions from storage vessels that have flashing losses (e.g., storage vessels at well sites or centralized production facilities). Besides the control options described above, we did not find other available control options through our review, including review of the RACT/BACT/ LAER Clearinghouse. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 In the development of the 2012 NSPS OOOO, we found that using either a VRU or a combustion control device could achieve a 95 percent or higher VOC emission reduction efficiency. Available information since then continues to support that such devices can achieve a 95 percent control efficiency for both methane and VOC emissions. We are not proposing to require higher control efficiency because, in order to achieve a minimum of 95 percent control efficiencies on a continuous basis, operators will need to design and operate the control to achieve greater than 95 percent. Thus, while the control device may commonly operate at greater than 95 percent control efficiencies, there may be process fluctuations in heat loads, inlet backpressure, and other variables that may affect performance that may lower the control efficiencies achieved. For example, there are field conditions, such as high winds that may influence combustion efficiencies.250 We also note that, while the EPA established operating and monitoring requirements to ensure flares achieve a 98 percent control efficiency at petroleum refineries in 40 CFR part 63, subpart CC, these requirements include sophisticated monitoring and operational controls and tend to lead to additional fuel use and greater secondary impacts than combustion systems targeting to achieve a minimum of 95 percent control efficiency. Considering these factors, we conclude that, consistent with CAA section 111(a) definition of a ‘‘standard of performance,’’ 95 percent control efficiency as the minimum allowable control efficiency at any time continues to reflect ‘‘the degree of emission limitation achievable’’ through the application of the BSER for tank batteries (a combustor or a VRU). We solicit comment on the issues described above for requiring higher than 95 percent reduction.251 During pre-proposal outreach, some small businesses raised a concern that the NSPS OOOOa requirement for a continuous pilot light for a storage vessel control device generated more emissions than it prevented for storage vessels with low emissions. Specifically, small business 250 EPA. April 2012. Parameters for Properly Designed and Operated Flares. Prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC. 251 Further, in section XIII.E (solicitation of comment on control device efficiency), the EPA solicits comment on the level of reduction that can be reliably achieved using a flare and what measures need to be in place to assure such reduction. PO 00000 Frm 00091 Fmt 4701 Sfmt 4702 63199 representatives raised concerns that there are situations where propane or other fossil fuel must be used to maintain continuous pilot lights for flares used as control devices on storage vessels that do not produce enough emissions. The EPA is interested in whether the benefits of reducing emissions with these control devices are negated by the need to burn additional fossil fuels and whether there are additional factors that lead to variability in emissions from storage vessels that could be used to more narrowly target these requirements to limit the unnecessary operation of flares. We are soliciting comment from all stakeholders on this issue. e. Control Options and BSER Analysis For this proposal, the EPA evaluated regulatory options based on different potential emissions thresholds for VOC and methane. We assumed the potential tank battery emissions were reduced by 95 percent using either a VRU or a combustion control device. Since VRUs recover saleable products, we also estimated the value of the recovered product when VRUs were used. The EPA encourages the use of VRUs to capture and sell the emissions from the storage vessels by classifying VRUs as part of the process, therefore emission recovered would not be included in the potential emissions at a site. For new, modified, or reconstructed sources, we evaluated the cost of control using a single combustion device (or VRU) on a single storage vessel as well as a tank battery made up of multiple storage vessels. To do this, we evaluated the use of a single control device achieving 95 percent reduction of VOC and methane emissions at the following potential emission thresholds: 6 tpy VOC from a single storage vessel; 3 and 6 tpy VOC from a tank battery; and 1.3 tpy, 5.3 tpy, 20 tpy, and 50 tpy methane from a tank battery. Based on our cost analysis we propose to retain the 6 tpy applicability threshold. The estimated all-in capital costs for a single combustion control device are approximately $80,000. The estimated annualized costs include the capital recovery cost (calculated at a 7 percent interest rate for 15 years) and labor costs for operations and maintenance and are estimated at approximately $31,500/yr. The estimated capital costs for a VRU sized for a source with potential VOC emissions of 6 tpy are approximately $32,000 and the estimated annualized costs are estimated at approximately $24,000/yr not considering any potential recovery credits from sales. More information on this cost analysis E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63200 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules is available in the NSPS OOOOb and EG TSD for this proposal. Based on our analysis, the cost effectiveness of controlling VOC and methane emissions from a tank battery with the potential for VOC emissions of 6 tpy, under the single pollutant approach where all the costs are assigned to the reduction of VOC, is $5,540 per ton of VOC eliminated assuming the use a single combustion control device. As explained above, storage vessels are commonly located adjacent to one another as part of tank battery, which allows the vapors from the storage vessels within the tank battery to be collected and routed to a single control device, when one is used. The single pollutant cost effectiveness for a VRU to control a tank battery with potential VOC emissions of 6 tpy is approximately $4,000 per ton of VOC eliminated. As shown in section IX, costs ranging from $4,000 to $5,540 per ton of VOC reduced are within the range that the EPA considers to be cost effective for reducing VOC emissions. Because it is cost effective to reduce the VOC emissions from a tank battery with potential VOC emissions of 6 tpy or greater, one of the two targeted pollutants in this action, it is cost effective to reduce both VOC and methane emissions from a single storage vessel or a tank battery at that level. Based on our estimate, a tank battery with potential 6 tpy VOC emissions has potential 1.3 tpy of methane emissions. Because storage vessels contain crude oil, condensate, intermediate hydrocarbons, or produced water, which are approximately 80 percent VOC, the methane emissions from storage vessels are generally less than the VOC emissions. We also evaluated the cost effectiveness at a lower VOC threshold of 3 tpy. As shown in the NSPS OOOOb and EG TSD, the single pollutant cost effectiveness for controlling a tank battery with potential emissions of 3 tpy ranges from $7,500 to $11,000. As shown in section IX, costs ranging from $7,500 to $11,000 per ton of VOC reduced is not within the range that the EPA considers to be cost effective for reducing VOC emissions. Using the multipollutant approach, the VOC cost effectiveness is between $3,800 and $5,500, which is considered reasonable, but the methane cost effectiveness is between $17,000 and $25,000 for any of the methane thresholds assessed in conjunction with 3 tpy VOC limit, which is considered unreasonable. Therefore, the 3 tpy VOC control option was not considered reasonable at this time using either the single pollutant or multipollutant approach. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 Our analysis also shows that, under the single pollutant approach where all the costs are assigned to the reduction of methane and zero to VOC, it is cost effective to control a single storage vessel or a tank battery with potential methane emissions of 20 tpy (at costs ranging from $1,250 to $1,660 per ton methane). Based on our estimate, a tank battery with potential methane emissions of 20 tpy would have the potential VOC emissions of 91 tpy, 95 percent of which would be reduced at zero cost. Under the multipollutant costeffectiveness approach, where half of the cost is allocated to methane reduction and the other half to VOC reduction, it is cost effective to control a tank battery with potential methane emissions of 10 tpy and corresponding potential VOC emissions of 46 tpy, at an average cost of $1,500 per ton methane reduced and $330 per ton VOC reduced. In light of the above, 6 tpy of VOC is the lowest threshold that is cost effective to control both VOC and methane emissions. Therefore, the EPA is proposing to define the affected facility for purposes of regulating both VOC and methane emissions as a tank battery with potential VOC emissions of 6 tpy or greater. 2. EG OOOOc The EPA is proposing presumptive standards for reducing methane emissions from existing storage vessels. For purposes of the EG, we are proposing to define a designated facility as a single storage vessel or tank battery with the potential for methane emissions of 20 tpy or greater. For purposes of the EG, we are proposing the same definition of a storage vessel affected facility, which is a single storage vessel or a group of storage vessels that are physically adjacent and that receive fluids from the same source (e.g., well, process unit, or set of wells or process units). The available controls for reducing methane emissions from existing tank batteries are the same as those for reducing methane and VOC emissions from new, modified and reconstructed tank batteries. In assessing the control costs for existing sources, we applied a 30 percent retrofit factor to the capital and installation costs to account for added costs of manifolding existing storage vessels and installing the control system on an existing tank battery. When applying controls to new sources, there is limited additional costs in designing the fixed roof with fittings to manifold the vapors and installing the closed vent piping or ducts during the tank installation process. For existing sources, installing fittings on an existing PO 00000 Frm 00092 Fmt 4701 Sfmt 4702 tank may require special lifts to access the roof and cut new ports in the roof. This may also require the tank to be taken out of service to conduct these installations, which requires additional time and labor. Additionally, when installing controls as part of the design for a new source, the facility layout can be designed to accommodate the control systems near the tank battery and the control device can be installed with the same crew installing the storage vessels, minimizing additional installation costs. For existing sources, there may be other equipment near the tanks that may require the control equipment to be further from the tank battery, which increases materials and installation costs. Also, control equipment costs will include the full costs of crew mobilization. Therefore, it is more expensive to install controls at an existing tank battery than to install controls as part of a new tank battery. We considered the same regulatory options based on potential methane emissions thresholds of 1.3 tpy, 5.3 tpy, 20 tpy, and 50 tpy per tank battery. The estimated capital costs for a single combustion control device for emissions in this range are approximately $103,000. The estimated annual costs include the capital recovery cost (calculated at a 7 percent interest rate for 15 years) and labor costs for operations and maintenance and are estimated at approximately $34,000. The costs for VRU are more variable than combustion control systems and dependent on the potential emissions for which the VRU is designed to recover. The estimated capital costs for a VRU sized for a source with potential methane emissions of 20 tpy device are approximately $106,000 and the estimated annualized costs are approximately $49,000/yr not considering any potential recovery credits. With a VRU, the recovered VOC and methane are recovered as salable products. Considering the value of recovered product, the annualized cost for VRU sized to recover potential methane emissions of 20 tpy is estimated to be $26,000/yr. More information on this cost analysis is available in the NSPS OOOOb and EG TSD for this proposal. The resulting cost effectiveness, for the application of a single combustion control device or VRU to achieve a 95 percent emission reduction ranges from $19,000 to $27,400 per ton of methane eliminated at a threshold of 1.3 tpy methane. This cost is not considered reasonable. Next, we evaluated the cost effectiveness at a methane threshold of 5.3 tpy, which ranged from $10,000 to $13,700 per ton of methane reduced, E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules which is also not considered reasonable. At a threshold of 20 tpy methane, the cost effectiveness ranges from $1,400 to $1,800 per ton methane reduced. At a threshold of 50 tpy methane, the cost effectiveness ranges from $340 to $720 per ton methane reduced. When we considered the application of these options at a national level, the overall cost effectiveness of the 20 tpy potential methane emissions threshold was $400 per ton methane reduced without considering product recovery credits and has a net cost savings considering product recovery credits. Additionally, the incremental cost effectiveness of the 20 tpy option relative to the 50 tpy potential methane emissions threshold was approximately $900 per ton additional methane reduced when considering product recovery credits. Based on the cost analysis summarized above, we find that the cost effectiveness for achieving 95 percent emission reduction of methane from a tank battery with potential methane emissions of 20 tpy is reasonable for methane. A cost-effective value of $1,800/ton of methane reduction is comparable to the estimated methane cost-effectiveness values for the controls identified as BSER for the 2016 NSPS OOOOa and which we consider to be representative of reasonable control cost for reducing methane emissions from the Crude Oil and Natural Gas source category, as explained in section IX.B. We further note that both California and Colorado require 95 percent reduction of methane (California) and hydrocarbon (Colorado) emissions from storage vessels. For California, existing separator and tank systems with an annual emission rate greater than 10 tpy methane must control emissions using a vapor collection system that reduces emissions by at least 95 percent.252 For Colorado, storage vessels that emit greater than or equal to 2 tpy of actual uncontrolled VOC emissions must reduce VOC emissions by 95 percent.253 These requirements, which are comparable to the proposed presumptive standards, are further indication that the cost of implementing the proposal is reasonable and not excessive. 252 See sections 95668 and 95671 of California Code of Regulations, Title 17, Division 3, Chapter 1, Subchapter 10 Climate Change, Article 4. 253 See section I.D.3.a of Colorado Department of Public Health and Environment, ‘‘Control of Ozone via Ozone Precursors and Control of Hydrocarbons via Oil and Gas Emissions (Emissions of Volatile Organic Compounds and Nitrogen Oxides), Regulation Number 7’’ (5 CCR 1001–9), July 2021. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 3. Legally and Practicably Enforceable Limits In addition to the BSER analysis described above, the EPA is clarifying the term ‘‘legally and practicably enforceable limits’’ as it related to storage vessel affected facilities in the proposed NSPS OOOOb and EG OOOOc. In the 2016 NSPS OOOOa, the EPA stated that ‘‘any owner or operator claiming technical infeasibility, nonapplicability, or exemption from the regulation has the burden to demonstrate the claim is reasonable based on the relevant information. In any subsequent review of a technical infeasibility or nonapplicability determination, or a claimed exemption, the EPA will independently assess the basis for the claim to ensure flaring is limited and emissions are minimized, in compliance with the rule.’’ See 81 FR 35824, 35844 (June 3, 2016). In the context of storage vessels under both the 2012 NSPS OOOO and 2016 NSPS OOOOa, the EPA has learned that numerous owners and operators claim that their storage vessels are not affected facilities under 40 CFR 60.5365(e) and 40 CFR 60.5365a(e). This claim is made based on a determination that the potential for VOC emissions is less than 6 tpy when taking into account requirements under a legally and practicably enforceable limit in an operating permit or other requirement established under a Federal, State, local or Tribal authority.254 However, when the EPA has reviewed the limits considered by these facilities as legally and practicably enforceable, we have become aware that the limits do not require a reduction in emissions; they are often self-imposed or of such a general nature as to be unenforceable or otherwise lack measures to assure the required emission reduction. For example, a permit contains an emission limit of 2 tpy for a single storage vessel, but does not contain any performance testing requirements, continuous or other monitoring requirements, recordkeeping and reporting, or other requirements that would ensure that emissions are maintained below the emissions limit in the permit. In National Mining Ass’n v. EPA, 59 F.3d 1351 (D.C. Cir. 1995), the court explained what constitutes ‘‘effective’’ control in assessing a source’s potential to emit. According to the court, while ‘‘effective’’ controls need not be Federally enforceable, ‘‘EPA is clearly not obliged to take into account controls 254 40 CFR 60.5365(e) and 40 CFR 60.5365a(e)(1) and (2) allow owners and operators to take into account these requirements when calculating the potential VOC emissions. PO 00000 Frm 00093 Fmt 4701 Sfmt 4702 63201 that are only chimeras and do not really restrain an operator from emitting pollution.’’ Id. at 1362. The court also emphasized that these non-Federally enforceable controls must stem from state or local government regulations, and not ‘‘operational restrictions that an owner might voluntarily adopt.’’ Id. at 1362. Further, as a general ‘‘default rule,’’ the burden of proof falls ‘‘upon the party seeking relief.’’ Schaffer ex rel. Schaffer v. Weast, 546 U.S. 49, 57–58, 126 S.Ct. 528, 163 L.Ed.2d 387 (2005). In light of the above, the EPA is proposing to include a definition for a ‘‘legally and practicably enforceable limit’’ as it relates to limits used by owners and operators to determine the potential for VOC emissions from storage vessels that would otherwise be affected facilities under these rules. The intent of this proposed definition is to provide clarity to owners and operators claiming the storage vessel is not an affected facility in the Oil and Gas NSPS due to legally and practicably enforceable limits that limit their potential VOC emissions below 6 tpy. This definition is being proposed for NSPS OOOOb and the proposed presumptive standard included in EG OOOOc. This proposed definition of ‘‘legally and practicably enforceable limit’’ is consistent with the EPA’s historic position on what is considered ‘‘legally and practicably enforceable,’’ as tailored to storage vessels in the oil and gas sector that would otherwise be affected facilities under these rules. The proposed definition is as follows: ‘‘For purposes of determining whether a single storage vessel or tank battery is an affected facility, a legally and practicably enforceable limit must include all of the following elements: i. A quantitative production limit and quantitative operational limit(s) for the equipment, or quantitative operational limits for the equipment; ii. an averaging time period for the production limit in (i) (if a productionbased limit is used) that is equal to or less than 30 days; iii. established parametric limits for the production and/or operational limit(s) in (i), and where a control device is used to achieve an operational limit, an initial compliance demonstration (i.e., performance test) for the control device that establishes the parametric limits; iv. ongoing monitoring of the parametric limits in (iii) that demonstrates continuous compliance with the production and/or operational limit(s) in (i); v. recordkeeping by the owner or operator that demonstrates continuous E:\FR\FM\15NOP2.SGM 15NOP2 63202 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules compliance with the limit(s) in (i–iv); and vi. periodic reporting that demonstrates continuous compliance.’’ In this proposed definition, the EPA is not addressing the various ways in which a State or other authority’s permit may be issued since the format of permit issuances varies by jurisdiction. The proposed definition of ‘‘legally and practicably enforceable’’ does not specify limits, monitoring requirements, or recordkeeping. Instead, the owner or operator should work with the permitting authority to establish specific limits, monitoring requirements and recordkeeping that will ensure any permitted emission limit is achieved. Only those limits that include the elements described above will be considered ‘‘legally and practicably enforceable’’ for purposes of determining the potential for VOC emissions from a single storage vessel or tank battery, and thus applicability (or non-applicability) of each single storage vessel or tank battery as an affected facility under the rule. This proposed definition will provide clarity to owners and operators in what limits are necessary to ensure they have appropriately determined their single storage vessels or tank batteries are affected facilities under the proposed NSPS OOOOb or designated facilities under the proposed EG OOOOc. Further, as stated in the 2016 NSPS OOOOa, well-designed rules ensure fairness among industry competitors and are essential to the success of future enforcement efforts. 81 FR 35844 (June 3, 2016). The EPA is soliciting comment on this proposed definition from all stakeholders. C. Proposed Standards for Pneumatic Controllers khammond on DSKJM1Z7X2PROD with PROPOSALS2 1. NSPS OOOOb a. Background In the 2012 NSPS OOOO, the EPA established VOC standards for natural gas-driven pneumatic controllers. Specifically, subpart OOOO established a natural gas bleed rate limit of 6 scfh for individual, continuous bleed, natural gas-driven controllers located in the production segment. Continuous bleed, natural gas-driven controllers with a bleed rate of 6 scfh or less are commonly called ‘‘low bleed’’ controllers. However, that rule also allowed for the use of ‘‘high bleed’’ controllers (those with a bleed rate over 6 scfh) where required by functional needs such as response time, safety, and positive actuation. At natural gas processing plants, subpart OOOO implemented a VOC standard that VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 required a bleed rate of zero (‘‘zero bleed’’ or ‘‘no bleed’’). The rule also included allowances for the use of continuous bleed natural gas-driven controllers at natural gas processing plants where required by functional needs. In the 2016 NSPS OOOOa, the EPA extended the 6 scfh natural gas bleed rate standard to the natural gas transmission and storage segment and established GHG standards for all segments. Effectively, the 2016 NSPS OOOOa required low bleed controllers to reduce methane and VOC emissions from the production and transmission and storage segments and required a bleed rate of zero for pneumatic controllers at natural gas processing plants. Like the 2012 NSPS OOOO, the 2016 NSPS OOOOa included allowances for the use of continuous high bleed controllers in the production and transmission and storage segments and continuous natural gas-driven pneumatic controllers at natural gas processing plants where required by functional needs. Emissions from natural gas-driven intermittent vent pneumatic controllers were not addressed in either the 2012 NSPS OOOO or the 2016 NSPS OOOOa. This was because, when operated and maintained properly, methane and VOC emissions from intermittent controllers are substantially lower (by an order of magnitude) than emissions from other types of natural gas-driven controllers. However, the EPA is now aware that these intermittent controllers often malfunction and vent during idle periods. Emissions factors considering this fact are around four times higher than the factors for low-bleed controllers. Further, as presented in subsection c of this section, methane emissions from intermittent controllers make up a significant portion of the overall methane emissions from all natural gas and petroleum system sources in the GHGI. As such, the EPA is now proposing to reduce emissions from intermittent controllers via NSPS OOOOb. b. Affected Facility Definitions and Zero Emissions Standard As a result of the review of these requirements in the 2016 NSPS OOOOa, the previous BSER determinations, and the consideration of new information, including State regulations that have been enacted since 2016, the EPA is proposing GHG (methane) and VOC standards for natural gas-driven pneumatic controllers in all segments of the industry included in the Crude Oil and Natural Gas source category (i.e., PO 00000 Frm 00094 Fmt 4701 Sfmt 4702 production, processing, transmission and storage). First, in terms of the definition of an affected facility, the EPA is proposing to revise the types of pneumatic controllers that are affected facilities to include both continuous bleed controllers and intermittent vent controllers. For continuous bleed controllers, an affected facility is each single continuous bleed natural gasdriven pneumatic controller that vents to the atmosphere. For intermittent vent controllers, an affected facility is each single natural gas-driven pneumatic controller that is not designed to have a continuous bleed rate but is designed to only release natural gas to the atmosphere as part of the actuation cycle. These affected facility definitions apply for pneumatic controllers in both the production and transmission and storage segments, as well as for those at natural gas processing plants. Next, in terms of standards, we are proposing a requirement that all controllers (continuous bleed and intermittent vent) in the production and natural gas transmission and storage segments must have a methane and VOC emission rate of zero. Controllers that emit zero methane and VOC to the atmosphere can include, but are not limited to, air-driven pneumatic controllers (also referred to as instrument air-driven or compressed airdriven controllers), mechanical controllers, electronic controllers, and self-contained natural gas-driven pneumatic controllers. While these ‘‘zero-emissions controllers’’ would not technically be affected facilities because they are not driven by natural gas (airdriven, mechanical, and electronic) or because they do not vent to the atmosphere, owners and operators should maintain documentation if they would like to be able to demonstrate to permit writers or enforcement officials that there are no methane or VOC emissions from the controllers and that these controllers are not affected facilities and are not subject to the rule. The proposed standard would apply to both continuous bleed and intermittent vent controllers at these sites. For all natural gas processing plants, we are proposing to essentially retain the 2016 NSPS OOOOa standard that requires that controllers must have a methane and VOC emission rate of zero (i.e., zero-emissions controllers must be used). However, we are proposing to slightly change the wording of the standard from subparts OOOO and OOOOa, which require a ‘‘bleed rate of zero.’’ Many natural gas processing plants use pneumatic controllers that are powered by compressed air, which E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 can technically have a compressed air bleed rate greater than zero. Put another way, some controllers that are powered with compressed air can allow some of that compressed air to leave the controller and thus be released into the atmosphere (they can ‘‘bleed’’ compressed air). However, since the compressed air does not contain any natural gas, methane, or VOC, we are clarifying the standard by proposing to require that pneumatic controllers at natural gas processing plants have a methane and VOC emission rate of zero. In both NSPS OOOO and OOOOa, there is an exemption from the standards in cases where the use of a pneumatic controller affected facility with a bleed rate greater than the applicable standard is required based on functional needs, including but not limited to response time, safety, and positive actuation. The EPA is not maintaining this exemption in the proposed NSPS OOOOb, except for in very limited circumstances explained below. As discussed below, the reasons to allow for an exemption based on functional need in NSPS OOOO and OOOOa were based on the inability of a low-bleed controller to meet the functional requirements of an owner/ operator such that a high-bleed controller would be required in certain instances. Since we are now proposing that pneumatic controllers have a methane and VOC emission rate of zero, we do not believe that the reasons related to the use of low bleed controllers are still applicable. The proposed rule also does include an exemption from the zero-emission requirement for pneumatic controllers in Alaska at locations where electricity power is not available. In these situations, the proposed standards would require the use of a low-bleed controller instead of high-bleed controller. The proposed rule also includes the exemption for pneumatic controllers in Alaska at sites without power that would allow the use of highbleed controllers instead of low-bleed based on functional needs. In addition, inspections of intermittent vent controllers to ensure they are not venting during idle periods described above would also be required at sites in Alaska without power. c. Description Pneumatic controllers are devices used to regulate a variety of physical parameters, or process variables, using air or gas pressure to control the operation of mechanical devices, such as valves. The valves, in turn, control process conditions such as levels, temperatures and pressures. When a VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 pneumatic controller identifies the need to alter a process condition, it will open or close a control valve. In many situations across all segments of the Oil and Natural Gas Industry, pneumatic controllers make use of the available high-pressure natural gas to operate or control the valve. In these ‘‘natural gasdriven’’ pneumatic controllers, natural gas may be released with every valve movement (intermittent) and/or continuously from the valve control. Pneumatic controllers can be categorized based on the emissions pattern of the controller. Some controllers are designed to have the supply-gas provide the required pressure to power the end-device, and the excess amount of gas is emitted. The emissions of this excess gas are referred to as ‘‘bleed,’’ and this bleed occurs continuously. Controllers that operate in this manner are referred to as ‘‘continuous bleed’’ pneumatic controllers. These controllers can be further categorized based on the rate of bleed they are designed to have. Those that have a bleed rate of less than or equal to 6 scfh are referred to as ‘‘low bleed,’’ and those with a bleed rate of greater than 6 scfh are referred to as ‘‘high bleed.’’ Another type of controller is designed to release gas only when the process parameter needs to be adjusted by opening or closing the valve, and there is no vent or bleed of gas to the atmosphere when the valve is stationary. These types of controllers are referred to as ‘‘intermittent vent’’ pneumatic controllers. A third type of natural gas-driven controller releases gas to a downstream pipeline instead of the atmosphere. These ‘‘self-contained’’ types of controllers can be used in applications with very low pressure. As discussed above, emissions from natural gas-powered pneumatic controllers occur as a function of their design. Self-contained controllers do not emit natural gas to the atmosphere. Continuous bleed controllers using natural gas as the power source emit a portion of that gas at a constant rate. Intermittent vent controllers using natural gas as the power source are designed to emit natural gas only when the controller sends a signal to open or close the valve, which is called actuation. From continuous bleed and intermittent vent controllers, another source of emissions is from improper operation or equipment malfunctions. In some instances, a low bleed controller may emit natural gas at a higher level than it is designed to do (i.e., over 6 scfh) or an intermittent vent controller could emit continuously or near PO 00000 Frm 00095 Fmt 4701 Sfmt 4702 63203 continuously rather than only during actuation. Not all pneumatic controllers are driven by natural gas. At sites with power, electrically powered pneumatic devices or pneumatic controllers using compressed air can be used. As these devices are not driven by pressurized natural gas, they do not emit any natural gas to the atmosphere, and consequently, they do not emit VOC or methane to the atmosphere. In addition, some controllers operate mechanically without a power source or operate electronically rather than pneumatically. At sites without electricity provided through the grid or on-site electricity generation, mechanical controllers and electronic controllers using solar power can be used. The emissions from natural gaspowered pneumatic controllers represent a significant portion of the total emissions from the Oil and Natural Gas Industry. In the 2021 GHGI, the estimated methane emissions for 2019 from pneumatic controllers were 700,000 metric tons of methane for petroleum systems and 1.4 million metric tons for natural gas systems. These levels represent 45 percent of the total methane emissions estimated from all petroleum systems (i.e., exploration through refining) sources and 22 percent of all methane emissions from natural gas systems (i.e., exploration through distribution). The vast majority of these emissions are from natural gas-driven intermittent vent controllers, which the EPA is proposing to define as an affected facility for the first time in NSPS OOOOb. Of the combined methane emissions from pneumatic controllers in the petroleum systems and natural gas systems production segments, emissions from intermittent vent controllers make up 88 percent of the total. Continuous high bleed and low bleed controllers make up 8 and 4 percent, respectively. d. Control Options In identifying control options for this NSPS OOOOb proposal, we reexamined the options previously evaluated in the rulemakings to promulgate the 2012 NSPS OOOO and the 2016 NSPS OOOOa, and also examined State rules with requirements for pneumatic controllers that achieve emission reductions beyond those achieved by NSPS OOOOa. For NSPS subparts OOOO and OOOOa, we identified options for reducing emissions from continuous bleed natural gas-driven pneumatic controllers. These options included using low bleed controllers in place of E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63204 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules high bleed controllers, enhanced maintenance (i.e., periodic inspection and repair), and using zero-emissions controllers. For the production and transmission and storage segments, only the option to require low bleed controllers was fully analyzed in these previous analyses. Based on the EPA’s determination at that time that electricity was ‘‘likely unavailable’’ at production and transmission and storage sites, the EPA did not fully consider instrument air or electronic controllers. The EPA also did not evaluate enhanced maintenance, as it was concluded that the highly variable nature of determining the proper methods of maintaining a controller could incur significant costs. The EPA did not evaluate options to reduce emissions from intermittent vent controllers in either the 2012 or 2016 NSPS. Three U.S. States (California, Colorado, and New Mexico) and two Canadian provinces (Alberta and British Columbia) have rules or proposed rules that achieve emission reductions beyond those achieved by NSPS OOOOa. Starting on January 1, 2019, and subject to certain exceptions, a California rule requires that all new and existing continuous bleed devices must not vent natural gas to the atmosphere. The rule allows low bleed devices installed prior to January 1, 2016, to continue to operate, provided that annual testing is performed to verify that the low bleed rate is maintained. A Colorado rule adopted in February 2021, requires that all new controllers are nobleed controllers (which includes selfcontained natural gas-driven controllers), and over a period of two years, a sizeable portion of existing controllers must be retrofit to have a natural gas bleed rate of zero. New Mexico has proposed a rule that would require an emission rate of zero from all controllers located at sites with access to electrical power. The Canadian provinces of Alberta (effective 2022) and British Columbia (effective 2021) also regulate emissions from pneumatic controllers. In British Columbia, pneumatic devices that emit natural gas must not be used at new sources and at existing gas processing plants and large compressor stations, and in Alberta, owners and operators must prevent or control (by 95 percent) vent gas from new pneumatic controllers. While the terminology differs across these regulations, the EPA believes that all these requirements (with the exception of the 95 percent reduction requirement in Alberta) are very similar to if not the same as the zero methane and VOC VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 emission requirement being proposed by the EPA for NSPS OOOOb. From EPA’s review of our past BSER analysis as well as reviewing these other rules, several options were identified for the BSER analysis for NSPS OOOOb to reduce methane and/or VOC emissions from natural gas-driven pneumatic controllers. These include the following: (1) Use of low bleed natural gas-driven pneumatic controllers in the place of high bleed natural gas-driven pneumatic controllers; (2) require zero emissions from intermittent vent controllers except during actuation, and (3) prohibit the emissions of methane and VOC from all pneumatic controllers (i.e., establish a zero methane and VOC emission standard for both continuous bleed and intermittent bleed controllers). e. 2021 BSER Analysis Production and Transmission and Storage Segments For production and transmission and storage sites, the EPA evaluated two options. The first was an option to require the use of low bleed natural gasdriven pneumatic controllers in the place of high bleed natural gas-driven pneumatic controllers, along with a requirement that natural gas-driven intermittent vent pneumatic controllers only discharge natural gas during actuation. We also evaluated an option of establishing a zero methane and VOC emissions standard, which we propose to determine represents the BSER for production and natural gas transmission and storage sites. The first option evaluated was the use of low bleed natural gas-driven pneumatic controllers in the place of high bleed natural gas-driven pneumatic controllers. In the analysis of this option, we examined the emissions reduction potential, the cost of implementation, and the cost effectiveness in terms of cost per ton of emissions eliminated. The emission reduction potential of using a low bleed controller in place of a high bleed controller depends on the actual bleed rate of each device, which varies from device to device. Using average emission factors for each device type, the difference in emissions can be estimated on a per-controller basis. We estimated this difference between a low bleed and a high bleed device to be an 84 percent reduction for controllers in the production segment and a 92 percent reduction in emissions in the transmission and storage segment, equating to a difference of 2.1 tpy methane and 0.6 tpy VOC per controller in the production segment and 2.9 tpy methane and 0.08 tpy VOC per PO 00000 Frm 00096 Fmt 4701 Sfmt 4702 controller in the transmission and storage segment. The cost of a new low bleed natural gas-driven pneumatic controller is approximately $255 higher than the cost of a new high bleed device. On an annualized basis, assuming a 15-year equipment lifetime and a 7 percent interest rate, the cost is $28 per year per low bleed controller. Under the single pollutant approach where all the costs are assigned to the reduction of one pollutant, the estimated cost effectiveness is $13 per ton of methane avoided and $48 per ton of VOC avoided per controller in the production segment. Using the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the estimated cost effectiveness is $7 per ton of methane avoided and $24 per ton of VOC avoided. When considering the cost of saving the natural gas that would otherwise be emitted for the production segment, the cost effectiveness shows an overall savings under both the single pollutant and multipollutant approaches. For the natural gas transmission and storage segment, the cost effectiveness is $10 per ton methane avoided and $355 per ton VOC avoided per controller using the single pollutant method, and $5 per ton of methane and $178 per ton of VOC avoided per controller using the multipollutant method. Transmission and storage facilities do not own the natural gas; therefore, revenues from reducing the amount of natural gas emitted/lost was not applied for this segment. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches. We also evaluated a requirement that natural gas-driven intermittent vent pneumatic controllers only discharge natural gas during actuations. This emissions reduction option would be required in conjunction with a requirement to use low bleed controllers in place of high bleed controllers. The average emission factor determined by an industry study for natural gas-driven intermittent vent controllers, including both properly and improperly operating controllers, is 9.2 scfh natural gas.255 Comparing this to the emission factor for a properly operating intermittent vent controller of 0.3 scfh natural gas illustrates the significant potential for reductions from a program that 255 API Field Measurement Study: ‘‘Pneumatic Controllers EPA Stakeholder Workshop on Oil and Gas.’’ November 7, 2019—Pittsburgh PA. Paul Tupper. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules identifies intermittent vent controllers that are improperly operating and repairing, replacing, or altering their operating conditions so they may function properly. To ensure these devices are emitting natural gas only during actuations in accordance with their design, there would be no equipment expenditure or associated capital costs; however, emissions monitoring or inspections, combined with repair as needed, would be necessary to ensure this proper operation is achieved. We considered requiring independent inspections specifically for intermittent vent controllers but concluded that it would be more efficient to couple inspections of these controllers with the inspections of equipment for leaks under the fugitive monitoring program (see section XII.A of this preamble). The second option we evaluated was a zero methane and VOC emissions standard. While applicability of both the 2012 NSPS OOOO and the 2016 NSPS OOOOa are based on an individual pneumatic controller (as is the proposed definition of affected facility under NSPS OOOOb), zero-emissions controller options are more appropriately evaluated as ‘‘site-wide’’ controls. While individual natural gasdriven pneumatic controllers can be switched to other types of natural-gas driven pneumatic controllers (e.g., high bleed to low bleed types or low bleed to self-contained), the implementation of some zero-emissions controllers options would require equipment that would presumably be used for all the controllers at the site. For example, in order to utilize instrument air driven controllers, a compressor and related equipment would need to be installed. For the vast majority of situations, the EPA does not believe that an owner and operator would install a compressor just for a single controller, but rather would instead install a site-wide system to provide compressed air to all the controllers at the site. Therefore, to adequately account for the costs of the system, including the controllers and the common equipment, we evaluated these zero-emissions controller options using ‘‘model’’ plants. These model plants include assumptions regarding the number of each type of pneumatic controller at a site. Emissions were estimated for each of the model plants using a calculation based on of the number of controllers at the plant and emission factors for each controller. Three sizes of model plants (i.e., small, medium, and large) were developed and used for both the production and transmission and storage segments. Each model plant VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 contained one high bleed natural gasdriven controller and increasing numbers of low bleed and intermittent natural gas-driven controllers. For the production segment, the controllerspecific emission factors used are from a recent study conducted by the American Petroleum Institute,256 and are 2.6 scfh, 16.4 scfh, and 9.2 scfh total natural gas emissions for low bleed, high bleed, and intermittent bleed controllers, respectively. This API study did not cover the transmission and storage segment; therefore, the emission factors from GHGRP subpart W were used, which are 1.37 scfh, 18.2 scfh, and 2.35 scfh for low bleed, high bleed, and intermittent bleed controllers, respectively. It was assumed that the portion of natural gas that is methane is 82.9 percent in the production segment and 92.8 percent in the transmission and storage segment. Further, it was assumed that VOCs were present in natural gas at a certain level compared to methane. The specific ratios assumed were 0.278 pounds VOC per pound methane in the production segment and 0.0277 pounds VOC per pound methane in the transmission and storage segment. This information results in estimated emissions for a single natural gas-driven pneumatic controller in the production segment of 0.39, 2.48, and 1.39 tpy methane and 0.1, 0.7, and 0.4 tpy VOC per low bleed, high bleed, and intermittent vent controller, respectively. The emissions for a single natural gas-driven pneumatic controller in the transmission and storage segment are 0.23, 3.08, and 0.40 tpy methane and 0.006, 0.08, and 0.01 tpy VOC per low bleed, high bleed, and intermittent vent controller, respectively. Based on the factors described above and the number of each type of controller in each model plant, baseline emissions for the model plants were calculated. For the production model plants, the baseline emissions were calculated to be 5.7 tpy methane and 1.6 tpy VOC for the small model plant (assumes fewer controllers on site than medium plant), 11.2 tpy methane and 3.1 tpy VOC for the medium model plant (assumes more controllers on site than small plant), and 24.9 tpy methane and 6.9 tpy VOC for the large model plant (assumes more controllers on site than the medium plant). For the transmission and storage model plants, the baseline emissions were calculated to be 4.1 tpy methane and 0.1 tpy VOC for the small model plant, 5.7 tpy 256 API Field Measurement Study: ‘‘Pneumatic Controllers EPA Stakeholder Workshop on Oil and Gas.’’ November 7, 2019—Pittsburgh PA. Paul Tupper. PO 00000 Frm 00097 Fmt 4701 Sfmt 4702 63205 methane and 0.2 tpy VOC for the medium model plant, and 10.0 tpy methane and 0.3 tpy VOC for the large model plant. For detailed information on the configuration of these model plants and the calculation of the baseline emissions, see the NSPS OOOOb and EG TSD for this rulemaking, which is available in the docket. Instrument air controllers and electronic controllers were the two zero emission options evaluated. Both these options require electricity to operate. Instrument air systems use compressed air as the signaling medium for pneumatic controllers and pneumatic actuators, whereas electronic controllers send an electric signal to an electric actuator (rather than sending a pneumatic signal to a pneumatic actuator). As instrument air systems are usually installed at facilities where there is a high concentration of pneumatic control valves, electrical power from the grid, and the presence of an operator that can ensure the system is properly functioning, we evaluated the use of instrument air for the large model plant with more controllers and the use of electronic controllers, which can be powered by solar panels, at the small and mediumsized model plant with less controllers. The emission reduction potential of using these zero-emissions controllers rather than natural-gas-driven pneumatic controllers is 100 percent since these systems eliminate all natural gas emissions (they do not emit any VOC or methane). Based on the information available to the EPA during development of this proposal, these two zero-emissions options were the only two analyzed. The EPA solicits comment on the other potential zeroemission options for these sites (mechanical-only controllers, selfcontained natural gas-driven controllers, and natural gas-driven controllers where the emissions are captured and routed to a process). For the small and medium-sized model plants, the zero-emissions option evaluated was the use of electronic controllers. The respective emissions reduction for small and medium-sized plants would be 5.7 and 11.2 tpy methane and 1.6 and 3.1 tpy VOC in the production segment and 4.1 and 5.7 tpy methane and 0.11 and 0.16 tpy VOC in the transmission and storage segment. The cost of a new electronic controller system using electricity from the grid or other on-site power generation is estimated to be $26,000 and $46,000, for small and medium-sized plants respectively. The cost of a new solarpowered electronic controller system is E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63206 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules estimated to be $28,000 and $52,000, for small and medium-sized plants respectively. The estimated annualized capital costs, assuming a 15-year equipment lifetime and a 7 percent interest rate, are $2,800 and $5,040, respectively for a system powered with electricity from the grid or other power source for small and medium-sized plants, and $3,090 and $5,630, respectively, for a solar-powered system for small and medium-sized plants. For the production segment, considering the slightly more expensive solar-powered system, under the single pollutant approach, the estimated cost effectiveness is $550 per ton of methane avoided and $1,970 per ton of VOC avoided for a small plant and $500 per ton of methane avoided and $1,810 per ton of VOC avoided for a medium-sized plant. Using the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the estimated cost effectiveness is $275 per ton of methane avoided and $980 per ton of VOC avoided for a small plant and $250 per ton of methane avoided and $900 per ton of VOC avoided for a medium-sized plant in the production segment. When considering the cost of saving the natural gas that would otherwise be emitted for the production segment, the cost effectiveness is $370 per ton of methane avoided and $1,320 per ton of VOC avoided for a small plant and $320 per ton of methane avoided and $1,150 per ton of VOC avoided for a medium-sized plant. Using the multipollutant approach, the estimated cost effectiveness is $185 per ton of methane avoided and $660 per ton of VOC avoided for a small plant and $160 per ton of methane avoided and $580 per ton of VOC avoided for a mediumsized plant in the production segment. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches. For the natural gas transmission and storage segment, considering the slightly more expensive solar-powered system, the estimated cost effectiveness is $750 per ton of methane avoided and $27,200 per ton of VOC avoided for a small plant and $990 per ton of methane avoided and $35,700 per ton of VOC avoided for a medium-sized plant. Using the multipollutant approach, the estimated cost effectiveness is $380 per ton of methane avoided and $13,600 per ton of VOC avoided for a small plant and $490 per ton of methane avoided and $17,800 per ton of VOC avoided for a mediumsized plant. Transmission and storage facilities do not own the natural gas; VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 therefore, revenues from reducing the amount of natural gas emitted/lost was not applied for this segment. While the cost effectiveness values for VOC are higher than the range of what the EPA considers to be reasonable for VOC, the cost effectiveness for methane is within the range of what the EPA considers to be reasonable for methane using the single pollutant approach. For the large model plants, the zeroemissions option evaluated was the use of instrument air systems. For the production segment, the emissions avoided would be 24.9 tpy methane and 6.9 tpy VOC, and in the transmission and storage segment 10.0 tpy methane and 0.3 tpy VOC. The cost of a new instrument air system is estimated to be $96,000 and the estimated annualized capital costs, assuming a 15-year equipment lifetime and a 7 percent interest rate, are $10,500. For the production segment, under the single pollutant approach, the estimated cost effectiveness is $420 per ton of methane avoided and $1,520 per ton of VOC avoided. Using the multipollutant approach, the estimated cost effectiveness is $210 per ton of methane avoided and $760 per ton of VOC avoided. When considering the cost of saving the natural gas that would otherwise be emitted for the production segment, the cost effectiveness is $240 per ton of methane avoided and $860 per ton of VOC avoided. Using the multipollutant approach, the estimated cost effectiveness is $120 per ton of methane avoided and $430 per ton of VOC avoided in the production segment. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches. For the natural gas transmission and storage segment, the estimated cost effectiveness is $1,050 per ton of methane avoided and $38,000 per ton of VOC avoided. Using the multipollutant approach, the estimated cost effectiveness is $530 per ton of methane avoided and $19,000 per ton of VOC avoided. Transmission and storage facilities do not own the natural gas; therefore, revenues from reducing the amount of natural gas emitted/lost was not applied for this segment. While the cost effectiveness values for VOC are higher than the range of what the EPA considers to be reasonable for VOC, the cost effectiveness for methane is within the range of what the EPA considers to be reasonable for methane using the single pollutant approach. Note that the annual costs for these zero-emissions controllers are based on the annualized capital costs only. While PO 00000 Frm 00098 Fmt 4701 Sfmt 4702 we assume the maintenance costs for electric controllers is less than the costs for natural gas-driven controllers, there are costs associated with the use of electricity that are not incurred for natural gas-driven controllers. We solicit comments on whether such operational costs should be included in these estimates, as well as information regarding these costs. The capital costs of solar-powered controllers include the cost of the batteries, which represents around 7 percent of the total cost of a solarpowered system. As noted above, the capital cost was annualized assuming a 15-year lifetime, however batteries for a solar system may have a shorter life. We are soliciting comment on the life of these batteries and, if this life is shorter than 15 years, how the costs of these batteries should be included as a maintenance cost for solar powered systems. The EPA finds that the cost effectiveness for both the low bleed and zero-emissions options are reasonable for sites in the production and natural gas transmission and storage segments. The incremental cost effectiveness in going from the low bleed option to the zero-emissions option is estimated to be $390 and $340 per ton of additional methane eliminated for small and medium-sized plants ($1,400 and $1,200 per ton of VOC), respectively, in the production segment and $640 and $870 per ton of additional methane eliminated for small and medium-sized plants ($23,000 and $31,500 per ton of VOC), respectively, in the transmission and storage segment. The incremental cost effectiveness in going from the low bleed option to the non-emissions option is estimated to be $260 and $940 per ton of additional methane and VOC avoided, respectively, for large plants in the production segment and to be $940 and $34,000 per ton of additional methane and VOC avoided, respectively, for large plants in the transmission and storage segment. These incremental costs of control do not consider savings for the production segment. The EPA believes the incremental costs of control are reasonable for methane and VOC in the production segment, and for methane in the transmission and storage segment. As discussed above, several States and Canadian provinces require the use of controllers that do not emit methane or VOC throughout the Oil and Natural Gas Industry, which further demonstrates the reasonableness of this option and that there are no technical barriers inhibiting the use of electronic controllers or instrument air systems at sites in the production and transmission E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules and storage segments. In 2015, the EPA concluded that, ‘‘[a]t sites without available electrical service sufficient to power an instrument air compressor, only gas driven pneumatic devices are technically feasible in all situations.’’ (80 FR 56623, September 18, 2015). However, since that time, at least two States and two Canadian provinces have adopted regulations that require zero emitting controllers at all new sites. The EPA evaluated these rules, and considers these rules, along with the basic understanding that sources in these areas are able to comply with the rules, evidence that the feasibility issues that led to the EPA’s previous decision not to require zero emission controllers in 2015 have been overcome. Further, the EPA recognizes that industry commenters on the proposed Colorado rule raised some of the same technical feasibility issues that have been presented to the EPA in the past, including battery storage capacity issues, weather-related issues, and mechanical issues related to vibration.257 However, despite these issues being raised, Colorado finalized the requirement that new controllers have a natural gas bleed rate of zero at all sites, even though without power. The EPA has considered new information since 2016 and has now concluded that use of zero-emission controllers is technically feasible subject to a particular proposed exception discussed below. The EPA specifically requests comments on this conclusion. The EPA further solicits comment on market availability of zero-emission options. Secondary impacts from the use of electronic controllers and instrument air systems are indirect, variable, and dependent on the electrical supply used to power the compressor or controllers. These impacts are expected to be minimal. For example, it is estimated that the electricity needed to operate a compressor is only around 0.4 kW/hour/ controller when the compressor is operating. No other secondary impacts are expected. The EPA solicits comment on whether owners and operators would use diesel generators to generate power to run zero-emissions controllers. The EPA recognizes that diesel generators would generate formaldehyde emissions and there could be associated secondary impacts. The EPA does not intend for diesel generators to be used. 257 Pneumatic Controller Task Force Report to the Air Quality Control Commission. Pneumatic Controller Field Study and Recommendations. Colorado Department of Public Health and Environment. Air Pollution Control Division. June 1, 2020. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 In light of the above, we find that the BSER for reducing methane and VOC emissions from natural gas-driven pneumatic controllers at production and transmission and storage sites is the use of zero-emissions controllers. Therefore, for NSPS OOOOb, we are proposing to require zero emissions of methane and VOC to the atmosphere for all pneumatic controllers at production and transmission and storage sites. Both NSPS OOOO and NSPS OOOOa allow the use of high-bleed pneumatic controllers at production sites and natural gas-driven continuous bleed controllers at natural gas processing plants if it is determined that the use of such a pneumatic controller affected facility with a bleed rate greater than the applicable standard is required ‘‘based on functional needs, including but not limited to response time, safety and positive actuation.’’ See 40 CFR 60.5390(a) and 60.5390a(a). This exemption was based on comments received on the 2011 proposed NSPS OOOO rule. There, ‘‘[t]he commenters suggest exemptions that address situations such as those where the natural gas includes impurities that could increase the likelihood of fouling a low-bleed pneumatic controller, such as paraffin or salts; where weather conditions could degrade pneumatic controller performance; during emergency conditions; where flow is not sufficient for low-bleed pneumatic controllers; where electricity is not available; and where engineering judgment recommends their use to maintain safety, reliability or efficiency.’’ (77 FR 49520, August 16, 2012). These reasons to allow for an exemption based on functional need were based on the inability of a lowbleed controller to meet the functional requirements of an owner/operator such that a high-bleed controller would be required in certain instances. Since we are now proposing that nearly all pneumatic controllers have a methane and VOC emission rate of zero, subject to exemption explained below, we do not believe that the reasons cited above are still applicable. Therefore, the proposed rule does not include an exemption based on functional need. The EPA is requesting comment regarding the possibility of situations where functional requirements/needs dictate that a natural gas-driven controller that emits any amount of VOC and/or methane be used. For example, are there situations where a zeroemission controller cannot be used due to functional needs such that an owner/ operator must use a low-bleed controller or an intermittent controller instead? PO 00000 Frm 00099 Fmt 4701 Sfmt 4702 63207 Comments requesting such an exemption should include details of the specific functional need and why all zero-emission controller options are not suitable. For many sites, the EPA believes that the most feasible zero-emission option will be solar-powered controllers. The EPA recognizes that solar-powered controllers are dependent on sunshine, and in areas at higher latitudes that undergo prolonged periods without sunshine, this option could be problematic to implement due to the technical limitations of solar panels coupled with the practical realities related to the hours of sunshine received. Therefore, the proposed rule includes an exemption from the zeroemission requirement for pneumatic controllers at sites in Alaska that do not have access to power (i.e., electricity from the grid or produced using natural gas on-site). Sites with power have clearly demonstrated that zero emissions from controllers is achievable, and therefore the EPA is not proposing to exempt pneumatic controllers at sites in Alaska that have power. The proposed exemption would only apply to pneumatic controllers at sites located in Alaska that do not have access to power. In those situations, affected facilities would not be required to comply with the zero-emission standard, but instead must use lowbleed pneumatic controllers (unless a high bleed device is needed for functional reasons) and must monitor any intermittent controllers in conjunction with the fugitives monitoring program to ensure they are not venting when idle. The EPA is soliciting comment on this proposed exemption. Specifically, the EPA is interested in comments regarding the technical feasibility of solar panels to power pneumatic controllers in Alaska. The EPA is also interested in comments regarding whether there are other locations outside of Alaska where such an exemption may be warranted. In submitting responses to this request, commenters should be mindful that two Canadian Provinces, which are north of any U.S. State other than Alaska, require zero-emitting controllers at all new sites. Natural Gas Processing Plants Natural gas processing plants typically have higher numbers of pneumatic controllers than production and transmission and storage sites. Model plants were also used for this analysis, specifically the model plants used are the same as those used for the 2011 and 2015 BSER analyses, and include small, medium, and large sites. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63208 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules The number of controllers is 15, 63, and 175 for small, medium, and large model plants, respectively. All controllers at these sites are assumed to be continuous, but the number of low bleed and high bleed devices is not specified for the model plants. It was assumed that each controller emitted 1 tpy methane, as derived from Volume 12 of a 1996 GRI report.258 In addition, it was assumed that the portion of natural gas that is methane is 82.8 percent in the natural gas processing segment, and the specific VOC to methane ratio assumed was 0.278 pounds VOC per pound methane. For detailed information on the configuration of these model plants, see the NSPS OOOOb and EG TSD, which is available in the docket. For natural gas processing plants, the only option evaluated was the requirement to use zero-emission controllers. For our analysis, we examined the use of instrument air, which is the most commonly used controller technology at natural gas processing plants. For this analysis, we used cost data from the 2011 NSPS OOOO TSD updated to 2019 dollars. The updated capital costs for an instrument air system at a natural gas processing plant ranges from $20,000 to $162,000, depending on the system size. The annualized costs were based on a 7 percent interest rate and a 10-year equipment life. This equated to an annualized cost of approximately $13,000 to $96,000 per system. The emissions reduction associated with the installation of an instrument air system over natural gas-driven pneumatic controllers ranged from approximately 15 to 175 tpy methane and 4.2 to 49 tpy VOC per system. The cost effectiveness is estimated to range from approximately $550 to $900 per ton methane eliminated $2,000 to $3,100 per ton VOC eliminated. When considering the costs of saving the natural gas that would otherwise be emitted, the cost effectiveness improves, with a cost effectiveness of $370 to $700 per ton of methane eliminated and $1,300 to $2,500 per ton of VOC eliminated. These cost effectiveness values are presented on a single pollutant basis, and the cost of control on a multipollutant basis is 50 percent of these values. These values are well within the range of what the EPA considers to be reasonable for methane 258 Radian International LLC. Methane Emissions from the Natural Gas Industry, Vol. 12: Pneumatic Devices. Prepared for the Gas Research Institute and Environmental Protection Agency. EPA–600/R–96– 080k. June 1996. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 and VOC using both the single pollutant and multipollutant approaches. The 2012 NSPS OOOO and 2016 NSPS OOOOa require a zero-bleed emission rate for pneumatic controllers at natural gas processing plants. Natural gas processing plants have successfully met this standard for many years now. Further, several State agencies have rules that include this zero-bleed requirement for controllers at natural gas processing plants. This is further demonstration of the reasonableness of a zero methane and VOC emission standard for pneumatic controllers at natural gas processing plants. We find the cost effectiveness of eliminating methane and VOC emissions using both the single pollutant and multipollutant approaches to be reasonable. Secondary impacts from the use of instrument air systems are indirect, variable, and dependent on the electrical supply used to power the compressor. These impacts are expected to be minimal, and no other secondary impacts are expected. In light of the above, we find that the BSER for reducing methane and VOC emissions from natural gas-driven pneumatic controllers at natural gas processing plants is the use of zeroemissions controllers. Therefore, for NSPS OOOOb, we are proposing to require a natural gas emission rate of zero for all pneumatic controllers at natural gas processing plants. However, we recognize that there may be technical limitations in some situations where zero-emissions controllers may not be feasible, and therefore, we are proposing an allowance for the use of natural gas-driven pneumatic controllers with an emission rate of methane and VOC greater than zero where needed due to functional requirements in this BSER determination. Justification of this functional need must be provided in an annual report and maintained in records. f. Use of Combustion Devices and VRUs Another option that could potentially be used to reduce emissions from pneumatic controllers is to collect the emissions from natural gas driven continuous bleed controllers and intermittent vent controllers and route the emissions through a closed vent system to a control device or process. This option is allowed in some State rules. While the EPA did not evaluate the cost effectiveness of this option due to a lack of available information regarding control system costs and feasibility across sites, we think this option could be cost effective for owners PO 00000 Frm 00100 Fmt 4701 Sfmt 4702 and operations in certain situations, particularly if the site already has a control device to which the emissions from controllers could be routed. As this option could be used to achieve significant methane and VOC emission reductions (95 percent or greater), we are soliciting comment on whether this is a control technique used in the industry to reduce emissions from natural gas-driven pneumatic controllers. We are also interested in information related to the performance testing, monitoring, and compliance requirements associated with these control devices. Finally, we are interested in ideas as to how this option could potentially fit with the proposed requirements for pneumatic controllers. For example, if an owner or operator determines that a natural gas-driven pneumatic controller is required for functional need reasons, the EPA could require that emissions be collected and routed to a control device that achieves 95, or 98, percent control. 2. EG OOOOc The EPA evaluated BSER for the control of methane from existing pneumatic controllers (designated facilities) in all segments in the Crude Oil and Natural Gas source category covered by the proposed NSPS OOOOb and translated the degree of emission limitation achievable through application of the BSER into a proposed presumptive standard for these facilities that essentially mirrors the proposed NSPS OOOOb. First, based on the same criteria and reasoning as explained above, the EPA is proposing to define the designated facilities in the context of existing pneumatic controllers as those that commenced construction on or before November 15, 2021. Based on information available to the EPA, we did not identify any factors specific to existing sources that would indicate that the EPA should change these definitions as applied to existing sources. As such, for purposes of the emission guidelines, the definition of a designated facility in terms of pneumatic controllers is each individual natural gas driven pneumatic controller (continuous bleed or intermittent vent) that vents to the atmosphere. Next, the EPA finds that the control options evaluated for new sources for NSPS OOOOb are appropriate for consideration in the context of existing sources under the EG OOOOc. The EPA finds no reason to evaluate different, or additional, control measures in the context of existing sources because the EPA is unaware of any control measures, or systems of emission E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules reduction, for pneumatic controllers that could be used for existing sources but not for new sources. Next, the methane emission reductions expected to be achieved via application of the control measures identified above for new sources are also expected to be achieved by application of the same control measures to existing sources. The EPA finds no reason to believe that these calculations would differ for existing sources as compared to new sources because the EPA believes that the baseline emissions of an uncontrolled source are the same, or very similar, and the efficiency of the control measures are the same, or very similar, compared to the analysis above. This is also true with respect to the costs, non-air environmental impacts, energy impacts, and technical limitations discussed above for the control options identified. For the most part, the information presented above regarding the costs related to new sources and the NSPS are also applicable for existing sources. The instance where the EPA estimated a difference in the costs between a new and existing source was for the retrofit of an existing production site to use instrument air at sites equipped with electrical power. While the equipment needed is the same as for new sites, it may be more difficult to design and install a retrofitted system. Therefore, the EPA estimates the costs for design and installation to be twice that of the costs for new systems (from approximately $32,000 for new systems to approximately $64,000 for existing systems), resulting in the capital cost of the system being approximately $127,000 with an annualized cost of approximately $14,000. As noted above, the EPA’s analysis for this proposal only examined the cost of instrument air for the large model plant. The total elimination of methane emissions (25 tons per year methane for production sites and 10 tons per year methane for transmission and storage sites) would be the same for existing sources as presented above for new sources. Considering the cost difference, the cost effectiveness for production sites is $560 per ton of methane eliminated without considering savings, and $365 per ton when considering savings. For the transmission and storage segment, the cost effectiveness is $1,400 per ton of methane eliminated. These values are within the range of what the EPA considers to be reasonable for methane. Since none of the other factors are different for existing sources when compared to the information discussed above for new sources, the EPA concludes that BSER for existing VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 63209 sources and the proposed presumptive standard for EG OOOOc to be the requirement to use zero-emission controllers. This proposed EG includes the exemption from the zero-emission standard for pneumatic controllers in Alaska as explained above in the context of the proposed NSPS OOOOb. effectiveness, costs, and other factors related to new natural gas processing plants and the NSPS are also applicable for existing sources. Therefore, the EPA concludes that BSER for existing sources and the EG OOOOc for natural gas processing plants is the requirement to use zero-emission controllers. b. Possible Phase-In Approach for Existing Sources The EPA recognizes there could be different compliance time approaches that could be implemented for existing pneumatic controllers. The EPA’s proposal for compliance times State plans must include to meet the requirements of the EG can be found in Section XIV.E. As explained there, the EPA is proposing that State plans must generally include a 2-year timeline for compliance in the proposed EG, but is also soliciting comment on the possibility of the EG requiring different compliance timelines for different emission points. Specifically, in the context of pneumatic controllers, the EPA is further soliciting comment on including a phase-in approach in the EG. The EPA recognizes that a phase-in approach may only be appropriate for existing sources as new facilities could presumably plan for zero-emission controllers during construction. A phase-in period could span a number of years (e.g., 2 years), to allow owners and operators to prioritize conversion of natural gas-driven controllers at existing sites based on specific factors (e.g., focus first on sites with onsite power, sites with highest production, sites with the highest number of controllers). A phase-in approach could also result in the conversion of a certain percentage of sites within a given area (e.g., State or basin). For example, the State of Colorado requires a minimum of 40 percent of sites to be converted after 2 years, with 15 percent in year 1 and 25 percent in year 2. The EPA also recognizes potential challenges with a phase-in approach, such as difficulties with enforcement and calculation of the percentage converted due to the frequency at which sites may change ownership. The EPA solicits comment on all aspects of the EG requiring State plans to include a phase-in approach, and whether the agency should consider this type of approach rather than a single compliance time. The EPA also solicits comment on cost and feasibility factors that would enter into adopting and designing a phase-in timeline. D. Proposed Standards for Well Liquids Unloading Operations c. Natural Gas Processing Plants The information presented above regarding the emissions, emission reduction options and their PO 00000 Frm 00101 Fmt 4701 Sfmt 4702 1. NSPS OOOOb a. Background In the 2015 NSPS OOOOa proposal (80 FR 56614–56615, September 18, 2015), the EPA stated that based on available information and input received from stakeholders on the 2014 Oil and Natural Gas Sector Liquids Unloading Processes review document,259 sufficient information was not available to propose a standard for liquids unloading. At that time, the EPA requested comment on technologies and techniques that could be applied to new gas wells to reduce emissions from liquids unloading events in the future. In the 2016 NSPS OOOOa final rule (81 FR 35846, June 3, 2016), the EPA stated that, although the EPA received valuable information from the public comment process, the information was not sufficient to finalize a national standard representing BSER for liquids unloading at that time. For this proposal, the EPA conducted a review of available information, including new information that became available after the 2016 NSPS OOOOa rulemaking. As a result of this review, the EPA is proposing a zero VOC and methane emission standard under NSPS OOOOb for liquid unloading, which can be achieved using non-venting liquids unloading methods. In the event that it is technically infeasible or not safe to perform liquids unloading with zero emissions, the EPA is proposing to require that an owner or operator establish and follow BMPs to minimize methane and VOC emissions during liquids unloading events to the extent possible. These proposed requirements apply to each well liquids unloading event. An overall description of liquids unloading, the definition of a modification, the definition of affected facility, our BSER analysis, and the proposed format of the standard are presented below. 259 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Liquids Unloading Processes. Report for Oil and Natural Gas Sector. Liquids Unloading Processes Review Panel. April 2014. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63210 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules b. Description In new gas wells, there is generally sufficient reservoir pressure/gas velocity to facilitate the flow of water and hydrocarbon liquids through the well head and to the separator to the surface along with produced gas. In mature gas wells, the accumulation of liquids in the wellbore can occur when the bottom well pressure/gas velocity approaches the average reservoir pressure (i.e., volumetric average fluid pressure within the reservoir across the areal extent of the reservoir boundaries).260 This accumulation of liquids can impede and sometimes halt gas production. When the accumulation of liquids results in the slowing or cessation of gas production (i.e., liquids loading), removal of fluids (i.e., liquids unloading) is required in order to maintain production. These gas wells therefore often need to remove or ‘‘unload’’ the accumulated liquids so that gas production is not inhibited. The 2019 U.S. GHGI estimates almost 175,800 metric tpy of methane emissions from liquids unloading events for natural gas systems. Specifically, this includes almost 175,800 metric tpy from natural gas production, 98,900 metric tpy of which is from liquids unloading events that use a plunger lift, and 76,900 metric tpy from liquids unloading events that do not use a plunger lift. The overall total represents 3 percent of the total methane emissions estimated from natural gas systems. In addition to the GHGI information, we also examined the information submitted under GHGRP subpart W. Specifically, we examined the GHGRP subpart W liquids unloading emissions data reported for Reporting Years 2015 to 2019. The liquids unloading emissions reported under GHGRP subpart W include emissions from venting wells, including those wells that vent during events that use a plunger lift and wells that vent during events that do not use a plunger lift. The information reported shows that methane emissions from liquids unloading for a well range from 0 to over 1,000 metric tons (1,100 tons) per year. While the single well with liquids unloading emissions of 1,100 tpy appears to be an outlier, there were over 65 subbasins with reported average liquids unloading emissions of 50 tpy or greater per well when disaggregating data by year and calculation method. There were over 1,000 wells reporting in these subbasins. In addition, there were almost 300 sub-basins with reported 260 Gordon Smith Review. Oil & Natural Gas Sector Liquids Unloading Processes. Submitted: June 16, 2014. Pg. 4. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 average liquids unloading methane emissions of 10 tpy or greater per well. There were almost 8,000 wells reporting in these subbasins. Another source of information reviewed related to emissions information from liquids unloading was a study published in 2015 by Allen, et al. (University of Texas (UT) Study).261 262 The UT Study collected monitoring data across regions of the U.S. Among other findings in this report, for wells that vent more than 100 times per year, the average methane emissions per well per year were 27 metric tpy, with 95 percent confidence bounds of 10 to 50 Mg/yr (based on the confidence bounds in the emissions per event). The monitoring data shows that methane emissions from liquids unloading for a well range from 1 to 19,500 Mscf per year, or 0.02 to 406 tpy.263 As indicated by the UT study 264 emissions information, a small fraction of wells account for a large fraction of liquids unloading emissions. c. Modification As noted in section XII.D.1.b, new wells typically do not require liquids unloading until the point that the accumulation of liquids impedes or even stops gas production. At that point, the well must be unloaded of liquids to improve the gas flow. One method to accomplish this involves the intentional manual venting of the well to the atmosphere to improve gas flow. This is done using various techniques. One common manual unloading technique diverts the well’s flow, bypassing the production separator to a lower pressure source, such as an atmospheric pressure tank. Under this scenario, venting to the atmospheric tank occurs because the separator operates at a higher pressure than the atmospheric tank and the well will temporarily flow to the atmospheric tank (which has a lower pressure than the pressurized separator). Natural gas is released through the tank vent to the atmosphere until liquids are unloaded and the flow diverted back to the 261 D.T. Allen, D.W. Sullivan, D. Zavala-Araiza, A.P. Pacsi, M. Harrison, K. Keen, M.P. Fraser, A. Daniel Hill, B.K. Lamb, R.F. Sawyer, J.H. Seinfeld, Methane emissions from process equipment at natural gas production sites in the United States: Liquid unloadings. Environ. Sci. Technol. 49, 641– 648 (2015). doi:10.1021/es504016r Medline. (UT Study). 262 D.T. Allen, D.W. Sullivan, D. Zavala-Araiza, A.P. Pacsi, M. Harrison, K. Keen, M.P. Fraser, A. Daniel Hill, B.K. Lamb, R.F. Sawyer, J.H. Seinfeld. Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Liquid Unloadings—Supporting Information; (UT Study—SI). Table S5–1, pg. 21. 263 UT Study—SI. Tables S3–1 to S3–3, pgs. 11– 14. 264 UT Study. pg. 642. PO 00000 Frm 00102 Fmt 4701 Sfmt 4702 separator. As discussed later in this section, the EPA has received feedback that there are technical difficulties with flaring vented emissions as a result of the intermittent and surging flow characteristic of venting for liquids unloading, and the changing velocities during an unloading event. Since each unloading event constitutes a physical or operational change to the well that has the potential to increase emissions, the EPA is proposing to determine each event of liquids unloading constitutes a modification that makes a well an affected facility subject to the NSPS. See 40 CFR 60.14(a) (‘‘any physical or operational change to an existing facility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies shall be considered a modification within the meaning of section 111 of the Act’’). The EPA solicits comment on this determination. d. Definition of Affected Facility Given that we have proposed to determine that every liquids unloading event is a modification, the next step is to define the affected facility. The EPA recognizes that methods are commonly employed that significantly reduce, or even eliminate, emissions from liquids unloading. Therefore, the EPA is coproposing two options on how a modified well due to a liquids unloading event would be covered under the rule. Under the first option, the affected facility subject to the requirements of NSPS OOOOb would be defined as every well that undergoes liquids unloading after the effective date of the final rule. Under this scenario, a well that undergoes liquids unloading is an affected facility regardless of whether the liquids unloading approach used results in venting to the atmosphere. This option posits that techniques employed to unload liquids that do not increase emissions are not to be considered in whether the unloading event is an affected facility or not, since the liquids unloading event in their absence could result in an emissions increase. This is somewhat analogous to a physical change to an existing storage vessel that resulted in the ability to increase throughput, and thus emissions. This physical change could result in an increase in emissions even if emissions were captured and routed back to a process such that the level of pollutant actually emitted to the atmosphere did not change. Under this scenario, the EPA could request and obtain compliance and enforcement information on non-venting liquids E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 unloading event methods commonly employed (simple records and reporting requirements), as well as venting liquids unloading events. Under the second option, the affected facility would be defined as every well that undergoes liquids unloading using a method that is not designed to totally eliminate venting (i.e., that results in emissions to the atmosphere). Under this scenario, if an owner or operator employs a method to unload liquids that does not vent to the atmosphere, the liquids unloading event would not constitute an increase in emissions and therefore, the well would not be an affected facility. As such, the first liquids unloading event that vents to the atmosphere after the effective date of the final rule, would be an affected facility subject to the requirements of NSPS OOOOb. This option could create an enforcement information and compliance gap. Specifically, the EPA would not be able to obtain compliance assurance information on liquids unloading events and emissions/ methods and there could be a decreased incentive for owners or operators to ensure that no unexpected emission episodes occur when a method designed to be non-venting is used. The EPA solicits comments on the two affected facility definition options being co-proposed. Specifically, we request comment on whether there are implementation and/or compliance assurance concerns that arise with applying either of the co-proposed options. In addition, we request comment on if there are any appropriate exemptions for operations that may be unlikely to result in emissions, such as wellheads that are not operating under positive pressure. e. 2021 BSER Analysis The choice of what liquids unloading technique to employ is based on an operator well-by-well and reservoir-byreservoir engineering analysis. Because liquids unloading operations entail a number of complex science and engineering considerations that can vary across well sites, there is no single technological solution or technique that is optimal for liquids unloading at all wells. Rather, a large number of differing technologies, techniques and practices (i.e., ‘‘methods’’) have been developed to address the unique characteristics of individual wells so as to manage liquids and maintain production. These methods include, but are not limited to, manual unloading, velocity tubing or velocity strings, beam or rod pumps, electric submergence pumps, intermittent unloading, gas lift (e.g., use of a plunger lift), foam agents, VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 wellhead compression, and routing the gas to a sales line or back to a process. Selecting a particular method to meet a particular well’s unloading needs must be based on a production engineering decision that is designed to remove the barriers to production. The situation is further complicated as the best method for a particular well can change over time. At the onset of liquids loading, techniques that rely on the reservoir energy are typically used. Eventually a well’s reservoir energy is not sufficient to remove the liquids from the well and it is necessary to add energy to the well to continue production. In the 2016 NSPS OOOOa final rule preamble, the EPA acknowledged that operators must select the technique to perform liquids unloading operations based on the conditions of the well each time production is impaired. During the development of the 2016 NSPS OOOOa rule, the EPA considered subcategorization based on the potential for well site liquids unloading emissions but determined that the differences in liquids unloading events (with respect to both frequency and emissions level) are due to specific conditions of a given well at the time the operator determines that well production is impaired such that unloading must be done. Since owners and operators must select the technique to perform an unloading operation based on those conditions, and because well conditions change over time, each iteration of unloading may require repeating a single technique or attempting a different technique that may not have been appropriate under prior conditions. As noted above, we recognized that the choice of method to unload liquids from a well needs to be a production engineering decision based on the characteristics of the well at the time of the unloading, and owners and operators need the flexibility to select a method that is effective and can be safely employed. No information has become available since 2016 that leads the EPA to reach a different conclusion regarding subcategorization of wells for the purpose of developing standards to address liquids unloading emissions. Further, the EPA acknowledges the need for owners and operators to have the flexibility to select the most appropriate method(s) and recognize that any standard must not impede this flexibility. Many methods used for liquids unloading do not result in any venting to the atmosphere, provided that the method is properly executed. High-level PO 00000 Frm 00103 Fmt 4701 Sfmt 4702 63211 summaries of a few of these methods are provided below.265 A commonly used method employed in the field is the use of a plunger lift system. While plunger lift systems often are used in a way to minimize emissions, under certain conditions they can be operated to unload liquids in a manner that eliminates the need to vent to the atmosphere. Plunger lifts use the well’s own energy (gas/pressure) to drive a piston or plunger that travels the length of the tubing in order to push accumulated liquids in the tubing to the surface. Specific criteria regarding well pressure and liquid to gas ratio can affect applicability. Candidate wells for plunger lift systems generally do not have adequate downhole pressure for the well to flow freely into a gas gathering system. Optimized plunger lift systems (e.g., with smart well automation) can decrease the amount of gas vented by up to and greater than 90 percent, and in some instances can reduce the need for venting due to overloading. Plunger lift costs range from $1,900 to $20,000.266 Adding smart automation can cost anywhere between an estimated $4,700 to $18,000 depending on the complexity of the well. Natural Gas STAR estimates that the annual cost savings from avoided emissions from the use of an automated system ranges anywhere between $2,400 and $10,241 per year.267 Other artificial lifts (e.g., rod pumps, beam lift pumps, pumpjacks and downhole separator pumps) are typically used when there is inadequate pressure to use a plunger lift, and the only means of liquids unloading to keep gas flowing is downhole pump technology. Artificial lifts can be operated in a manner that produces no emissions. The use of an artificial lift requires access to a power source. The capital and installation costs (including location preparation, well clean out, artificial lift equipment and pumping unit) is estimated to be $41,000 to $62,000/well, with the average cost of a pumping unit being between $17,000 to $27,000. 268 265 ‘‘Oil and Natural Gas Sector Liquids Unloading Processes’’. Report for Oil and Natural Gas Sector Liquids Unloading Processes Review Panel. Prepared by U.S. EPA OAQPS. April 2014. 265 80 FR 56593, September 18, 2015. 266 U.S. Environmental Protection Agency. Installing Plunger Lift Systems in Gas Wells. Office of Air and Radiation: Natural Gas Star Program. Washington, DC. 2006. 267 U.S. Environmental Protection Agency. (U.S. EPA) 2011. Options for Removing Accumulated Fluid and Improving Flow in Gas Wells. Office of Air and Radiation: Natural Gas Star Program. Washington, DC. 2011. pg. 1. 268 U.S. EPA, 2011. pg. 9. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63212 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules Velocity tubing is smaller diameter production tubing that reduces the cross-sectional area of flow, increasing the flow velocity and achieving liquids removal without blowing emissions to the atmosphere. Generally, a gas flow velocity of 1,000 feet per minute (fpm) is necessary to remove wellbore liquids. Velocity tubing strings are appropriate for low volume natural gas wells upon initial completion or near the end of their productive lives with relatively small liquids production and higher reservoir pressure. Candidate wells include marginal gas wells producing less than 60 Mcfd. Similarly, coil tubing can also be used in wells with lower velocity gas production (i.e., seamed coiled tubing may provide better lift due to elimination of turbulence in the flow stream). The proper use of velocity tubing is considered to be a ‘‘no emissions’’ solution. It is also low maintenance and effective for low volumes lifted. Velocity lifting can be deployed in combination with foaming agents (discussed below). The capital and installation costs are estimated to range anywhere from $7,000 to $64,000 per well.269 Installation requires a well workover rig to remove existing production tubing and placement of the smaller diameter tubing string in the well. The use of foaming agents (soap, surfactants) as a method to unload liquids is implemented by the injection of foaming agents in the casing/tubing annulus by a chemical pump on a timer basis. The gas bubbling of the soapwater solution creates gas-water foam which is more easily lifted to the surface for water removal. This, like the use of artificial lifts, requires power to run the surface injection pump. Additionally, foaming agents work best if the fluid in the well is at least 50 percent water and are not effective for natural gas liquids or liquid hydrocarbons. This method requires that the soap supply be monitored. If the well is still unable to unload fluid, smaller tubing may be needed to help lift the fluids. Foaming agents and velocity tubing are reported as possibly being more effective when used in combination. No equipment is required in shallow wells. In deep wells, a surfactant injection system requires the installation of surface equipment and regular monitoring. Foaming agents are reported as being low cost ‘‘no emissions’’ solution. The capital and startup costs to install soap launchers and velocity tubing is estimated to range between $7,500 and $67,880, with the monthly cost of the foaming agent is approximately $500 269 U.S. EPA, 2011. pg. 8. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 per well or approximately $6,000 per year.270 These are just a few examples of demonstrated methods that are being used in the industry to unload accumulated liquids that impair production, that can be implemented without venting and, thus, without emissions. As stressed earlier, the selection of a specific method must be made based on well-specific characteristics and conditions. Since GHGRP subpart W only requires reporting of liquids unloading events that resulted in venting of methane, no information is submitted regarding those wells that utilize a non-venting method. The EPA is also not aware of information that specifies the total number of wells that need to undergo liquids unloading. A 2012 report sponsored by the API and American Natural Gas Alliance (ANGA) 271 provided more definitive insight into the number of wells that use nonventing liquids unloading methods. This report indicated that an estimated 21.1 percent of plunger equipped wells vent, and 9.3 percent of non-plunger equipped wells vent. The EPA interprets this to mean that almost 80 percent of plunger-equipped wells, and over 90 percent of non-plunger-equipped wells perform liquids unloading and utilize non-venting methods. As noted above, there is a tremendous range in the emissions from liquids unloading reported for individual wells. Further, as discussed above, the costs for the non-venting methods range considerably. Also, as discussed above, we have determined that the myriad of possible reservoir conditions and unloading methods do not lend to any reasonable subcategorization of the industry for which representative wells could be designed. Therefore, it is not possible to develop a ‘‘model’’ well, or even a series of model wells, that can be used to conduct the type of analysis frequently performed for BSER determinations that calculates a cost per ton of emissions reduced (or in this case eliminated). Based on the highest costs included in the cost examples provided above, the cost effectiveness of a non-venting method would be considered reasonable for wells with annual methane emissions from liquids unloading of 16 tpy or greater, or VOC emissions of 3 tpy 270 U.S. EPA. 2011. Pg. 8. T. URS Corporation and Lev-On, M. the LEVON Group. Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production. Summary and Analysis of API and ANGA Survey Responses. Prepared for the American Petroleum Institute and the American Natural Gas Alliance. September 21, 2012. 271 Shires, PO 00000 Frm 00104 Fmt 4701 Sfmt 4702 or greater. This upper range is based on the cost of the combination of velocity tubing and soap launchers. The upper range of the capital cost cited above was $67,800. Annualizing this capital cost at a 7 percent interest rate over 10 years, and adding in the $6,000 per year foaming agent cost, results in a total annual cost of $15,600. Given the total elimination of emissions, the cost effectiveness for a well with 16 tpy methane emissions would be $980 per ton of methane reduced, which is a level that the EPA considers reasonable for methane. Similarly, for VOC, the cost effectiveness for a well with 3 tpy VOC emissions would be $5,200 per ton of VOC reduced. This is also a level that the EPA considers reasonable. Given the range of costs, it could be reasonable even for some wells with annual liquids unloading methane emissions as low as 2.5 tpy ($400 per ton of methane reduced (velocity tubing)), or VOC emissions as low as 0.2 tpy ($5,000 per ton of VOC reduced (velocity tubing)). Based on the GHGRP subpart W data for the years 2015 through 2019, around 50 percent of the wells that performed liquids unloading and reported emissions reported emissions higher than these levels. While owners and operators must select a liquids unloading method that is applicable for the well-specific conditions, they have the choice of many methods that can be used to eliminate venting/emissions from liquids unloading events. While we do not have information to calculate the specific percentage of total wells undergoing liquids unloading that use non-venting methods, available information suggests that a majority of wells that undergo liquids unloading do not vent. The EPA solicits information on the number (or percent) of liquids unloading events that vent to the atmosphere versus do not vent to the atmosphere under normal conditions and whether there are technical obstacles (other than costs) that would not allow liquids unloading to be performed without venting. CAA section 111(a) requires that the standard reflect the BSER that the EPA determines ‘‘has been adequately demonstrated.’’ An ‘‘adequately demonstrated system’’ is one that ‘‘has been shown to be reasonably reliable, reasonably efficient, and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.’’ Essex Chem., 486 F.2d at 433. For the reasons explained above and further elaborated below, the EPA considers non-venting methods such as those described above E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules to have been adequately demonstrated as the BSER for liquids unloading events. The complete elimination of emissions from liquids unloading with these non-venting methods have been adequately demonstrated in practice. The EPA notes that as part of decisions regarding liquids unloading, one goal of owners and operators is to eliminate venting to prevent the loss of product (natural gas) that could be routed to the sales line. States currently encourage the use of methods to eliminate emissions unless venting of emissions is necessary for safety reasons or when it is technically infeasible to not vent to unload liquids from the wellbore. For example, Pennsylvania has a general plan approval and/or general operating permit application (BAQ–GPA/GP–5A) that specifies that an owner or operator that conducts wellbore liquids unloading operations shall use best management practices including, but not limited to, plunger lift systems, soaping, swabbing, unless venting is necessary for safety to mitigate emissions during liquids unloading activities (Best Available Technology (BAT) Compliance Requirements under Section L of the General Permit). As discussed previously, a majority of wells already conduct liquids unloading operations without venting to the atmosphere. Also, as discussed previously, there are multiple nonventing liquids unloading methods that an owner and operator can select based on a well’s specific characteristics and conditions. Our evaluation of costs shows that there are non-venting liquids unloading methods that could be employed to unload liquids that are reasonable given a wide range of emission levels. Finally, there are no negative secondary environmental impacts that would result from the implementation of methods that would eliminate venting of methane and VOC emissions to the atmosphere. In light of the above, the EPA considers nonventing liquids unloading methods to have been adequately demonstrated to represent BSER for reducing methane and VOC emissions during liquids unloading events. An ‘‘adequately demonstrated’’ system needs not be one that can achieve the standard ‘‘at all times and under all circumstances.’’ Essex Chem., 486 F.2d at 433. That said, as discussed below, the EPA recognizes that there may be reasons that a non-venting method is infeasible for a particular well, and the proposed rule would allow for the use of BMPs to reduce the emissions to the maximum extent possible. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 The EPA recognizes that there may be safety and technical reasons why venting to the atmosphere is necessary to unload liquids. In addition, it is possible that a well production engineer has already explored non-venting options and determined that there was no feasible option due to its specific characteristics and conditions. For scenarios where a liquids unloading method employed requires venting to the atmosphere, the EPA evaluated requiring BMPs that would minimize venting to the maximum extent possible. There are several States that require the development and implementation of BMPs that minimize emissions from liquids unloading events that vent. For example, Colorado requires specified BMPs to eliminate or minimize vented emissions from liquids unloading. The rule requires that all attempts be made to unload liquids without venting unless venting is required for safety reasons. If venting is required, the rule requires that owners and operators be on site and that they ensure that any venting is limited to the maximum extent practicable. Specific BMPs evaluated are based on State rules that require BMPs to minimize emissions during liquids unloading events are to require operators to monitor manual liquids unloading events onsite and to follow procedures that minimize the need to vent emissions during an event. This includes following specific steps that create a differential pressure to minimize the need to vent a well to unload liquids and reducing wellbore pressure as much as possible prior to opening to atmosphere via storage tank, unloading through the separator where feasible, and requiring closure of all well head vents to the atmosphere and return of the well to production as soon as practicable. For example, where a plunger lift is used, the plunger lift can be operated so that the plunger returns to the top and the liquids and gas flow to the separator. Under this scenario, venting of the gas can be minimized and the gas that flows through the separator can be routed to sales. In situations where production engineers select an unloading technique that results or has the potential to vent emissions to the atmosphere, owners and operators already often implement BMPs in order to increase gas sales and reduce emissions and waste during these (often manual) liquids unloading activities. We performed a cost and impacts evaluation of the use of BMPs to reduce emissions from liquids unloading. This evaluation is provided in the NSPS PO 00000 Frm 00105 Fmt 4701 Sfmt 4702 63213 OOOOb and EG TSD for this rulemaking. Another potential method for reducing emissions from liquids unloading is to capture the vented gas from an unloading event and route it to a control device. At the time the Crude Oil and Natural Gas Sector Liquids Unloading Processes draft review document was submitted to reviewers, the EPA noted that, although the EPA was not aware of any specific instances where combustion devices/flares were used to control emissions vented from unloading events, the EPA requested information on the technical feasibility of flaring as an emissions control option for liquids unloading events. Feedback received from reviewers indicated that there are technical reasons that flaring during liquids unloading is not a feasible option.272 Reviewers emphasized that, in order to flare gas during liquids unloading, the liquids would need to be separated from the well stream, and the intermittent and surging flow characteristics of venting for liquids unloading, changing velocities during an unloading, and flare ignition considerations for a sporadically used flare (i.e., would require either a continuous pilot or electronic igniter) would make use of a flare technically and financially infeasible.273 274 The reviewers indicated that separating the liquids from the well stream would require the well stream to flow through a separator with sufficient backpressure to separate the gas and liquids. One reviewer noted that after separating the liquids from the well stream the gas would then be piped to flare system, where the backpressure needed to operate the separator would affect the performance of a plunger lift system (if used). Based on feedback received on the technical and cost feasibility of using a flare to control vented emissions from liquids unloading events indicating that a flare cannot be used in all situations, we did not consider this option any further in this proposal. However, the EPA is soliciting comments about the use of control devices to reduce emissions from liquids unloading events. Specifically, we request information on the types of wells and unloading events for which routing to control is feasible 272 U.S. Environmental Protection Agency. Oil and Natural Gas Sector Liquids Unloading Processes. Report for Crude Oil and Natural Gas Sector. Liquids Unloading Processes Review Panel. April 2014. 273 Gordon Smith Review. Oil and Natural Gas Sector Liquids Unloading Processes. Review Submitted: June 16, 2014. Pg. 31. 274 Jim Bolander, P.E., Senior Vice President, Southwestern Energy (SWN). Review Submitted: April 2014. Pg. 8. E:\FR\FM\15NOP2.SGM 15NOP2 63214 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 and effective, the level of emission reduction achieved, and the testing and monitoring requirements that apply. A similar potential method is to capture the vented gas from an unloading event and route it to the sales line or back to a process. This could potentially represent another method that results in zero emissions. While this is not a mitigation option that has been specifically mentioned for emissions from liquids unloading, it is a common option for other emission sources in the oil and natural gas production segment. The EPA is soliciting comments about the option to collect and route emissions back to the sales line or to a process. Specifically, we request information on the types of wells and unloading events for which this option is feasible (if any). If this option is feasible, we also request information on the specifics of the equipment and processes needed to accomplish this, as well as the costs. In conclusion, the EPA evaluated several options and identified the use of non-venting methods as the BSER for reducing methane and VOC emissions during liquids unloading events. However, the EPA recognizes there could be situations where it is infeasible to utilize a non-venting method. Therefore, the EPA proposes to allow for the development and implementation of BMPs to reduce emissions to the extent possible during liquids unloading where it is infeasible to utilize a non-venting method. f. Format of the Standard As discussed under section XII.D.1.d of this preamble, the EPA is coproposing two regulatory approaches to implement the BSER determination. For Option 1, the affected facility would be defined as every well that undergoes liquids unloading. This would mean that wells that utilize a non-venting method for liquids unloading would be affected facilities and subject to certain reporting and recordkeeping requirements. These requirements would include records of the number of unloadings that occur and the method used. A summary of this information would also be required to be reported in the annual report. The EPA also recognizes that under some circumstances venting could occur when a selected liquids unloading method that is designed to not vent to the atmosphere is not properly applied (e.g., a technology malfunction or operator error). Under the proposed rule Option 1 owners and operators in this situation would be required to record and report these instances, as well as document and report the length of VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 venting and what actions were taken to minimize venting to the maximum extent possible. For wells that utilize methods that vent to the atmosphere, the proposed rule would require that they: (1) Document why it is infeasible to utilize a non-venting method due to technical, safety, or economic reasons; (2) develop BMPs that ensure that emissions during liquids unloading are minimized; (3) follow the BMPs during each liquids unloading event and maintain records demonstrating they were followed; (4) report the number of liquids unloading events in an annual report, as well as the unloading events when the BMP was not followed. While the proposed rule would not dictate the specific practices that must be included, it would specify minimum acceptance criteria required for the types and nature of the practices. Examples of the types and nature of the required practice elements for BMP are provided in section XII.D.1.e, such as those contained in Colorado’s rule. The EPA is specifically requesting comment on the minimum elements that should be required in BMPs and the specificity that the proposed rule should include regarding these elements. An advantage of this regulatory option is that it would provide information to the EPA on the number of liquids unloading events that occur and the types of unloading methods used. Having this important information would enhance the EPA, the industry, and the public’s knowledge of emissions from liquids unloading. Option 1 would also provide incentive for owners and operators to ensure that non-venting methods are applied as they are designed such that unexpected emissions do not occur as the result of technology malfunctions or operator error. However, it would result in some recordkeeping and reporting burden for wells that already use or plan to use non-venting methods that would not be incurred under Option 2. For Option 2, the affected facility would be defined as every well that undergoes liquids unloading using a method that is not designed to eliminate venting. The significant difference in this option is that wells that utilize nonventing methods would not be affected facilities that are subject to the NSPS OOOOb. Therefore, they would not have requirements other than to maintain records to demonstrate that they used non-venting liquids unloading methods. The requirements for wells that use methods that vent would be the same as described above under Option 1. The EPA believes that this option would provide additional incentive for PO 00000 Frm 00106 Fmt 4701 Sfmt 4702 owners and operators to seek ways to overcome potential infeasibility issues to ensure that their wells are not affected facilities and subject to reporting and recordkeeping requirements. This would ultimately result in lower emissions. However, this would not provide the EPA information to have a more comprehensive understanding of emissions and emission reduction methods from liquids unloading. It would also not provide incentive for owners and operators to ensure that no unexpected emission episodes occur when a method designed to be non-venting is used. 2. EG OOOOc As described above, the EPA is proposing that each unloading event represents a modification, which will make the well subject to new source standards under NSPS. Therefore, existing wells that undergo liquids unloading would become subject to NSPS OOOOb. This will mean that there will never be a well that undergoes liquids unloading that will be ‘‘existing’’ for purposes of CAA section 111(d). Therefore, there is no need for emissions guidelines or an associated presumptive standard under EG OOOOc for liquids unloading operations. E. Proposed Standards for Reciprocating Compressors 1. NSPS OOOOb a. Background The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each individual new or reconstructed reciprocating compressor, except for those compressors located at a well site, or those located at an adjacent well site and servicing more than one well site. The 2016 NSPS OOOOa required the reduction of methane and VOC emissions from new, reconstructed, or modified reciprocating compressors by replacing rod packing systems within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing. As an alternative, the 2016 NSPS OOOOa allowed owners or operators to collect the emissions from the rod packing using a rod packing emissions collection system that operates under negative pressure and route the rod packing emissions to a process through a closed vent system. In determining BSER for reciprocating compressors in 2016, the EPA determined that the previous determination for NSPS OOOO conducted in 2011/2012 still represented BSER in 2016. In the 2012 determination the EPA first concluded that the piston rod packing wear E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules produces fugitive emissions that cannot be captured and conveyed to a control device, and that an operational standard pursuant to section 111(h) of the CAA was appropriate. The EPA conducted analyses of the costs and emission reductions of the replacement of rod packing every 3 years or 26,000 hours of operation and determined that the costs per ton of emissions reduced were reasonable for the industry, with the exception of compressors at well sites. Based on the 2011 BSER analysis, requiring replacement of rod packing every 3 years or 26,000 hours of operation for well site reciprocating compressors was not considered cost effective (almost $57,000 per ton of VOC reduced).275 No other more stringent control options were evaluated at that time. For this review of the NSPS, the EPA focused on these control options which were previously assessed for the 2012 NSPS OOOO and the 2016 NSPS OOOOa. In addition, we evaluated an option that would require annual monitoring to determine if the rod packing needed to be replaced. This option is in contrast to the option where replacement is required on a fixed (e.g., 3 year) schedule. For this review, BSER was evaluated for reciprocating compressors at gathering and boosting stations in the production segment (considered to be representative of emissions from reciprocating compressors at centralized production facilities), at natural gas processing plants, and at sites in the transmission and storage segment. In 2012 and in 2016, the EPA determined that the cost effectiveness of replacement of the rod packing based on the fixed 3-year (or 26,000 hours) schedule was unreasonable for reciprocating compressors located at the well site (discussed below). No new information has become available to change this determination. Therefore, we did not include reciprocating compressors located at well sites in our evaluation of regulatory options. However, as discussed in section XI.L (Centralized Production Facilities) of this preamble, the EPA believes the definition of ‘‘well site’’ in NSPS OOOOa may cause confusion regarding whether reciprocating compressors located at centralized production facilities are also exempt from the standards. The EPA is proposing a new definition for a ‘‘centralized production facility’’. The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, 275 2011 NSPS OOOO TSD. pg. 6–17. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of ‘‘centralized production facilities’’. This proposal is necessary in the context of reciprocating compressors to distinguish between these compressors at centralized production facilities where the EPA has determined that the standard should apply, and compressors at standalone well sites where the EPA has determined that the standard should not apply. In our current analysis, described below, we consider the reciprocating compressor gathering and boosting segment emission factor as being representative of reciprocating compressor emissions located at centralized production facilities. As such, the EPA is proposing that reciprocating compressors located at centralized production facilities would be subject to the standards in NSPS OOOOb and the EG in subpart OOOOc, but reciprocating compressors at well sites (standalone well sites) would not. As a result of the EPA’s review of NSPS OOOOa, we are proposing that BSER is to replace the rod packing when, based on annual flow rate measurements, there are indications that the rod packing is beginning to wear to the point where there is an increased rate of natural gas escaping around the packing to unacceptable levels. We are proposing that if annual flow rate monitoring indicates a flow rate for any individual cylinder as exceeding 2 scfm, an owner or operator would be required to replace the rod packing. b. Description In a reciprocating compressor, natural gas enters the suction manifold, and then flows into a compression cylinder where it is compressed by a piston driven in a reciprocating motion by the crankshaft powered by an internal combustion engine. Emissions occur when natural gas leaks around the piston rod when pressurized natural gas is in the cylinder. The compressor rod packing system consists of a series of flexible rings that create a seal around the piston rod to prevent gas from escaping between the rod and the inboard cylinder head. However, over time, during operation of the compressor, the rings become worn and the packaging system needs to be replaced to prevent excessive leaking from the compression cylinder. As discussed previously, emissions from a reciprocating compressor occur when, over time, during operation of the compressor, the rings that form a seal around the piston rod that prevents gas from escaping become worn. This PO 00000 Frm 00107 Fmt 4701 Sfmt 4702 63215 results in increasing emissions from the compression cylinder. Based on the 2021 GHGI,276 the methane emissions from reciprocating compressors in 2019 represented 14 percent of the total methane emissions from natural gas systems in the Crude Oil and Natural Gas Industry sector. For segments where the GHGI included a breakdown of methane emissions for reciprocating compressors, the reported emissions were 309,500 metric tons for the gathering and boosting segment, 46,700 metric tons for the processing segment, 406,500 metric tons for the transmission segment, and 103,200 metric tons for the storage segment. c. Affected Facility For purposes of the NSPS, the reciprocating compressor affected facility is a single reciprocating compressor. A reciprocating compressor located at a well site, or an adjacent well site and servicing more than one well site, is not an affected facility under the proposed rule for the NSPS OOOOb. As discussed above, the EPA is proposing that the affected facility includes reciprocating compressors located at centralized production facilities and the affected facility exception for ‘‘a well site, or an adjacent well site servicing more than one well site’’ applies to standalone well sites and not centralized production facilities. d. 2021 BSER Analysis The methodology used for estimating emissions from reciprocating compressor rod packing is consistent with the methodology developed for the 2012 NSPS OOOO BSER analysis and then also used to support the 2016 NSPS OOOOa BSER. This approach uses volumetric methane emission factors referenced in the EPA/GRI study 277 as the basis, multiplied by the density of methane. These factors were per cylinder, so they were multiplied by the average number of cylinders per reciprocating compressor at each oil and gas industry segment, the pressurized factor (percentage of hours per year the compressor was pressurized), and 8,760 hours (number of hours in a year). Once the methane emissions were calculated, VOC emissions were calculated by multiplying the methane by ratios developed based on representative gas composition. The specific ratios that were used for this analysis were 0.278 276 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks (1990–2019). Published in 2021. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990– 2019. 277 EPA/GRI. (1996). Methane Emissions from the Natural Gas Industry: Volume 8—Equipment Leaks. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63216 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules pounds VOC per pound of methane for the production and processing segments, and 0.0277 pounds VOC per pound of methane for the transmission and storage segment. The resulting baseline emissions from reciprocating compressors were 12.3 tpy methane (3.4 tpy VOC) from gathering and boosting stations, 23.3 tpy methane (6.5 tpy VOC) from natural gas processing plants, 27.1 tpy methane (0.75 tpy VOC) from transmission stations, and 28.2 tpy methane (0.78 tpy VOC) from storage facilities. Reducing emissions that result from the leaking of natural gas past the piston rod packing can be accomplished through several approaches including: (1) Specifying a frequency for the replacement of the compressor rod packing, (2) monitoring the emissions from the compressor and replacing the rod packing when the results exceed a specified threshold, (3) specifying a frequency for the replacement of the piston rod, (4) requiring the use of specific rod packing materials, and/or (5) capturing the leaking gas and routing it either to a process or a control device. There was either insufficient information to establish BSER or it was determined that the option cannot be applied in all situations for approach options (3) through (5). These are discussed briefly below. Like the packing rings, piston rods on reciprocating compressors also deteriorate. Piston rods, however, wear more slowly than packing rings, having a life of about 10 years.278 Rods wear ‘‘out-of-round’’ or taper when poorly aligned, which affects the fit of packing rings against the shaft (and therefore the tightness of the seal) and the rate of ring wear. An out-of-round shaft not only seals poorly, allowing more leakage, but also causes uneven wear on the seals, thereby shortening the life of the piston rod and the packing seal. Replacing or upgrading the rod can reduce reciprocating compressor rod packing emissions. Also, upgrading piston rods by coating them with tungsten carbide or chrome reduces wear over the life of the rod. We assume that operators will choose, at their discretion, when to replace/realign or retrofit the rod as part of regular maintenance procedures and replace the rod when appropriate when the compressor is out of service for other maintenance such as rod packing replacement. Although replacing/ realigning or retrofitting the rod has been identified as a potential methane 278 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR Program. 2006. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 and VOC emission reduction option for reciprocating compressors, there is insufficient information on its emission reduction potential and use throughout the industry. Therefore, we did not evaluate this option any further as BSER for this proposal. Although specific analyses have not been conducted, there may be potential for reducing methane and VOC emissions by updating rod packing components made from newer materials, which can help improve the life and performance of the rod packing system. One option is to replace the bronze metallic rod packing rings with longer lasting carbon-impregnated Teflon rings. Compressor rods can also be coated with chrome or tungsten carbide to reduce wear and extend the life of the piston rod. Although changing the rod packing material has been identified as a potential methane and VOC emission reduction option for reciprocating compressors, there is insufficient information on its emission reduction potential and use throughout the industry. Therefore, we did not evaluate this option any further as BSER for this proposal. The 2016 NSPS OOOOa includes the alternative to route the emissions from reciprocating compressors to a process. One estimate obtained by the EPA states that a gas recovery system can result in the elimination of over 99 percent of methane emissions that would otherwise occur from the venting of the emissions from the compressor rod packing. The emissions that would have been vented are combusted in the compressor engine to generate power. It was estimated that, if a facility is able to route rod packing vents to a VRU system, it is possible to recover approximately 95–100 percent of emissions. As a comparison, the EPA estimated that the 3-year/26,000-hour changeout results in between 55 and 80 percent emission reduction. Therefore, an option to achieve additional emission reductions could be to require routing the reciprocating compressor emissions to a process/through a closed vent system under negative pressure. Although this was a control option considered in the 2016 NSPS OOOOa (and included as an alternative), the EPA did not require routing to a process for all compressors because at that time there was insufficient information to require this as a control for all reciprocating compressors. The EPA received feedback that this option cannot be applied in every installation, and has not received any new information that indicates this has changed. Thus, this option was not considered further as a requirement but PO 00000 Frm 00108 Fmt 4701 Sfmt 4702 for this proposal, as with the 2016 NSPS OOOOa, it is considered to be an acceptable alternative to mitigate methane and VOC emissions where it is technically feasible to apply. Similarly, another option evaluated as having the potential to achieve methane and VOC emission reductions was to require the collection of emissions in a closed vent system and routing them to a flare or other control device. If the gas is routed to a flare, approximately 95 percent of the methane and VOC would be reduced. The EPA has expressed historically and maintains that combustion is not believed to be a technically feasible control option for reciprocating compressors because, as detailed in the 2011 NSPS OOOO TSD, routing of emissions to a control device can cause positive back pressure on the packing, which can cause safety issues due to gas backing up in the distance piece area and engine crankcase in some designs. The EPA has not identified any new information to indicate that this has changed. Therefore, this option was not considered further as BSER for this proposal. The remaining two control option approaches that were evaluated further for this proposal include: (1) Specifying a frequency for the replacement of the compressor rod packing (equivalent to the frequency used in the 2016 NSPS OOOOa BSER control level), and (2) monitoring the emissions from the compressor and replacing the rod packing when the results exceed a specified threshold. Both of these approaches would reduce the escape of natural gas from the piston rod. No wastes would be created (other than the worn packing that is being replaced) and no wastewater would be generated. As noted previously, periodically replacing the packing rings ensures the correct fit is maintained between packing rings and the rod, thereby limiting emissions occurring around the flexible rings that fit around the shaft by recreating a seal against leakage that may have been lost due to wear. The potential emission reductions for reciprocating compressors at gathering and boosting stations, processing plants, and transmission and storage facilities were calculated by comparing the average rod packing emissions with the average emissions from newly installed and worn-in rod packing. As noted above, because the EPA concluded that the cost effectiveness of this option was extremely unreasonable for reciprocating compressors at well sites in previous BSER analyses (see the 2011 NSPS OOOO TSD, section 2.2; 80 FR 56620, September 18, 2015), and since no new information was identified that E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules would change this outcome as it relates to stand alone well sites, reductions and costs were not re-evaluated in this analysis for reciprocating compressors at production well sites. The emissions after the replacement of the rod packing were calculated using the methodology used under previous NSPS actions (see NSPS OOOOb and EG TSD, section 7.1). The resulting emission reductions used for the analysis represented the emission reductions expected in the year the rod packing is replaced. It is expected that there would be an increase in the emissions (and decrease in the emission reductions) from a compressor where the rod packing was replaced the second and third years before the next replacement. As noted above, this assumed reduction was between 55 and 80 percent depending on the location of the compressor. The costs of replacing rod packing were obtained from a Natural Gas STAR Lessons Learned document 279 and the dollars were converted to 2019 dollars. The estimated cost to replace the packing rings in 2019 dollars was estimated to be $1,920 per cylinder. It was assumed that rod packing replacement would occur during planned shutdowns and maintenance, and therefore no additional travel costs would be incurred for implementing a rod packing replacement program. Since the assumed number of cylinders differs for reciprocating compressors at different segments, this means the capital costs also vary. These estimated capital costs are $6,350 at gathering and boosting and transmission stations, $4,800 at processing plants, and $8,650 at storage stations. The 26,000-hour replacement frequency used for the cost impacts in the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD was determined using a weighted average of the annual percentage of time that reciprocating compressors are pressurized. The weighted average percentage was calculated to be 98.9 percent. This percentage was multiplied by the total number of hours in 3 years to obtain a value of 26,000 hours. This calculates to an average of 3.8 years for gathering and boosting compressors, 3.3 years for processing compressors, 3.8 years for transmission compressors, and 4.4 years for storage compressors. The calculated years were assumed to be the equipment life of the compressor rod packing and were used to calculate the capital 279 EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. Environmental Protection Agency. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 recovery factor for each of the segments. Assuming an interest rate of 7 percent, the capital recovery factors were calculated to be 0.3093, 0.3498, 0.3093, and 0.2695 for the gathering and boosting part of production, processing, transmission, and storage segments, respectively. The capital costs were calculated using the average rod packing cost noted above and the average number of cylinders per compressor (which differs depending on sector segment). The annual capital costs were calculated using the capital costs and the capital recovery factors. The estimated annual costs ranged from $1,700 at processing plants to just over $2,300 at storage facilities. Note that these estimated costs represent the costs, and associated emission reductions, that would occur in the year when the rod packing was changed. There would be no costs for the other two years in the three-year cycle. The costs presented for gathering and boosting segment reciprocating compressors represent the estimated costs assumed for reciprocating compressors located at centralized production facilities. There are monetary savings associated with the amount of natural gas saved with reciprocating compressor rod packing replacement. Monetary savings associated with the amount of gas saved with reciprocating compressor rod packing replacement were estimated using a natural gas price of $3.13 per Mcf. Estimated savings were only applied for gathering and boosting stations and processing plants, as it is assumed the owners of the compressor station do not own the natural gas that is compressed at the station. Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness of replacement of the reciprocating rod packing within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing, is approximately $290 per ton of methane reduced for gathering and boosting ($100 per ton if gas savings are considered), $90 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $90 per ton of methane reduced for the transmission segment, and $110 per ton of methane reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of replacement of the reciprocating rod packing within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing, is approximately $140 per ton PO 00000 Frm 00109 Fmt 4701 Sfmt 4702 63217 of methane reduced for gathering and boosting ($50 per ton if gas savings are considered), $45 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $45 per ton of methane reduced for the transmission segment, and $50 per ton of methane reduced for the storage segment. Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the VOC cost effectiveness of replacement of the reciprocating rod packing within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing, is approximately $1,030 per ton of VOC reduced for gathering and boosting ($380 per ton if gas savings are considered), $330 per ton of VOC reduced for the processing segment (net savings if gas savings are considered), $3,260 per ton of VOC reduced for the transmission segment, and $3,860 per ton of VOC reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of replacement of the reciprocating rod packing within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing, is approximately $520 per ton of VOC reduced for gathering and boosting ($190 per ton if gas savings are considered), $160 per ton of VOC reduced for the processing segment (net savings if gas savings are considered), $1,630 per ton of VOC reduced for the transmission segment, and $1,930 per ton of VOC reduced for the storage segment. As an alternative to replacing the rod packing on a fixed schedule, another option is to replace the rod packing when, based on measurements, there are indications that the rod packing is beginning to wear to the point where there is an increased rate of natural gas escaping around the packing to unacceptable levels. This is an approach required by the California Greenhouse Gas Emission Regulation and in Canada. The California Greenhous Gas Emission Regulation requires that the rod packing/seal be tested during periodic inspections and, if the rod packing/seal leak concentration exceeds the specified threshold of 2 scfm/cylinder, repairs must be made within 30 days.280 Similarly, certain Canadian jurisdictions require periodic monitoring measurements of rod packing vent 280 State of California Air Resources Board (CARB). ‘‘Regulation for Greenhouse Gas Emission Standards for Crude Oil and Natural Gas Facilities.’’ Oil and Gas Final Regulation Order (ca.gov). E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63218 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules volumes (typically annually) for existing reciprocating compressors. Where specified vent volumes are exceeded, the rules require corrective action be taken to reduce the flow rate to below or equal to a specified limit, as demonstrated by a remeasurement. Vent volume thresholds specified that would result in the need for corrective action vary from 0.49 to 0.81 scfm/cylinder.281 This approach is similar to an approach identified in the Natural Gas STAR Program referred to as ‘‘Economic Packing and Piston Rod Replacement.’’ 282 Under this approach, facilities use specific financial objectives and monitoring data to determine emission levels at which it is cost effective to replace rings and rods. Benefits of calculating and utilizing this ‘‘economic replacement threshold’’ include methane and VOC emission reductions and natural gas cost savings. Using this approach, one Natural Gas STAR partner reportedly achieved savings of over $233,000 annually at 2006 gas prices. An economic replacement threshold approach can also result in operational benefits, including a longer life for existing equipment, improvements in operating efficiencies, and long-term savings. The EPA is not proposing to establish a financial objective or economic replacement threshold in this proposal, but the costs and emission reductions of replacing rod packing based on monitoring from this program were considered in the analysis discussed below. The elements of such a program include establishing a frequency of monitoring, identifying a threshold where action is required to reduce emissions, and specifying the action for reducing emissions. The option defined by the EPA and evaluated below is for annual monitoring and requiring the replacement of the rod packing if the measured flow rate for any individual cylinder exceeds 2 scfm. This threshold is consistent with California’s regulation. However, this option differs from the California regulation in that it would require a complete replacement of the rod packing if this threshold is exceeded, where California allows repair sufficient to reduce the flow rate back below 2 scfm. The 2 scfm flow rate threshold was established based on 281 Canadian Federal standards: https:// gazette.gc.ca/rp-pr/p2/2018/2018-04-26-x1/pdf/g2152x1.pdf; Discussion Draft Regulation 26.11.41 (maryland.gov); MAP-Technical-Report-December19-2019-FINAL.pdf (nm.gov). 282 U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners. Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR Program. 2006. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 manufacturer guidelines indicating that a flow rate of 2 scfm or greater was considered indicative of rod packing failure.283 We estimated the emission reductions from requiring annual flow rate monitoring and repair/replacement of packing when the measured flow rate exceeds 2 scfm total gas during pressurized operation. Based on California’s background regulatory documentation, information provided to the State indicated that the average leak rate for those compressors emitting more than 2 scfm was about 3 scfm during pressurized operation, and less than 2 scfm during pressurized idle and unpressurized states. Therefore, we assumed that the leak rate for compressors emitting more than 2 scfm was about 3 scfm during pressurized operation. As indicated above for the fixed schedule rod packing replacement option, based on the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD, the average emissions from a newly installed rod packing are assumed to be 11.5 scfh per cylinder.284 Using a ratio of 0.829 methane: Total natural gas ratio, 3 scfm total gas is approximately 2.49 scfm (149.2 scfh) methane. This compressor emission rate, which was used for all industry segments, was converted to an annual mass emission rate by applying segment-specific pressurized factors, then converted to a mass basis. The estimated percent reduction in methane emissions that would be achievable from reducing 149.2 scfh methane/cylinder to 11.5 scfh methane/ cylinder (average emissions from a newly installed rod packing/cylinder) is 92 percent. We applied this percent reduction in methane emissions and estimated reciprocating compressor methane and VOC emission reductions that would be achieved from repairing/ replacing rod packing based on the annual flow rate monitoring option. The calculations assume that all cylinders are emitting at 3 scfm, and that the rod packings for all compressor cylinders are replaced. This represents the emission reductions expected for the year in which the rod packings are replaced. Emissions would be expected to increase (and emission reductions decrease) in subsequent years until the next time the annual measurements require that the rod packing be replaced. The capital and annual costs of replacing the rod packings are the same 283 State of California. Air Resources Board Public Hearing to Consider the Proposed Regulation for Greenhouse Gas Emission Standards for Crude Oil and Natural Gas Facilities. Staff Report: Initial Statement of Reasons. pgs. 96–97. 284 2011 TSD, pg. 6–13. PO 00000 Frm 00110 Fmt 4701 Sfmt 4702 as presented above for the fixed interval rod packing replacement option. In addition, this option would include the costs associated with the annual flow measurements. The estimated costs of this monitoring are based on the costs for annual flow rate monitoring under GHGRP subpart W for similar flow rate annual measurement requirements ($597). The capital costs associated with replacing compressor rod packing would only occur in the year when packing is required to be replaced. The monitoring costs would be incurred every year. Additionally, the cost estimates assume that the packing of all compressor cylinders would need to be replaced (which is unlikely to be the case in many instances) and are therefore conservative estimates. Support information for the California rule cites data indicating that approximately 14 percent of compressors measurements indicated a leak rate of over 2 scfm per cylinder. Based on an average of 3.45 cylinders/ compressor, California assumed that the packing for 2 cylinders/compressor would need to be replaced to come into compliance with the 2 scfm standard (57.9 percent).285 Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness of the annual monitoring option is approximately $230 per ton of methane reduced for gathering and boosting ($40 per ton if gas savings are considered), $110 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $100 per ton of methane reduced for the transmission segment, and $110 per ton of methane reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of replacement of the reciprocating rod packing based on the annual monitoring approach is approximately $110 per ton of methane reduced for gathering and boosting ($20 per ton if gas savings are considered), $50 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $50 per ton of methane reduced for the transmission 285 Based on Appendix B. Economic Analysis. State of California. Air Resources Board. Proposed Regulation for Greenhouse Gas Emission Standards for Crude Oil and Natural Gas Facilities. pg. B–28. Notice Package for Oil and Gas Reg (ca.gov); State of California. Air Resources Public Hearing to Consider the Proposed Regulation for Greenhouse Gas Emission Standards for Crude Oil and Natural Gas Facilities. Staff Report: Initial Statement of Reasons. Date of Release: May 31, 2016. pg. 99. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules segment, and $60 per ton of methane reduced for the storage segment. Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the VOC cost effectiveness of the annual monitoring option is approximately $810 per ton of VOC reduced for gathering and boosting ($160 per ton if gas savings are considered), $380 per ton of VOC reduced for the processing segment (net savings if gas savings are considered), $3,700 per ton of VOC reduced for the transmission segment, and $4,100 per ton of VOC reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of replacement of the reciprocating rod packing based on the annual monitoring approach is approximately $410 per ton of VOC reduced for gathering and boosting ($80 per ton if gas savings are considered), $190 per ton of VOC reduced for the processing segment (net savings if gas savings are considered), $1,850 per ton of VOC reduced for the transmission segment, and $2,040 per ton of VOC reduced for the storage segment. We also assessed the incremental cost effectiveness of the annual monitoring option compared to the fixed 3-year/ 26,000 replacement schedule. Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the incremental cost effectiveness (without natural gas savings) from the fixed replacement option to the annual monitoring option for methane is approximately $130 per ton for gathering and boosting stations, $210 per ton for processing plants, $180 per ton for transmission stations, and $140 per ton for storage facilities. For VOC, the incremental cost effectiveness is approximately $480 per ton for gathering and boosting stations, $750 per ton for processing plants, $6,600 per ton for transmission stations, and $5,150 per ton for storage facilities. The cost effectiveness of both options (fixed schedule and annual monitoring) are reasonable for methane and VOC using either the single pollutant or multipollutant approach. The incremental cost effectiveness in going from the fixed schedule option to the annual monitoring option is reasonable for all scenarios, with the exception of VOC for transmission stations. Therefore, based on the consideration of the costs in relation to the emission reductions, the EPA finds that the annual monitoring option is the most reasonable option. Further, as discussed above, California requires reciprocating VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 compressor annual rod packing flow rate monitoring and repair and or replacement of the packing where flow rate monitoring indicates a measurement that exceeds 2 scfm. This further supports the reasonableness of a monitoring program. Neither the fixed schedule rod packing replacement option nor the rod packing replacement based on annual monitoring option would result in secondary emissions impacts as both options would reduce the escape of natural gas from the piston rod. No wastes would be created (other than the worn packing that is being replaced) and no wastewater would be generated. An advantage related to the replacement of rod packing for reciprocating compressors based on annual rod packing monitoring is that it would only require replacement of the rod packing where monitoring of the rod packing indicates wear and increasing flow rate/ emissions to unacceptable levels. This optimizes the output of capital expenditures to focus on emissions control where an increased emissions potential is identified. In light of the above we determined that annual rod pack flow rate monitoring and replacement of the packing where flow rate monitoring indicates a measurement that exceeds 2 scfm represents BSER for NSPS OOOOb for this proposal for all segments including reciprocating compressors located at centralized productions facilities (with the exception of compressors at stand-alone well sites). As in the 2016 NSPS OOOOa, the EPA is proposing to allow the collection and routing of emissions to a process as an alternative standard because that option would achieve emission reductions equivalent to, or greater than, the proposed standard for NSPS OOOOb. The affected facility based on EPA’s review would continue to be each reciprocating compressor not located at a well site, or an adjacent well site and servicing more than one well site. As discussed above, the EPA is proposing a new definition for a ‘‘centralized production facility’’. The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of ‘‘centralized production facilities’’. Thus, the EPA is proposing that reciprocating compressors located at centralized production facilities would be subject to the standards in NSPS in OOOOb, but reciprocating PO 00000 Frm 00111 Fmt 4701 Sfmt 4702 63219 compressors at well sites (standalone well sites) would not. 2. EG OOOOc The EPA evaluated BSER for the control of methane from existing reciprocating compressors (designated facilities) in all segments in the Crude Oil and Natural Gas source category covered by the proposed NSPS OOOOb and translated the degree of emission limitation achievable through application of the BSER into a proposed presumptive standard for these facilities that essentially mirrors the proposed NSPS OOOOb. First, based on the same criteria and reasoning as explained above, the EPA is proposing to define the designated facility in the context of existing reciprocating compressors as those that commenced construction on or before November 15, 2021. Based on information available to the EPA, we did not identify any factors specific to existing sources that would indicate that the EPA should alter this definition as applied to existing sources. Next, the EPA finds that the control measures evaluated for new sources for NSPS OOOOb are appropriate for consideration for existing sources under the EG OOOOc. The EPA finds no reason to evaluate different, or additional, control measures in the context of existing sources because the EPA is unaware of any control measures, or systems of emission reduction, for reciprocating compressors that could be used for existing sources but not for new sources. Next, the methane emission reductions expected to be achieved via application of the control measures identified above to new sources are also expected to be achieved by application of the same control measures to existing sources. The EPA finds no reason to believe that these calculations would differ for existing sources as compared to new sources because the EPA believes that the baseline emissions of an uncontrolled source are the same, or very similar, and the efficiency of the control measures are the same, or very similar, compared to the analysis above. This is also true with respect to the costs, non-air environmental impacts, energy impacts, and technical limitations discussed above for the control options identified. The EPA has not identified any costs associated with applying these controls at existing sources, such as retrofit costs, that would apply any differently than, or in addition to, those costs assessed above regarding application of the identified controls to new sources. The cost effectiveness values for the E:\FR\FM\15NOP2.SGM 15NOP2 63220 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules proposed presumptive standard of replacement of the rod packing based on an annual monitoring threshold is approximately $230 per ton of methane reduced ($40 per ton if gas savings are considered) for the gathering and boosting segment (including reciprocating compressors located at centralized tank facilities), $110 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $100 per ton of methane reduced for the transmission segment, and $110 per ton of methane reduced for the storage segment. In summary, the EPA did not identify any factors specific to existing sources, as opposed to new sources, that would alter the analysis above for the proposed NSPS OOOOb as applied to the designated pollutant (methane) and the designated facilities (reciprocating compressors). As a result, the proposed presumptive standard for existing reciprocating compressors is as follows. For reciprocating compressors in the gathering and boosting segment (including reciprocating compressors located at centralized tank facilities), processing, and transmission and storage segments, the presumptive standard is replacement of the rod packing based on an annual monitoring threshold. Specifically, the presumptive standard would require an owner or operator of a reciprocating compressor designated facility to monitor the rod packing flow rate annually. When the measured leak rate exceeds 2 scfm (in pressurized mode), the standard would require replacement of the rod packing. As an alternative, the presumptive standard would be routing rod packing emissions to a process via a closed vent system under negative pressure. F. Proposed Standards for Centrifugal Compressors khammond on DSKJM1Z7X2PROD with PROPOSALS2 1. NSPS OOOOb a. Background The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each wet seal compressor not located at a well site, or an adjacent well site and servicing more than one well site. The 2016 NSPS OOOOa required methane and VOC emissions be reduced from each centrifugal compressor wet seal fluid degassing system by 95.0 percent. Compliance with this requirement allowed routing of emission from the wet seal fluid degassing system to a control device or to a process. Dry seal compressors were not subject to requirements under the 2016 NSPS OOOOa. In determining BSER for wet seal compressors in 2016, the EPA VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 determined that the previous determination for NSPS OOOO conducted in 2011/2012 still represented BSER for the control of VOC in 2016. In addition, the EPA determined that analogous control of methane represented BSER. In the 2012 determinations, the EPA conducted analyses of the cost and emission reductions of (1) requiring the conversion of a wet seal system to a dry seal system, and (2) routing to a control device or process. The 2011 NSPS OOOO rule (76 FR 52738, 52755, August 23, 2011) proposed an equipment standard that would have required the use of dry seals to limit the VOC emissions from new centrifugal compressors. At that time, the EPA solicited comments on the emission reduction potential, cost, and any technical limitations for the option of routing the gas back to a low-pressure fuel stream to be combusted as fuel gas. In addition, in 2011 (76 FR 52738), the EPA solicited comments on whether there are situations or applications where a wet seal is the only option, because a dry seal system is infeasible or otherwise inappropriate. The EPA received information indicating that the integration of a centrifugal compressor into an operation may require a certain compressor size or design that is not available in a dry seal model, and in the case of capture of emissions with routing to a process, there may not be down-stream equipment capable of handling a low-pressure fuel source. In the final 2012 NSPS OOOO rule, the EPA made the determination that the replacement of wet seals with dry seals and routing to a process was not technically feasible or practical for some centrifugal compressors, and also that the costs per ton of emissions reduced were reasonable for routing emissions to a control device or process. No other more stringent control options were evaluated at that time. During the development of the 2016 NSPS OOOOa rule, the EPA reviewed available information on control options for wet seal compressors and did not identify any new information to indicate that this has changed. For this review, the EPA also focused on these control options. BSER was evaluated for wet-seal centrifugal compressors at gathering and boosting stations (considered to be representative of emissions from centrifugal compressors at centralized production facilities) in the production segment, at natural gas processing plants, and at sites in the transmission and storage segment. During the development of the 2012 NSPS OOOO and 2016 NSPS PO 00000 Frm 00112 Fmt 4701 Sfmt 4702 OOOOa rulemakings, our data indicated that there were no centrifugal compressors located at well sites. Since the 2012 NSPS OOOO and 2016 NSPS OOOOa rulemakings, we have not received information that would change our understanding that there are no centrifugal compressors in use at well sites. However, as discussed in section XI.L (Centralized Production Facilities) of this preamble, the EPA believes the definition of ‘‘well site’’ in NSPS OOOOa may cause confusion regarding whether centrifugal compressors located at centralized production facilities are also exempt from the standards. The EPA is proposing a new definition for a ‘‘centralized production facility’’. The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of ‘‘centralized production facilities’’. This proposal is necessary in the context of centrifugal compressors to distinguish between these compressors at centralized production facilities where the EPA has determined that the standard should apply, and compressors at standalone well sites where the EPA has determined that the standard should not apply. In our current analysis, described below, we consider the centrifugal compressor gathering and boosting segment emission factor as being representative of centrifugal compressor emissions located at centralized production facilities. As such, the EPA is proposing that centrifugal compressors located at centralized production facilities would be subject to the standards in NSPS OOOOb and the EG in subpart OOOOc, but centrifugal compressors at well sites (standalone well sites) would not. In addition to the requirement to reduce methane and VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95.0 percent, the 2016 NSPS OOOOa requires compressor components to be monitored as fugitive emissions components and leaks found are to be repaired under the fugitive emissions monitoring requirements of 40 CFR 60.5397a. The monitoring frequency depends on source (i.e., well sites, compressor stations) and sector segment. These fugitive emissions components were not considered part of the centrifugal compressor affected facility. Based on the EPA’s review of NSPS OOOOa, we are proposing that BSER continues to be that methane and VOC E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 emissions be reduced from each centrifugal compressor wet seal fluid degassing system by 95.0 percent. b. Description Centrifugal compressors use a rotating disk or impeller to increase the velocity of the natural gas where it is directed to a divergent duct section that converts the velocity energy to pressure energy. These compressors are primarily used for continuous, stationary transport of natural gas in the processing and transmission systems. Some centrifugal compressors use wet (meaning oil) seals around the rotating shaft to prevent natural gas from escaping where the compressor shaft exits the compressor casing. The wet seals use oil which is circulated at high pressure to form a barrier against compressed natural gas leakage. The circulated oil entrains and adsorbs some compressed natural gas that may be released to the atmosphere during the seal oil recirculation process. Off gassing of entrained natural gas from wet seal centrifugal compressors is not suitable for sale and is either released to the atmosphere, flared, or routed back to a process. Some centrifugal compressors utilize dry seal systems. Dry seal systems minimize leakage by using the opposing force created by hydrodynamic grooves and springs. The hydrodynamic grooves are etched into the surface of the rotating ring affixed to the compressor shaft. When the compressor is not rotating, the stationary ring in the seal housing is pressed against the rotating ring by springs. When the compressor shaft rotates at high speed, compressed natural gas has only one pathway to leak down the shaft, and that is between the rotating and stationary rings. This natural gas is pumped between the grooves in the rotating and stationary rings. The opposing force of highpressure natural gas pumped between the rings and springs trying to push the rings together creates a very thin gap between the rings through which little natural gas can leak. While the compressor is operating, the rings are not in contact with each other and, therefore, do not wear or need lubrication. O-rings seal the stationary rings in the seal case. Historically, the EPA has considered dry seal centrifugal compressors to be inherently lowemitting and has never required control of emissions from dry seal compressors. The EPA has received feedback,286 however, that there are some wet seal compressor system designs that are also low emitting when compared to dry seal 286 Conference Call. Prepared by Tora Consulting. December 19, 2018. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 compressors and is soliciting comment on lower emitting wet seal compressor system designs and dry seal compressor emissions in this proposed action. The 2021 U.S. GHGI estimates over 166,700 metric tpy of methane emissions in 2019 from compressors from natural gas systems. For the natural gas processing and transmission segments, wet seal compressor methane emissions are estimated to be about 78,700 metric tons and dry seal compressor methane estimated emissions are estimated to be about 88,000 metric tons.287 The wet seal and dry seal compressor methane emission estimates reflect the increasing prevalence of the use of dry seals over wet seals and emissions control requirements that require the control of emissions from wet seal compressors. The methane emissions from centrifugal compressors represent 3 percent of the total methane emissions from natural gas systems in the Oil and Natural Gas Industry sector. c. Affected Facility For purposes of the NSPS, the centrifugal compressor affected facility is a single centrifugal compressor using wet seals. A centrifugal compressor located at a well site, or an adjacent well site and servicing more than one well site, is not an affected facility under the proposed rule for NSPS OOOOb. As discussed above, the EPA is proposing that the affected facility includes centrifugal compressors located at centralized production facilities and the affected facility exception for ‘‘a well site, or an adjacent well site servicing more than one well site’’ applies to standalone well sites and not centralized production facilities. d. 2021 BSER Analysis The methodology we used for estimating emissions from compressors is consistent with the methodology developed for the 2012 NSPS OOOO BSER analysis, which was also used to support the 2016 NSPS OOOOa BSER.288 The wet-seal centrifugal compressor methane uncontrolled emission factors are based on the volumetric emission factors used for the GHGI, which were converted to a mass emission rate using a density of 41.63 pounds of methane per thousand cubic feet. The VOC emissions were calculated using the ratio of 0.278 287 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks (1990–2019). Published in 2021. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990– 2019. 288 2011 NSPS OOOO TSD, section 6.2.2; 2016 NSPS OOOOa TSD, section 7.2.2. PO 00000 Frm 00113 Fmt 4701 Sfmt 4702 63221 pounds VOC per pound of methane for the production and processing segments, and 0.0277 pounds VOC per pound of methane for the transmission and storage segment. The resulting baseline uncontrolled emissions per centrifugal compressor are 157 tpy methane (43.5 tpy VOC) from wet-seal compressors at gathering and boosting sites, 211 tpy methane (58.7 tpy VOC) from wet-seal compressors at natural gas processing plants, 157 tpy methane (4.3 tpy VOC) from wet-seal compressors at transmission compressor stations, and 117 (3.24 tpy VOC) from wet-seal compressors at storage facilities. Since the emission factors for dry seal compressors are approximately lower than wet seal compressors,289 the EPA considered requiring dry seals as a replacement to wet seals as a control option in 2011. The EPA proposed dry seals as a replacement to wet seals to control VOC emissions at that time. Based on comments received on the proposal that dry seal compressors were not feasible in all instances based on costs and technical reasons, the EPA did not finalize the proposal that dry seal compressors represented BSER. Instead, the EPA separately evaluated the control options for wet seal compressors (77 FR 49499–49500, 49523, August 16, 2012). In the 2015 NSPS OOOOa proposed rule, the EPA maintained that available information since the 2012 NSPS OOOO rule continued to show that dry seal compressors cannot be use in all circumstances. The EPA has not identified any new information since that time that indicates that dry seal compressors as a replacement for wet seal compressors is technically feasible in all circumstances. Thus, we did not evaluate the replacement of a wet seal system with a dry seal system as BSER for controlling emissions from wet seal systems for the NSPS OOOOb proposal. In addition to soliciting comment and information on lower-emitting wet seal compressor designs (that emit less than dry seal compressors), the EPA is soliciting information on dry seal compressor emissions. Feedback received (noted above) on lower emitting wet seal compressor designs included concern that lower emitting wet seal systems were being replaced by higher emitting (but still low emitting) dry seal systems because they were not subject to the NSPS. Given that the trend has been that wet seal compressor systems are increasingly being replaced by dry seal compressor systems, the EPA solicits comments on dry seal compressor emissions and whether/and 289 2011 NSPS OOOO TSD, Table 6–2, pg. 6–4; 2016 NSPS OOOOa TSD, Table 7–2, pg. 104. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63222 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules to what degree operational or malfunctioning conditions (e.g., low seal gas pressure, contamination of the seal gas, lack of supply of separation gas, mechanical failure) have the potential to impact methane and VOC emissions. The EPA also solicits comment on whether owners and operators implement standard operating procedures to identify and correct operational or malfunction conditions that have the potential to increase emissions from dry seal systems. Finally, the EPA solicits comments on whether we should consider evaluating BSER and developing NSPS standards for dry seal compressors. The control options to reduce emissions from centrifugal compressors evaluated include control techniques that reduce emissions from leaking of natural gas from wet seal compressors by capturing leaking gas and route it either to (1) a control device (combustion device), or (2) to the process. We evaluated the costs and impacts of both of these options. Combustion devices are commonly used in the Crude Oil and Natural Gas Industry to combust methane and VOC emission streams. Combustors are used to control VOC and methane emissions in many industrial settings, since the combustor can normally handle fluctuations in concentration, flow rate, heating value and inert species content.290 A combustion device generally achieves 95 percent reduction of methane and VOC when operated according to the manufacturer instructions. For this analysis, we assumed that the entrained natural gas from the seal oil that is removed in the degassing process would be directed to a combustion device that achieves a 95 percent reduction of methane and VOC emissions. This option was determined to be BSER under the 2011 NSPS OOOO (77 FR 49490, August 16, 2012) and 2016 NSPS OOOOa rules. The combustion of the recovered gas creates secondary emissions of hydrocarbons (NOX, CO2, and CO emissions). Routing the captured gas from the centrifugal compressor wet seal degassing system to a combustion device has associated capital and operating costs. The capital and annual costs for the installation of a combustion device (an enclosed flare for the analysis) were calculated using the methodology in the EPA Control Cost Manual.291 The 290 U.S. Environmental Protection Agency. AP 42, Fifth Edition, Volume I, Chapter 13.5 Industrial Flares. Office of Air Quality Planning & Standards. 1991. 291 U.S. Environmental Protection Agency. OAQPS Control Cost Manual: Sixth Edition (EPA 452/B–02–001). Research Triangle Park, NC. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 capital costs of a flare and the equipment (closed vent system) necessary to route emissions to the flare are based on costs from the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD. These costs were updated to 2019 dollars. The updated capital costs of $80,930 were annualized at 7 percent based on an equipment life of 10 years. The total annualized capital costs were estimated to be $11,520. The annual operating costs are also based on the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD. These costs were updated to 2019 dollars. The 2019 annual operating costs were estimated to be $117,160. The combined annualized capital and operating costs per compressor per year is an estimated $128,680. There is no cost savings estimated for this option because the recovered natural gas is combusted. The costs presented for gathering and boosting segment centrifugal compressors represent the estimated costs assumed for centrifugal compressors located at centralized production facilities. Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness of routing emissions from a wet seal system to a new flare for methane emissions is $870 per ton of methane reduced for the transmission segment and gathering and boosting, $640 per ton of methane reduced for the processing segment, and $1,160 per ton of methane reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of routing emissions from a wet seal system to a new flare for methane emissions is $430 per ton of methane reduced for the transmission segment and gathering and boosting, $320 per ton of methane reduced for the processing segment, and $580 per ton of methane reduced for the storage segment. Using the single-pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness of routing emissions from a wet seal system to a new flare for VOC emissions is $3,100 per ton of VOC reduced for gathering and boosting, $2,300 per ton of VOC reduced for the processing segment, $31,200 per ton of VOC reduced for the transmission segment, and $41,800 per ton of VOC reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of routing emissions from a wet seal PO 00000 Frm 00114 Fmt 4701 Sfmt 4702 system to a new flare for VOC emissions is $1,600 per ton of VOC reduced for gathering and boosting, $1,200 per ton of VOC reduced for the processing segment, $15,600 per ton of VOC reduced for the transmission segment, and $20,900 per ton of VOC reduced for the storage segment. In addition to an owner or operator having the option to capture emissions and routing to a new combustion control device, a less costly option that may be available could be for owners and operators to capture and route emissions to a combustion control device installed for another source (e.g., a control device that is already on site to control emissions from another emissions source). The costs, which are provided in the NSPS OOOOb and EG TSD for this rulemaking, would be for the ductwork to capture the emissions and route them to the control device. The analysis assumes that the combustion control device on site achieves a 95 percent reduction in emissions of methane and VOC. Another option for reducing methane and VOC emissions from the compressor wet seal fluid degassing system is to route the captured emissions back to the compressor suction or fuel system, or other beneficial use (referred to collectively as routing to a process). Routing to a process would entail routing emissions via a closed vent system to any enclosed portion of a process unit (e.g., compressor or fuel gas system) where the emissions are predominantly recycled, consumed in the same manner as a material that fulfills the same function in the process, transformed by chemical reaction into materials that are not regulated materials, incorporated into a product, or recovered. Emissions that are routed to a process are assumed to result in the same or greater emission reductions as would have been achieved had the emissions been routed through a closed vent system to a combustion device.292 For purposes of this analysis, we assumed that routing methane and VOC emissions from a wet seal fluid degassing system to a process reduces VOC emissions greater than or equal to a combustion device (i.e., greater than or equal to 95 percent). There are no secondary impacts with the option to control emissions from centrifugal wet seals by capturing gas and routing to the process. 292 U.S. Environmental Protection Agency. Control Techniques Guidelines for the Oil and Natural Gas Industry. Office of Air Quality Planning and Standards, Sector Policies and Programs Division. October 2016. EPA–453/B–16–001. (2016 CTG). pgs. 5–19 to 5–20. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules The capital cost of a system to route the seal oil degassing system to a process is estimated to be $26,210 ($2,019),293 The estimated costs include an intermediate pressure degassing drum, new piping, gas demister/filter, and a pressure regulator for the fuel line. The annual costs were estimated to be $2,880 (without savings) assuming a 15-year equipment life at 7 percent interest. Because the natural gas is not lost or combusted, the value of the natural gas represents a savings to owners and operators in the production (gathering and boosting) and processing segments. Savings were estimated using a natural gas price of $3.13 per Mcf, which resulted in annual savings of $27,000 per year at gathering and boosting stations and $36,400 per year at processing plants. The annual cost savings are much greater than the annual costs, which results in an overall savings when they are considered. Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for methane emissions is approximately $19 per ton of methane reduced for the transmission segment and gathering and boosting, $14 per ton of methane reduced for the processing segment, and $26 per ton of methane reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for methane emissions is approximately $10 per ton of methane reduced for the transmission segment and gathering and boosting, $7 per ton of methane reduced for the processing segment, and $13 per ton of methane reduced for the storage segment. As noted above, there is an overall net savings if the value of the natural gas recovered is considered. Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for VOC emissions is approximately $70 per ton of VOC reduced for gathering and boosting, $50 per ton of VOC reduced for the processing segment, $700 per ton of VOC reduced for the transmission segment, and $940 per ton of VOC reduced for the storage segment. Using the multipollutant approach, where half 293 2011 NSPS OOOO TSD, pg. 114; 2016 CTG, pg. 5–20. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for VOC emissions is approximately $35 per ton of VOC reduced for gathering and boosting, $26 per ton of VOC reduced for the processing segment, $350 per ton of VOC reduced for the transmission segment, and $470 per ton of VOC reduced for the storage segment. As noted above, there is an overall net savings if the value of the natural gas recovered is considered. The cost effectiveness of both options (routing emissions to a combustion device or to a process) are reasonable for methane for all of the evaluated segments, using both the single pollutant and multipollutant approaches. The cost effectiveness of routing emissions to a process are also reasonable for VOC for all of the evaluated segments, using both the single pollutant and multipollutant approaches. For routing emissions to a combustion device, the cost effectiveness is reasonable for the gathering and boosting and processing segments using the single pollutant and multipollutant approaches. Based on the consideration of the costs in relation to the emission reductions of both methane and VOC, the EPA finds that requiring emissions to be reduced from each centrifugal compressor using a wet seal by at least 95 percent (which can be achieved by either option) continues to be reasonable in the gathering and boosting (considered to be representative of emissions/costs from centrifugal compressors at centralized production facilities). processing, transmission and storage segments. The 2012 NSPS OOOO and the 2016 NSPS OOOOa require emissions be reduced from each centrifugal compressor wet seal fluid degassing system by at least 95.0 percent by routing emissions to a control device or to a process. States have generally adopted/incorporated this NSPS level of control (or a level of control that is substantially similar) in their State regulations for the control of emissions from centrifugal compressor sources using wet seals. Owners and operators have successfully met this standard for almost a decade. These facts further demonstrate the reasonableness of this level of control. In the discussion above, we reviewed two options to reduce emissions from wet seal compressors that are both current regulatory options under the 2016 NSPS OOOOa: (1) Capturing leaking gas and route to a combustion device (flare), or (2) PO 00000 Frm 00115 Fmt 4701 Sfmt 4702 63223 capturing leaking gas and route to the process. Under the 2016 NSPS OOOOa, the level of control determined based on BSER was that methane and VOC emissions be reduced from each centrifugal compressor wet seal fluid degassing system by 95 percent or greater. The EPA has not identified any other control options or any other Federal, State, or local requirements that would achieve a greater reduction in methane and VOC emissions from centrifugal compressor wet seal systems. Although capturing leaking gas and routing to the process has the advantage of both reducing emissions by at least 95 percent or greater and capturing the natural gas (resulting in a natural gas savings), the EPA has received feedback in the development of the 2012 NSPS OOOO rule that this option may not be a viable option in situations where there may not be down-stream equipment capable of handling a low-pressure fuel source. During the development of the 2016 NSPS OOOOa rule, the EPA reaffirmed that information since the development of the 2012 NSPS OOOO rule continues to show that capturing leaking gas and routing to the process cannot be used in all circumstances. No new information has been identified since the development of the 2016 NSPS OOOOa rule to indicate that capturing leaking gas and routing to the process can be achieved in all circumstances (80 FR 56619, September 18, 2015). Thus, by establishing a 95 percent methane and VOC emissions control level as BSER, an owner or operator has the option of routing emissions to a process where it is a viable option, or to a combustion device where routing to a process is not a viable option. If an owner or operator chooses to route to a process to meet the 95 percent level of control, there are no secondary impacts. If an owner or operator chooses to route to a combustion device to meet the 95 percent level of control, the combustion of the recovered gas creates secondary emissions of hydrocarbons (NOX, CO2, and CO emissions). The costs, emission reductions, and cost effectiveness values were presented above for collecting the wet seal compressor emissions and routing them to both a combustion device and to a process to achieve at least a 95 percent control. The EPA considers the cost effectiveness of both of these control options reasonable across all segments evaluated (i.e., the gathering and boosting portion of production, processing, transmission, storage) for the reduction of methane emissions under the single pollutant approach and multipollutant approach. As discussed E:\FR\FM\15NOP2.SGM 15NOP2 63224 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 above, in our current analysis, we consider the centrifugal compressor gathering and boosting segment emission factor as being representative of centrifugal compressor emissions located at centralized production facilities. Thus, the cost analysis performed for the gathering and boosting segment represents the estimated costs of evaluated options for centrifugal compressors with wet seals located at centralized storage facilities. In light of the above, we determined that reducing methane and VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95 percent or greater continues to represent BSER for NSPS OOOOb for this proposal. The affected facility based on EPA’s review would continue be each wet seal compressor not located at a well site, or an adjacent well site and servicing more than one well site. As discussed above, the EPA is proposing a new definition for a ‘‘centralized production facility’’. The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of ‘‘centralized production facilities’’. Thus, the EPA is proposing that centrifugal compressors located at centralized production facilities would be subject to the standards in the NSPS in OOOOb, but centrifugal compressors at well sites (standalone well sites) would not. 2. EG OOOOc The EPA evaluated BSER for the control of methane from existing centrifugal compressors using wet seals (not located at a well site, or an adjacent well site and servicing more than one well site) (designated facilities) in all segments in the Crude Oil and Natural Gas source category covered by the proposed NSPS OOOOb and translated the degree of emission limitation achievable through application of the BSER into a proposed presumptive standard for these facilities that essentially mirrors the proposed NSPS OOOOb. First, based on the same criteria and reasoning as explained above, the EPA is proposing to define the designated facility in the context of existing centrifugal compressors using wet seals (not located at a well site, or an adjacent well site and servicing more than one well site) as those that commenced construction on or before November 15, 2021. Based on information available to the EPA, we did not identify any factors VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 specific to existing sources that would indicate that the EPA should alter this definition as applied to existing sources. Next, the EPA finds that the control measures evaluated for new sources for NSPS OOOOb are appropriate for consideration for existing sources under the EG OOOOc. The EPA finds no reason to evaluate different, or additional, control measures in the context of existing sources because the EPA is unaware of any control measures, or systems of emission reduction, for centrifugal compressors that could be used for existing sources but not for new sources. Next, the methane emission reductions expected to be achieved via application of the control measures identified above to new sources are also expected to be achieved by application of the same control measures to existing sources. The EPA finds no reason to believe that these calculations would differ for existing sources as compared to new sources because the EPA believes that the baseline emissions of an uncontrolled source are the same, or very similar, and the efficiency of the control measures are the same, or very similar, compared to the analysis above. This is also true with respect to the costs, non-air environmental impacts, energy impacts, and technical limitations discussed above for the control options identified. The EPA has not identified any costs associated with applying these controls at existing sources, such as retrofit costs, that would apply any differently than, or in addition to, those costs assessed above regarding application of the identified controls to new sources. The cost effectiveness values for the proposed presumptive standard of reducing methane emissions from each centrifugal compressor wet seal fluid degassing system by 95 percent or greater are based on the cost effectiveness of routing emissions from a wet seal system to a flare or to a process. The cost effectiveness of routing emissions from a wet seal system to a new flare for methane emissions is $870 per ton of methane reduced for the transmission segment and gathering and boosting, $640 per ton of methane reduced for the processing segment, and $1,160 per ton of methane reduced for the storage segment. The cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for methane emissions is approximately $19 per ton of methane reduced for the transmission segment and gathering and boosting, $14 per ton of methane reduced for the processing segment, and PO 00000 Frm 00116 Fmt 4701 Sfmt 4702 $26 per ton of methane reduced for the storage segment. In summary, the EPA did not identify any factors specific to existing sources, as opposed to new sources, that would alter the analysis above for the proposed NSPS OOOOb as applied to the designated pollutant (methane) and the designated facilities (centrifugal compressors using wet seals). As a result, the proposed presumptive standard for existing centrifugal compressors using wet seals is as follows. For centrifugal compressors using wet seals in the gathering and boosting segment (including centrifugal compressors using wet seals located at centralized tank facilities), processing, and transmission and storage segments, the presumptive standard is to reduce methane emissions by at least 95 percent. An owner or operator can meet this presumptive standard by routing methane emissions to a control device or process that reduces emissions by at least 95 percent. As discussed previously, the EPA is proposing a new definition for a ‘‘centralized production facility’’. The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of ‘‘centralized production facilities’’. Thus, the EPA is proposing that centrifugal compressors located at centralized production facilities would be subject to the standards in the EG in OOOOc, but centrifugal compressors at well sites (standalone well sites) would not. G. Proposed Standards for Pneumatic Pumps 1. NSPS OOOOb a. Background In the 2016 NSPS OOOOa, the EPA established GHG (in the form of limitations on methane emissions) and VOC standards for natural gas-driven diaphragm pneumatic pumps located at well sites. This standard required that natural gas emissions be reduced by 95.0 percent by routing to an existing control device if: (1) A control device was onsite, (2) the control device could achieve a 95.0 percent reduction, and (3) it was technically feasible to route the emissions to the control device. The standard did not require the installation of a control device solely for the purpose of complying with the 95.0 percent reduction for the emissions from pneumatic pumps. It also allowed E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules the option of routing emissions to a process. At natural gas processing plants, the EPA established a standard that required a natural gas emission rate of zero (i.e., that prohibited methane and VOC emissions from pneumatic pumps). As a result of the review of these requirements and the previous BSER determination, the EPA is proposing methane and VOC standards in NSPS OOOOb for natural gas-driven pneumatic pumps located in all segments of the source category. Specifically, the EPA is proposing that each natural gas driven pneumatic pump is an affected facility. The EPA is proposing that methane and VOC emissions from natural gas-driven diaphragm and piston pumps at well sites and all other sites in the production segment be reduced by 95.0 percent or routed to a process, provided that there is an existing control device onsite or it is technically feasible to route the emissions to a process. For natural gas driven pneumatic pumps at natural gas transmission stations and natural gas storage facilities, the same requirement applies, but only to diaphragm pumps. The EPA is proposing to retain the technical infeasibility provisions of NSPS OOOOa for purposes of NSPS OOOOb. If there is a control device onsite,294 the owner or operator is not required to route emissions to that control device if it is not technically feasible to do so, even for new construction sites which the EPA had previously referred to as ‘‘greenfield’’ sites. The EPA is also proposing to retain in NSPS OOOOb the exception to the 95.0 percent reduction requirement if there is a control device onsite that it is technically feasible to route to that cannot achieve that level of reduction but can achieve a lower level of reductions. In those situations, the emissions from the pump are still to be routed to the control device and controlled at the level that the device can achieve. The EPA is also proposing a prohibition on methane and VOC emissions from pneumatic pumps (diaphragm and piston pumps) at natural gas processing plants. While zero emissions pneumatic pumps would not technically be affected facilities because they are not driven by natural gas, owners and operators should maintain documentation if they would like to be able to demonstrate to permit writers or enforcement officials that there are no methane or VOC emissions 294 For the same reasons discussed in section X.B.2, the EPA is proposing that boilers and process heaters are not control devises for purposes of controlling emissions from pneumatic pumps. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 from the pumps and that these pumps are not affected facilities subject to the rule. This BSER for reducing methane and VOC from pneumatic pumps are the same as those for the 2016 NSPS OOOOa, except that (1) the EPA determined that the NSPS OOOOa levels of control also represent BSER for diaphragm pumps at all sites in the production segment (including gathering and boosting stations), and for all transmission and storage sites, and (2) the EPA determined that the NSPS OOOOa levels of control also represent BSER for piston pumps (in addition to diaphragm pumps) in the production segment and at natural gas processing plants. As discussed below, a primary reason that the EPA is unable to conclude that requiring a natural gas emission rate of zero for production and transmission and storage facilities is BSER at this time is because proven technologies that eliminate natural gas emissions rely on electricity to function. In contrast to pneumatic controllers, our review of information that has become available since the promulgation of the 2016 NSPS OOOOa standards, including State-level regulations for pneumatic pumps, does not demonstrate that zero emission technology for pneumatic pumps would be feasible at sites that lack access to onsite power. The EPA is specifically soliciting comments on the possibility of subcategorizing production and natural gas transmission and storage sites into those sites that have access to onsite power and those that do not, and then determining BSER separately for each subcategory. Further, the EPA is soliciting comment on how, if at all, the proposed NSPS OOOOb standards for pneumatic controllers might factor into how the EPA ought to evaluate the possibility of requiring a natural gas emission rate of zero for pneumatic pumps in the production and transmission and storage segments. For example, if a site installs a solarpowered system to operate their controllers, then could that same system provide power to the pumps such that all pumps at the site could have zero emissions of natural gas? b. Description A pneumatic pump is a positive displacement reciprocating unit generally used by the Oil and Natural Gas Industry for one of four purposes: (1) Hot oil circulation for heat tracing/ freeze protection, (2) chemical injection, (3) moving bulk liquids, and (4) glycol circulation in dehydrators. There are two basic types of pneumatic pumps used in the Oil and Natural Gas PO 00000 Frm 00117 Fmt 4701 Sfmt 4702 63225 Industry, diaphragm pumps and piston pumps. Pumps used for heat tracing/ freeze protection circulate hot glycol or other heat-transfer fluids in tubing covered with insulation to prevent freezing in pipelines, vessels and tanks. These heat tracing/freeze protection pumps are usually diaphragm pumps. Chemical injection pumps are designed to inject precise amounts of chemical into a process stream to regulate operations of a plant and protect the equipment. Typical chemicals injected in an oil or gas field are biocides, demulsifiers, clarifiers, corrosion inhibitors, scale inhibitors, hydrate inhibitors, paraffin dewaxers, surfactants, oxygen scavengers, and H2S scavengers. These chemicals are normally injected at the wellhead and into gathering lines or at production separation facilities. Since the injection rates are typically small, the pumps are also small. They are often attached to barrels containing the chemical being injected. These chemical injection pumps are primarily piston pumps, although they can be small diaphragm pumps. Examples of the use of pneumatic pumps to transfer bulk liquids at oil and natural gas production sites include pumping motor oil or pumping out sumps. Pumps used for these purposes ae typically diaphragm pumps. Glycol dehydrator pumps recover energy from the high-pressure rich glycol/gas mixture leaving the absorber and use that energy to pump the lowpressure lean glycol back into the absorber. Glycol dehydrator pumps are controlled under the oil and gas NESHAPs (40 CFR part 63, subparts HH and HHH), are not included as affected facilities for the 2016 NSPS OOOOa and were not included in the review for proposed NSPS OOOOb. Both diaphragm and piston pumps are positive displacement reciprocating pumps, meaning they use contracting and expanding cavities to move fluids. These pumps work by allowing a fluid (e.g., the heat transfer fluid, demulsifier, corrosion inhibitor, etc) to flow into an enclosed cavity from a low-pressure source, trapping the fluid, and then forcing it out into a high-pressure receiver by decreasing the volume of the cavity. The piston and diaphragm pumps have two major components, a driver side and a motive side, which operate in the same manner but with different reciprocating mechanisms. Pressurized gas provides energy to the driver side of the pump, which operates a piston or flexible diaphragm to draw fluid into the pump. The motive side of the pump delivers the energy to the fluid being moved in order to discharge E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63226 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules the fluid from the pump. The natural gas leaving the exhaust port of the pump is either directly discharged into the atmosphere or is recovered and used as a fuel gas or stripping gas. Diaphragm pumps work by flexing the diaphragm out of the displacement chamber, and piston pumps typically include plunger pumps with a large piston on the gas end and a smaller piston on the liquid end to enable a high discharge pressure with a varied but much lower pneumatic supply gas pressure. As noted above, energy is supplied to the driver side of the pump to operate the piston or diaphragm. Commonly, this energy is provided by pressurized gas. This gas can be compressed air, or ‘‘instrument air,’’ provided by an electrically powered air compressor. In many situations across all segments of this industry, electricity is not available, and this energy is provided by pressurized natural gas (i.e., ‘‘natural gas-driven pneumatic pumps’’). This energy can also be directly provided by electricity. Natural gas-driven pneumatic pumps emit methane and VOC as part of their normal operation. These emissions occur when the gas used in the pump stroke is exhausted to enable liquid filling of the liquid cavity of the pump. Emissions are a function of the amount of fluid pumped, the pressure of the pneumatic supply gas, the number of pressure ratios between the pneumatic supply gas pressure and the fluid discharge pressure, and the mechanical inefficiency of the pump. The 2021 U.S. GHGI estimates almost 215,000 metric tpy of methane emissions from pneumatic pumps in the oil and natural gas production segment in 2019. Specifically, this includes almost 113,000 metric tpy from natural gas production, 75,000 from petroleum production, and 26,000 from gathering and boosting compressor stations. These emissions make up 5 percent of all methane emissions in the GHGI for the combined gas and oil production segment, and 2 percent of all methane emissions for gathering and boosting. The overall total, which represents 3 percent of the total methane emissions from this industry, does not include emissions from the processing, transmission, and storage segments which the EPA is now proposing to regulate under NSPS OOOOb. c. 2021 BSER Analysis BSER was evaluated for all segments of the industry. The 2015 NSPS OOOOa proposal included methane and VOC standards for pneumatic pumps in the production and transmission and VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 storage segments. However, the EPA did not finalize regulations for pneumatic pumps at gathering and boosting stations in the final 2016 NSPS OOOOa due to lack of data on the prevalence of the use of pneumatic pumps at gathering and boosting stations. Since that time, GHGRP subpart W has required that emissions from natural gas-driven pneumatic pumps be reported from gathering and boosting stations. As reported above, the 2021 GHGI estimates over 26,000 metric tpy of methane emissions from these pumps in the gathering and boosting segment in 2019. Similarly, the EPA did not include pneumatic pumps in the transmission and storage segment in the final 2016 NSPS OOOOa because we did not have a reliable source of information indicating the prevalence of pneumatic pumps or their emission rates in the transmission and storage segment. While the GHGI does not include emissions from pneumatic pumps in the transmission and storage segment, and the GHGRP does not require the reporting of emissions from these pumps in this segment, State rules (notably the California rule and the proposed New Mexico rule) do include requirements for natural gas driven pneumatic pumps at transmission and storage facilities. The EPA is soliciting comment on whether natural gas driven pneumatic pumps are used in the natural gas transmission and storage segment and to what extent. In 2015, the EPA identified several options for reducing methane and VOC emissions from natural gas-driven pumps in the production and natural gas transmission and storage segments: Replace natural gas-driven pumps with instrument air pumps, replace natural gas-driven pumps with solar-powered direct current pumps (solar pumps), replace natural gas-driven pumps with electric pumps, route natural gas-driven pump emissions to a control device, and route natural gas-driven pump emissions to a process. The only option identified in 2015 and analyzed at natural gas processing plants was the use of instrument air. The EPA reevaluated that information as well as new information including updated GHGI and GHGRP information, as well as information from more recent State regulations. No additional options were identified at this time. Therefore, for this analysis for the NSPS, the EPA reevaluated these options as BSER. In the discussion below, the options to require technology that would eliminate methane and VOC emissions by requiring the use of a non-natural gas driven pumps are discussed, followed PO 00000 Frm 00118 Fmt 4701 Sfmt 4702 by a discussion of routing natural gas driven pumps to a control device. With the exception of the evaluation of instrument air systems, the BSER analysis for pneumatic pumps was conducted on an individual pump basis. Due to the differences in the level of emissions, we conducted the BSER analysis separately for natural gasdriven diaphragm pneumatic pumps and natural gas-driven piston pneumatic pumps for the production and transmission and storage segments. The emission factor for diaphragm pneumatic pumps is 3.46 tpy of methane, while it is only 0.38 tpy of methane for piston pumps. The corresponding VOC emission factors are 0.96 tpy for the production segment and 0.096 tpy for the transmission and storage segment for diaphragm pumps, and 0.11 and 0.01 tpy for piston pumps, for production and transmission and storage segment, respectively. For instrument air systems, the BSER analysis was conducted using model plants that included combinations of diaphragm and piston pumps. For example, the smallest model plant included two diaphragm pumps and two piston pumps. Therefore, the cost effectiveness calculated for these instrument air systems represents the cost to eliminate emissions from both types of pumps. Since instrument air was the only option evaluated for natural gas processing plants, the BSER determination was made for all pumps at the plants (as opposed to separate determinations for diaphragm and piston pumps). Zero Emissions Options For this analysis, we first evaluated the options that would eliminate methane and VOC emissions from pneumatic pumps, specifically instrument/compressed air systems, electric pumps, and solar-powered pumps. Instrument air systems require a compressor, power source, dehydrator, and volume tank. No alterations are needed to the pump itself to convert from using natural gas to instrument air. However, they can only be utilized in locations with sufficient electrical power. Instrument air systems are more economical and, therefore, more common at facilities with a high concentration of pneumatic devices and where an operator can ensure the system is properly functioning. Electric pumps provide the same functionality as gas-driven pumps and are only restricted by the availability of a source of electricity. Solar-powered pumps are a type of electric pump, except that the power is E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules provided by solar-charged direct current (DC). Solar-powered pumps can be used at remote sites where a source of electricity is not available, and they have been shown to be able to handle a range of throughputs up to 100 gallons per day with maximum injection pressure around 3,000 pounds per square inch gauge (psig). Production and Transmission and Storage Segments. For the production and transmission and storage segments, we evaluated the costs and impacts of these ‘‘zero-emissions’’ options (See Chapter 9 of the NSPS OOOOb and EG TSD for this rulemaking). We found that the cost-effectiveness of these options, for both diaphragm and piston pumps, were generally within the ranges that the EPA considers reasonable. However, for instrument air systems and electric pumps, our analysis assumes that electricity is available onsite. As noted above, in 2015, the EPA determined that a zero-emission standard for pumps in the production and transmission and storage segments was infeasible because (1) electricity is not available at all sites and (2) solar pumps are not technically feasible in all situations for which piston pumps and diaphragm pumps are needed. 80 FR 56625–56626. While we specifically requested comment on this determination in 2015, nothing was submitted at that time that caused a reversal in this decision. At this time, we are unclear as to whether these limitations have been overcome and whether zero-emission pneumatic pumps are technically feasible for all pneumatic pumps throughout the production and transmission and storage segments. Therefore, at this time, we are unable to conclude that this zero-emission option represents BSER in this proposal, but we are soliciting comment on this issue to better understand whether a zeroemission option is now technically feasible. As explained in Section XII.C.1.e, the EPA believes that similar previously identified technical limitations have been overcome in the context of pneumatic controllers. Further, a few States do prohibit emissions from pneumatic pumps throughout the Crude Oil and Natural Gas Industry. California prohibits the venting of natural gas to the atmosphere from pneumatic pumps through the use of compressed air or electricity, or by collecting all potentially vented natural gas with the use of a vapor collection system that undergoes periodic leak detection and repair. While California requires this, the fact that other States (e.g., Colorado, Wyoming) do not require zero emissions from pneumatic pumps at all locations VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 leads us to be uncertain as to whether it is technically feasible at this time. Canadian Provinces also regulate emissions from natural gas-driven pneumatic pumps. In British Columbia, pneumatic pumps installed after January 1, 2021, must not emit natural gas, and in Alberta, vent gas from pneumatic pumps installed after January 2, 2022, must be prevented. In addition, New Mexico has proposed a regulation that requires zero-emitting pumps, but only at production and transmission and storage sites that have access to electricity. The EPA is soliciting comment on the basis for our proposed determination: That because electricity is not available at all sites and that there are applications at these sites where solarpowered pumps may not be feasible the Agency is uncertain as to whether the zero-emission options represent BSER. Also, as noted above, we are soliciting comment on an approach where the EPA would propose to subcategorize pneumatic pumps located in the production and transmission and storage sites based on availability of electricity and develop separate standards for each subcategory. Natural gas processing plants. Natural gas processing plants are known to have a source of electrical power. Therefore, instrument air and electric pumps are technically feasible options at these facilities. As the next step in the BSER determination, we evaluated capital and annual costs of compressed air systems for the natural gas processing plants. While electric pumps are an option at natural gas processing plants, we assumed that natural gas processing plants will elect to always use instrument air and an impacts analysis for electric pumps was not conducted. The capital costs for an instrument air system were estimated to range from $4,500 to $39,500. The annual costs include the capital recovery cost (calculated at a 7 percent interest rate for 10 years), labor costs for operations and maintenance, and electricity costs. These are estimated to range from $11,300 to $81,350. Because gas emissions are avoided as compared to the use of natural gas-driven pumps, the use of an instrument air system will have natural gas savings realized from the gas not released. The EPA estimates that each diaphragm pump replaced will save 201 Mcf per year of natural gas from being emitted and each piston pump will save of 22 Mcf per year in the processing segment. The estimated value of the natural gas saved, based on $3.13 per Mcf, would range from $1,400 to $35,000 per year per plant. The PO 00000 Frm 00119 Fmt 4701 Sfmt 4702 63227 annual costs, including these savings, ranges from $9,900 to $46,500. More information on this cost analysis is available in the NSPS OOOOb and EG TSD for this proposal. The resulting cost effectiveness, under the single pollutant approach where all the costs are assigned to the reduction of one pollutant, for the application of instrument air to achieve a 100 percent emission reduction at natural gas processing plants ranges from $420 to $1,470 per ton of methane eliminated. For VOC, these cost effectiveness values ranged from $1,520 to $5,290 per ton of VOC eliminated. Considering savings, these cost effectiveness values range from $240 to $1,300 per ton of methane eliminated and $870 to $4,600 per ton of VOC eliminated. Under the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness ranges from $210 to $730 per ton of methane eliminated and $760 to $2,640 per ton of VOC eliminated. Considering savings, the cost effectiveness values range from $120 to $650 per ton of methane eliminated and from $440 to $2,320 per ton of VOC eliminated. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches. As discussed above, the evaluation for instrument air systems is based on a combination of diaphragm and piston pumps. Therefore, this determination of reasonableness applies to both types of pumps at natural gas processing plants. The 2016 NSPS OOOOa requires a natural gas emission rate of zero for pneumatic pumps at natural gas processing plants. Natural gas processing plants have successfully met this standard. Further, as discussed above several State agencies have rules that include this zero-emission requirement. This is a demonstration of the reasonableness of a natural gas emission rate of zero for pneumatic pumps at natural gas processing plants. Secondary impacts from the use of instrument air systems are indirect, variable, and dependent on the electrical supply used to power the compressor. These impacts are expected to be minimal, and no other secondary impacts are expected. In light of the above, we find that the BSER for reducing methane and VOC emissions from natural gas-driven piston and diaphragm pumps at gas processing plants is a natural gas emission rate of zero. This option results in a 100 percent reduction of emissions for both methane and VOC. Therefore, for NSPS OOOOb, we are E:\FR\FM\15NOP2.SGM 15NOP2 63228 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 proposing to require a natural gas emission rate of zero for all pneumatic pumps at natural gas processing plants. Routing to a Control Device or VRU Options Above we stated our determination that the EPA is unable to conclude that this zero-emission option represents BSER in this proposal for pumps in the production and transmission and storage segments. Therefore, we evaluated the use of control devices to reduce methane and VOC emissions. This BSER analysis was conducted on an individual pump basis and diaphragm and piston pumps were evaluated separately. Combustors (e.g., enclosed combustion devices, thermal oxidizers and flares that use a high-temperature oxidation process) can be used to control emissions from natural gasdriven pumps. Combustors are used to control VOCs in many industrial settings, since the combustor can normally handle fluctuations in concentration, flow rate, heating value, and inert species content. The types of combustors installed in the Crude Oil and Natural Gas Industry can achieve at least a 95 percent control efficiency on a continuous basis. It is noted that combustion devices can be designed to meet 98 percent control efficiencies, and can control, on average, emissions by 98 percent or more in practice when properly operated. However, combustion devices that are designed to meet a 98 percent control efficiency may not continuously meet this efficiency in practice in the oil and gas industry due to factors such as variability of field conditions. A related option for controlling emissions from pneumatic pumps is to route vapors from the pump to a process, such as back to the inlet line of a separator, to a sales gas line, or to some other line carrying hydrocarbon fluids for beneficial use, such as use as a fuel. Use of a VRU has the potential to reduce the VOC and methane emissions from natural gas-driven pneumatic pumps by 100 percent if all vapor is recovered. However, the effectiveness of the gas capture system and downtime for maintenance would reduce capture efficiency and therefore, we estimate that routing emissions from a natural gas-driven pump to a VRU and to a process can reduce the gas emitted by approximately 95 percent, while at the same time, capturing the gas for beneficial use. Based on a 95 percent reduction, the reduction in emissions in the production segment would be 3.29 tpy of methane and 0.91 tpy of VOC per VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 diaphragm pump, and 0.36 tpy methane and 0.10 tpy VOC per piston pump. In the transmission and storage segment, the reduction in emissions would be 3.29 tpy of methane and 0.09 tpy of VOC per diaphragm pump, and 0.36 tpy of methane and 0.01 ton per year of VOC per piston pump. Installation of a new combustion device or VRU. Costs for the installation of a new combustion device and a new VRU were evaluated. Installing a new combustion device has associated capital costs and operating costs. Based on the analysis conducted for the 2012 NSPS for a combustion device to control emissions from storage vessels, the capital cost for installing a new combustion device was $32,300 in 2008 dollars. We updated this to $38,500 to reflect 2019 dollars. Based on the life expectancy for a combustion device at 10 years, we estimate the annualized capital cost of installing a new combustion device to be $5,500 in 2019 dollars, using a 7 percent discount rate. The 2016 NSPS OOOOa TSD indicates the annual operating costs associated with a new combustion device were $17,000 in 2012 dollars, which we updated to $19,100 in 2019 dollars. Therefore, the total annual costs for a new combustion device are $24,600. Because the gas captured is combusted there are no gas savings associated with the use of a combustion device. Installing a new VRU would also have both capital costs and maintenance costs. We based the costs of a VRU on the analysis conducted for the 2012 NSPS for control of emissions from storage vessels, which is representative of the costs that would be incurred for a VRU used to reduce emissions from natural gas-driven pneumatic pumps. The capital cost and installation costs for a new VRU are estimated to be $116,900 (in 2019 dollars) and the annual operation and maintenance costs estimated to be $11,200 (in 2019 dollars). The total annualized cost of a new VRU is estimated to be $27,800, including the operation and maintenance cost and the annualized capital costs based on a 7 percent discount rate and 10-year equipment life. Because there is potential for beneficial use of gas recovered through the VRU, the savings that would be realized for 95 percent of the gas that would have emitted and lost were estimated. The gas saved would equate to 191 Mcf per year from a diaphragm pump and 21 Mcf per year from a piston pump. This results in estimated annual savings of $600 per diaphragm pump and $65 per piston pump in the production segment. The resulting PO 00000 Frm 00120 Fmt 4701 Sfmt 4702 annual costs, considering these savings, are $27,200 per diaphragm pump and $27,700 per piston pump in the production segment. Transmission and storage facilities do not own the natural gas; therefore, savings from reducing the amount of natural gas emitted/lost was not applied for this segment. More information on these cost analyses is available in the NSPS OOOOb and EG TSD for this proposal. The resulting cost effectiveness estimates for application of a new control device to reduce emissions from natural gas-driven pumps in the production segment by 95 percent, or the use of a VRU to route emissions back to a process, are discussed below under both the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, and the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction. The results are presented separately for diaphragm and piston pumps. These values assume that the control device or VRU is installed solely for the purpose of controlling the emissions from a single natural gas-driven pneumatic pump, and only the emission reductions from a single pump are considered. For diaphragm pumps in the production segment using the single pollutant approach, the cost effectiveness is estimated to be $7,500 per ton of methane reduced using a new combustion device, and $8,500 using a new VRU ($8,300 with savings). For VOC, these cost effectiveness values are $26,900 per ton of VOC reduced using a new combustion device, and $30,400 using a new VRU ($29,800 with savings). These values are outside of the range considered reasonable by the EPA for both methane and VOC. For diaphragm pumps in the production segment using the multipollutant approach, the cost effectiveness is estimated to be $3,750 per ton of methane reduced using a new combustion device, and $4,250 using a new VRU ($4,150 with savings). For VOC, these cost effectiveness values are $13,450 per ton of VOC reduced using a new combustion device, and $15,200 using a new VRU ($14,900 with savings). These values are outside of the range considered reasonable by the EPA for both methane and VOC. For piston pumps in the production segment using the single pollutant approach, the cost effectiveness is estimated to be $68,100 per ton of methane reduced using a combustion device, and $77,000 using a VRU ($76,800 with savings). For VOC, these cost effectiveness values are $244,800 E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules per ton of VOC reduced using a combustion device, and $277,000 using a VRU ($276,400 with savings). These values are outside of the range considered reasonable by the EPA for both methane and VOC. For piston pumps in the production segment using the multipollutant approach, the cost effectiveness is estimated to be $34,000 per ton of methane reduced using a combustion device, and $38,500 using a VRU ($38,400 with savings). For VOC, these cost effectiveness values are $122,400 per ton of VOC reduced using a combustion device, and $138,500 using a VRU ($138,200 with savings). These values are outside of the range considered reasonable by the EPA for both methane and VOC. For diaphragm pumps in the transmission and storage segment using the single pollutant approach, the cost effectiveness is estimated to be $7,400 per ton of methane reduced using a new combustion device, and $8,500 using a new VRU. For VOC, these cost effectiveness values are $270,000 per ton of VOC reduced using a new combustion device, and $305,000 using a new VRU. These values are outside of the range considered reasonable by the EPA for both methane and VOC. For diaphragm pumps in the transmission and storage segment using the multipollutant approach, the cost effectiveness is estimated to be $3,700 per ton of methane reduced using a new combustion device, and $4,200 using a new VRU. For VOC, these cost effectiveness values are $135,000 per ton of VOC reduced using a new combustion device, and $152,600 using a new VRU. These values are outside of the range considered reasonable by the EPA for both methane and VOC. For piston pumps in the transmission and storage segment using the single pollutant approach, the cost effectiveness is estimated to be $68,000 per ton of methane reduced using a combustion device, and $77,000 using a VRU. For VOC, these cost effectiveness values are $2.5 million per ton of VOC reduced using a combustion device, and $2.8 million using a VRU. These values are outside of the range considered reasonable by the EPA for both methane and VOC. For piston pumps in the transmission and storage segment using the multipollutant approach, the cost effectiveness is estimated to be $34,000 per ton of methane reduced using a combustion device, and $38,500 using a VRU. For VOC, these cost effectiveness values are $1.2 million per ton of VOC reduced using a combustion device, and $1.4 million using a VRU. These values VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 are outside of the range considered reasonable by the EPA for both methane and VOC. For diaphragm pumps, we do not consider the costs to be reasonable to install a new control device, or a new VRU to route the emissions to a process, for the production and transmission and storage segments for methane or VOC emission reduction using either the single pollutant or multipollutant approach. Similarly, for piston pumps, we do not consider the costs to be reasonable under any scenario. Therefore, we are unable to conclude that requiring the installation of a new control device, or the installation of a new VRU to route emissions to a process, to achieve 95 percent reduction of methane and VOC emissions from natural gas-driven pumps for the production or transmission segments represents BSER in this proposal. Routing to an existing combustion device or VRU. In addition to evaluating the installation of a new control device or new VRU installed solely for the purpose of reducing the emissions from a single natural gas-driven pneumatic pump, we evaluated the option of routing the emissions from natural gasdriven pneumatic pumps to an existing control device to achieve a 95 percent reduction in methane and VOC emissions or routing the emissions to an existing VRU and to a process. The emission reduction for this option would be the same as discussed above for a new control device achieving 95 percent control, that is 3.29 tpy of methane and 0.91 tpy of VOC per diaphragm pump, and 0.36 tpy methane and 0.10 tpy VOC per piston pump in the production segment and 3.29 tpy of methane and 0.09 tpy of VOC per diaphragm pump, and 0.36 tpy of methane and 0.01 ton per year of VOC per piston pump in the transmission and storage segment. The resulting cost effectiveness estimates for use of an existing control device to reduce emissions from natural gas-driven pumps in the production segment by 95 percent, or the use of an existing VRU to route emissions to a process, are discussed below under both the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, and the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction. The results are presented separately for diaphragm and piston pumps. We estimated the costs for routing emissions to an existing control device or VRU based on the average of the cost presented in the 2015 proposed NSPS OOOOa and the costs presented by two PO 00000 Frm 00121 Fmt 4701 Sfmt 4702 63229 commenters to the proposal,295 as documented in the 2016 NSPS OOOOa TSD. This yielded a capital cost estimate of $6,100 in 2019 dollars, for an annualized cost of $900 in 2019 dollars, using the 7 percent discount rate and 10-year equipment life. In the 2016 NSPS OOOOa TSD the EPA assumed there were no incremental operating costs for routing to an existing control device or VRU, so the total annual costs consist only of the $900 capital recovery cost. This assumption is maintained for this analysis. The same savings discussed above for the gas that is recovered by a VRU would be realized when routing to an existing VRU and to a process. These savings are $600 per year per diaphragm pump and $65 per year per piston pump in the production segment. The resulting annual costs for routing to an existing VRU and to process, considering these savings, are $270 per diaphragm pump and $800 per piston pump in the production segment. As noted above, transmission and storage facilities do not own the natural gas; therefore, savings from reducing the amount of natural gas emitted/lost was not applied for this segment. For diaphragm pumps in the production segment using the single pollutant approach, the cost effectiveness is estimated to be $260 per ton of methane reduced using an existing combustion device, and $260 per ton of methane using an existing VRU ($80 with savings). For VOC, these cost effectiveness values are $950 per ton of VOC reduced using an existing combustion device, and $950 using an existing VRU ($300 with savings). For diaphragm pumps in the production segment using the multipollutant approach, the cost effectiveness is estimated to be $130 per ton of methane reduced using an existing combustion device, and $130 using an existing VRU ($40 with savings). For VOC, these cost effectiveness values are $475 per ton of VOC reduced using an existing combustion device, and $475 using an existing VRU ($150 with savings). These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches. For diaphragm pumps in the transmission and storage segment using the single pollutant approach, the cost effectiveness is estimated to be $260 per ton of methane reduced using an existing combustion device, and $260 using an existing VRU. For VOC, these 295 EPA–HQ–OAR–2010–0505–6884–A1 and EPA–HQ–OAR–2010–0505–6881. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63230 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules cost effectiveness values are $9,500 per ton of VOC reduced using an existing combustion device, and $9,500 using an existing VRU. For diaphragm pumps in the transmission and storage segment using the multipollutant approach, the cost effectiveness is estimated to be $130 per ton of methane reduced using an existing combustion device, and $130 using an existing VRU. For VOC, these cost effectiveness values are $4,800 per ton of VOC reduced using an existing combustion device, and $4,800 using an existing VRU. These values are within the range of what the EPA considers to be reasonable. The 2016 NSPS OOOOa requires that emissions from natural gas driven pneumatic pumps at well sites achieve a 95 percent reduction in methane and VOC emissions by routing them to a control device if an existing control device is on site. Owners and operators at well sites have successfully met this standard. Further, several State agencies (e.g., California, proposed in New Mexico) have rules that include this requirement, and have extended the requirement to sites throughout the production segment as well as the transmission and storage segment. These factors considered together demonstrate the reasonableness of a requirement that emissions from natural gas driven pneumatic pumps at sites without access to electricity achieve a 95 percent reduction in methane and VOC emissions by routing them to a control device, provided that an existing control device is on site. There are secondary impacts from the use of a combustion device to control emissions routed from natural gasdriven diaphragm pumps. The combustion of the recovered natural gas creates secondary emissions of hydrocarbons, NOX, CO2, and CO. The EPA considers the magnitude of these emissions to be reasonable given the significant reduction in methane and VOC emissions that the control would achieve. Details of these impacts are provided in the NSPS OOOOb and EG TSD for this rulemaking. There are no other wastes created or wastewater generated. The secondary impacts from use of a VRU are indirect, variable, and dependent on the electrical supply used to power the VRU. No other secondary impacts are expected. In light of the above, we find that the BSER for reducing methane and VOC emissions from natural gas-driven diaphragm pumps in the production and transmission and storage segments is to route the emissions to an existing control device that achieves 95 percent control of methane and VOC, or to route the emissions to an existing VRU and to VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 a process. We are, therefore, proposing to include this requirement in NSPS OOOOb. For piston pumps in the production segment using the single pollutant approach, the cost effectiveness is estimated to be $2,400 per ton of methane reduced using a combustion device, and $2,400 using a VRU ($2,200 with savings). For VOC, these cost effectiveness values are $8,700 per ton of VOC reduced using a combustion device, and $8,700 using a VRU ($8,000 with savings). For piston pumps in the production segment using the multipollutant approach, the cost effectiveness is estimated to be $1,200 per ton of methane reduced using a combustion device, and $1,200 using a VRU ($1,100 with savings). For VOC, these cost effectiveness values are $4,350 per ton of VOC reduced using a combustion device, and $4,350 using a VRU ($4,000 with savings). For piston pumps in the production segment, we do not consider the costs to route emissions from a natural gasdriven pneumatic pump to an existing control device to achieve 95 percent reduction, or to route to an existing VRU and to a process, to be reasonable for methane or VOC using the single pollutant approach. However, the methane and VOC cost effectiveness using the multipollutant method is within the range that the EPA considers reasonable. There are secondary impacts from the use of a combustion device to control emissions routed from natural gasdriven piston pumps. These impacts are the same as discussed above for diaphragm pumps. In light of the above, we find that the BSER for reducing methane and VOC emissions from natural gas-driven piston pumps in the production and transmission and storage segments is to route the emissions to an existing control device that achieves 95 percent control of methane and VOC, or to route the emissions to an existing VRU and to a process. We are, therefore, proposing to include this requirement for piston pumps in NSPS OOOOb. The EPA notes that State rules for concerning natural gas-driven piston pumps emissions control requirements differ. For example, California specifically includes both diaphragm and piston pumps in the definition of pneumatic pumps, while Colorado specifically excludes piston pumps from control requirements. At this time, the EPA is unable to fully understand the basis for the piston pump State control requirement differences based on the PO 00000 Frm 00122 Fmt 4701 Sfmt 4702 background information for these State rules. We are specifically seeking comment on the emissions factors used to estimate the baseline emissions from pneumatic pumps, which are from a 1996 EPA/GRI study.296 The EPA is interested in more recent information regarding emissions from pneumatic pumps. For piston pumps in the transmission and storage segment using the single pollutant approach, the cost effectiveness is estimated to be $2,400 per ton of methane reduced using a combustion device, and $2,400 using a VRU. For VOC, these cost effectiveness values are $87,000 per ton of VOC reduced using a combustion device, and $87,000 using a VRU. For piston pumps in the transmission and storage segment using the multipollutant approach, the cost effectiveness is estimated to be $1,200 per ton of methane reduced using a combustion device, and $1,200 using a VRU. For VOC, these cost effectiveness values are $43,500 per ton of VOC reduced using a combustion device, and $43,500 using a VRU. For piston pumps in the transmission and storage segment, we do not consider the costs to be reasonable to route emissions from a natural gas-driven pneumatic pump to an existing control device, or to route to an existing VRU and to a process, for either methane or VOC under the single pollutant approach. Further, we do not find that the cost effectiveness for both methane and VOC to be reasonable under the multipollutant approach. Therefore, we are unable to conclude that requiring the routing of emissions from natural gas-driven piston pumps in the transmission and storage segment to an existing control device to achieve 95 percent reduction of methane and VOC emissions, or the routing of emissions to a VRU and to a process, represents BSER for NSPS OOOOb in this proposal. 2. EG OOOOc The EPA evaluated BSER for the control of methane from existing pneumatic pumps (designated facilities) in all segments in the Crude Oil and Natural Gas source category covered by the proposed NSPS OOOOb and translated the degree of emission limitation achievable through application of the BSER into a proposed presumptive standard for these facilities 296 Gas Research Institute (GRI)/U.S. Environmental Protection Agency. 1996d. Research and Development, Methane Emissions from the Natural Gas Industry, Volume 13: Chemical Injection Pumps. June 1996 (EPA–600/R–96–080m). E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules that mirrors the proposed NSPS OOOOb, with the exception of the BSER conclusion regarding piston pumps in the production segment. First, based on the same criteria and reasoning explained above the EPA is proposing to define the designated facility in the context of existing pneumatic pumps as those that commenced construction on or before November 15, 2021. Based on information available to the EPA, we did not identify any factors specific to existing sources that would indicate that the EPA should alter this definition as applied to existing sources. The EPA finds that the controls evaluated for new sources for NSPS OOOOb are appropriate for consideration for existing sources under the EG OOOOc. The EPA finds no reason to evaluate different, or additional, control measures in the context of existing sources because the EPA is unaware of any control measures, or systems of emission reduction, for pneumatic pumps that could be used for existing sources but not for new sources. Next, the methane emission reductions expected to be achieved via application of the control measures identified above to new sources are also expected to be achieved by application of the same control measures to existing sources. The EPA finds no reason to believe that these calculations would differ for existing sources as compared to new sources because the EPA believes that the baseline emissions of an uncontrolled source are the same, or very similar, and the efficiency of the control measures are the same, or very similar, compared to the analysis above. This is also true with respect to the costs, non-air environmental impacts, energy impacts, and technical limitations discussed above for the control options identified. The EPA has not identified any costs associated with applying these controls at existing sources, such as retrofit costs, that would apply any differently than, or in addition to, those costs assessed above regarding application of the identified controls to new sources. The cost effectiveness values for the option of zero emissions from pneumatic pumps in the natural gas processing sector range from $420 to $1,470 per ton of methane eliminated ($240 to $1,300 per ton considering savings). These cost effectiveness values are in the range considered reasonable by the EPA. However, as explained above in the context of new sources, at this time we are unclear as to whether the technical limitations associated with this option have been overcome and whether zeroemission pneumatic pumps are VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 technically feasible. Therefore, at this time, we are unable to conclude that this zero-emission option represents BSER in this proposal for the EG, but we are soliciting comment on this issue to better understand whether a zeroemission option is technically feasible. For diaphragm pumps in the production segment the cost effectiveness is estimated to be $260 per ton of methane reduced using an existing (on site) combustion device or VRU, and $260 per ton of methane using an existing (on site) VRU ($80 with savings). For diaphragm pumps in the transmission and storage segment the cost effectiveness of is estimated to be $260 per ton of methane reduced using an existing (on site) combustion device, and $260 using an existing (on site) VRU. This cost effectiveness is considered reasonable by the EPA. For piston pumps in the production segment the cost effectiveness is estimated to be $2,400 per ton of methane reduced using an existing (on site) combustion device or VRU, and $2,400 per ton of methane using an existing (on site) VRU ($2,200 with savings). For piston pumps in the transmission and storage segment the cost effectiveness is estimated to be $2,400 per ton of methane reduced using an existing (on site) combustion device, and $2,400 using an existing (on site) VRU. This cost effectiveness is outside of the range considered reasonable by the EPA. In summary, the EPA did not identify any factors specific to existing sources, as opposed to new sources, that would alter the analysis above for the proposed NSPS OOOOb as applied to the designated pollutant (methane) and the designated facilities (pneumatic pumps). However, the BSER conclusion regarding piston pumps in the production and transmission and storage segments for the EG differs from the conclusion for new sources under the NSPS. As a result, the proposed presumptive standards for existing pneumatic pumps are as follows. For diaphragm pneumatic pumps in the production and transmission and storage segments, the presumptive standard is routing emissions to an existing (already on site) control device or existing (already on site) VRU and to a process to achieve 95 percent reduction in methane. For pneumatic pumps (diaphragm and piston) in the natural gas processing sector, the presumptive standard is a natural gas emission rate of zero. As for new sources, the EPA is specifically soliciting comment on whether the production and transmission storage segments should be subcategorized based on the availability PO 00000 Frm 00123 Fmt 4701 Sfmt 4702 63231 of electricity and BSER determined separately for each subcategory in the EG. H. Proposed Standards for Equipment Leaks at Natural Gas Processing Plants 1. NSPS OOOOb a. Background In the 2012 NSPS OOOO, the EPA established VOC standards for equipment leaks at onshore natural gas processing plants. These standards were based on the Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry (NSPS VVa), which is an EPA Method 21 LDAR program generally requiring monthly monitoring of pumps with a leak definition of 2,000 ppm, quarterly monitoring of valves with a leak definition of 500 ppm, and annual monitoring of connectors with a leak definition of 500 ppm.297 In the 2016 NSPS OOOOa, the EPA added GHG (methane) to the title of the standards for equipment leaks at onshore natural gas plants but continued to rely on the requirements in NSPS VVa, which limited monitoring and repair (if found leaking) to those equipment components ‘‘in VOC service.’’ Based on our review of the current standards, we are proposing to revise the equipment leak standards for onshore natural gas plants to more readily apply to equipment components that have the potential to emit methane even though they are not ‘‘in VOC service.’’ b. Technology and LDAR Program Review The EPA acknowledges that advancements are being made in leak detection, including remote sensing, sensor networks, and OGI. The EPA already provides use of OGI as an alternative work practice at 40 CFR 60.18(g); however, the alternative work practice requires annual EPA Method 21 monitoring as part of the OGI monitoring protocol. Parallel with this proposal, the EPA is proposing appendix K to part 60 to provide a standard method for OGI leak monitoring. This allows us to consider a wider range of LDAR programs when evaluating the BSER for equipment leaks at onshore natural gas processing plants. To evaluate different LDAR programs, we used a Monte Carlo simulation that simulated initiation of leaks for pumps, valves, and connectors at monthly intervals based on 297 40 CFR part 60, subpart VVa, includes ‘‘skip period’’ provisions that may alter the cited monitoring frequencies. E:\FR\FM\15NOP2.SGM 15NOP2 63232 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules efficiencies of this LDAR program applied to similar industrial processes.298 However, when considering the components not monitored at the onshore natural gas processing plant because they are not ‘‘in VOC service’’, the overall hydrocarbon control efficiency of the current NSPS OOOOa requirements drops to 73.2 percent. Thus, significant emission reductions can be achieved by extending the current provisions to include all components that have the potential to emit methane. Based on our model simulation of an OGI-based LDAR program, we found that bimonthly OGI monitoring of all equipment components (with potential VOC or methane emissions) using devices capable of identifying mass leaks at 30 g/hr and at 15 g/hr would achieve emission reductions of 88.5 percent and 92.2 percent, respectively. Based on the requirements in appendix K that the instrument be able to detect a methane leak of 17 g/hr, these results suggest that bimonthly OGI monitoring following appendix K will achieve comparable emission reductions as the current NSPS OOOOa requirements for the equipment components subject to the monitoring requirements. component specific leak frequencies and EPA Method 21 leak size distributions based on historical EPA Method 21 leak data. We randomly assigned a mass emission rate based on the EPA Method 21 leak size assuming a lognormal distribution for the mass emission rate around the EPA Method 21 screening value correlation equation estimates. The simulation runs for five years for each LDAR program to build up leaks that might not be repaired under a given program, and compares the emissions estimated in the fifth year of the simulation for different LDAR programs. The model also records the number of repairs made in the fifth year of the simulation to assess the annual repair costs associated with the LDAR program. More information on the LDAR program Monte Carlo simulation and associated cost analyses is available in the NSPS OOOOb and EG TSD for this proposal. Based on our model simulation of NSPS OOOOa requirements (Method 21 based LDAR program following the requirements in NSPS VVa), the EPA projects that the program achieves a 91.5 percent emission reduction for the components monitored. This is comparable to the projected control c. Control Options and 2021 BSER Analysis The EPA then evaluated various LDAR programs for their control efficiency, cost and cost effectiveness for a small and a large model natural gas processing plant. These ‘‘small’’ and ‘‘large’’ model plants were based on the number of components at each facility in various monitoring summaries for onshore natural gas processing plants.299 We considered the (option 1) current NSPS OOOOa standards expanded to components that also have the potential to emit methane regardless of the VOC content of the stream, (option 2) bimonthly OGI following appendix K for all components (VOC or methane), and (options 3 and 4) a hybrid approach following the current alternative work practice (regular OGI with annual EPA Method 21). For option 3 we evaluated requiring quarterly OGI with an annual EPA Method 21 survey at 10,000 ppm. For option 4 we evaluated requiring bimonthly OGI with an annual EPA Method 21 survey at 10,000 ppm. These control options and their associated costs are summarized in Tables 18 and 19 for the small and large model plants, respectively. TABLE 18—SUMMARY OF CONTROL OPTIONS AND COSTS FOR SMALL MODEL PLANTS Emissions reduction (tpy) Control option VOC Capital cost ($) CE a ($/ton methane) CE a ($/ton VOC) Annual cost ($/yr) Methane Incremental ($/ton VOC) Incremental ($/ton methane) ........................ ¥189,100 696,200 87,000 ........................ ¥41,300 151,100 18,800 Methane and VOC Service 1 2 3 4 ........................................ ........................................ ........................................ ........................................ a Cost 12.34 12.61 12.64 12.76 56.95 58.19 58.33 58.92 $17,700 1,500 19,200 19,200 $114,100 62,800 84,500 95,500 $9,200 5,000 6,700 7,500 $2,000 1,100 1,400 1,600 effectiveness (CE) compared to no monitoring. TABLE 19—SUMMARY OF CONTROL OPTIONS AND COSTS FOR LARGE MODEL PLANTS Emissions reduction (tpy) Control option VOC Capital cost ($) CE a ($/ton methane) CE a ($/ton VOC) Annual cost ($/yr) Methane Incremental ($/ton VOC) Incremental ($/ton methane) ........................ ¥200,000 760,000 79,500 ........................ ¥43,100 165,200 17,100 Methane and VOC Service 1 2 3 4 ........................................ ........................................ ........................................ ........................................ khammond on DSKJM1Z7X2PROD with PROPOSALS2 a Cost 25.59 26.11 26.17 26.44 118.27 120.81 121.10 122.31 $36,200 3,000 39,200 39,200 $229,000 123,500 170,500 191,300 $9,000 4,700 6,500 7,200 $1,900 1,000 1,400 1,600 effectiveness (CE) compared to no monitoring. We further assumed that all facilities outsource their equipment leak surveys. The first year ‘‘capital’’ costs of implementing an EPA Method 21 program (identifying components required to be monitored and developing a data system to track the proper frequency to monitor each component) are summarized in Tables 18 and 19. Additionally, these tables summarize the annualized costs of conducting a complete EPA Method 21 298 EPA, October 2007. ‘‘Leak Detection and Repair—A Best Practices Guide.’’ Office of Enforcement and Compliance Assurance. EPA–305– D–07–001. See ‘‘Table 4.1—Control effectiveness for an LDAR program at a chemical process unit and a refinery.’’ 299 See Section 10.4 of Chapter 10 ‘‘Equipment Leaks from Natural Gas Processing Plants’’ in the TSD located at Docket ID No. EPA–HQ–OAR–2021– 0317. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 PO 00000 Frm 00124 Fmt 4701 Sfmt 4702 E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules monitoring survey of all equipment (those in VOC service or contacting methane), which includes the annual costs of conducting required surveys and making the necessary repairs as well as annualized first year ‘‘capital’’ costs. The first-year startup costs for OGI surveys are small, estimated to be $750 for small plants and $1,500 for large plants. Because OGI surveys can be conducted much more quickly, the annualized cost of conducting bimonthly OGI surveys is approximately half the annualized cost of EPA Method 21 surveys through NSPS VVa. Both EPA Method 21 and OGI LDAR programs reduce loss of product. Therefore, the costs of the LDAR programs are offset to some degree to the emissions reduced. When evaluating LDAR programs that consider all components (both VOC and methane), the annual value of the product not lost due to reduced emissions is approximately $14,000/yr. Based on our analysis, the resulting cost effectiveness is reasonable for all of the options when assigning all costs to the reduction of methane. When assigning all costs to VOC reduction, however, only the bimonthly OGI option is considered reasonable at $5,000/ton VOC reduced for small plants and $4,700/ton VOC reduced at large plants. The EPA next considered the incremental cost-effectiveness between the four options to determine which option represents the BSER for equipment leaks at onshore natural gas processing plants. All four options achieve similar emission reductions, as discussed in the previous section. Bimonthly OGI (option 2) reduces an additional 2 tpy of methane at a cost savings. Adding annual EPA Method 21 to bimonthly OGI monitoring (option 4) reduces an additional 1.5 tpy methane for large model gas plant but at significant cost well above any costs the EPA would consider appropriate, at approximately $45,000/ton methane reduced (comparing option 4 with option 2). Therefore, the EPA does not consider it reasonable to require the additional of annual EPA Method 21. Based on the discussion above, we consider a bimonthly OGI LDAR program following appendix K that includes all equipment components that have the potential to emit VOC or methane to be BSER for new sources. Therefore, we are proposing this LDAR requirement for new sources under NSPS OOOOb. Because an EPA Method 21 monitoring program based on the requirements of NSPS VVa when applied to all equipment components that have the potential to emit VOC or methane is projected to achieve similar VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 emission reductions, we are proposing that this EPA Method 21-based LDAR program may be used as an alternative to bimonthly OGI surveys. In the development of the 2012 NSPS OOOO, we found that NSPS VVa provisions for PRDs, open-ended valves or lines, and closed vent systems and equipment designated with no detectable emissions were BSER. Available information since then continues to support this conclusion. Therefore, we are proposing to retain the current requirements in the 2016 NSPS OOOOa (which adopts by reference specific provisions NSPS VVa) for PRDs, open-ended valves or lines, and closed vent systems and equipment designated with no detectable emissions, except expanding the applicability to sources that have the potential to emit methane. The EPA is soliciting information that would support the use of the proposed bimonthly OGI monitoring requirement for these equipment components in place of the NSPS VVa annual EPA Method 21 monitoring. The EPA requests comments on ways to streamline approval of alternative LDAR programs using remote sensing techniques, sensor networks, or other alternatives for equipment leaks at onshore natural gas processing plants. Based on our Monte Carlo equipment leak model that assumes wellimplemented LDAR programs with no delayed repair, both an EPA Method 21 based program following NSPS VVa and a bimonthly OGI monitoring program following appendix K are projected to achieve a 91-percent emission reduction effectiveness. We request comment on whether providing such an emission reduction target and equipment leak modeling tool to simulate LDAR under similar ‘‘ideal’’ program implementation conditions may facilitate future equivalency determinations. 2. EG OOOOc The application of an LDAR program at an existing source is the same as at a new source because there is no need to retrofit equipment at the site to achieve compliance with the work practice standard. The cost effectiveness for implementing a bimonthly OGI LDAR program for all equipment components that have the potential to emit methane is approximately $850/ton methane reduced. As explained above, the cost effectiveness of this OGI monitoring option is within the range of costs we believe to be reasonable for methane reductions. Therefore, we consider a bimonthly OGI LDAR program following appendix K that includes all equipment components that PO 00000 Frm 00125 Fmt 4701 Sfmt 4702 63233 have the potential to emit methane to be BSER for existing sources. I. Proposed Standards for Well Completions 1. NSPS OOOOb a. Background Pursuant to CAA section 111(b)(1)(B), the EPA reviewed the current standards in NSPS OOOOa for well completions and proposes to determine that they continue to reflect the BSER for reducing methane and VOC emissions during oil and natural gas well completions following hydraulic fracturing and refracturing. Accordingly, we are not proposing revisions to these standards. Provided below are a description of the affected facilities, the current standards, and a summary of our review. Natural gas and oil wells all must be ‘‘completed’’ after initial drilling in preparation for production. Well completion activities not only will vary across formations but can vary between wells in the same formation. Over time, completion and recompletion activities may change due to the evolution of well characteristics and technology advancement. Well completion activities include multiple steps after the well bore hole has reached the target depth. Developmental wells are drilled within known boundaries of a proven oil or gas field and are located near existing well sites where well parameters are already recorded and necessary surface equipment is in place. When drilling occurs in areas of new or unknown potential, well parameters such as gas composition, flow rate, and temperature from the formation need to be ascertained before surface facilities required for production can be adequately sized and brought on site. In this instance, exploratory (also referred to as ‘‘wildcat’’) wells and field boundary delineation wells typically either vent or combust the flowback gas. One completion step for improving oil and gas production is to fracture the reservoir rock with very high-pressure fluid, typically a water emulsion with a proppant (generally sand) that ‘‘props open’’ the fractures after fluid pressure is reduced. Natural gas emissions are a result of the backflow of the fracture fluids and reservoir gas at high pressure and velocity necessary to clean and lift excess proppant to the surface. Natural gas from the completion backflow escapes to the atmosphere during the reclamation of water, sand, and hydrocarbon liquids during the collection of the multi-phase mixture directed to a surface impoundment. As the fracture fluids are depleted, the E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63234 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules backflow eventually contains a higher volume of natural gas from the formation. Due to the specific additional equipment and resources involved and the nature of the backflow of the fracture fluids, completions involving hydraulic fracturing have higher costs and vent substantially more natural gas than completions not involving hydraulic fracturing. During its lifetime, wells may need supplementary maintenance, referred to as recompletions (these are also referred to as workovers). Recompletions are remedial operations required to maintain production or minimize the decline in production. Examples of the variety of recompletion activities include completion of a new producing zone, re-fracture of a previously fractured zone, removal of paraffin buildup, replacing rod breaks or tubing tears in the wellbore, and addressing a malfunctioning downhole pump. During a recompletion, portable equipment is conveyed back to the well site temporarily and some recompletions require the use of a service rig. As with well completions, recompletions are highly specialized activities, requiring special equipment, and are usually performed by well service contractors specializing in well maintenance. Any flowback event during a recompletion, such as after a hydraulic fracture, will result in emissions to the atmosphere unless the flowback gas is captured. When hydraulic re-fracturing (recompletions) is performed, the emissions are essentially the same as new well completions involving hydraulic fracture, except that surface gas collection equipment will already be present at the wellhead after the initial fracture. The flowback velocity during re-fracturing will typically be too high for the normal wellhead equipment (separator, dehydrator, lease meter), while the production separator is not typically designed for separating sand. Flowback emissions are a result of free gas being produced by the well during well cleanup event, when the well also happens to be producing liquids (mostly water) and sand. The high rate flowback, with intermittent slugs of water and sand along with free gas, is directed to an impoundment or vessels until the well is fully cleaned up, where the free gas vents to the atmosphere while the water and sand remain in the impoundment or vessels. Therefore, nearly all of the flowback emissions originate from the recompletion process but are vented as the flowback enters the impoundment or vessels. Minimal amounts of emissions are caused by the fluid (mostly water) held in the VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 impoundment or vessels since very little gas is dissolved in the fluid when it enters the impoundment or vessels. The 2021 GHGI estimates approximately 34,000 metric tpy of methane emissions from hydraulically fractured completion/workover natural gas well events and approximately 12,000 metric tpy of methane emissions from hydraulically fractured completion/workover oil well events in 2019. b. Affected Facility Each affected facility is a single well that conducts a well completion operation following hydraulic fracturing or refracturing. c. Current NSPS Requirements The current NSPS for natural gas and oil well completions and recompletions are the same. For well completions of hydraulically fractured (or refractured) wells, the EPA identified two subcategories of hydraulically fractured wells for which well completions are conducted: (1) Non-wildcat and nondelineation wells (subcategory 1 wells); and (2) wildcat and delineation wells and low-pressure wells (subcategory 2 wells). A wildcat well, also referred to as an exploratory well, is a well drilled outside known fields or is the first well drilled in an oil or gas field where no other oil and gas production exists. A delineation well is a well drilled to determine the boundary of a field or producing reservoir. In the 2016 NSPS OOOOa rule, the EPA finalized operational standards for non-wildcat and non-delineation wells (subcategory 1 wells) that required a combination of REC and combustion. Because RECs are not feasible for every well at all times during completion or recompletion activities due to variability of produced gas pressure and/or inert gas concentrations, the rule allows for wellhead owners and operators to continue to reduce emissions when RECs are not feasible due to well characteristics (e.g., wellhead pressure or inert gas concentrations) by using a completion combustion device. For wildcat and delineation wells and low-pressure wells (subcategory 2 wells), the EPA finalized an operational standard that required either (1) routing all flowback directly to a completion combustion device with a continuous pilot flame (which can include a pit flare) or, at the option of the operator, (2) routing the flowback to a well completion vessel and sending the flowback to a separator as soon as a separator will function and then directing the separated gas to a completion combustion device with a PO 00000 Frm 00126 Fmt 4701 Sfmt 4702 continuous pilot flame. For option 2, any gas in the flowback prior to the point when the separator will function was not subject to control. For both options (1) and (2), combustion is not required in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost, or waterways. Under the 2016 NSPS OOOOa rule, oil wells with a gas-to-oil ratio less than 300 scf of gas per stock tank barrel of oil produced are affected facilities but have no requirements other than to maintain records of the low GOR certification and a claim signed by the certifying official. As discussed in section X.B.1 of this preamble, in the 2020 Technical Rule, the EPA made certain amendments (e.g., related to the use of a separator, amended definition of flowback, amended recordkeeping and reporting requirements) to the VOC standards for well completions in the 2016 NSPS OOOOa, and is proposing to apply the same amendments to the methane standards for well completions in the 2016 NSPS OOOOa. d. 2021 BSER Analysis The two techniques considered under the previous BSER analyses that have been proven to reduce emissions from production segment well completions and recompletions include REC and completion combustion. REC is an approach that not only reduces emissions but delivers natural gas product to the sales meter that would typically be vented. The second technique, completion combustion, destroys the organic compounds. No other emissions control techniques were identified as being required under other rules (Federal, State, or local rules) that would exceed the level of control required under the 2016 NSPS OOOOa rule. Therefore, no other technology control requirements were evaluated in this review. Reduced emission completions, also referred to as ‘‘green’’ or ‘‘flareless’’ completions, use specially designed equipment at the well site to capture and treat gas so it can be directed to the sales line. This process prevents some natural gas from venting and results in additional economic benefit from the sale of captured gas and, if present, gas condensate. However, as the EPA has previously acknowledged, there are some limitations that may exist for performing RECs based on technical barriers. These limitations continue to exist. Three main limitations for performing a REC include the proximity of pipelines to the well, the pressure of the produced gas, and the inert gas E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules concentration. These limitations are discussed below. For exploratory wells (in particular), no nearby sales line may exist. The lack of a nearby sales line incurs higher capital outlay risk for exploration and production companies and/or pipeline companies constructing lines in exploratory fields. The EPA is soliciting comment on how ‘‘access to a sales line’’ and a ‘‘sales line’’ should be defined. During the completion/recompletion process, the pressure of flowback fluids may not be sufficient to overcome the gathering line backpressure. In this case, combustion of flowback gas is one option, either for the duration of the flowback or until a point during flowback when the pressure increases to flow to the sales line. Another potential compressor application is to boost pressure of the flowback gas after it exits the separator. This technique is experimental because of the difficulty operating a compressor where there is a widely fluctuating flowback rate. Lastly, if the concentration of inert gas, such as nitrogen or CO2, in the flowback gas exceeds sales line concentration limits, venting to the atmosphere or to a combustion device of the flowback may be necessary for the duration of flowback or until the gas energy content increases to allow flow to the sales line. Further, since the energy content of the flowback gas may not be high enough to sustain a flame due to the presence of the inert gases, combustion of the flowback stream would require a continuous ignition source with its own separate fuel supply. Where a REC can be conducted, the achievable emission reductions vary according to reservoir characteristics and other parameters including length of completion, number of fractured zones, pressure, gas composition, and fracturing technology/technique. Based on several experiences presented at Natural Gas STAR technology transfer workshops, this analysis assumes 90 percent of flowback gas can be recovered during a REC.300 Gas that cannot be recovered during a REC can be directed to a completion combustion device in order to achieve an estimated 95 percent reduction in overall emissions. Completion combustion devices commonly found on drilling sites are generally crude and portable, often installed horizontally due to the liquids that accompany the flowback gas. These 300 Memorandum to Bruce Moore, U.S. EPA from ICF Consulting. Percent of Emissions Recovered by Reduced Emission Completions. May 2011. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 flares can be as simple as a pipe with a basic ignition mechanism and discharge over a pit near the wellhead. However, the flow directed to a completion combustion device may or may not be combustible depending on the inert gas composition of flowback gas, which would require a continuous ignition source. Sometimes referred to as pit flares, these types of combustion devices do not employ an actual control device and are not capable of being tested or monitored for efficiency. They do provide a means of minimizing vented gas and is preferable to venting. The efficiency of completion combustion devices, or exploration and production flares, can be expected to achieve 90 percent, on average, over the duration of the completion or recompletion.301 If the energy content of natural gas is low, then the combustion mechanism can be extinguished by the flowback gas. Therefore, it is more reliable to install an igniter fueled by a consistent and continuous ignition source. Because of the exposed flame, open pit flaring can present a fire hazard or other undesirable impacts in some situations (e.g., dry, windy conditions and proximity to residences). As a result, owners and operators may not be able to combust unrecoverable gas safely in every case. Noise and heat are the two adverse impacts of completion combustion device operations. In addition, combustion and partial combustion of many pollutants also create secondary pollutants including NOX, CO, sulfur oxides (SOX), CO2, and smoke/ particulates. The degree of combustion depends on the rate and extent of fuel mixing with air and the temperature maintained by the flame. Most hydrocarbons with carbon-to-hydrogen ratios greater than 0.33 are likely to smoke. The high methane content of the gas stream routed to the completion combustion device, it suggests that there should not be smoke except in specific circumstances (e.g., energized fractures). The stream to be combusted may also contain liquids and solids that will also affect the potential for smoke. The previous BSER analyses cost effectiveness per ton of methane and VOC emissions reduced per completion event evaluated for REC, completion combustion, and REC and completion combustion were updated to 2019 dollars. The results of this updated analysis are provided below, and details 301 77 FR 48889–48890, March 22, 2013 (Approval and Promulgation of Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa, and Arikara Nation), North Dakota; Rule). PO 00000 Frm 00127 Fmt 4701 Sfmt 4702 63235 are provided in the NSPS OOOOb and EG TSD for this rulemaking. The updated capital cost for performing a REC for a well completion or recompletion lasting 3 days is estimated to be $15,174 (2019 dollars). Monetary savings associated with additional gas captured to the sales line is estimated based on a natural gas price of $3.13 per Mcf. It was assumed that all gas captured would be included as sales gas. The updated capital and cost for wells including completion combustion devices resulted in an estimated average completion combustion device cost of approximately of $4,198 per well completion (2019 dollars). For both REC and completion combustion devices, the capital costs are one-time events, and annual costs were conservatively assumed to be equal to the capital costs. The EPA also evaluated the costs that would be associated with using a combination of a REC and completion combustion device. The annual costs would be a combined estimated capital and annual cost of $19,371 (2019 dollars). As a result of updating capital/ annual costs to reflect 2019 dollars and decreasing the control efficiency assumed for completion combustion from 95 percent to 90 percent, the cost effectiveness estimates are slightly higher, but substantially similar to previous cost effectiveness BSER analysis control option estimates for natural gas well and oil well completions and recompletions. For gas wells, under the single pollutant approach where all the costs are assigned to the reduction of methane emissions and zero to reduction of VOC, the cost effectiveness estimates were approximately $1,180 per ton of methane reduced for REC ($990 with natural gas savings), $330 for completion combustion, and $1,420 for a combination of REC and completion combustion ($1,250 with natural gas savings). If all costs were assigned to VOC reduction and zero to methane reduction, the cost effectiveness estimates were approximately $4,230 per ton of VOC removed for REC ($3,570 with natural gas savings), $1,170 for completion combustion, and $5,110 for a combination of REC and completion combustion ($4,490 with natural gas savings). Under the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, these estimates are approximately $590 per ton of methane reduced for REC ($500 with natural gas savings), $160 for completion combustion, and $710 for a combination of REC and completion combustion ($630 with natural gas savings). For VOC, the cost effectiveness E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63236 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules estimates were approximately $2,100 per ton of VOC removed for REC ($1,790 with natural gas savings), $590 for completion combustion, and $2,600 for a combination of REC and completion combustion ($2,250 with natural gas savings). For oil wells, under the single pollutant approach where all the costs are assigned to the reduction of methane emissions and zero to reduction of VOC emissions, the cost effectiveness values were approximately $1,620 per ton of methane reduced for REC ($1,440 with natural gas savings), $450 for completion combustion, and $1,960 for a combination of REC and completion combustion ($1,790 with natural gas savings). Where all costs were assigned to reducing VOC emissions and zero to reducing methane emissions, the cost effectiveness estimates were approximately $5,840 per ton of VOC removed for REC ($5,190 with natural gas savings), $1,620 for completion combustion, and $7,070 for a combination of REC and completion combustion ($6,450 with natural gas savings). Under the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, these estimates are approximately $810 per ton of methane reduced for REC ($720 with natural gas savings), $230 for completion combustion, and approximately $980 for a combination of REC and completion combustion ($900 with natural gas savings). For VOC, the cost effectiveness estimates were approximately $2,920 per ton of VOC removed for REC ($2,600 with natural gas savings), $810 for completion combustion, and $3,530 for a combination of REC and completion combustion ($3,220 with natural gas savings). As noted above, the current NSPS OOOOa requirements consist of a combination of REC and completion combustion for hydraulically fractured natural gas and oil well completions. These techniques have been employed by the oil and gas industry since 2012 for natural gas well completions and 2016 for oil well completions. The EPA concludes that the cost effectiveness of REC, completion combustion, or a combination, for natural gas and oil wells are within the range that the EPA considers to be reasonable when considering both methane and VOC cost effectiveness. Since there are multiple scenarios where the cost effectiveness of the control measures is reasonable for natural gas and oil wells (including the cost effectiveness of VOC for REC and combined REC and completion VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 combustion), we conclude that the overall cost effectiveness is reasonable. There are secondary impacts from the use of a completion combustion device, as the combustion of the gas creates secondary emissions of hydrocarbons, NOX, CO2, and CO. The EPA considers the magnitude of these emissions to be reasonable given the significant reduction in methane and VOC emissions that the control would achieve. Details of these impacts are provided in the NSPS OOOOb and EG TSD for this rulemaking. There are no other wastes created or wastewater generated from either REC or completion combustion. In light of the above, we determined that the current standards, which consist of a combination of REC and combustion, continue to represent the BSER for reducing methane and VOC emissions from well completions of hydraulically fractured or refractured oil and natural gas wells. We therefore propose to retain these standards in the proposed NSPS OOOOb. As discussed in section XII.I.1.c, in the 2020 Technical Rule, the EPA made certain amendments to the VOC standards for well completions in the 2016 NSPS OOOOa. For the same reasons provided in the 2020 Technical Rule and discussed in section X.B.1 of this preamble for including these amendments for methane in NSPS OOOOa, the EPA is proposing to include these methane and VOC amendments for well completions in the NSPS OOOOb rule. 2. EG OOOOc A well completion operation following hydraulic fracturing or refracturing is a ‘‘modification,’’ as defined in CAA section 111(a), as each such well completion operation involves a physical change to a well that results in an increase in emissions; accordingly, each such operation would trigger the applicability of the NSPS. Therefore, there are no ‘‘existing’’ well completion operations of hydraulically fractured or refractured oil or natural gas wells. In light of the above, there are no proposed presumptive standards for such operations in this action. J. Proposed Standards for Oil Wells With Associated Gas 1. NSPS OOOOb a. Background Wells in some formations and shale basins are drilled primarily for oil production. Although the wells are drilled for oil, the wells may produce an associated, pressurized natural gas stream. The natural gas is either PO 00000 Frm 00128 Fmt 4701 Sfmt 4702 naturally occurring in a discrete gaseous phase within the liquid hydrocarbon or is released from the liquid hydrocarbons by separation. In many areas, a natural gas gathering infrastructure may be at capacity or unavailable. In such cases, if there is not another beneficial use of the gas at the site (e.g., as fuel) the collected natural gas is either flared or vented directly to the atmosphere. Emissions from associated gas venting and flaring are not regulated by either the 2012 NSPS OOOO or the NSPS OOOOa. The EPA did not evaluate BSER for associated gas production in either rulemaking. For this rulemaking, the EPA is proposing that methane and VOC emissions resulting from associated gas production be reduced by at least 95 percent. b. Definition of Affected Facility The EPA is proposing the definition of an oil well associated gas affected facility as an oil well that produces associated gas. c. Description In 2019, according to the EIA, the number of onshore gas producing oil wells in the U.S.302 was 334,342 and the volume of vented and flared natural gas in 2019 was 523,066 million cubic feet.303 According to the 2021 GHGI, in 2019 venting of associated gas emitted 42,051 metric tons of CH4 and 1,291 metric tons of CO2 and flaring of associated gas emitted 81,797 metric tons of CH4 and 25,355,892 metric tons of CO2. For the 2019 reporting year in GHGRP subpart W, there were a total of 2,500 wells that reported emissions from the venting of associated gas emissions. The total emissions from these wells were just over 33,900 metric tons of methane (848,000 metric tons CO2e). Over 90 percent of these methane emissions were reported in three basins—Gulf Coast, Williston, and Permian. Examining this information by State shows that almost half of the venting wells and over 64 percent of the methane emissions from the venting of associated gas occurs in Texas. Texas and North Dakota account for almost 90 302 https://www.eia.gov/dnav/ng/ng_prod_ oilwells_s1_a.htm. The number of onshore gas producing oil wells was derived from the ‘‘U.S. Natural Gas Number of Oil Wells’’ subtracting ‘‘Federal Offshore—Gulf of Mexico’’ wells [336,732—2,390 = 334,342 wells]. 303 https://www.eia.gov/dnav/ng/ng_prod_sum_a_ EPG0_VGV_mmcf_a.htm. The volume of vented and flared natural gas was derived from ‘‘U.S. Natural Gas Vented and Flared’’ subtracting ‘‘Alaska—State Offshore’’ and ‘‘California—State Offshore’’ and ‘‘Federal Offshore—Gulf of Mexico’’ and ‘‘Louisiana—State Offshore’’ and ‘‘Texas—State Offshore’’ [538,479¥825¥0¥14,461¥45¥82 = 523,066]. E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 percent of the reported methane emissions from vented associated gas oil wells. The average methane emissions from the venting of associated gas in 2019 was 13.6 metric tpy per venting well. The average per State ranges from 0.03 tpy per venting well in California to over 340 tpy per venting well in North Dakota. The 2019 GHGRP subpart W data also show that there were over 38,000 wells reporting that they flared associated gas, with over 21 million metric tons of CO2 emissions and over 68,000 metric tons of methane emissions. As with the venting emissions, the majority of the wells flaring associated gas (over 93 percent) were in the Gulf Coast, Williston, and Permian basins. Approximately 96 percent of the CO2 and methane emissions were reported in these three basins. The majority of the wells flaring associated gas (over 72 percent) and emissions (over 87 percent) were from wells in Texas and North Dakota. d. Control Options For new and existing sources (oil wells), options to mitigate emissions from associated gas in order of environmental and resource conservation benefit include: • Capturing the associated gas from the separator and routing into a gas gathering flow line or collection system; • Beneficially using the associated gas (e.g., onsite use, natural gas liquid processing, electrical power generation, gas to liquid); • Reinjecting for enhanced oil recovery; and • Flaring with legally and practicably enforceable limits. Typically, State oil and gas regulatory agencies (or, on certain public and Tribal lands, the BLM) regulate venting and flaring of associated gas from oil wells to ensure oil and natural gas resources are conserved and utilized in a manner consistent with their respective statutes. State oil and gas regulatory agencies typically encourage, and in some cases require, capture (conservation) over flaring, then flaring over venting. In addition, these State regulators have adopted a variety of approaches for regulating venting and flaring of associated gas from oil wells. Some require technical and economic feasibility analyses for continuing flaring beyond a certain time (e.g., one year). Some require gas capture plans to track and incrementally increase the percentage of gas captured (rather than flared) over prescribed timelines and some of these include provisions to curtail production in the event of not meeting gas capture goals. Many State VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 oil and gas regulations recognize that there are times when gas capture may not be feasible, such as when there is no gas gathering pipeline to tie into, the gas gathering pipeline may be at capacity, or a compressor station or gas processing plant downstream may be off-line, thus closing in the gas gathering pipeline. Venting is allowed by some State and regulatory agencies in certain circumstances such as emergency or upset conditions, during production evaluation, and well purging or productivity tests. In cases where venting is allowed, these rules typically require reporting of the volume of gas flared and vented (and sometimes a gas analysis), while some States combine flaring and venting information together in publicly accessible well data. Where flares are allowed, these State oil and gas regulations typically do not include monitoring, recordkeeping and reporting on the performance of the flare and would not be recognized as providing legally and practicably enforceable limits for CAA purposes. Some State environmental regulators address associated gas with a regulation stipulating flaring over venting that includes monitoring, recordkeeping and reporting provisions, while others regulate flaring over venting without monitoring requirements. The EPA is interested in information on, and the feasibility, of options to utilize associated gas in some useful manner in situations where a sales line is not available. In addition to use as fuel, such options could include conversion technologies where methane is converted into hydrogen or other added value chemicals. The EPA is interested in information on these, as well as other, technologies. e. 2021 BSER Analysis In performing the BSER analysis for emissions from associated gas oil wells, we recognize there are similarities between the control options available for associated gas and those available for emissions from oil well completions. We are soliciting comment on these similarities. For both flowback emissions during oil well completions and associated gas production, if the infrastructure exists to allow the routing of the gas to a sales line (e.g., ‘‘into a gas flow line or collection system’’), owners and operators will almost always choose that option given the economic benefits of being able to sell the gas. For example, in the 2019 GHGRP subpart W data, applicable facilities reported over 1.2 trillion scf of associated gas was routed to sales lines. This represents only a subset of the total volume of associated gas sent to a sales line, as PO 00000 Frm 00129 Fmt 4701 Sfmt 4702 63237 GHGRP subpart W does not require reporting of this volume in subbasins where the company is not also reporting venting or flaring associated gas. The environmental benefit of routing all associated gas to a sales line is significant, as there are no methane and VOC emissions. The EPA assumes that in situations where gas sales line infrastructure is available, there is minimal cost to owners and operators to route the associated gas to the sales line. While situations at well sites can differ, which would impact this cost, the EPA believes that in every situation the value of the natural gas captured and sold would outweigh these minimal costs of routing the gas to the sales line, thus resulting in overall savings. Given the prevalence of this practice, the environmental benefit, and the economic benefits to owners and operators, the EPA concludes that BSER is routing associated gas from oil wells to a sales line. The EPA seeks comment on this proposed BSER determination, including comment on how to define whether an oil well producing associated gas has access to a sales line for purposes of this BSER and what factors (such as proximity to an existing sales line) should bear on that determination. NSPS OOOOa also includes other compliance options that achieve a 100 percent reduction in emissions from recovered flowback gas. These are ‘‘reinject the recovered gas into the well or another well, use the recovered gas as an onsite fuel source, or use the recovered gas for another useful purpose that a purchased fuel or raw material would serve.’’ 40 CFR 60 60.5375a(a)(1)(ii). The EPA believes that, for associated gas from oil wells, the options of using the gas as an onsite fuel source or for another useful purpose are also viable alternatives to routing to a sales line. However, a significant difference exists between the short-term and relatively small volume of gas recovered during the limited duration of completion flowback versus the consistent flow of recovered gas from ongoing production from the well. Because of this difference, the EPA does not have information that supports reinjecting the associated gas into the well or another well as a viable emissions control alternative. Therefore, the EPA is specifically requesting comment on whether NSPS OOOOb should include re-injecting associated gas as an alternative to routing the gas to a sales line. The format of the well completion provisions in NSPS OOOOa recognize that routing the recovered gas to a gas flow line or collection system, re- E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63238 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules injecting the recovered gas, or using the recovered gas fuel or for another purpose may not be technically feasible. In these situations, owners and operators are required to route the flowback emissions to a completion combustion device. Similarly, the EPA recognizes that there are associated gas oil wells where there is no access to a gas sales line. Therefore, as an aspect of BSER in these situations, the EPA evaluated the flaring of the associated gas as an option to control emissions for situations where access to a sales line is not available. As discussed previously, the average annual methane emissions from the venting of associated gas reported in GHGRP subpart W for 2019 is 13.6 metric tpy (14.9 tpy) per venting well. Using a representative gas composition for the production segment, the estimated VOC emissions would be 4.15 tpy per well. We conducted the BSER analysis using this emissions level as a representative well. The installation and proper operation of a flare can achieve 95 percent and greater reduction in methane and VOC emissions. To be conservative, a 95 percent emission reduction was used for the BSER analysis. Therefore, the resulting emission reductions are 14.2 tpy methane and 3.9 tpy VOC. The capital cost of a flare is estimated to be $5,719. This was based on a 2011 Natural Gas Star Pro Fact Sheet and updated to 2019 dollars. The resulting capital recovery, assuming a 7 percent interest rate and 15-year equipment life, was $628. The Natural Gas Star Pro report estimated the cost of the natural gas needed for the pilot was $1,800 per year. For this cost analysis, we assumed that this cost was not warranted since the associated gas could be used to fuel the pilot. We are soliciting comments on this cost estimate. The EPA stresses that 95 percent or greater emission reduction is achievable if the flare is properly operated and maintained. In order to ensure that this occurs, the EPA proposes to apply the requirements in § 60.18 of the part 60 General Provisions to oil wells flaring associated gas. In order to account for the cost of the compliance with these requirements, we assumed that the associated cost would be 25 percent of the total annual costs, or an additional $160. This results in a total estimated annual cost of $785. We are soliciting comment on the estimated costs associated with compliance with the § 60.18 monitoring, reporting, and recordkeeping costs for flares used to control emissions of vented associated gas emissions, and whether those requirements would ensure the flare is VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 achieving the proposed emission reduction of 95 percent or greater. Based on these annual costs and the emission reductions cited above, the cost effectiveness, using the single pollutant method, is $55 per ton of methane reduction and $200 per ton of VOC reduction. Using the multipollutant approach, the cost effectiveness is $30 per ton of methane and $100 per ton of VOC. These cost effectiveness values are well within the range considered reasonable by the EPA. As discussed above, while flares significantly reduce the methane and VOC emissions, there are CO, CO2, and NOX emissions resulting from the combustion of the associated gas. We estimate that for the representative well, the annual emissions resulting from the flaring of the associated gas would be 50 tpy CO2, 0.1 tpy CO, and 0.03 tpy NOX. While these secondary impacts are not negligible, the EPA notes that emissions from flaring represents over an 80 percent reduction in CO2e emissions as compared to venting. Based on our analysis, we find that the BSER for reducing methane and VOC emissions from associated gas venting at well sites is routing of the associated gas from oil wells to a sales line. In the event that access to a sales line is not available, we are proposing that the gas can be used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, or routed to a flare or other control device that achieves at least a 95 percent reduction in emissions of methane and VOC. We are requesting comment on the affected facility definition and the overall format of the proposed requirements. The EPA is proposing that an associated gas oil well affected facility be each oil well that produces associated gas. The EPA is soliciting comments on how to define ‘‘associated gas’’ or an ‘‘oil well that produces associated gas.’’ The proposed NSPS OOOOb would require that all associated gas be routed to a sales line. In the event that access to a sales line is not available, the proposed NSPS OOOOb would require that the gas can be used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, or routed to a flare or other control device that achieves at least a 95 percent reduction in emissions of methane and VOC. Under this proposal, every oil well that produces associated gas would be an affected facility and therefore, subject to the rule. For those wells where the associated gas is routed to a sales line, the only requirement would be to certify PO 00000 Frm 00130 Fmt 4701 Sfmt 4702 that this is occurring. Wells that use the associated gas as a fuel or for another purpose would be required to document how it is used. If the associated gas is routed to a flare, all of the proposed monitoring, recordkeeping, and reporting requirements would apply. As an alternative, the EPA is soliciting comments on defining the affected facility as each oil well that produces associated gas and does not route the gas to a sales line. This would significantly reduce the number of affected facilities, although the burden for owners and operators that route the gas to a sales line would be similar. While they would not be required under NSPS OOOOb to maintain documentation that the gas is routed to a sales line, they would still need to maintain documentation to prove that the well was not an affected facility. Under this alternative, the proposed rule would require that the gas be used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, or routed to a flare or other control device that achieves at least a 95 percent reduction in emissions of methane and VOC. The EPA’s concern with this alternative is that while we believe that most owners and operators would route the gas to a sales line if there is access, it would not specifically require routing the gas to a sales line. We expect that the cost of a flare, along with the associated monitoring, reporting, and recordkeeping costs, will provide additional incentive for owners and operators to connect to an available sales line. We are requesting comment on how, under this alternative approach, to incentivize owners and operators even more to capture or beneficially use associated gas. The EPA is specifically requesting comment on whether the proposed requirements will incentivize the sale or productive use of captured gas, and if not, other methods that the EPA could use to incentivize or require the sale or productive use instead of flaring. 2. EG OOOOc The EPA evaluated BSER for the control of methane from existing associated gas oil wells that do not route the gas to a sales line or to a process for another beneficial use (designated facilities) and translated the degree of emission limitation achievable through application of the BSER into a proposed presumptive standard for these facilities that essentially mirrors the proposed NSPS OOOOb. First, based on the same criteria and reasoning as explained above, the EPA is proposing to define the designated E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules facilities in the context of those that commenced construction on or before November 15, 2021. Based on information available to the EPA, we did not identify any factors specific to existing sources that would indicate that the EPA should change these definitions as applied to existing sources. As such, for purposes of the emission guidelines, the definition of a designated facility in terms of associated gas oil wells as existing oil wells with associated gas that do not route the gas to a sales line or to a process for another beneficial use. Next, the EPA finds that the control options evaluated for new sources for NSPS OOOOb are appropriate for consideration in the context of existing sources under the EG OOOOc. The EPA finds no reason to evaluate different, or additional, control measures in the context of existing sources because the EPA is unaware of any control measures, or systems of emission reduction, for the venting of associated gas that could be used for existing sources but not for new sources. Next, the methane emission reductions expected to be achieved via application of the control measures identified above for new sources are also expected to be achieved by application of the same control measures to existing sources. The EPA finds no reason to believe that these calculations would differ for existing sources as compared to new sources because the EPA believes that the baseline emissions of an uncontrolled source are the same, or very similar, and the efficiency of the control measures are the same, or very similar, compared to the analysis above. This is also true with respect to the costs, non-air environmental impacts, energy impacts, and technical limitations discussed above for the control options identified. The information presented above regarding the costs related to new sources and the NSPS are also applicable for existing sources. The EPA considers these cost effectiveness values to be reasonable. Since none of the other factors are different for existing sources when compared to the information from discussed above for new sources, the EPA concludes that BSER for existing sources and the proposed presumptive standard for EG OOOOc to be the requirement to route associated gas to a flare or other control device that achieves at least 95 percent control. Related to control option of flaring with legally and practicably enforceable limits at existing oil wells specifically, enhancing monitoring and performance requirements for flares at existing oil wells may be an important emissions VerDate Sep<11>2014 21:29 Nov 12, 2021 Jkt 256001 reduction measure. For those operators who have already installed monitoring capability on their existing flares, the additional investment may be minimal to cover reporting of performance. For those existing oil wells where operators do not have flare monitoring installed, the EPA solicits comment both on the flare performance monitoring technology available and the cost of procuring, installing, operating and maintaining such technology. This could include, but is not limited to, digital pilot light monitors, combustion temperature, gas flow meters, gas chromatography (GC) units, and passive remote monitoring of combustion efficiencies at the flare tip. Similar technologies have been used for flares controlling landfill gas, including automated notifications of flare failure. Additional discussion of control devices, including flares, is included in section XIII.D of this preamble. K. Proposed Standards for Sweetening Units Sulfur dioxide (SO2) standards for onshore sweetening units were first promulgated in 1985 and codified in 40 CFR part 60, subpart LLL (NSPS LLL). In 2012, the EPA reviewed the NSPS for the oil and natural gas sector, and the resulting 2012 NSPS OOOO rule incorporated provisions of NSPS LLL with minor revisions to adapt the NSPS LLL language to NSPS OOOO (77 FR 49489). The incorporated provisions required sweetening unit affected facilities to reduce SO2 emissions via sulfur recovery. The EPA also increased the SO2 emission reduction standard from the subpart LLL requirement for units with a sulfur production rate of at least 5 long tons per day (LT/D) from 99.8 percent to 99.9 percent. This change was based on the reanalysis of the original data used in the NSPS LLL BSER analysis. In 2016, the EPA finalized the NSPS OOOOa rule—which established standards for both methane and VOCs for certain equipment, process and activities across the oil and natural gas sector. The final 2016 NSPS OOOOa rule reaffirmed and included the SO2 emission reduction requirements as specified in the 2012 NSPS OOOO rule (81 FR 35824). The EPA then amended the 2016 NSPS OOOOa rule in 2020 to correct an affected facility definition applicability error in the rule as it pertains to sweetening units. The 2016 NSPS OOOOa rule erroneously limited the applicability of the SO2 standards to sweetening units located at onshore natural gas processing plants. This limitation was not included in NSPS PO 00000 Frm 00131 Fmt 4701 Sfmt 4702 63239 LLL, and no reason was identified as to ‘‘why the extraction of natural gas liquids relates in any way to the SO2 standards such that the standards should only apply to sweetening units located at onshore natural gas processing plants engaged in extraction or fractionation activities’’ (85 FR 57398). Therefore, the 2020 NSPS OOOOa final rule amendments corrected the affected facility description applicability error to correctly define affected facilities as any onshore sweetening unit that processes natural gas produced from either onshore or offshore wells at 40 CFR 60.5365a(g). A sweetening unit refers to a process device that removes H2S and/or CO2 from the sour natural gas stream (40 CFR 60.5430a)—i.e., sweetening units convert H2S in acid gases (i.e., H2S and CO2) that are separated from natural gas by a sweetening process, like amine gas treatment, into elemental sulfur in the Claus process. These units can operate anywhere within the production and processing segments of the oil and natural gas source category, including as stand-alone processing facilities that do not extract or fractionate natural gas liquids from field gas (85 FR 57408, September 15, 2020). An estimated 6,900 tons of SO2 emissions were reported under the National Emissions Inventory (NEI) for Year 2017 304 for Source Classification Code 31000201 (Industrial Processes Oil and Gas Production, Natural Gas Production, Gas Sweetening: Amine Process) and SCC 31000208 (Industrial Processes, Oil and Gas Production, Natural Gas Production, Sulfur Recovery Units). Pursuant to CAA section 111(b)(1)(B), the EPA reviewed the current standards in NSPS OOOOa (including the 2020 revisions) for sweetening units and proposes to determine that they continue to reflect the BSER for reducing SO2 emissions. The EPA has not identified any greater emissions control level than what is currently required under NSPS OOOOa for sweetening unit affected facilities. Therefore, the EPA is proposing to retain/include the current NSPS OOOOa requirements for sweetening units for the control of SO2 emissions from sweetening unit affected facilities in NSPS OOOOb. The proposed NSPS OOOOb maintains the requirement that each sweetening unit that processes natural gas produced from either onshore or offshore wells is an affected facility; as well as each sweetening unit 304 2017 National Emissions Inventory (NEI) Data | US EPA. E:\FR\FM\15NOP2.SGM 15NOP2 63240 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 that processes natural gas followed by a sulfur recovery unit. Units with a sulfur production rate of at least 5 long tons per day must reduce SO2 emissions by 99.9 percent. Compliance with the standard is determined based on initial performance tests and daily reduction efficiency measurements. For affected facilities that have a design capacity less than 2 LT/D of H2S in the acid gas (expressed as sulfur), recordkeeping and reporting requirements are required; however, emissions control requirements are not required. Facilities that produce acid gas that is entirely reinjected into oil/gas-bearing strata or that is otherwise not released to the atmosphere are also not subject to emissions control requirements. XIII. Solicitations for Comment on Additional Emission Sources and Definitions The EPA is considering including additional sources as affected facilities under the proposed NSPS OOOOb and the proposed EG OOOOc. Specifically, the EPA is evaluating the potential for establishing standards applicable to abandoned and unplugged wells, pipeline pigging and related blowdown activities, and tank truck loading operations. While the EPA has assessed these sources based on currently available information, we have determined that we need additional information to evaluate BSER and propose NSPS and EG for these emissions sources. As described below, the EPA is soliciting information to assist in this effort. The EPA is also assessing whether proposed standards that would require 95 percent reduction based on a combustion control device as the BSER (e.g., standards for storage vessels, centrifugal compressors, pneumatic pumps, and associated gas that cannot be routed to a sales line or consumed for a useful purpose) could be further strengthened, including the potential for additional monitoring and associated recordkeeping and reporting requirements, to ensure proper design and operation of combustion control devices. While we are not proposing NSPS nor EG for these emissions sources (i.e., abandoned wells, pigging operations, or tank truck loading) or updates to ensure proper design and operation of combustion control devices in this action, the EPA is soliciting comment and information that would better inform the EPA as we continue to evaluate options for these sources. Should the EPA receive information through the public comment process that would help the Agency evaluate VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 BSER for these emission sources, the EPA could consider NSPS and EG for these sources through a supplemental proposal. In this section we summarize the available information that we have evaluated regarding emissions, control options, and where specific States may have existing requirements, and we solicit specific comments. In the case of combustion control devices, we solicit comment on the current standard of 95 percent reduction and what additional monitoring, recordkeeping, and reporting may be appropriate to ensure compliance. We also generally solicit comment and information on the following topics associated with these emission sources. The EPA solicits comment on the control options discussed below and how these controls may be broadly applied across different basins or geographic areas. The EPA solicits comment on what equipment is onsite during these emission events. The EPA solicits comment on the technical feasibility of control options and any instances where it is not technically feasible to minimize emissions from these sources including, but not limited to, any retrofit concerns for existing sources. The EPA solicits comment on any practices owners and operators already implement as part of voluntary efforts or State requirements to minimize emissions from these sources. The EPA solicits comment on methods/ approaches for estimating baseline emissions from these sources, estimating cost of control, and efficiency of control options. Finally, the EPA solicits comment on the cost of maintaining records and submitting reports for these emissions sources, including the types of records that are appropriate to maintain and report. A. Abandoned Wells The EPA is soliciting comment for potential NSPS and EG to address issues with emissions from abandoned, or nonproducing oil and natural gas wells that are not plugged or are plugged ineffectively. Should the EPA receive information through the public comment process that would help the Agency evaluate BSER, the EPA may propose NSPS and EG through a supplemental proposal. The EPA broadly characterizes abandoned wells as oil or natural gas wells that have been taken out of production, which may include a wide range of non-producing wells. This includes wells that State governments classify as idle, inactive, dormant, or shut-in, but not plugged. The classification varies from State to State, and State governments may allow these PO 00000 Frm 00132 Fmt 4701 Sfmt 4702 wells to be dormant, without plugging, for varying time periods that may last several years. It also includes wells with no production for many years— sometimes more than a decade—and no responsible operator. These wells are commonly referred to as orphaned, deserted, or long-term idle. Finally, this includes wells that have been abandoned for long periods, known as legacy wells. State governments have varied definitions of temporarily idled, orphaned, or non-producing wells. It is the EPA’s understanding that since non-producing oil and natural gas wells generally are not staffed and are seldom monitored, many have fallen into disrepair. The EPA recognizes that some States and NGOs also have elevated concerns about the potential number of low-production wells that could be abandoned in the near future as they reach the end of their productive lives. The 2021 GHGI estimates that in 2019 the U.S. population of abandoned wells (including orphaned wells and other non-producing wells) is around 3.4 million (about 2.7 million abandoned oil wells and 0.6 million abandoned natural gas wells).305 These non-producing wells often have methane, CO2, and VOC emissions. The most recent studies of emissions from abandoned wells focus on methane emissions, which are larger than the CO2 or VOC emissions from such wells.306 The GHGI estimates that abandoned oil wells emitted 209 kt of methane and 4 kt of CO2 in 2019. While emissions of both pollutants from abandoned oil wells decreased by 10 percent from 1990, the total population of these wells increased 28 percent. The GHGI estimates that abandoned gas wells emitted 55 kt of methane and 2 kt of CO2 in 2019. While emissions of both pollutants increased from abandoned gas wells by 38 percent from 1990, the total population of such wells increased 84 percent. The large populations of abandoned unplugged wells are likely due to various circumstances. For instance, some operators declare bankruptcy before wells are plugged, and for many, bonding requirements represent only a fraction of the actual costs to plug the well and restore the well site. Wells are also abandoned or idled when changing oil or natural gas prices make them unprofitable to continue production. 305 The GHGI separates non-producing oil and gas wells into those that are unplugged and plugged. The abandoned wells identified in the GHGI include those that have been taken out of production temporarily, but can return to production, as well as orphan wells. 306 See TSD at Docket ID No. EPA–HQ–OAR– 2021–0317. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules The EPA recognizes that many oil and natural gas producing States require the plugging of non-producing oil and natural gas wells, and subsequent restoration of the well site. However, the large number of abandoned, unplugged wells nationwide suggests that Federal standards may be warranted. Many oil and gas producing States specify the time in which wells may remain in idle status without State approval. At the end of that time, States generally require tests of well integrity before giving approval for additional time in this idle status. In its 2018 survey of idled and abandoned wells, the IOGCC documented State definitions and requirements for idled wells, as well as the management plans for those wells.307 There is variation in how States define these idle wells, ranging from no definitions to specific definitions for documented and undocumented orphaned and abandoned wells. Further, there is great variability in the allowance for the length of time a well may remain in idle status with or without approval, with some States limiting that time to a few months while other States allow idled status indefinitely. While some States require strict management plans of idled wells, others do not. Finally, some States provide funds for plugging, remediating, and reclaiming orphan wells, and others do not. These funds are supported by civil penalties, settlements, forfeited bonds, and State appropriations. The IOGCC’s survey found that 28 States and Canadian provinces have wells approved to remain in idle status, with most having between 100 and 10,000 approved idle wells. Most States and provinces maintain inventories of documented orphan wells and prioritize orphan wells for plugging according to risk. States and provinces reported from zero to 13,266 documented orphan wells, with about half reporting fewer than 100 orphan wells. The IOGCC’s 2018 survey also collected estimates from some States on the number of undocumented orphan wells, including those for which no permits or other records exist. Most of these wells were drilled before there was any regulatory oversight. Ten States reported no undocumented orphan wells. Nine other States did not provide an estimate. Eleven States provided an estimate ranging from fewer than 10 to 100,000 or more undocumented orphan wells. Most of the States surveyed by the IOGCC had established funds 307 See IOGCC Report located at Docket ID No. EPA–HQ–OAR–2021–0317. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 dedicated to plugging orphan wells. Money for these funds comes primarily from taxes, fees, or other assessments on the oil and gas industry. The EPA has identified the following potential strategies to reduce air emissions from these sources. The first strategy is to employ practices and procedures to ensure proper well closure. Under this strategy, the EPA could focus on well closure requirements aimed at preventing future abandonment of unplugged wells and halt the growth of this unplugged population. Given that all wells eventually reach their end of life, this strategy could be applied to both new and existing wells. Under the NSPS, for example, the EPA could require owners or operators to submit a closure plan describing when and how the well would be closed and to demonstrate whether the owner or operator has the financial capacity to continue to demonstrate compliance with the rules until the well is closed and to carry out any required closure procedures per the rule. This demonstration could require some financial assurance or bonding if the Agency determines the financial capacity of the owner or operator to continue to assure compliance with the rule is in doubt. The EPA also could require reporting any transfer of well ownership, along with a copy of the well closure requirements, to the EPA and/or the applicable State when transferring ownership. The Agency might also consider a requirement to temporarily close the well to the atmosphere with a swedge and valve or packer or other approved method once a well is temporarily abandoned or shut in. As one example, this is a requirement under Colorado law for all wells that are designated as shut in or temporarily abandoned.308 The primary purpose of detailing financial capacity as part of a compliance plan, and to potentially require some financial assurance bonding, is to ensure that State governments have adequate resources to plug oil and gas wells when the owner or operator is unwilling or unable to do so. The IOGCC notes that States typically have requirements for both single-well or blanket financial assurance. In the IOGCC’s 2018 survey, 35 States reported information on the types of financial assurance accepted in their jurisdictions, with most accepting more than one type. The IOGCC noted that the amounts and criteria for bonding vary considerably among the 308 Code of Colorado Regulations, Oil and Gas Conservation Commission, 2 CCR 404–1, paragraph b, ‘‘Temporary Abandonment,’’ p. 80. PO 00000 Frm 00133 Fmt 4701 Sfmt 4702 63241 States. Single-well bond amounts range from $1,500 to $500,000 per well; blanket bonds (covering multiple wells) vary from $7,500 to $30,000,000, the IOGCC said. In some States, bond amounts are based on well depth; in others, bond amounts are based on caseby-case evaluations; and in several, bond amounts may be increased if determined necessary. That study identified the following types of financial assurance, including cash deposit of a payment given as a guarantee that an obligation will be met, certificate of deposit of a financial instrument certifying that the face amount is on deposit with the issuing bank to be redeemed for cash by the State if required, financial statements of a report of basic accounting data that depicts a firm’s financial history and activities, letter of credit, irrevocable letter of credit where payment is guaranteed if stipulated conditions are met, security interest giving the right to take property or a portion of property offered as security, and surety or performance bonds as a contract by which one party agrees to make payment on the default or debt of another party. Other forms of financial assurance include certificates of insurance, consolidated financial funds, escrow accounts, and liens. The amounts and criteria for financial assurance vary considerably among the States and provinces. Another strategy under consideration is to require fugitive emissions monitoring at a specified frequency for the duration of time the well is idled and unplugged. The EPA’s understanding, however, is that most idled and non-producing well sites would be classified as wellhead only sites, which the EPA is proposing to exclude from fugitive emissions monitoring for both new and existing well sites (see section XI.A). The EPA is aware that other Federal agencies have information on, and experience with, abandoned wells, such as the U.S. Forest Service, National Park Service, U.S. Fish and Wildlife Service, and the BLM. On Federal and Tribal mineral estate, the BLM coordinates with the surface management agency when remediating abandoned wells to mitigate the potential risks those wells may pose. The EPA may be informed by the methods employed by the BLM to monitor and remediate abandoned wells on Federal lands, as well as by draft legislative initiatives that may expand the scope of the BLM’s efforts. The EPA understands that one such initiative, the ‘‘Revive Economic Growth and Reclaim Orphaned Wells (REGROW) Act,’’ could amend the Energy Policy Act of 2005 to E:\FR\FM\15NOP2.SGM 15NOP2 63242 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 require the BLM to establish a new program to plug, remediate, and reclaim orphaned oil and gas wells and surrounding land, and to provide funds to State and Tribal governments for this purpose.309 The EPA is soliciting additional information that would support a determination of the BSER to address emissions from abandoned, idled, and non-producing wells. The specific information of interest includes updates to the number of abandoned, orphaned, or temporarily idled wells in the U.S., which could be State-specific or basinspecific; fugitive emission estimates for the wells; and costs of mitigation measures, including effective closure requirements and proper plugging practices, financial assurance mechanisms, and requiring fugitive emissions monitoring while in idled and unplugged status. The EPA is also soliciting information on mechanisms to disincentivize operator delay in permanently abandoning wells and/or transfer of late-life assets to companies that may not be well-positioned to fund proper closure. The EPA also solicits information at the State level, on the length of time that wells remain temporarily idled before they must be inspected by State governments. Further, we are seeking information about what would be included in well closure requirements, including what closure requirements are appropriate and any recordkeeping and reporting associated with those requirements, as well as whether it is appropriate to close the well to the atmosphere once it is designated as shut in or temporarily abandoned. The EPA also solicits information on whether compliance assurance for well closure requirements will necessitate certain forms of financial assurance on the part of well owners and operators. The EPA solicits comment on effective plugging, such as criteria or guidelines are necessary for sufficient plugging and post-plugging follow up monitoring necessary over a certain time period. Finally, the EPA solicits comments on the cost of monitoring idled or abandoned wells or monitoring techniques that might lower the costs of such monitoring. 309 S. 1076, ‘‘To amend the Energy Policy Act of 2005 to require the Secretary of the Interior to establish a program to plug, remediate, and reclaim orphaned oil and gas wells and surrounding land, to provide funds to State and Tribal governments to plug, remediate, and reclaim orphaned oil and gas wells and surrounding land, and for other purposes,’’ 117th Congress, 1st Session, as introduced on April 12, 2021, available at https:// www.congress.gov/117/bills/s1076/BILLS117s1076is.xml. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 B. Pigging Operations and Related Blowdown Activities The EPA is soliciting comment for potential NSPS and EG under consideration that include addressing emissions from pipeline pigging and related blowdown activities. Should the EPA receive information through the public comment process that would help the Agency evaluate BSER, the EPA may propose NSPS and EG through a supplemental proposal. Raw natural gas is transported from production wells to natural gas processing plants through networks of gathering pipelines. After natural gas processing, pipeline networks in the transmission and storage segment transport the gas to downstream customers. Raw natural gas is frequently saturated with hydrocarbons and may contain other components such as water, carbon dioxide, and hydrogen sulfide, especially upstream of the natural gas processing plant. Liquid condensates can accumulate in low elevation segments of the gathering pipelines, impeding the flow of natural gas. To maintain gas flow and operational integrity of the gathering pipelines, operators mechanically push these condensates out of the low elevations and down the pipeline by an operation called ‘‘pigging,’’ which involves first inserting a device called a pig 310 into a pig launcher upstream of the pipeline segment where condensates have accumulated. The natural gas flowing through the pipeline then pushes the pig through the pipeline, allowing the pig to sweep along the accumulated condensates. The pig is removed from the pipeline segment when it is caught in a pig receiver. Pigging operations are also conducted using ‘‘smart’’ pigs that are equipped with sensors to collect data about the pipeline’s structural characteristics and integrity for safety and maintenance purposes. Before a pig can be inserted or removed through the hatch of a pig launcher or a pig receiver, the pipeline gas in the launcher or receiver barrel must be removed. It is common practice to vent the gas directly to the atmosphere where gas capture or control are not used. This gas is under the same pressure as the pipeline and contains methane, ethane, and VOCs including HAP such as benzene, toluene, ethylbenzene, and xylene. Emissions can also result from the volatilization of collected condensate liquid when the pig barrel is depressurized. 310 Pigs are typically spherical, barrel- or bulletshaped objects slightly smaller than the diameter of the pipeline. PO 00000 Frm 00134 Fmt 4701 Sfmt 4702 Pig launchers and receivers can be installed within larger facilities, such as at a compressor station or natural gas processing plant, or can be ‘‘standalone’’ sites, where the only equipment at a particular location is related to pigging operations. Additionally, sections of pipeline or equipment that are separate from the pig launcher or receiver may need to be evacuated of gas for reasons other than pigging, such as routine maintenance or inspection activities. Emissions from blowdowns can be calculated by accounting for the volume of the section of pipeline or equipment being evacuated, composition of that gas being vented, pressure of the gas vented, frequency of the blowdown activity, and inclusion of emissions from any volatile liquids present in the pipeline section or equipment being vented. The EPA is aware of some State and local governments have regulations in place that address blowdown activities, including pigging. These include limits on the amount of emissions from pigging operations, required use of addon controls, and implementation of best management practices.311 Estimating emissions from pigging operations is fairly straightforward if all variables (e.g., volume, pressure, and composition of gas) are known. However, the wide range of variables, which are applied in different combinations and are dependent on the frequency of blowdown events, can make it challenging to estimate total nationwide emissions from pigging and related blowdown activities. For example, in 2019, six of the eight operators reporting to GHGRP subpart W in the Uinta Basin reported a collective 7,299 blowdown events due to pigging that met the threshold for reporting under GHGRP subpart W, but the attribution of emissions from each individual pigging event is undetermined at this time.312 Data reported in 2019 under GHGRP subpart W include 472,995 total individual blowdown events from 1,212 facilities for a combined 307,630 metric tons of methane emitted, including 79,746 events at pig launchers or receivers for a combined total of 19,066 metric tons of methane, however, these data only include emissions from blowdown equipment with a unique physical volume greater than 50 cubic feet and occurring at a facility with total emissions greater than 25,000 metric 311 See TSD located at Docket ID No. EPA–HQ– OAR–2021–0317. 312 EPA (2020) Greenhouse Gas Reporting Program. U.S. Environmental Protection Agency. Data reported as of September 26, 2020. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules tons CO2 Eq.313 The EPA is also aware of a single operator in the Marcellus Shale region that operates around 400 pig launchers and receivers which collectively emit approximately 1,335 metric tons of methane annually, but the total annual emissions from each launcher or receiver varies widely, due to variations in the inputs used to calculate emissions from an individual pigging event.314 The EPA is seeking comment on the availability of nationwide data sets or methodologies to better identify the total inventory of pig launchers and receivers, and, if no such data set or proxy exists, comment on the most defensible method of calculating total emissions from pigging and related blowdown activities. The EPA has identified the following potential control options that can reduce emissions from pipeline pig launchers and receivers: (1) Reducing the frequency that the pig launcher or receiver must be evacuated of gas; (2) eliminating or reducing the volume of gas vented during blowdowns; (3) using add-on controls that are applied to blowdown emissions; or (4) a combination of these strategies. The EPA has identified the following systems as potential control strategies to evaluate further. First, pig ball valves are a design alternative to conventional pig launcher and receiver systems that have a smaller sized barrel (or chamber) that launches and receives the pig, thus resulting in reduced emissions from pigging operations. A conventional pig launcher or receiver system can be retrofitted by replacing the conventional launcher and receiver barrels with special ball valves used to insert and remove the pig directly from the main pipeline. By replacing the large volume barrel with the much smaller volume ball valve, the volume of gas vented during each pigging operation can be reduced by as much as 80 to 95 percent, with a corresponding reduction in emissions and other risks associated with pipeline pigging operations. The net cost of a pig ball valve compared to a traditional launcher/receiver should consider not only the cost of the valve and its installation, but also the savings realized from the prevention of large quantities of vented gas and personnel time spent blowing down a larger launcher/receiver. These costs and savings will vary according to sitespecific dimensions, gas composition, and pigging frequency. The EPA understands that not every dimension of 313 Id. 314 See Appendix A to the TSD located at Docket ID No. EPA–HQ–OAR–2021–0317. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 pipeline and pig launcher or receiver can use a pig ball valve and seeks further comment on specific circumstances where such equipment is appropriate, potential challenges to using a pig ball valve or retrofitting a launcher or receiver to accommodate a pig ball valve, and specific costs of installing or retrofitting a launcher or receiver compared to a conventional full-barrel launcher or receiver. Second, multi-pig launcher systems are a design alternative to conventional launcher/receiver systems and reduce pigging emissions by reducing the frequency that launchers and receivers must be opened to the atmosphere and vented prior to pig insertion and removal. The launcher barrel is designed to hold multiple spherical pigs, which are each held in place by gates or pins prior to release. Emission reductions are approximately proportional to the reduction in frequency of opening the launcher and receiver hatch. For example, if a pig launcher holds six pigs, which are loaded all at once, the frequency of venting of the pig barrel is reduced to one-sixth of what it would have been if each pig were loaded individually. The EPA understands that multi-pig launchers and receivers are most appropriate for large diameter pipelines where the footprint of the launcher or receiver site is large enough to accommodate such a system. The EPA seeks comment on specific circumstances where such equipment is appropriate, and requests information on emission reductions and specific costs and savings of installing or retrofitting and operating a multi-pig launcher or receiver compared to a conventional single-pig launcher or receiver. Next, there are several liquids management technologies that focus on reducing emissions from the liquid condensate that is collected during pigging operations. The first technology relates to the design of condensate drains on receiver barrels. Drains can be installed in the bottom of receiver barrels and pig ball valves to ensure that all condensate is drained from the system prior to depressurization. These drains generally route the condensate back into the main pipelines, to onsite storage tanks, or to onsite processes via enclosed piping and can be retrofitted to existing systems. Recovering condensate prevents emissions that would occur when the liquids volatilize during depressurization of the pig receiver. The EPA seeks comment on different configurations of condensate drains, how the recovered condensate is routed and managed, limitations on using this PO 00000 Frm 00135 Fmt 4701 Sfmt 4702 63243 technology, and data showing the amount of condensate recovered and associated emissions prevented. The second liquids management technology is a pig ramp on a receiver barrel. A pig ramp 315 is a simple device that can be installed inside a receiver barrel to allow liquids trapped in front of the pig to be captured and to allow liquids clinging to the pig itself to drain before the pig is pulled from the chamber. Pig ramps are typically used in conjunction with condensate drains. The pig ramp promotes the flow of liquid through the barrel and into the drain line by elevating the pig on a racklike apparatus within the receiver barrel, thereby preventing the pig from creating blockages in the receiver. By promoting the flow of liquid to a location within the receiver or pipeline where the liquids can be captured and drained prior to depressurization, pig ramps reduce the amount of condensed VOCs that would otherwise volatilize during depressurization and removal of the pig from the receiver, thereby reducing emissions. The EPA seeks comment on the successful installation and use of pig ramps as well as information on cost, emission reductions, and concerns or challenges that may make the use of pig ramps inappropriate. The third liquids management technology involves enhanced liquids containment. If recovered condensate cannot be routed back to the pipeline or to controlled storage vessels, covering containers that collect liquids remaining in a receiver barrel after depressurization with a fitted impermeable material will reduce emissions from evaporation. However, whether or not this strategy will ultimately reduce emissions depends on how the recovered condensate is actually managed. The EPA seeks comment on how recovered condensate can be managed to ensure that emissions from the volatilization of the liquids is minimized, thereby achieving emissions reductions. Lastly, the EPA has identified several additional control options that can be employed to reduce emissions. First, an owner or operator could install ‘‘jumper lines’’ that allow routing high pressure systems to lower pressure systems. The depressurization emissions from high pressure launchers and receivers can be reduced by routing the high-pressure gases to a lower pressure system before venting the remaining gases to the atmosphere or to control equipment. 315 https://www.mplx.com/content/documents/ mplx/markwest/Launcher%20Receiver%20 Design%20Detail.pdf. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63244 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules Routing to a lower pressure system is achieved with a depressurization line (or jumper line) exiting the top of the barrel, or exiting the top of the pig ball valve, and connecting to nearby lowpressure lines on site. Compressor stations and gas plants have low pressure lines on the site that typically can receive these depressurized gases and recycle them through the process. Similarly, launchers and receivers along high pressure pipelines are occasionally located near low pressure pipelines that can receive depressurized gases exiting the barrel or pig ball valve. The EPA seeks comment on the universe of sites where jumper lines are feasible to install, as well as information on cost, emission reductions, and comment on implementation successes and challenges. Second, owners and operators can route low-pressure systems into a fuel gas system or VRU. Gases that remain in high pressure barrels after venting to low pressure systems, and gases in low pressure barrels, can be recovered during depressurization by discharging the gases to very low-pressure systems at the site (e.g., 10–15 psig). Two examples of very low-pressure systems at compressor stations are a fuel gas system and a condensate tank VRU. Applying such an approach can reduce the gas pressure in the barrels to the pressure of the very low-pressure system, with a corresponding reduction in depressurization emissions. The feasibility of this option is contingent upon the presence of such equipment already onsite. The EPA seeks comment on the universe of sites where routing gas to low-pressure systems is feasible, as well as information on cost, emission reductions, and comment on implementation successes and challenges. Third, owners and operators can utilize barrel pump-down systems. In barrel pump-down systems, small fixed or portable compressors are used to pump vapors in the receiver or a launcher barrel back into the main pipeline prior to venting and opening the barrel hatch. In barrel pump-down systems, the inlet of a gas compressor is connected to the receiver or launcher depressurization line, and the compressor discharge is connected into the main pipeline. Vapors exiting the depressurization line are pulled into the compression system and recovered back into the pipeline at system pressure. These control systems can recover greater than 99 percent of the depressurization vapors from pig launchers and receivers. The EPA seeks comment on the universe of sites where barrel pump-down systems are feasible, VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 as well as information on cost, emission reductions, and comment on implementation successes and challenges. Finally, owners and operators could route depressurization gases to combustion devices to control emissions from pigging operations. Depressurization gases from barrels and pig ball valves can be routed through the depressurization line to onsite combustion devices. Well-designed and operated combustion devices can achieve vapor destruction efficiencies as high as 95 to 98 percent. Combustion devices can be used in conjunction with engineering solutions discussed above that first reduce accumulation of or recover as much natural gas and condensate as possible, before destroying the remaining vapors in the combustion device. An example would be to route high pressure systems to low pressure lines and drain barrel condensate, then route the remaining vapors to a combustion device. The EPA understands that large, high-capacity combustion devices are typically available at compressor stations and processing plants and can be used to control pigging gases while meeting the other flaring needs of the facility. There are also numerous low-capacity combustion devices available for serving remote launcher/receiver sites. The EPA seeks comment on the universe of sites where routing depressurization gases from pigging operations to a combustion device is feasible, as well as information on cost, emission reductions, and comment on implementation successes and challenges. In addition to those methods already identified above for reducing emissions from pigging and related blowdown activities, the EPA is seeking comment on other existing technologies and work practices to reduce the need for blowdown events or reduce emissions from blowdown events when they occur. The EPA is specifically interested in the costs of such technologies or work practices and any variables impacting cost, the control efficiency of the technology or work practice and variables affecting efficiency, and any technological or logistical limitations to implementing the technology or work practice. While blowdown emissions due to pigging are the primary area where the EPA seeks comment, the EPA is aware that planned blowdowns occur for many reasons, typically related to maintenance or inspection activities. Planned blowdowns may occur at facilities such as a gas processing plant, compressor station, well pad, or standalone pig launcher and receiver station, PO 00000 Frm 00136 Fmt 4701 Sfmt 4702 but may also occur at locations other than these facilities, including along pipelines. Under GHGRP subpart W, blowdown vent stack equipment or event types are grouped into the following seven categories: Facility piping (i.e., piping within the facility boundary), pipeline venting (i.e., physical volumes associated with pipelines vented within the facility boundary), compressors, scrubbers/ strainers, pig launchers and receivers, emergency shutdowns (this category includes emergency shutdown blowdown emissions regardless of equipment type), and all other equipment with a physical volume greater than or equal to 50 cubic feet.316 The EPA seeks comment on any substantive differences between pigging blowdowns and other types of planned blowdowns. Further, the EPA is soliciting comment on how to define an affected facility that includes these blowdown activities, and specific limitations (e.g., technical or logistical) to including non-pigging-related types of blowdowns as part of affected facilities. In particular, the EPA is considering whether the pipeline itself could be defined as an affected facility for purposes of regulating blowdowns. In this scenario, the owner or operator of the pipeline would be responsible for complying with any requirements in place for blowdown activities that occur anywhere along the pipeline. The EPA is soliciting comment on any potential concerns this type of approach would raise for owners and operators, particularly where pipelines cross State boundaries or at the location where pipeline ownership may change from the upstream owner to a different downstream owner. C. Tank Truck Loading The EPA is considering including emission standards and EG for tank truck loading operations; however, additional information is needed to evaluate BSER and propose NSPS or EG for this emissions source. The EPA is therefore soliciting comment on adding tank truck loading operations as an affected facility in both the NSPS and EG. Depending on the information received through the public comment process, the EPA may propose NSPS and EG for this source through a supplemental proposal. In this section we summarize the available information we have reviewed for this emissions source and potential control options. Tank truck loading operations result in emissions when organic vapors in empty tank trucks are displaced to the 316 40 E:\FR\FM\15NOP2.SGM CFR 98.233(i)(2). 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 atmosphere as crude oil, condensate, intermediate hydrocarbon liquids, or produced water from storage vessels is loaded into the tank trucks.317 Tank truck loading emissions are the primary source of evaporative emissions from tank trucks. It is the EPA’s understanding that these vapors are a composite of vapors formed in the empty tank truck by evaporation of residual materials from previous loads, vapors transferred to the tank truck in vapor balance systems as materials are being unloaded, and vapors generated in the tank truck as new material is being loaded. Further, the quantity of evaporative losses from loading operations is, therefore, a function of the parameters such as the physical and chemical characteristics of the crude oil, condensate, intermediate hydrocarbon liquids, or produced water; the method of unloading the crude oil, condensate, intermediate hydrocarbon liquids, or produced water from the storage vessel into the tank truck; and the operations to transport the empty tank truck offsite. The composition of evaporative losses includes VOC, methane, and some HAP. According to the 2017 NEI, VOC emissions from tank truck loading operations were approximately 72,448 tpy, of which over 70,990 tpy were emitted in the crude oil and natural gas production segment, with the balance of approximately 1,457 tpy emitted from the natural gas processing segment. According to the Oklahoma loading losses guidance, 318 a loading loss vapor VOC content of 85 percent by weight (i.e., 15 percent by weight methane and ethane) may be assumed at wellhead facilities. Condensate and crude oil being loaded at a facility other than a wellhead facility may assume a vapor VOC content of 100 percent. Applying these compositions to the emissions in the 2017 NEI results in approximately 12,528 tpy methane at well sites and 1,457 tpy methane from other segments. According to EIA, the contiguous continental states area comprising of 48 States have a six year daily average condensate production (API gravity greater than or equal to 50) 319 of 911,000 bbls/day.320 Emissions per 317 Section 5.2.2.1.1 of the AP–42 Section 5.2: Transportation and Marketing of Petroleum Liquids https://www.epa.gov/sites/default/files/2020-09/ documents/5.2_transportation_and_marketing_of_ petroleum_liquids.pdf. 318 See https://www.deq.ok.gov/wp-content/ uploads/deqmainresources/LoadingLosses Guidance_08-2019.pdf. 319 See https://glossary.oilfield.slb.com/en/terms/ c/condensate. 320 See https://www.eia.gov/dnav/pet/pet_crd_api_ adc_mbblpd_m.htm and TSD located at Docket ID No. EPA–OAR–HQ–2021–0317. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 barrel of liquids loaded into tank trucks may be estimated at 0.43lb VOC/bbl. It is the EPA’s understanding that most sites use tank trucks with a capacity of approximately 130 bbl. The EPA solicits comment on whether API gravity greater than or equal to 50 is the appropriate gravity of condensate to use. The EPA understands that there are three options generally in use for controlling emissions during the tank truck loading process. The first control option is vapor balancing which is used to route the vapors displaced during material loading from the tank truck back to the storage vessel. Vapor balancing requires a vapor capture line to connect the tank truck to the storage vessel or manifold system of a tank battery. Because vapor balancing is a closed system, the only anticipated emissions from this control option would be fugitive in nature. However, emissions may occur from the tank truck if it is not properly maintained to DOT specifications, or when the tank truck is cleaned or reloaded without control off-site. Vapor balancing does not have any secondary air impacts or energy requirements. We estimate the capital cost associated with a vapor balancing loading arm (equipment associated with a capture line to connect the tank truck to the storage vessel) at about $5000 per arm based on limited available information. The second control option is use of a closed vent system operating with a reduction efficiency of 95 to 99 percent. A vapor capture system is used and routed to a vapor recovery device (VRD) or VRU which uses refrigeration, absorption, adsorption, and/or compression. The recovered liquid product is piped back to storage. Alternatively, the vapors may be collected via a vapor capture system and routed to an on-site thermal oxidizer or flare. It is possible to route emissions from this closed vent system to an existing control device located on-site for another purpose. The EPA recognizes that this option may have secondary impacts dependent on the type of control chosen (e.g., VRU, VRD, or combustion device). Finally, the third option is to directly pipe liquids downstream. By directly piping liquids downstream, no emissions from tank truck loading are released to the atmosphere. We are not aware of any secondary impacts or energy costs associated with this option. However, the EPA is also unsure if this option is technically feasible for every site. It is our understanding that this option requires access to pipelines that can transport the crude oil and/or condensate to downstream locations, PO 00000 Frm 00137 Fmt 4701 Sfmt 4702 63245 and availability of pipelines or capacity to move these liquids in existing pipelines may present an issue with requiring this option for all sites. In addition to these three control options, the EPA has also identified work practices related to the method of loading which are important and play a role in minimizing air emissions. Practices such as submerged fill and bottom loading help reduce emissions when the fill pipe opening is below the liquid surface level which reduces liquid turbulence and results in much lower vapor generation than encountered during splash (top) loading. We estimate the capital costs of submerged fill loading arms are approximately $1,500 per arm based on limited available data at this time. The EPA is soliciting comment on the three control options and work practices presented in this section to control or reduce emissions resulting from the tank truck loading process. We solicit comment on other control options or other work practice standards similar to those used in other sectors such as petroleum refineries and how appropriate those options may be for the Crude Oil and Natural Gas source category. We solicit comment on how widely used the control measure and work practices are, any feasibility challenges, and estimates of baseline emissions and cost information associated with these control options and work practices. The EPA is aware of several State regulations that have established standards for this emissions source.321 Finally, the EPA solicits comment on any practices owners and operators already implement as part of voluntary efforts or State requirements to minimize emissions from these sources. D. Control Device Efficiency and Operation As discussed above in sections XI.B, F, and G and XII.B, F, and G, the EPA is proposing to retain the 95 percent reduction performance standard for storage vessels, wet seal centrifugal compressors, and pneumatic pumps based on our analysis showing that a combustion control device remains the BSER for these affected facilities and can reliably achieve this performance standard. This 95 percent reduction is generally achieved by capturing the emissions in a closed vent system that routes those emission to either a control device or back to the process. Under the 2016 NSPS OOOOa, as amended by the 2020 Technical Rule with further 321 See TSD located at Docket ID No. EPA–OAR– HQ–2021–0317. E:\FR\FM\15NOP2.SGM 15NOP2 63246 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 amendments proposed in this action, closed vent systems must be designed and operated with no detectable emissions, which is defined as either no emissions detected greater than 500 ppm above background with EPA Method 21, no emissions detected with OGI, or no audible, visual, or olfactory emissions detected. Thus, for a closed vent system, the assumed control efficiency is 100 percent. Therefore, any control device used must be designed and operated to achieve at least 95 percent reduction of emissions to comply with the standard. Examples of control devices include flares, thermal oxidizers, catalytic oxidizers, enclosed combustion devices, carbon adsorption systems, condensers, and VRUs. However, there are various data sources available that suggest combustion control devices, which we have again identified as the BSER for these affected facilities, can achieve a continuous destruction efficiency of 98 percent.322 Therefore, the EPA is soliciting comment on potentially proposing a change in the standards for wet seal centrifugal compressors, storage vessels, and pneumatic pumps that would require 98 percent reduction of methane and VOC emissions from these affected facilities. It is the EPA’s understanding that combustion control devices, such as flares and enclosed combustion devices, may achieve at least 98 percent control of all organic compounds. Further, as noted in AP–42 Chapter 13.5, properly operated flares achieve at least 98 percent destruction efficiency in the flare plume in normal operating conditions.323 However, the EPA has received some data 324 relevant to the use of these controls at oil and gas facilities that indicates air-assisted and steam-assisted flares have been found operating outside of the conditions necessary to achieve at least 98 percent control efficiency on a continuous basis. Therefore, the EPA is soliciting comment and information that would help us better understand the cost, 322 Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution. Background Supplemental Technical Support Document for the Final New Source Performance Standards; EPA–HQ–OAR–2010–0505–7631, pp. 19–20. 323 https://www.epa.gov/sites/default/files/202010/documents/13.5_industrial_flares.pdf. 324 ‘‘Intermittency of Large Methane Emitters in the Permian Basin’’ Daniel H. Cusworth, et al. Environmental Science & Technology Letters 2021 8 (7), 567–573 DOI: 10.1021/acs.estlett.1c00173; and Irakulis-Loitxate, I., Guanter, L., Liu, Y.N., Varon, D.J., Maasakkers, J.D., Zhang, Y., Lyon, D., . . . & Jacob, D. J. (2021). Satellite-based characterization of methane point sources in the Permian Basin (No. EGU21–15877). Copernicus Meetings. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 feasibility, and emission reduction benefits associated with establishing a 98 percent control efficiency requirement for flares in the Crude Oil and Natural Gas source category, including information on the level of performance being achieved in practice by flares in the field, what conditions or factors contribute to malfunctions or poor performance at these flares, and what measures the EPA could or should require in order to ensure that flares perform at a 98 percent level of control. The EPA also requests comment on whether additional measures to ensure proper performance of flares would be appropriate to ensure that flares meet the current 95 percent control requirement. For example, the EPA is soliciting comment on the specific requirements that could be used to demonstrate continuous compliance when using a combustion control device. In its July 8, 2021, report, the Office of Inspector General (OIG) 325 observed that State permitting authorities had difficulty verifying continuous compliance with combustion efficiency requirements for flares and enclosed combustors. The OIG recommended that the EPA explore additional means to verify continuous compliance in NSPS OOOO and NSPS OOOOa that would provide additional tools for State agencies to properly permit and enforce combustion efficiency. In considering this recommendation, the EPA has determined that additional information is necessary to support the development of cost-effective continuous compliance requirements. The current standards in NSPS OOOO and NSPS OOOOa require owners and operators to perform an initial demonstration of compliance for all control devices used to meet the standards in the rule. Further, NSPS OOOO and NSPS OOOOa require monthly EPA Method 22 observations to demonstrate continuous compliance with visible emission requirements, in addition to monitoring for the presence of a pilot light. When an enclosed combustion device is used, owners and operators may demonstrate initial compliance through field testing or through manufacturer testing. The EPA maintains a list of devices for which manufacturers have demonstrated compliance with the testing requirements, including achieving a destruction efficiency of at least 95 percent. The devices that have 325 EPA Office of Inspector General Report ‘‘EPA Should Conduct More Oversight of SyntheticMinor-Source Permitting to Assure Permits Adhere to EPA Guidance,’’ Report No. 21–P–0175 July 8, 2021. PO 00000 Frm 00138 Fmt 4701 Sfmt 4702 demonstrated compliance through manufacturer testing have achieved greater than 98 percent destruction efficiency; however, this is demonstrated in a testing environment only, and while the testing is designed to challenge the units, the units may not necessarily demonstrate the same destruction efficiency in field applications. The EPA is seeking comment on alternative means to demonstrate continuous compliance with the required control efficiency (whether maintained at 95 percent or increased to 98 percent). The Petroleum Refinery Sector Standards, 40 CFR part 63, subpart CC, were amended in 2015 (80 FR 75178) to include a series of additional monitoring requirements that ensure flares achieve the required 98 percent control of organic compounds. Previously these flares had been subject to the flare requirements at 40 CFR 60.18 in the part 60 General Provisions. More recently, the updated flare requirements in NESHAP subpart CC have been applied to other source categories in the petrochemical industry, such as ethylene production facilities (40 CFR part 63, subpart YY), to ensure that flares in that source category also achieve the required 98 percent control of organic compounds. These monitoring requirements include continuous monitoring of waste gas flow, composition and/or net heating value of the vent gases being combusted in the flare, assist gas flow, and supplemental gas flow. The data from these monitored parameters are used to ensure the net heat value in the combustion zone is sufficient to achieve good combustion. The monitoring also includes prescriptive requirements for monitoring pilot flames, visible emissions, and maximum permitted velocity. Lastly, where fairly uniform, consistent waste gas compositions are sent to a flare, owners or operators can simplify the monitoring by taking grab samples in lieu of continuously monitoring waste gas composition, and in some instances, engineering calculations can be used to determine flow measurements. While effective, the EPA seeks comment on how appropriate any such monitoring requirements and systems would be for the oil and gas production, gathering and boosting, gas processing, or transmission and storage segments subject to the proposed NSPS OOOOb and EG OOOOc. The EPA seeks comment on how to distinguish among flare units where such monitoring is practical, and alternatives where such systems are not practical because they E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules lack continuous, on-site personnel or do not have the supporting infrastructure. Additionally, the EPA seeks comment on several facets of ongoing compliance, including: (1) Owner or operator experience in determining the proper location of a thermocouple for monitoring the presence of a pilot flame, and how to avoid pilot flame failure; (2) how OGI may be used to identify poor combustion efficiency (e.g., to effectively utilize OGI to qualitatively screen enclosed combustion devices) for additional quantitative testing. As noted in Section XI.A.1 of this preamble, we are proposing that emissions resulting from control devices operating in a manner that is not in full compliance with any Federal rule, State rule, or permit, are also considered fugitive emissions. However, there may be other ways to use OGI beyond seeing these fugitive emissions to determine whether control devices are operating properly. For instance, the EPA is interested in how OGI has been used to evaluate heat signature of gases exiting the top of the stack and/or the presence of any unburned hydrocarbon trailing or advective plumes. With respect to enclosed combustors, the EPA is seeking information on the development of comprehensive specifications for creating an operating envelope under which a make/model can achieve 98 percent reduction (i.e., parameters that should be identified on enclosed combustion device specification sheets), such as maximum heat load, minimum heat load, minimum inlet pressure of waste gas stream, temperature of combustion zone (and proper location for temperature monitor), air intake rate, operation and maintenance necessary for optimal combustion. The EPA also seeks information on real-time monitoring of enclosed combustion device inlet waste gas stream pressure aimed at achieving higher combustion efficiency. The EPA is also soliciting comment on the current use of non-combustion control devices, the practicality of requiring 98 percent reduction through the use of non-combustion control devices, and the monitoring requirements necessary to demonstrate initial and continuous compliance with such control efficiency. NSPS OOOO and NSPS OOOOa require parametric monitoring for condensers, carbon adsorption systems, and similar control devices, to demonstrate continuous compliance. However, the EPA is seeking comment on whether those monitoring requirements are sufficient to assure continuous compliance should the EPA propose a requirement of 98 percent reduction. In addition to VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 monitoring requirements, the EPA is seeking information on what additional records should be maintained and/or reported for demonstrating continuous compliance when non-combustion control devices are used. The EPA is particularly concerned that increasing the level of control from 95 to 98 percent would disincentivize use or potentially force replacement of noncombustion control devices entirely, including those that capture product for reuse in vapor recovery systems. For example, Texas requires additional monitoring and other significant engineering upgrades for a VRU operator to meet a higher control efficiency than 95 percent.326 Adding to this concern is the potential increase in overall costs of the rule and potential increase in emissions where facilities replace non-combustion control devices with combustion control devices. Finally, the EPA is seeking comment on new technologies that would address control efficiency from flares specifically and provide real-time or near real-time measurement of control efficiency. One example would be OGI continuous flame imaging systems that capture flame size and temperature to ensure these parameters are within acceptable ranges. New optical technology is in the early phases of development and deployment. The EPA acknowledges that it may be challenging to analyze costs and reductions without comprehensive data specific to a particular technology, but in the interest of a forward-looking standard, we seek information on potential methods to assure continuous compliance for these control devices. E. Definition of Hydraulic Fracturing During pre-proposal outreach, a number of small businesses stated that the NSPS has unintentionally been applied to conventional and vertical wells that engage in hydraulic fracturing. The small business stakeholders contended that these wells have a very different profile from unconventional or horizontal wells in terms of footprint, water usage, chemical usage, equipment used, and flowback period. They recommended that the EPA explicitly exempt these wells from the proposal. We maintain that the original intent of the NSPS was to regulate hydraulically fractured wells, in both conventional and 326 See Vapor Recovery Unit Capture/Control Guidance located at https://www.tceq.texas.gov/ assets/public/permitting/air/NewSourceReview/ oilgas/vapor-rec-unit.pdf. PO 00000 Frm 00139 Fmt 4701 Sfmt 4702 63247 unconventional reservoirs,327 and both vertical and horizontal wells.328 NSPS OOOOa defines hydraulic fracturing as ‘‘the process of directing pressurized fluids containing any combination of water, proppant, and any added chemicals to penetrate tight formations, such as shale or coal formations, that subsequently require high rate, extended flowback to expel fracture fluids and solids during completions.’’ The NSPS does not offer numeric thresholds that define ‘‘tight formations’’ or ‘‘high rate, extended flowback’’. When developing the original NSPS OOOO, EPA’s analysis assumed hydraulic fracturing is performed in tight sand, shale, and coalbed methane formations which have an in situ permeability (flow rate capability) to gas of less than 0.1 millidarcy.329 The EPA also assumed the flowback lasted between 3 and 10 days for the average gas well,330 and 3 days for the average oil well.331 However, in response to a public comment on the 2015 NSPS OOOOa proposal claiming the definition of hydraulic fracturing was too broad, the EPA clarified it intended to ‘‘include operations that would increase the flow of hydrocarbons to the wellhead’’.332 Similarly, in response to a public comment seeking an exemption for wells that have a flowback period of less than 24 hours, the EPA acknowledged that there is a range of flowback periods, finding that the requested exemption was not warranted.333 We are soliciting comment on if numeric thresholds for ‘‘tight formations’’ or ‘‘high rate, extended flowback’’ are appropriate to include in the definition of hydraulic fracturing, and if so, what those numeric thresholds should be. Alternatively, we solicit comment on if it is appropriate to align the NSPS definition with the U.S. Geologic Survey (USGS) definition of hydraulic fracturing (‘‘the process of injecting water, sand, and/or chemicals into a well to break up underground bedrock to free up oil or gas 327 See Docket ID Item Nos. EPA–HQ–OAR–2010– 0505–0445, Chapter 4, p. 4–2 and EPA–HQ–OAR– 2010–0505–4546, p. 30. 328 See Docket ID Item No. EPA–HQ–OAR–2010– 0505–4546, p. 61. 329 See Docket ID Item No. EPA–HQ–OAR–2010– 0505–0445, Chapter 4, p. 4–2. 330 See Docket ID Item No. EPA–HQ–OAR–2010– 0505–0445, Chapter 4, p. 4–1. 331 See Docket ID Item No. EPA–HQ–OAR–2010– 0505–5021, p.20. 332 See Docket ID Item No. EPA–HQ–OAR–2010– 0505–7632, Chapter 3, p. 3–113. 333 See Docket ID Item No. EPA–HQ–OAR–2010– 0505–7632, Chapter 3, p. 3–64. E:\FR\FM\15NOP2.SGM 15NOP2 63248 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules reserves’’),334 which may more accurately capture the EPA’s original intent. khammond on DSKJM1Z7X2PROD with PROPOSALS2 XIV. State, Tribal, and Federal Plan Development for Existing Sources Over the last forty years, under CAA section 111(d), the agency has regulated four pollutants from five source categories (i.e., sulfuric acid plants (acid mist), phosphate fertilizer plants (fluorides), primary aluminum plants (fluorides), kraft pulp plants (total reduced sulfur), and municipal solid waste landfills (landfill gases)).335 In addition, the agency has regulated additional pollutants under CAA section 111(d) in conjunction with CAA section 129.336 The Agency has not previously addressed emissions of GHGs (in the form of limitations of methane) from the Crude Oil and Natural Gas source category under CAA section 111(d). However, the EPA has ample experience with this source category from implementing the NSPS for so long, and has examined existing sources in a variety of context including the 2013 Federal Implementation Plan (FIP) for oil and natural gas well production facilities on the Fort Berthold Indian Reservation (78 FR 17836 (Mar. 22, 2013)), the 2016 Oil and Natural Gas Control Techniques Guidelines (81 FR 74798 (Oct. 27, 334 USGS. Hydraulic Fracturing. https:// www.usgs.gov/mission-areas/water-resources/ science/hydraulic-fracturing?qt-science_center_ objects=0#qt-science_center_objects. Accessed September 1, 2021. 335 See ‘‘Phosphate Fertilizer Plants; Final Guideline Document Availability,’’ 42 FR 12022 (March 1, 1977); ‘‘Standards of Performance for New Stationary Sources; Emission Guideline for Sulfuric Acid Mist,’’ 42 FR 55796 (October 18, 1977); ‘‘Kraft Pulp Mills, Notice of Availability of Final Guideline Document,’’ 44 FR 29828 (May 22, 1979); ‘‘Primary Aluminum Plants; Availability of Final Guideline Document,’’ 45 FR 26294 (April 17, 1980); ‘‘EG and Compliance Times for Municipal Solid Waste Landfills,’’ 81 FR 59276 (August 29, 2016). In addition, EPA regulated mercury from coal-fired electric power plants in a 2005 rule that was vacated by the D.C. Circuit, ‘‘Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units; Final Rule,’’ 70 FR 28606 (May 18, 2005) (Clean Air Mercury Rule), vacated by New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). EPA also regulated GHG from fossil fuel-fired electric power plants in a 2015 rule that EPA subsequently repealed and replaced with a 2019 rule that, in turn, was vacated by the D.C. Circuit. ‘‘Carbon Pollution EG for Existing Stationary Sources: Electric Utility Generating Units; Final Rule,’’ 80 FR 64662 (Oct. 23, 2015) (Clean Power Plan), repealed and replaced by ‘‘Repeal of the Clean Power Plan; EG for Greenhouse Gas Emissions From Existing Electric Utility Generating Units; Revisions to EG Implementing Regulations,’’ 84 FR 32520 (July 8, 2019) (Affordable Clean Energy Rule), vacated by Am. Lung Assoc. 336 See, e.g., ‘‘Standards of Performance for New Stationary Sources and EG for Existing Sources: Sewage Sludge Incineration Units, Final Rule,’’ 76 FR 15372 (March 21, 2011). VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 2016)), and the 2020 proposed FIP for managing emissions from oil and natural gas sources on Indian country lands within the Uintah and Ouray Indian Reservation (85 FR 3492 (Jan. 21, 2020)). The draft EG contained in this proposal draw from, among other sources of information and analysis, all of these experiences combined with information on State laws that regulate existing sources. In this action, the EPA is proposing EG for Sates to follow in developing their plans to reduce emissions of GHGs (in the form of limitations on methane) from designated facilities within the Crude Oil and Natural Gas source category. A. Overview While section IV of this preamble provides a general overview of the State planning process triggered by the EPA’s finalization of EG under CAA section 111(d), this section explains the EG process and proposed State plan requirements in more detail, and also solicits comment on various issues related to this EG. The EG process is governed by CAA section 111(d) as well as the final EG and the EPA’s implementing regulations at 40 CFR part 60, subpart Ba.337 After the EPA establishes the BSER in the final EG, as described in preamble sections XI and XII, each State that includes a designated facility must develop, adopt, and submit to the EPA its State plan under CAA section 111(d). The EPA then must determine whether to approve or disapprove the plan. If a State does not submit a plan, or if the EPA does not approve a State’s plan, then the EPA must establish a Federal plan for the State. Each of these steps, and more, is discussed in detail in this section which is organized into six parts. First, we discuss the components of the EG. Second, we discuss establishing standards of performance in State plans in response to a finalized EG. Third, we discuss the components of an approvable State plan submission. Fourth, we discuss the timing for State plan submissions and compliance times. Fifth, we discuss the EPA’s action on State plans and promulgation of a Federal plan, if needed. Sixth, we discuss the CAA section 111(d) process as it relates to Tribes. While this section describes the requirements of the implementing regulations under 40 CFR part 60, subpart Ba, proposes 337 As previously noted, the D.C. Circuit has vacated certain timing provisions within subpart Ba. Am. Lung Assoc. v. EPA. However, the court did not vacate the applicability provision, and therefore Subpart Ba applies to any EG that EPA finalizes from this proposal. PO 00000 Frm 00140 Fmt 4701 Sfmt 4702 requirements for States in the context of this EG, and solicits comments in the context of this EG, nothing in this proposal is intended to reopen the implementing regulations themselves for comment. B. Components of EG As previously described, CAA sections 111(d)(1) and 111(a)(1) collectively establish and define certain roles and responsibilities for the EPA and the States. The EPA addresses its responsibilities by drafting and publishing EG in accordance with 40 CFR 60.22a, which ‘‘[contain] information pertinent to control of the designated pollutant from designated facilities.’’ Mirroring language included in CAA section 111(d)(1), the EPA’s implementing regulations define a designated pollutant as ‘‘any air pollutant, the emissions of which are subject to a standard of performance for new stationary sources, but for which air quality criteria have not been issued and that is not included on a list published under section 108(a) or section 112(b)(1)(A) of the Act.’’ 40 CFR 60.21a(a). The EPA’s implementing regulations also define a designated facility as ‘‘any existing facility (see § 60.2) which emits a designated pollutant and which would be subject to a standard of performance for that pollutant if the existing facility were an affected facility (see § 60.2).’’ Id. at § 60.21a(b). The designated pollutant for purposes of the draft EG included in this proposal is GHGs, but the presumptive standards in the EG are expressed in terms of limitations on methane. A description of each of the designated facilities included in the draft EG can be found above in preamble sections XI and XII. More specifically, 40 CFR 60.22a(b) lists six components to be included in EG to provide information for development of the State plans triggered by the promulgation of the EG. First, EG must include information regarding the ‘‘endangerment of public health or welfare caused, or contributed to, by the designated pollutant.’’ 40 CFR 60.22a(b)(1). Information on the harmful public health and welfare impacts of methane emissions from the oil and natural gas industry are included above in section III of this document. Second, the EG must include a ‘‘description of systems of emission reduction which, in the judgment of the Administrator, have been adequately demonstrated.’’ 40 CFR 60.22a(b)(2). The EPA has included such a description above in sections XI and XII of this preamble, and the NSPS OOOOb and EG TSD located at Docket ID No. EPA–HQ–OAR–2021–0317. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules Third, the EG must include information regarding ‘‘the degree of emission limitation’’ achievable through application of each system, along with information ‘‘on the costs, non-air quality health environmental effects, and energy requirements of applying each system to designated facilities.’’ 40 CFR 60.22a(b)(3). The EPA has included such a description in sections XI and XII of this preamble, and the NSPS OOOOb and EG TSD located at Docket ID No. EPA–HQ–OAR–2021–0317. Fourth, the EG must include information regarding the amount of time that the EPA believes would be normally necessary for designated facilities to design, install, and startup the control systems identified in component number three. See 40 CFR 60.22a(b)(4). The EPA explains how it proposes to address this component below in section XIV.E. Fifth, and likely most helpful to States when developing their plans in response to the final EG, the EG must include information regarding the ‘‘degree of emission limitation achievable through the application of the best system of emission reduction’’ that has been adequately demonstrated, taking into account the same factors as described in component three (cost, non-air quality health and environmental impact and energy requirements), ‘‘and the time within which compliance with standards of performance can be achieved.’’ 40 CFR 60.22a(b)(5). The EPA has included such information in sections XI and XII of this preamble and the NSPS OOOOb and EG TSD located at Docket ID No. EPA–HQ–OAR–2021–0317 as well as in section XIV.E of this preamble. In identifying the degree of achievable emission limitation, the EPA may subcategorize, that is to ‘‘specify different degrees of emission limitation or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make subcategorization appropriate.’’ Id. The EPA can choose to exercise that discretion to subcategorize within the draft EG for certain emission points. Sixth, and last, the EG is to include any other information not contemplated by the five other components that the EPA ‘‘determines may contribute to the formulation of State plans.’’ This section includes such information and guidance specifically VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 designed to assist States in developing their plans under CAA 111(d) for these draft EG. C. Establishing Standards of Performance in State Plans While the EPA has the authority and responsibility to determine the BSER and the degree of limitation achievable through application of the BSER, CAA section 111(d)(1) provides that States shall submit to the EPA plans that establish standards of performance for designated facilities (i.e., existing sources) and provide for implementation and enforcement of such standards. In light of the statutory text, and as reflected in the technical completeness criteria in the EPA’s implementing regulations (explained below), State plans implementing the EG should include requirements and detailed information related to two key aspects of implementation: establishing standards of performance for designated facilities and providing measures that implement and enforce such standards. Establish Standards of Performance for Designated Facilities. As an initial matter, a State must identify existing facilities within its borders that meet the applicability requirements in the final EG and are thereby considered a ‘‘designated facility’’ under the EG.338 Then, States are required to establish standards of performance for the identified designated facilities. There is a fundamental requirement under CAA section 111(d) that a State’s standards of performance reflect the degree of emission limitation achievable through the application of the BSER, which derives from the definition of ‘‘standard of performance’’ in CAA section 111(a)(1). The statute further requires the EPA to permit States, in applying a standard of performance, to consider a source’s remaining useful life and other factors. Accordingly, based on both the mandatory and discretionary aspects of CAA section 111(d), a certain level of process is required of State plans: namely, the standards of performance must reflect the degree of emission limitation achievable through application of the BSER, and if the State 338 In accordance with 40 CFR 60.23a(b), states without any designated facilities are directed to submit to the Administrator a letter of negative declaration certifying that there are no designated facilities, as defined by EPA’s emissions guidelines, located within the state. No plan is required for states that do not have any designated facilities. PO 00000 Frm 00141 Fmt 4701 Sfmt 4702 63249 chooses, the consideration of remaining useful life and other factors in applying a standard of performance to a designated facility. For this EG the EPA is proposing to translate the degree of emission limitation achievable through application of the BSER (i.e., level of stringency) into presumptive standards of performance that States may use in the development of State plans for specific emission points. The EPA believes that the presumptive standards of performance included in the EG will provide States with the level of stringency that the EPA would require to approve a State plan. Put another way, the EPA is choosing to format this EG such that if a State chooses to adopt the presumptive standards as the standards of performance in their State plan, then the EPA believes that such plan could be approved as meeting the requirements of CAA section 111(d) and the finalized EG, assuming the plan meets all other applicable requirements. In this way, the presumptive standards included in the EG serve a similar purpose as a model rule because they are intended to assist States in developing their plan submissions by providing the States with a starting point for their standards that are based on general industry parameters and assumptions. The EPA believes that providing these presumptive standards of performance will create a streamlined approach for States in developing plans and for the EPA in evaluating State plans. Of course, the EPA cannot predetermine the outcome of a future rulemaking process, and inclusion of these presumptive standards in this EG does not impact the rulemaking process associated with the EPA’s review of, and action on, a State plan submission. In its review of State plans, the EPA will consider the information in the final EG (including what EPA publishes in the final EG as the presumptive standards), as well as information submitted by the State and the public. The EPA will evaluate the approvability of all plans through individual notice-and-comment rulemaking processes. As described in sections XI and XII, the EPA is proposing to translate the degree of emission limitation achievable through application of the BSER into presumptive standards for the following designated facilities as shown in Table 20. E:\FR\FM\15NOP2.SGM 15NOP2 63250 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules TABLE 20—SUMMARY OF PROPOSED EG SUBPART OOOOC PRESUMPTIVE NUMERICAL STANDARDS Designated facility Proposed presumptive mass-based standards in the draft emissions guidelines for GHGs Storage Vessels: Tank Battery with PTE of 20 tpy or More of Methane. Pneumatic Controllers: Natural Gas Driven that Vent to the Atmosphere. Wet Seal Centrifugal Compressors ............................... Pneumatic Pumps: Natural Gas Processing Plants ..... Pneumatic Pumps: Locations Other Than Natural Gas Processing Plants. Associated Gas from Oil Wells ..................................... For these designated facilities, State plans would generally be expected to establish standards of performance that reflect these numerical presumptive standards, if included in the final EG. Further, for these designated facilities, the EPA is proposing to require that the standards of performance be expressed in the same form as the numerical presumptive standards set forth in Table 20. For example, for storage vessels that are part of a tank battery with a PTE of 20 tpy or more of methane, the EPA is proposing a numerical presumptive standard of 95-percent control. Accordingly, if finalized as proposed, States would be required to submit a plan that includes numerical standards of performance for these designated facilities expressed in the same form as the presumptive standard of 95 percent control. As described in this proposal and the associated supporting materials 95 percent control. VOC and methane emission rate of zero. 95 percent control. Zero natural gas emissions from diaphragm and piston pneumatic pumps. 95 percent control of diaphragm pneumatic pumps if there is an existing control or process on site. 95 percent control not required if (1) routed to an existing control that achieves less than 95 percent or (2) it is technically infeasible to route to the existing control device or process. Route associated gas to a sales line. In the event that access to a sales line is not available, the gas can be used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, or routed to a flare or other control device that achieves at least 95 percent control. in the docket, the EPA has extensively and rigorously performed technical analyses in order to determine the appropriate proposed BSER for each set of designated facilities. The form of the numerical expression of the degrees of emission limitation achievable through application of the BSERs, and the associated presumptive standards, are a result of these technical analyses. The EPA believes that requiring States to maintain the same form of numerical standard in their plans will preserve the integrity of the BSERs and avoid analytic issues that are likely to arise if EPA is required to determine whether a different form of numerical standard submitted by a State has the same level of stringency as the final EG. Accordingly, having a uniform form of standard of performance will help streamline the States’ development of their plans, as well as the EPA’s review of those plans, since there will be fewer variables to evaluate in the development and review of each standard of performance. The EPA solicits comment on its proposal to require State plans to include numerical standards of performance for these designated facilities that are in the same form as the numerical presumptive standards, and whether EPA should additionally allow States to include a different form of numerical standards for these facilities so long as States demonstrate the equivalency of such standards to the level of stringency required under the final EG. For the following designated facilities, the EPA is proposing to translate the degree of emission limitation achievable through application of the BSER into the presumptive standards shown in Table 21. TABLE 21—SUMMARY OF PROPOSED EG SUBPART OOOOC PRESUMPTIVE NON–NUMERICAL STANDARDS Designated facility Proposed presumptive non-numerical standards in the draft emissions guidelines for GHGs Fugitive Emissions: Well Sites—>0 to <3 tpy methane Perform fugitive emissions survey and repair to demonstrate actual site emissions are reflected in calculation. Quarterly OGI monitoring following appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Semiannual OGI monitoring following appendix K. (Optional semiannual EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Quarterly OGI monitoring following appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Quarterly OGI monitoring following appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. Annual OGI monitoring following appendix K. (Optional annual EPA Method 21 monitoring with 500 ppm defined as a leak). First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt. (Optional) Alternative bimonthly screening with advanced measurement technology and annual OGI monitoring following appendix K. Natural gas bleed rate no greater than 6 scfh. Fugitive Emissions: Well Sites—≥3 tpy methane ......... (Co-proposal) Fugitive Emissions: Well Sites—≥3 to <8 tpy methane. (Co-proposal) Fugitive Emissions: Well Sites—≥8 tpy methane. Fugitive Emissions: Compressor Stations .................... khammond on DSKJM1Z7X2PROD with PROPOSALS2 Fugitive Emissions: Well Sites and Compressor Stations on Alaska North Slope. Fugitive Emissions: Well Sites and Compressor Stations.. Pneumatic Controllers: Alaska (at sites where onsite power is not available—continuous bleed natural gas driven). Pneumatic Controllers: Alaska (at sites where onsite power is not available—intermittent natural gas driven). Reciprocating Compressors .......................................... Equipment Leaks at Gas Plants ................................... VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 Monitor and repair through fugitives program. Replace the reciprocating compressor rod packing based on annual monitoring (when measured leak rate exceeds 2 scfm) or route emissions to a process. Bimonthly OGI LDAR program (NSPS VVa as optional alternative). PO 00000 Frm 00142 Fmt 4701 Sfmt 4702 E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules The EPA’s implementing regulations at 40 CFR 60.24a(b) require that standards of performance shall either be based on allowable rate or limit of emissions, except when the EPA identifies cases in an EG where it would not be feasible to prescribe or enforce a rate or limit. Put another way, 40 CFR 60.24a(b) permits the EPA to identify cases where it is not feasible for States to prescribe or enforce a numerical standard, and in those cases the EPA can include non-numerical emissions limitations such as design, equipment, work practice, or operational standards, or a combination thereof, in the EG. See also definition of ‘‘standard of performance’’ in 40 CFR 60.21a(f). This authority in the context of the EG is akin to the EPA’s authority under CAA section 111(h) to prescribe nonnumerical standards where the Administrator determines it is not feasible to prescribe or enforce a numerical standard of performance. Where the EPA finalizes EG that authorize design, equipment, work practice, or operational standard, or a combination thereof, the State ‘‘plan shall, to the degree possible, set forth the emission reductions achievable by implementation of such standards, and may permit compliance by the use of equipment determined by the State to be equivalent to that prescribed’’ by the State plan. See 40 CFR 60.24a(b). For the designated facilities listed in Table 21 the EPA has determined that it is not feasible to prescribe or enforce a numerical standard. As such, for these designated facilities, the EPA is proposing presumptive standards that are comprised of design, equipment, work practice, and/or operational standards. For these designated facilities, States are generally expected to establish the same non-numerical presumptive standards in Table 21. If States do not incorporate the presumptive standards included in the final EG into their State plan, but instead wish to utilize a different design, equipment, work practice, and/ or operational standard for any of the designated facilities listed in Table 21, then the EPA is proposing to require that the State include in its plan a demonstration of how that standard will achieve a reduction in methane emissions at least equivalent to the reduction in methane emissions achieved by application of the presumptive standards included in the final EG. Such a demonstration should take into account, among other factors, the timelines for compliance. The EPA believes that this requirement is consistent with the AMEL provision in VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 CAA section 111(h)(3), which requires a demonstration that any alternative ‘‘will achieve a reduction in emissions . . . at least equivalent to the reduction in emissions’’ achieved by EPA’s standard, and the technical completeness criteria found at 40 CFR 60.27a(g)(3)(iv), which requires that State plans must include a ‘‘demonstration that the State plan submittal is projected to achieve emissions performance under the applicable EG.’’ To the extent that a State determines the presumptive standards in the final EG are not reasonable for a particular designated facility due to remaining useful life and other factors, the statute requires that the EPA’s regulations under CAA section 111(d) permit States to consider such factors in applying a standard of performance. As such, the EPA’s implementing regulations at 40 CFR 60.24a(e) allow States to consider remaining useful life and other factors to apply a less stringent standard of performance to a designated facility or class of facilities if one or more demonstrations are made. These demonstrations include unreasonable cost of control resulting from plant age, location, or basic process design; physical impossibility of installing necessary control equipment; or other factors specific to the facility (or class of facilities) that make application of a less stringent standard or final compliance time significantly more reasonable. The implementing regulations also clarify that, absent such a demonstration, the State’s standards of performance must be ‘‘no less stringent than the corresponding’’ EG. See 40 CFR 60.24a(c). The EPA intends to provide further clarification on the general process and requirements for accounting for remaining useful life and other factors, including on the reasonableness aspect of the required demonstration, via a rulemaking to amend the implementing regulations in the near future. However, the EPA also recognizes that the oil and natural gas industry is unique such that the general approach to considering remaining useful life and other factors in the implementing regulations may not be an ideal fit. For example, the sheer number and variety of designated facilities in the oil and natural gas industry could make a source-specific (or even a class-specific) evaluation of remaining useful life and other factors extremely difficult and burdensome for States that want to undertake a demonstration. In addition, the presumptive standards for these designated facilities generally entail fewer major capital expenses compared with other industries for which EPA has PO 00000 Frm 00143 Fmt 4701 Sfmt 4702 63251 previously issued EG under CAA section 111(d), and many of the proposed presumptive standards generally take the form of design, equipment, work practice, or operational standards rather than numerical emission limitations. Further, in proposing the presumptive standards for existing sources, the EPA has deliberately included certain flexibilities (e.g., in cases of technical infeasibility) such that the EPA believes the presumptive standards should be achievable and cost-effective for a wide variety of facilities across the source category. Given these facts, the EPA believes that it would likely be difficult for States to demonstrate that the presumptive standards are not reasonable for the vast majority of designated facilities. The EPA is soliciting comment on these observations, and any other facts and circumstances that are unique to the oil and natural gas industry that could impact the remaining-useful-life-andother-factors demonstration. The EPA is also soliciting comment as to whether the Agency should include specific provisions regarding the consideration of remaining useful life and other factors in this EG that would supplement or supersede the general provisions in the implementing regulations. To the extent a State chooses to submit a plan that includes standards of performance that are more stringent than the requirements of the final EG, States have the authority to do so under CAA section 116, and the EPA has the authority to approve such plans and render them Federally enforceable if all applicable requirements are met. Union Electric Co. v. EPA, 427 U.S. 246, (1976). See also 40 CFR 60.24a(f). The EPA acknowledges that in the Affordable Clean Energy (ACE) rule, it previously took the position that Union Electric does not control the question of whether CAA section 111(d) State plans may be more stringent than Federal requirements. The ACE rule took this position on the basis that Union Electric on its face applies only to CAA section 110, and that it is potentially salient that CAA section 111(d) is predicated on specific technologies whereas CAA section 110 gives States broad latitude in the measures used for attaining the National Ambient Air Quality Standards (NAAQS). 84 FR 32559–61 (July 8, 2019). The EPA no longer takes this position. Upon further evaluation, the EPA believes that because of the structural similarities between CAA sections 110 and 111(d), CAA section 116 as interpreted by Union Electric E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63252 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules requires the EPA to approve CAA section 111(d) State plans that are more stringent than required by the EG if the plan is otherwise is compliance with all applicable requirements. See FCC v. Fox Television Stations, Inc., 556 U.S. 502 (2009). The D.C. Circuit in Union Electric rejected a construction of CAA sections 110 and 116 that measures more stringent than those required to attain the NAAQS cannot be approved into a federally enforceable State Implementation Plan (SIP) but must be adopted and enforced only as a matter of State law. Id. at 263–64. While the BSER and the NAAQS are distinct from one another in that the former is technology-based and the latter is based on ambient air quality, both CAA sections 111(d) and 110 are structurally similar in that States must adopt and submit to the EPA plans which include requirements to meet the objectives of each respective section. Requiring States to enact and enforce two sets of standards, one that is a federally approved CAA section 111(d) plan and one that is a stricter State plan, runs directly afoul of the court’s holding that there is no basis for interpreting CAA section 116 in such manner. Therefore, the EPA interprets CAA sections 111(d) and 116 as allowing States to include, and the EPA to approve, more stringent standards of performance in State plans. The EPA notes that its authority is constrained to approving measures which comport with applicable statutory and regulatory requirements. For example, CAA section 111(d) only contemplates that State plans include requirements for designated facilities, therefore the EPA believes it does not have the authority to approve and render federally enforceable measures on other entities. The EPA is also aware that in the context of regulating the oil and natural gas industry many States have existing programs they may want to leverage for purposes of satisfying their CAA section 111(d) State plan obligations. The EPA anticipates providing information on ways in which State plans can accommodate existing State programs to the extent such programs are at least as stringent as the requirement of the final EG. Consistent with the proposed presumptive standards, the EPA proposes that a State plan which relies on an existing State program must still establish standards of performance that are in the same form as the presumptive standards. The EPA solicits comment on whether States relying on existing programs should be authorized to include a different form of standard in their plans so long as they demonstrate VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 the equivalency of such standards to the level of stringency required under the final EG, and how such equivalency demonstrations can be made in a rigorous and consistent way. The EPA proposes to require that, in situations where a State wishes to rely on State programs (statutes and/or regulations) that pre-date finalization of the EG proposed in this document to satisfy the requirements of CAA section 111(d), the State plan should identify which aspects of the existing State programs are being submitted for approval as federally enforceable requirements under the plan, and include a detailed explanation and analysis of how the relied upon existing State programs are at least as stringent as the requirements of the final EG. The EPA notes that the completeness criteria in 40 CFR 60.27a(g) requires a copy of the actual State law/regulation or document submitted for approval and incorporation into the State plan. Put another way, where a State is relying on an existing State program for its plan, a copy of the pre-existing State statute or regulation underpinning the program would be required by this criterion, and would be a critical component of the EPA’s evaluation of the approvability of the plan. The EPA also solicits comment on various ways in which existing State programs can be adopted into State plans. Particularly, the EPA is interested in how existing State programs that regulate both designated facilities and sources not considered as designated facilities under this EG could be tailored for a State plan to meet the requirements of CAA section 111(d). Providing Measures that Implement and Enforce Such Standards. As part of establishing standards of performance, State plans must also include compliance schedules for those standards. See 40 CFR 60.24a(a). Section XIV.E, explains how the EPA is proposing to approach compliance schedules. The EPA’s implementing regulations require that, except where the State chooses to account for remaining useful life and other factors, State plans shall require final compliance as expeditiously as practicable, but no later than the compliance times specified in the EG. See 40 CFR 60.24a(c). Where a State applies a less stringent standard of performance because of remaining useful life and other factors, the compliance schedule must appropriately comport with that standard.339 339 40 CFR 60.24a(d) additionally required state plans to include increments of progress for any compliance schedule that extended more than 24 PO 00000 Frm 00144 Fmt 4701 Sfmt 4702 In addition to establishing standards of performance and compliance schedules, State plans must also include, adequately document, and demonstrate the methods employed to implement and enforce the standards of performance such that the EPA can review and identify measures that assure transparent and verifiable implementation. As part of ensuring that regulatory obligations appropriately meet statutory requirements such as enforceability, the EPA has historically and consistently required that obligations placed on sources be quantifiable, non-duplicative, permanent, verifiable, and enforceable. See 40 CFR 60.27a(g)(3)(vi). In accordance with the EPA’s implementing regulations, standards of performance required for designated facilities as part of a State plan to implement the EG proposed here must be non-duplicative, permanent, verifiable, and enforceable. The EPA acknowledges that it may not be feasible to quantify certain non-numerical standards of performance included in the EG. As such, the EPA is proposing that standards of performance for this EG be quantifiable to the extent feasible. A State plan implementing the EG should include information adequate to support a determination by the EPA that the plan meets these requirements. Additionally, States must include appropriate monitoring, reporting, and recordkeeping requirements to ensure that State plans adequately provide for the implementation and enforcement of standards of performance. For designated facilities where the EPA’s presumptive standards include associated monitoring, reporting, and/or recordkeeping requirements, the EPA has determined that such requirements are necessary to ensure compliance. Thus, for those designated facilities, the EPA is proposing to require that the standards of performance established by States maintain the same monitoring, reporting, and recordkeeping requirements, or equivalent requirements. For example, the EG’s presumptive standards for fugitives monitoring at well sites includes requirements for owners and operators to maintain records and submit reports that demonstrate compliance with the monitoring and repair provisions. As such, the EPA is proposing that the portion of the State plan which months after the state plan submittal date. While the substantive requirement for increments of progress was not challenged and remains effective, the timing aspect of this provision was vacated by the D.C. Circuit. Am. Lung Assoc., 985 F.3d at 991. The EPA intends to address the timing aspect of this provision in the near future. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules establishes standards of performance for that designated facility also includes requirements for owners and operators to maintain records and submit reports that demonstrate compliance with the monitoring and repair provisions. Where a State plan adopts standards of performance that differ from the presumptive standards, the plan may accordingly include different monitoring, reporting, and recordkeeping requirements than those in the presumptive standards, but such requirements must be appropriate for the implementation and enforcement of the standards. For components of a State plan that differ from any presumptively approvable aspects of the final EG, the EPA will review the approvability of such components through notice and comment rulemaking. Emissions Inventories. The implementing regulations at 40 CFR 60.25a contain generally applicable requirements for emission inventories, source surveillance, and reports. State plans must include provisions to meet these requirements as well. Section 60.25a further specifies that such data shall be summarized in the plan, and emission rates of designated pollutants from designated facilities shall be correlated with applicable standards of performance. Typically, the EPA would expect that State plans would present this information on a source-specific or unit-specific level. However, the EPA recognizes that due to the very large number of existing oil and natural gas sources,340 and the frequent change of configuration and/or ownership, that it may not be practical to require States to compile this information in the same way that is typically expected for other industries under other EG. Therefore, the EPA is soliciting comment on whether to supersede the requirements of 40 CFR 60.25a(a) for purposes of this EG. The EPA may supersede any requirement in its implementing regulations for CAA section 111(d) if done so explicitly in the EG. See 40 CFR 60.20a(a)(1). Specially, for the reasons explained previously, the EPA believes that in this context it could be difficult for the State plans to include ‘‘an inventory of all designated facilities, including emission data for the designated pollutants and information related to emissions as specified in appendix D to this part’’ as required by the first sentence in 40 CFR 60.25a(a). The EPA understands that States may 340 In the U.S. the EPA has identified over 15,000 oil and gas owners and operators, around 1 million producing onshore oil and gas wells, about 5,000 gathering and boosting facilities, over 650 natural gas processing facilities, and about 1,400 transmission compression facilities. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 not have such an inventory of all designated facilities already available and that creating such an inventory could be resource intensive. Likewise, the EPA understands that States may not have site-specific emissions data for each designated facility, and that creating such an inventory could also be very resource intensive. The EPA does not believe that such detailed information is necessary for States to develop standards of performance, and that standards of performance could be developed with a different type of emissions inventory data. Therefore, in order to avoid the potential burden that could be imposed by applying 40 CFR 60.25a(a) as written to this EG, the EPA is soliciting comment on whether the Agency should supersede the requirements of 40 CFR 60.25a(a) for purposes of this EG, and replace that requirement with a different emissions inventory requirement that seeks to represent the same general type of information but allows States to utilize existing inventories and emissions data. An example of an inventory that could be leveraged, and on which the EPA specifically solicits comment, is the GHGRP. The EPA envisions a superseding requirement that would not impose such a resource intensive burden on States by allowing use of an inventory of GHG emissions data and operational data for designated facilities during the most recent calendar year for which data is available at the time of State plan development and/or submission. The emissions inventory data submitted for this purpose could be derived from the GHGRP, and/or other available existing inventory information available to the State. The EPA recognizes that in this situation the facility definitions used for purposes of compiling the emissions inventory data might not be fully aligned with the designated facilities in the EG, and that it is possible that there could be designated facilities under this EG that are not required to report under the emissions inventory program being relied upon. Further, the EPA recognizes that the GHGRP may include a reporting threshold and/or utilize emission factors in a different manner than the EG. The EPA solicits comment on whether it is appropriate to utilize or supersede 40 CFR 60.25a(a) for purposes of this EG. Specifically, the EPA solicits comment on the practicality of States compiling an inventory for all designated facilities and on what reasonable alternatives may be more practical. Meaningful Engagement. The fundamental purpose of CAA section PO 00000 Frm 00145 Fmt 4701 Sfmt 4702 63253 111 is to reduce emissions from certain stationary sources that cause, or significantly contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare. Therefore, a key consideration in the State’s development of a State plan pursuant to an EG promulgated under CAA section 111(d) is the potential impact of the proposed plan requirements on public health and welfare. A robust and meaningful public participation process during State plan development is critical to ensuring that these impacts are fully considered. The EPA is proposing and soliciting comment on requiring States to perform outreach and meaningful engagement with overburdened and underserved communities during the development process of their State plan pursuant EG OOOOc. States often rely primarily on public hearings as the foundation of their public engagement in their State plan development process because a public hearing is explicitly required pursuant to the applicable regulations. The existing provisions in subpart Ba (40 CFR 60.23a(c)–(f)) detail the public participation requirements associated with the development of a CAA section 111(d) State plan. Per these implementing regulations, States must provide certain notice of and conduct one or more public hearings on their State plan before such plan is adopted and submitted to the EPA for review and action. However, robust and meaningful public involvement in the development of a State plan should go beyond the minimum requirement to hold a public hearing. Meaningful engagement should include ensuring that States share information with and solicit input from stakeholders at critical junctures during plan development, which helps ensure that a plan is adequately addressing the potential impacts to public health and welfare that are the core concern of CAA section 111. This early engagement is especially important for those stakeholders and communities directly impacted by the GHG emissions from designated facilities within the Crude Oil and Natural Gas source category being addressed in a State plan developed pursuant the EG OOOOc. As reflected in section VI and VII of the preamble, engagement with stakeholders and in particular adjacent communities was key during the development of the proposed NSPS and EG and will be key in the development of corresponding State plans that achieve the intended emission reductions and provide benefits to these communities. In E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63254 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules recognizing that minority and lowincome populations often bear an unequal burden of environmental harms and risks, the EPA continues to consider ways to protect them from adverse public health and environmental effects of air pollution emitted from sources within the Oil and Natural Gas Industry that are addressed in this proposed rulemaking. For these reasons, the EPA is proposing to include an additional requirement associated with the adoption and submittal of State plans pursuant to EG OOOOc (in addition to the current requirements of Subpart Ba) by requiring States to meaningfully engage with members of the public, including overburdened and underserved communities, during the plan development process and prior to adoption and submission of the plan to the EPA. The EPA’s authority for proposing to include an additional requirement for meaningful engagement is provided by the authority of both CAA sections 111(d) and 301(a)(1). Under CAA section 111(d), one of the EPA’s obligations is to promulgate a process ‘‘similar’’ to that of CAA section 110 under which States submit plans that implement emission reductions consistent with the BSER. CAA section 110(a)(1) requires States to adopt and submit State implementation plans (SIPs) after ‘‘reasonable notice and public hearings.’’ The Act does not define what constitutes ‘‘reasonable notice’’ under CAA section 110, and therefore the EPA may reasonably interpret this requirement in promulgating a process under which States submit section 111(d) plans. The EPA proposes to give the ‘‘reasonable notice’’ requirement additional and separate meaning from the ‘‘public hearing’’ requirement. Therefore, in addition to the generally applicable public participation requirements in 40 CFR 60.23a(c)–(f) (which presently only require public notification of a public hearing), the EPA proposes to promulgate these additional meaningful engagement requirements within the EG OOOOc to ensure that the public has reasonable notice of relevant information and the opportunity to participate in the State plan development throughout the process. Given the public health and welfare objectives of CAA section 111(d) in regulating specific existing sources, the EPA believes it is reasonable to require meaningful engagement as part of the public participation process in order to further these objectives. Additionally, CAA section 301(a)(1) provides that the EPA is authorized to prescribe such VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 regulations ‘‘as are necessary to carry out [its] functions under [the CAA].’’ The proposed meaningful engagement requirements would effectuate the EPA’s function under CAA section 111(d) in prescribing a process under which States submit plans to implement the statutory directives of this section. The proposed meaningful engagement requirements for State plan development would ensure that the process is inclusive, effective, and accessible to all. For this reason, the process must not be disproportionate or favor certain stakeholders. During the development of the State plan pursuant to EG OOOOc, the EPA expects States to identify any underserved or overburdened communities potentially impacted by the State plan. If any communities are identified, States should engage with these communities and develop public participation strategies to overcome linguistic, cultural, institutional, geographic, and other barriers to meaningful participation and ensure meaningful community representation in the process, recognizing diverse constituencies within any particular community. Community participation should occur as early as possible if it is to be meaningful. Meaningful engagement includes targeted outreach to underserved and overburdened communities, sharing information, and soliciting input on State plan development and on any accompanying assessments. The EPA uses the term ‘‘underserved’’ to mean populations sharing a particular characteristic, as well as geographic communities, that have been systemically denied a full opportunity to participate in aspects of economic, social, and civic life, and the term ‘‘overburdened’’ in referring to minority, low-income, Tribal, and indigenous populations or communities in the U.S. that potentially experience disproportionate environmental harms and risks as a result of greater vulnerability to environmental hazards . This increased vulnerability may be attributable to an accumulation of both negative and lack of positive environmental, health, economic, or social conditions within these populations or communities. This engagement will help ensure that State plans achieve meaningful emission reductions, that overburdened communities partake in the benefits and gains of the State plan, and that these communities are protected from being adversely impacted by the State plan. The EPA recognizes that emissions from designated sources could cross State borders, and therefore may affect PO 00000 Frm 00146 Fmt 4701 Sfmt 4702 underserved and overburdened communities in neighboring States. The EPA is soliciting comment on how meaningful engagement should apply to communities outside of the State that is developing a State plan, for example if a State should coordinate with the neighboring State for outreach or directly contact the affected community. In sections VI and VII of this preamble the EPA addresses environmental justice considerations, implications, and stakeholder outreach the agency is taking to help ensure vulnerable communities are not disproportionately impacted by this rule. The considerations, analyses, and outreach presented in these preamble sections could help States in designing, planning, and developing their own outreach and engagement plans associated with the development and implementation of their State plans to reduce emissions of GHGs from designated facilities within the Crude Oil and Natural Gas source category. To ensure that robust and meaningful public engagement process occurs as the States develop their CAA 111(d) plans, the EPA is also proposing to include a requirement within EG OOOOc for States to demonstrate in their plan submittal how they provided meaningful and timely engagement with all pertinent stakeholders, including, as necessary, industries and small businesses, as well as low-income communities, communities of color, and indigenous populations living near the designated facilities and who may be otherwise potentially affected by the State’s plan. The State would be required to describe, in their plan submittal, the engagement they had with their stakeholders, including their overburdened and underserved communities. Additionally, the EPA would evaluate the States’ demonstrations regarding meaningful public engagement as part of its completeness evaluation of a State plan submittal. If a State plan submission does not meet the required elements for public participation, including requirements for meaningful engagement, this may be ground for the EPA to find the submission incomplete or to disapprove the plan. The EPA further notes that the implementing regulations allow a State to request the approval of different State procedures for public participation pursuant 40 CFR 60.23a(h). The EPA proposes to require that such alternate State procedures do not supersede the meaningful engagement requirements being proposed within EG OOOOc, so that a State would still be required to comply with the meaningful E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 participation requirements even if they apply for a different procedure than the other public notice and hearing requirements under 40 CFR 60.23a. As provided in 40 CFR 60.23a(h), the EPA is proposing that States may also apply for, and the EPA may approve, alternate meaningful engagement procedures if, in the judgement of the Administrator, the procedures, although different from the requirements of within EG OOOOc, in fact provide for adequate notice to and meaningful participation of the public. D. Components of State Plan Submission Under CAA section 111(d)(2), the EPA has an obligation to determine whether each State plan is ‘‘satisfactory.’’ Therefore, in addition to identifying the components that the EG must include, the EPA’s implementing regulations for CAA section 111(d) identify additional components that a State plan must include. Many of these requirements are found in 40 CFR 60.23a, 60.24a, 60.25a, and 60.26a. These provisions include requirements for components such as the following: Procedures a State must go through for adopting a plan before submitting it to the EPA; the stringency of standards of performance and compliance timelines; emission inventories, reporting, and recordkeeping; and, the legal authority a State must show in adopting a plan. These requirements are also generally contained in a list of required State plan elements, referred to as the State plan completeness criteria, found at 40 CFR 60.27a(g)(2)–(3). If the EPA determines that a submitted plan does not meet these criteria then the State is treated as not submitting a plan and the EPA has a duty to promulgate a Federal plan for that State. See CAA section 111(d)(2)(A) and 40 CFR 60.27a(g)(1). If the EPA determines a plan submission is complete, such determination does not reflect a judgment on the eventual approvability of the submitted portions of the plan, which instead must be made through notice-and-comment rulemaking. The completeness criteria do not apply to States without any designated facilities because these States are directed to submit to the Administrator a letter of negative declaration certifying that there are no designated facilities, as defined by the EPA’s emissions guidelines, located within the State. See 40 CFR 60.23a(b). No plan is required for States that do not have any designated facilities. Designated facilities located in States that mistakenly submit a letter of negative declaration would be subject to a Federal plan until a State plan VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 regulating those facilities becomes approved by the EPA. The EPA established nine administrative and six technical criteria for complete State plans under CAA section 111(d). See 40 CFR 60.27a(g)(2)– (3). If a State plan does not include even one of these criteria, then the State plan may be deemed incomplete by the EPA. States that are familiar with the SIP submittal process under CAA section 110 will be familiar with the completeness criteria found in 40 CFR part 51, appendix V. While the completeness criteria for State plan submittals found at 40 CFR 60.27a(g)(2)–(3) is somewhat similar to the SIP submittal criteria in appendix V, it is not exactly the same. As such, even States that are familiar with the SIP submittal process under CAA section 110 are strongly encouraged to review the completeness criteria in 40 CFR 60.27a(g)(2)–(3) as well as the other State plan requirements found in 40 CFR 60.23a, 60.24a, 60.25a, and 60.26a early in their planning process. In short, the administrative completeness criteria require that the State’s plan include a formal submittal letter and a copy of the actual State regulations themselves, as well as evidence that the State has legal authority to adopt and implement the plan, actually adopted the plan, followed State procedural laws when adopting the plan, gave public notice of the changes to State law, held public hearing(s) if applicable, and responded to State-level comments. For a detailed description regarding the public hearing requirement, see 40 CFR 60.23a. For a detailed description of what the State plan must include in terms of evidence that the State has legal authority to adopt and implement the plan, see 40 CFR 60.26a. States are strongly encouraged to review the State plan requirements included in 40 CFR 60.23a and 60.26a in conjunction with the administrative completeness criteria in 40 CFR 60.27a. The technical criteria require that the State’s plan identify the designated facilities, the standards of performance, the geographic scope of the plan, monitoring, recordkeeping and reporting requirements (both for facilities to ensure compliance and for the State to ensure performance of the plan as a whole), and compliance schedules. The technical criteria further require that the State demonstrate that the plan is projected to achieve emission performance under the EG and that each emission standard is quantifiable, non-duplicative, permanent, verifiable, and enforceable. As previously described, it may not be PO 00000 Frm 00147 Fmt 4701 Sfmt 4702 63255 feasible to quantify certain nonnumerical standards of performance. The EPA is proposing to require States demonstrate that each standard of performance is quantifiable, as feasible. For a detailed description of the State plan requirements regarding standards of performance, see section XIV.C and 40 CFR 60.24a. In addition to these technical criteria, 40 CFR 60.25a(a) requires that State plans include certain emissions data for the designated facilities. As explained previously, the EPA is soliciting comment on superseding that requirement for this EG. Further, § 60.25a provides a detailed description of what the State plan is required to include in terms of certain compliance monitoring and reporting. States are strongly encouraged to review the State plan requirements included in 40 CFR 60.24a and 60.25a in conjunction with the technical completeness criteria in 40 CFR 60.27a. E. Timing of State Plan Submissions and Compliance Times The EPA acknowledges that the D.C. Circuit has vacated certain timing provisions within 40 CFR part 60, subpart Ba. Am. Lung Assoc. v. EPA, 985 F.3d at 991 (DC Cir. 2021). These provisions include timing requirements for when State plans are due upon publication of a final EG, for EPA’s action on a State plan submission, and for EPA’s promulgation of a Federal plan. The Agency plans to undertake rulemaking to address the provisions vacated under the court’s decision in the near future. At this time, the EPA is soliciting comment on any facts and circumstances that are unique to the oil and natural gas industry that the EPA should consider when proposing a timeline for plan submission applicable to a final EG for this source category. We recognize that the public needs to have an opportunity to review and comment on the new timelines that will address these regulatory gaps, including in particular the timeline for State plan submission, and the Agency is committed to publishing this proposed timeline for comment when available. In accordance with 40 CFR 60.22a(b)(5), the EPA’s EG is to provide information for the development of State plans that includes, among other things, ‘‘the time within which compliance with standards of performance can be achieved.’’ The EPA is proposing those compliance times for comment. See 40 CFR 60.25a(c). Each State plan must include compliance schedules that, subject to certain exception, require compliance as expeditiously as practicable but no later E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63256 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules than the compliance times included in the relevant EG. Id. at 60.24a(a) and (c). States are free to include compliance times in their plans that are earlier than those included in the final EG. Id. at 40 CFR 60.24a(f)(2). If a State chooses to include a compliance schedule in their plan that extends for a certain period beyond the date required for submittal of the plan, then ‘‘the plan must include legally enforceable increments of progress to achieve compliance for each designated facility.’’ 341 Id. at 40 CFR 60.24a(d). To the extent a State accounts for remaining useful life and other factors in applying a less stringent standard of performance (than required by the EPA in the final EG), the State must also include a compliance deadline that it can demonstrate appropriately correlates with that standard. The EPA is proposing to require that State plans impose a compliance timeline on designated facilities to require final compliance with the standards of performance as expeditiously as practicable, but no later than two years following the State plan submittal deadline. As explained above, the EPA anticipates proposing a State plan submission deadline in a separate document. The EPA believes that two years is an appropriate amount of time for designated facilities to ensure compliance based on the EPA’s general understanding of the industry and the proposed presumptive standards. However, the EPA recognizes that there are many existing sources in the oil and natural gas industry that would be subject to a State plan if the presumptive standards are finalized in a similar manner as proposed in this document, and that there may be a wide range of configurations that may be present at any given facility. Further, the EPA recognizes that it may be appropriate to require different compliance times for different designated facilities. For example, it may be appropriate to require one compliance schedule for reciprocating compressors and a different compliance schedule for storage vessels. There may not be a one-size-fits-all approach to compliance times that is appropriate for all designated facilities. Accordingly, the EPA is soliciting comment on whether a two-year compliance schedule is appropriate for all designated facilities, or whether the EG should require a shorter or longer compliance schedule. The EPA is 341 As previously noted, the timing aspect of this provision was vacated by the D.C. Circuit. Am. Lung Assoc. v. EPA, 985 F.3d 914 at 991. The EPA intends to address the timing aspect of this provision in the near future. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 further soliciting comment on whether it would be appropriate to establish different compliance schedules for different designated facilities, and if so, what are the appropriate timelines for each designated facility. The EPA is soliciting comment on this matter to collect information that might inform different compliance timeline(s) that Agency may propose for comment in the future via a supplemental proposal. F. EPA Action on State Plans and Promulgation of Federal Plans While CAA section 111(d)(1) authorizes States to develop State plans that establish standards of performance and provides States with certain discretion in determining the appropriate standards, CAA section 111(d)(2) provides the EPA a specific oversight role with respect to such State plans. This latter provision authorizes the EPA to prescribe a Federal plan for a State ‘‘in cases where the State fails to submit a satisfactory plan.’’ The States must therefore submit their plans to the EPA, and the EPA must evaluate each State plan to determine whether each plan is ‘‘satisfactory.’’ The EPA’s implementing regulations for CAA section 111(d) accordingly provide procedural requirements for the EPA to make such a determination. See 40 CFR 60.27a. Upon receipt of a State plan, the EPA is first required to determine whether the State plan submittal is complete in accordance with the completeness criteria explained above. See 40 CFR 60.27a(g)(1). The EPA would then have a set period of time to act on any State plan that is deemed complete.342 If the EPA determines that the State plan submission is incomplete, then the State will be treated as not having made the submission, and the EPA would be required to promulgate a Federal plan for the designated facilities in that State. Likewise, if a State does not make any submission then the EPA is required to promulgate a Federal plan. If the EPA does not make an affirmative determination regarding completeness of the State plan submission within a certain amount of time from receiving the State plan, then the submission is deemed complete by operation of law. Id. If a State has submitted a complete plan, then the EPA is required to evaluate that plan submission for 342 As explained above, the D.C. Circuit vacated the timing provisions regarding EPA’s action on a state plan submission, and EPA’s promulgation of a Federal plan. Am. Lung Assoc. v. EPA, 985 F.3d at 991. The Agency plans to undertake rulemaking to address the provisions vacated under the court’s decision in the near future. PO 00000 Frm 00148 Fmt 4701 Sfmt 4702 approvability in accordance with the CAA, EPA’s implementing regulations, and the applicable EG. The EPA may approve or disapprove the State plan submission in whole or in part. See 40 CFR 60.27a(b). If the EPA approves the State plan submission, then that State plan becomes Federally enforceable. If the EPA disapproves the required State plan submission, in whole or in part, then the EPA is required to promulgate a Federal plan for the designated facilities in that State via a notice-andcomment rulemaking, and with an opportunity for public hearing. See 40 CFR 60.27a(c) and (f). In either scenario that would give rise to the EPA’s duty to promulgate a Federal plan (a finding that a State did not submit a complete plan or a disapproval of a State plan), the EPA would not be required to promulgate the Federal plan if the State corrects the deficiency giving rise to the EPA’s duty and the EPA approves the State’s plan before promulgating the Federal plan. Requirements regarding the content of a Federal plan are included in 40 CFR 60.27a(e). G. Tribes and the Planning Process Under CAA Section 111(d) Under the Tribal Authority Rule (TAR) adopted by the EPA, Tribes may seek authority to implement a plan under CAA section 111(d) in a manner similar to a State. See 40 CFR part 49, subpart A. Tribes may, but are not required to, seek approval for treatment in a manner similar to a State for purposes of developing a Tribal Implementation Plan (TIP) implementing the EG. If a Tribe obtains approval and submits a TIP, the EPA will generally use similar criteria and follow similar procedures as those described above for State plans when evaluating the TIP submission, and will approve the TIP if appropriate. The EPA is committed to working with eligible Tribes to help them seek authorization and develop plans if they choose. Tribes that choose to develop plans will generally have the same flexibilities available to States in this process. If a Tribe does not seek and obtain the authority from the EPA to establish a TIP, the EPA has the authority to establish a Federal CAA section 111(d) plan for areas of Indian country where designated facilities are located. A Federal plan would apply to all designated facilities located in the areas of Indian country covered by the Federal plan unless and until the EPA approves an applicable TIP applicable to those facilities. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules XV. Prevention of Significant Deterioration and Title V Permitting In this section, the EPA is addressing how regulation of GHGs under CAA section 111 could have implications for other EPA rules and for permits written under the CAA PSD preconstruction permit program and the CAA title V operating permit program. The EPA is proposing to include provisions in the regulations that explicitly address some of these potential implications, consistent with our experience in prior rules regulating GHGs. The EPA included and explained the basis for similar provisions when promulgating 2016 NSPS OOOOa, as well as the 2015 subpart TTTT NSPS for electric utility generating units. See 81 FR 35823, 35871 (June 3, 2016); 80 FR 64509, 64628 (October 23, 2015). The discussion in these prior rule preambles equally applies to the oil and gas sources subject to NSPS OOOOb and EG OOOOc. In summary, in light of the U.S. Supreme Court’s decision in Utility Air Regulatory Group v. Environmental Protection Agency, 573 U.S. 302 (2014) (UARG), the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source (or modification thereof) for the purpose of PSD applicability. Certain portions of the EPA’s PSD regulations (specifically, the definition of ‘‘subject to regulation’’) effectively ensure that most sources will not trigger PSD solely by virtue of their GHG emissions. E.g., 40 CFR 51.166(b)(48)(iv), 52.21(b)(49)(iv).343 However, the EPA’s PSD regulations (specifically, the definition of ‘‘regulated NSR pollutant’’) provide additional bases for PSD applicability for pollutants that are regulated under CAA section 111. To address this latter component of PSD applicability, the EPA is proposing to add provisions within the subpart OOOOb NSPS and subpart OOOOc EG to help clarify that the promulgation of GHG standards under section 111 will not result in additional sources becoming subject to PSD based solely on GHG emissions, which would be contrary to the holding in UARG. These provisions will be similar to those in the 2016 NSPS OOOOa and other section 111 rules that regulate GHGs. See, e.g., 40 CFR 60.5360a(b)(1)–(2), 60.5515(b)(1)–(2). The EPA understands there are also concerns that if methane were to be subject to regulation as a separate air 343 In 2016, the EPA proposed additional revisions to the PSD and title V regulations that would address these and other concerns. 81 FR 58110 (October 3, 2016). VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 pollutant from GHGs, sources that emit methane above the PSD thresholds or modifications that increase methane emissions could be subject to the PSD program. To address this concern and for purposes of clarity, the EPA is proposing to adopt regulatory text within subpart OOOOb NSPS and subpart OOOOc EG to clarify that the air pollutant that is subject to regulation is GHGs, even though the standard is expressed in the form of a limitation on emission of methane. This language will be substantially similar to language found in, for example, the 2016 NSPS OOOOa and other rules. See, e.g., 40 CFR 60.5360a(a), 60.5515(a). For sources that are subject to the PSD program based on non-GHG emissions, the CAA continues to require that PSD permits satisfy the best available control technology (BACT) requirement for GHGs. Based on the language in the PSD regulations, the EPA and States may continue to limit the application of BACT to GHG emissions in those circumstances where a new source emits GHGs in the amount of at least 75,000 tpy on a CO2 Eq. basis or an existing major source increases emissions of GHGs by more than 75,000 tpy on a CO2 Eq. basis. See 40 CFR 51.166(b)(48)(iv), 52.21(b)(49)(iv). The proposed revisions to the regulatory text within subparts OOOOb NSPS and OOOOc EG will ensure that this BACT applicability level remains operable to sources of GHGs regulated under CAA section 111, as have similar revisions in prior rules. See, e.g., 40 CFR 60.5360a(b)(1)–(2), 60.5515(b)(1)–(2). This proposed rule will not require any additional revisions to SIPs. Regarding title V, the UARG decision similarly held that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source for the purpose of title V applicability. Promulgation of CAA section 111 requirements for GHGs will not result in the EPA imposing a requirement that stationary sources obtain a title V permit solely because such sources emit or have the potential to emit GHGs above the applicable major source thresholds.344 To be clear, however, unless exempted by the Administrator through 344 Additional regulatory text, based on that in prior rules, will further ensure that title V regulations are not applied to GHGs solely because they are regulated under CAA section 111. See, e.g., 40 CFR 60.5360a(b)(3)–(4), 60.5515(b)(3)–(4). The EPA understands that concerns regarding the regulation of methane as a separate air pollutant (described with respect to PSD) also apply to title V. The EPA’s proposed regulatory text—clarifying that the pollutant subject to regulation is GHGs— will similarly address these concerns with respect to title V. See, e.g., 40 CFR 60.5360a(a), 60.5515(a). PO 00000 Frm 00149 Fmt 4701 Sfmt 4702 63257 regulation under CAA section 502(a), any source, including a ‘‘non-major source,’’ subject to a standard or regulation under section 111 is required to apply for, and operate pursuant to, a title V permit that ensures compliance with all applicable CAA requirements for the source, including any GHGrelated applicable requirements. This aspect of the title V program is not affected by UARG.345 The EPA proposes to include an exemption from the obligation to obtain a title V permit for sources subject to NSPS OOOOb and EG OOOOc, unless such sources would otherwise be required to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a), as the EPA did in NSPS OOOO and OOOOa.346 See 40 CFR 60.5370, 60.5370a. However, sources that are subject to the CAA section 111 standards promulgated in this rule and that are otherwise required to obtain a title V permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) will be required to apply for, and operate pursuant to, a title V permit that ensures compliance with all applicable CAA requirements, including any GHG-related applicable requirements. XVI. Impacts of This Proposed Rule A. What are the air impacts? The EPA projected that, from 2023 to 2035, relative to the baseline, the proposed NSPS OOOOb and EG OOOOc will reduce about 41 million short tons of methane emissions reductions (920 million tons CO2 Eq.), 12 million short tons of VOC emissions reductions, and 480 thousand short tons of HAP emission reductions from facilities that are potentially affected by this proposal. The EPA projected regulatory impacts beginning in 2023 as that year represents the first full year of implementation of the proposed NSPS OOOOb. The EPA assumes that emissions impacts of the proposed EG OOOOc will begin in 2026. The EPA projected impacts through 2035 to illustrate the accumulating effects of this rule over a longer period. The EPA 345 See Memorandum from Janet G. McCabe, Acting Assistant Administrator, Office of Air and Radiation, and Cynthia Giles, Assistant Administrator, Office of Enforcement and Compliance Assurance, to Regional Administrators, Regions 1–10, Next Steps and Preliminary Views on the Application of Clean Air Act Permitting Programs to Greenhouse Gases Following the Supreme Court’s Decision in Utility Regulatory Group v. Environmental Protection Agency (July 24, 2014) at 5. 346 The EPA provided the rationale for exempting this source category from the title V permitting requirements during the rulemaking for the 2012 NSPS OOOO. See 76 FR 52737, 52751 (August 23, 2011). That rationale continues to apply to this source category. E:\FR\FM\15NOP2.SGM 15NOP2 63258 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules did not estimate impacts after 2035 for reasons including limited information, as explained in the RIA. khammond on DSKJM1Z7X2PROD with PROPOSALS2 B. What are the energy impacts? The energy impacts described in this section are those energy requirements associated with the operation of emission control devices. Potential impacts on the national energy economy from the rule are discussed in the economic impacts section in XVI.D. There will likely be minimal change in emissions control energy requirements resulting from this rule. Additionally, this proposed action continues to encourage the use of emission controls that recover hydrocarbon products that can be used on-site as fuel or reprocessed within the production process for sale. C. What are the compliance costs? The PV of the regulatory compliance cost associated with the proposed NSPS OOOOb and EG OOOOc over the 2023 to 2035 period was estimated to be $13 billion (in 2019 dollars) using a 3percent discount rate and $10 billion using a 7-percent discount rate. The EAV of these cost reductions is estimated to be $1.2 billion per year using a 3-percent discount rate and $1.2 billion per year using a 7-percent discount rate. These estimates do not, however, include the producer revenues associated with the projected increase in the recovery of saleable natural gas. Estimates of the value of the recovered product have been included in previous regulatory analyses as offsetting compliance costs. Using the 2021 Annual Energy Outlook (AEO) projection of natural gas prices to estimate the value of the change in the recovered gas at the wellhead projected to result from the proposed action, the EPA estimated a PV of regulatory compliance costs of the proposed rule over the 2023 to 2035 period of $7.2 billion using a 3-percent discount rate and $6.3 billion using a 7-percent discount rate. The corresponding estimates of the EAV of compliance costs after accounting for the recovery of saleable natural gas were $680 million per year using a 3-percent discount rate and $760 million using a 7-percent discount rate. D. What are the economic and employment impacts? The EPA conducted an economic impact and distributional analysis for this proposal, as detailed in section 4 of the RIA for this proposal. To provide a partial measure of the economic consequences of the proposed NSPS VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 OOOOb and EG OOOOc, the EPA developed a pair of single-market, static partial-equilibrium analyses of national crude oil and natural gas markets. We implemented the pair of single-market analyses instead of a coupled market or general equilibrium approach to provide broad insights into potential nationallevel market impacts while providing maximum analytical transparency. We estimated the price and quantity impacts of the proposed NSPS OOOOb and EG OOOOc on crude oil and natural gas markets for a subset of years within the time horizon analyzed in the RIA. The models are parameterized using production and price data from the U.S. Energy Information Administration and supply and demand elasticity estimates from the economics literature. The RIA projects that regulatory costs are at their highest in 2026, the first year the requirements of both the proposed NSPS OOOOb and EG OOOOc are assumed to be in effect and will represent the year with the largest market impacts based upon the partial equilibrium modeling. We estimated that the proposed rule could result in a maximum decrease in annual natural gas production of about 249 million Mcf in 2026 (or about 0.8 percent of natural gas production) with a maximum price increase of $0.05 per Mcf (or about 1.8 percent). We estimated the maximum annual reduction in crude oil production would be about 12.2 million barrels (or about 0.3 percent of crude oil production) with a maximum price increase of about $0.06 per barrel (or less than 0.1 percent). Before 2026, the modeled market impacts are much smaller than the 2026 impacts as only the incremental requirements under the proposed NSPS OOOOb are assumed to be in effect. As regulatory costs are projected to decline after 2026, the modelled market impacts for years after 2026 are smaller than the peaks estimated for 2026. Please see section 4.1 of the RIA for more detail on the formulation and implementation of the model as well as a discussion of several important caveats and limitations associated with the approach. As discussed in the RIA for this proposal, employment impacts of environmental regulations are generally composed of a mix of potential declines and gains in different areas of the economy over time. Regulatory employment impacts can vary across occupations, regions, and industries; by labor and product demand and supply elasticities; and in response to other labor market conditions. Isolating such impacts is a challenge, as they are difficult to disentangle from PO 00000 Frm 00150 Fmt 4701 Sfmt 4702 employment impacts caused by a wide variety of ongoing, concurrent economic changes. The oil and natural gas industry directly employs approximately 140,000 people in oil and natural gas extraction, a figure which varies with market prices and technological change, and employs a large number of workers in related sectors that provide materials and services.347 As indicated above, the proposed NSPS OOOOb and EG OOOOc are projected to cause small changes in oil and natural gas production and prices. As a result, demand for labor employed in oil and natural gas-related activities and associated industries might experience adjustments as there may be increases in compliance-related labor requirements as well as changes in employment due to quantity effects in directly regulated sectors and sectors that consume oil and natural gas products. E. What are the benefits of the proposed standards? To satisfy the requirement of E.O. 12866 and to inform the public, the EPA estimated the climate and health benefits due to the emissions reductions projected under the proposed NSPS OOOOb and EG OOOOc. The EPA expects climate and health benefits due to the emissions reductions projected under the proposed NSPS OOOOb and EG OOOOc. The EPA estimated the global social benefits of CH4 emission reductions expected from this proposed rule using the SC–CH4 estimates presented in the ‘‘Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under E.O. 13990 (IWG 2021)’’ published in February 2021 by the Interagency Working Group on the Social Cost of Greenhouse Gases (IWG). The SC–CH4 is the monetary value of the net harm to society associated with a marginal increase in emissions in a given year, or the benefit of avoiding that increase. In principle, SC–CH4 includes the value of all climate change impacts, including (but not limited to) changes in net agricultural productivity, human health effects, property damage from increased flood risk and natural disasters, disruption of energy systems, risk of conflict, environmental migration, and the value of ecosystem services. The SC–CH4 therefore, reflects the societal value of reducing emissions of the gas in question by one metric ton and is the theoretically appropriate value to use in conducting benefit-cost 347 Employment figure drawn from the Bureau of Labor Statistics Current Employment Statistics for NAICS code 211. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules analyses of policies that affect CH4 emissions. The interim SC–GHG estimates were developed over many years, using a transparent process, peer-reviewed methodologies, the best science available at the time of that process, and with input from the public. As a member of the IWG involved in the development of the February 2021 Technical Support Document (TSD): Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990 (IWG 2021), the EPA agrees that the interim SC–GHG estimates represent the most appropriate estimate of the SC–GHG until revised estimates have been developed reflecting the latest, peer-reviewed science. The EPA estimated the PV of the climate benefits over the 2023 to 2035 period to be $55 billion at a 3-percent discount rate. The EAV of these benefits is estimated to be $5.2 billion per year at a 3-percent discount rate. These values represent only a partial accounting of climate impacts from methane emissions and do not account for health effects of ozone exposure from the increase in methane emissions. Under the proposed NSPS OOOOb and EG OOOOc, the EPA expects that VOC emission reductions will improve air quality and are likely to improve health and welfare associated with exposure to ozone, PM2.5, and HAP. Calculating ozone impacts from VOC emissions changes requires information about the spatial patterns in those emissions changes. In addition, the ozone health effects from the proposed rule will depend on the relative proximity of expected VOC and ozone changes to population. In this analysis, we have not characterized VOC emissions changes at a finer spatial resolution than the national total. In light of these uncertainties, we present an illustrative screening analysis in Appendix B of the RIA based on modeled oil and natural gas VOC contributions to ozone concentrations as they occurred in 2017 and do not include the results of this analysis in the estimate of benefits and net benefits projected from this proposal. XVII. Statutory and Executive Order Reviews Additional information about these statutes and EOs can be found at https:// www.epa.gov/laws-regulations/lawsand-executive-orders. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review This proposed action is an economically significant regulatory action that was submitted to the OMB for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, ‘‘Regulatory Impact Analysis for the Proposed Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review’’, is available in the docket and describes in detail the EPA’s assumptions and characterizes the various sources of uncertainties affecting the estimates. B. Paperwork Reduction Act (PRA) The information collection activities in the proposed amendments for 40 CFR part 60, subparts OOOO and OOOOa, have been submitted for approval to the Office of Management and Budget (OMB) under the PRA. The information collection activities in the proposed rules for 40 CFR part 60, subparts OOOOb and OOOOc, will be submitted for approval to OMB under the PRA as part of a supplemental proposed rule.348 The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number 2523.04. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The final rule for this action will include updates to the CFR to reflect the disapproval of the 2020 Policy Rule that was effectuated by the joint resolution enacted pursuant to the CRA on June 30, 2021. The EPA is not soliciting comment on these updates. In addition, this rule proposes amendments to the 2016 NSPS OOOOa to address (1) certain resulting inconsistencies between the VOC and methane standards resulting from the CRA, and 348 While not quantified in this proposal, the EPA anticipates the estimated ICR burden of proposed NSPS OOOOb and EG OOOOc to be at least as burdensome as NSPS OOOOa. The EPA anticipates some sources may have similar ICR burden to NSPS OOOOa. Examples of these include fugitive emissions from compressor stations, pneumatic controllers at gas processing, centrifugal compressors, pneumatic pumps, well completions, and sweetening units. The EPA anticipates other sources could have dissimilar burden to NSPS OOOOa because the standards are different or are brand new to this proposal. Examples of these include fugitive emissions from well sites, storage vessels, pneumatic controllers, reciprocating compressors, liquids unloading, and equipment leaks at gas plants. PO 00000 Frm 00151 Fmt 4701 Sfmt 4702 63259 (2) rescind certain determinations made in the 2020 Technical Rule, with respect to fugitive emissions monitoring at low production well sites and gathering and boosting stations as they were not supported by the record for that rule, or by our subsequent information and analysis. The EPA is also proposing further amendments to its 2016 NSPS OOOOa to address technical and implementation issues. This ICR reflects the EPA’s proposed amendments to the 2016 NSPS OOOOa. The information collected will be used by the EPA and delegated State and local agencies to determine the compliance status of affected facilities subject to the rule. The respondents are owners or operators of onshore oil and natural gas affected facilities (40 CFR 60.5365a). For the purposes of this ICR, it is assumed that oil and natural gas affected facilities located in the U.S. are owned and operated by the oil and natural gas industry, and that none of the affected facilities in the U.S. are owned or operated by State, local, Tribal or the Federal government. All affected facilities are assumed to be privately owned for-profit businesses. The EPA estimates an average of 3,268 respondents will be affected by NSPS OOOOa over the three-year period (2021–2023). The average annual burden for the recordkeeping and reporting requirements for these owners and operators is 283,030 person-hours, with an average annual cost of $93,779,839 over the three-year period (2021–2023). Respondents/affected entities: Oil and natural gas operators and owners. Respondent’s obligation to respond: Mandatory. Estimated number of respondents: 3,268. Frequency of response: Varies depending on affected facility.349 Total estimated burden: 283,030 hours (per year). Burden is defined at 5 CFR 1320.3(b). Total estimated cost: $93,779,839 (2019$), which includes no capital or O&M costs. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. Submit your comments on the Agency’s need for this information, the accuracy of the 349 The specific frequency for each information collection activity within this request is shown in Tables 1a through 1d of the Supporting Statement in the public docket. E:\FR\FM\15NOP2.SGM 15NOP2 63260 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules provided burden estimates and any suggested methods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule. You may also send your ICRrelated comments to OMB’s Office of Information and Regulatory Affairs via email to OIRA_submission@ omb.eop.gov, Attention: Desk Officer for the EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after receipt, OMB must receive comments no later than December 15, 2021. The EPA will respond to any ICR-related comments in the final rule. khammond on DSKJM1Z7X2PROD with PROPOSALS2 C. Regulatory Flexibility Act (RFA) The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of this rule on small entities, a small entity is defined as: (1) A small business in the oil or natural gas industry whose parent company has revenues or numbers of employees below the SBA Size Standards for the relevant NAICS code; (2) a small governmental jurisdiction that is a government of a city, county, town, school district, or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field. Pursuant to section 603 of the RFA, the EPA prepared an initial regulatory flexibility analysis (IRFA) that examines the impact of the proposed rule on small entities along with regulatory alternatives that could minimize that impact. The complete IRFA is available for review in the docket and is summarized here. The IRFA describes the reason why the proposed rule is being considered and describes the objectives and legal basis of the proposed rule, as well as discusses related rules affecting the oil and natural gas sector. The IRFA describes the EPA’s examination of small entity effects prior to proposing a regulatory option and provides information about steps taken to minimize significant impacts on small entities while achieving the objectives of the rule. VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 The EPA also summarized the potential regulatory cost impacts of the proposed rule and alternatives in Section 2 of the RIA. The analysis in the IRFA drew upon some of the same analyses and assumptions as the analyses presented in the RIA. The IRFA analysis is presented in its entirely in Section 4.3 of the RIA. We estimated cost-to-sales ratios (CSR) for each small entity to summarize the impacts of the proposed rule on small entities. In the processing segment, we find that average compliance costs are expected to be negative, and no entity has a cost-tosales ratio greater than either 1 percent or 3 percent. In the production segment, when expected revenues from natural gas product recovery are included, 101 small entities (7.2 percent) have cost-tosales ratios greater than 1 percent, but none have cost-to-sales ratios greater than 3 percent. When expected revenues from natural gas product recovery are excluded, the number of small entities with cost-to-sales ratios greater than 1 percent increases to 331 (23 percent); about half of those small entities (11 percent) also have cost-to-sales ratios greater than 3 percent. The analysis above is subject to a number of caveats and limitations. These are discussed in detail in the IRFA, as well as in Section 4.3 of the RIA. As required by section 609(b) of the RFA, the EPA also convened a Small Business Advocacy Review (SBAR) Panel to obtain advice and recommendations from small entity representatives that potentially would be subject to the rule’s requirements. The SBAR Panel evaluated the assembled materials and small-entity comments on issues related to elements of an IRFA. A copy of the full SBAR Panel Report is available in the rulemaking docket. D. Unfunded Mandates Reform Act (UMRA) The proposed NSPS and EG do not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531–1538, and do not significantly or uniquely affect small governments. The proposed NSPS does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and Tribal governments, in the aggregate or the private sector in any one year. For projected cost estimates, see ‘‘Regulatory Impact Analysis for the Proposed Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review’’, which is PO 00000 Frm 00152 Fmt 4701 Sfmt 4702 available in the docket. The EG is proposed under CAA section 111(d) and does not impose any direct compliance requirements on designated facilities, apart from the requirement for States to develop State plans. As explained in section XIV.G., the EG also does not impose specific requirements on Tribal governments that have designated facilities located in their area of Indian country. The burden for States to develop State plans following promulgation of the rule is estimated to be below $100 million in any one year. Thus, the EG is not subject to the requirements of section 203 or section 205 of the UMRA. The NSPS and EG are also not subject to the requirements of section 203 of UMRA because, as described in 2 U.S.C. 1531–38, they contain no regulatory requirements that might significantly or uniquely affect small governments. The NSPS and EG action imposes no enforceable duty on any State, local, or Tribal governments or the private sector. Specifically, for the EG the State governments to which rule requirements apply are not considered small governments. In light of the interest among governmental entities, the EPA conducted pre-proposal outreach with national organizations representing States and Tribal governmental entities while formulating the proposed rule as discussed in section VII. The EPA considered the stakeholders’ experiences and lessons learned to help inform how to better structure this proposal and consider ongoing challenges that will require continued collaboration with stakeholders. With this proposal, the EPA seeks further input from States and Tribes. For public input to be considered during the formal rulemaking, please submit comments on this proposed action to the formal regulatory docket at EPA Docket ID No. EPA–HQ–OAR–2021–0317 so that the EPA may consider those comments during the development of the final rule. E. Executive Order 13132: Federalism Under Executive Order 13132, the EPA may not issue an action that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal Government provides the funds necessary to pay the direct compliance costs incurred by State and local governments, or the EPA consults with State and local officials early in the process of developing the proposed action. The proposed NSPS OOOOb does not have federalism implications. It will not have substantial direct effects on the E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 States, on the relationship between the Federal Government and the States, or on the distribution of power and responsibilities among the various levels of government. The proposed EG OOOOc may have federalism implications because development of State plans may entail many hours of staff time to develop and coordinate programs for compliance with the proposed rule, as well as time to work with State legislatures as appropriate, and develop a plan submittal. The Agency understands that the EG may impose a burden on States and is committed to providing aid and guidance to States through the plan development process. In the spirit of E.O. 13132 and consistent with the EPA policy to promote communications between the EPA and State and local governments, the EPA specifically solicits comment on this proposed rule from State and local officials including information on costs associated with developing and submitting State plans in accordance with EG OOOOc. F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments This action has Tribal implications. However, it will neither impose substantial direct compliance costs on Federally recognized Tribal governments, nor preempt Tribal law, and does not have substantial direct effects on the relationship between the Federal Government and Indian Tribes or on the distribution of power and responsibilities between the Federal Government and Indian Tribes, as specified in E.O. 13175. 65 FR 67249 (November 9, 2000). The majority of the designated facilities impacted by proposed NSPS and EG on Tribal lands are owned by private entities, and Tribes will not be directly impacted by the compliance costs associated with this rulemaking. There would only be Tribal implications associated with this rulemaking in the case where a unit is owned by a Tribal government or in the case of the NSPS, a Tribal government is given delegated authority to enforce the rulemaking. Tribes are not required to develop plans to implement the EG under CAA section 111(d) for designated existing sources. The EPA notes that this proposal does not directly impose specific requirements on designated facilities, including those located in Indian country, but before developing any standards for sources on Tribal land, the EPA would consult with leaders from affected Tribes. Consistent with previous actions affecting the Crude Oil and Natural Gas source category, there is significant VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 Tribal interest because of the growth of the oil and natural gas production in Indian country. Consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA will engage in consultation with Tribal officials during the development of this action. G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks This action is subject to E.O. 13045 (62 FR 19885, April 23, 1997) because it is an economically significant regulatory action as defined by E.O. 12866, and the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the agency has evaluated the environmental health and welfare effects of climate change on children. GHGs, including methane, contribute to climate change and are emitted in significant quantities by the oil and gas industry. The EPA believes that the GHG emission reductions resulting from implementation of these proposed standards and guidelines, if finalize will further improve children’s health. The assessment literature cited in the EPA’s 2009 Endangerment Findings concluded that certain populations and life stages, including children, the elderly, and the poor, are most vulnerable to climaterelated health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups’ vulnerabilities and the projected impacts they may experience. These assessments describe how children’s unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households. More detailed information on the impacts of climate change to human health and welfare is provided in section III of this preamble. PO 00000 Frm 00153 Fmt 4701 Sfmt 4702 63261 H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action, which is a significant regulatory action under Executive Order 12866, has a significant adverse effect on the supply, distribution or use of energy. To estimate the potential impacts of the proposed NSPS OOOOb and EG OOOOc on crude oil and natural gas production, the EPA developed a pair of single-market, static partialequilibrium analyses of national crude oil and natural gas markets. These analyses are presented in the RIA for this action, which is in the public docket. We treat crude oil markets and natural gas markets separately in these models. The EPA estimated that the proposed rule could result in a maximum decrease in annual natural gas production of about 249 million Mcf in 2026 (or about 0.8 percent of natural gas production). We estimated the maximum annual reduction in crude oil production would be about 12.2 million barrels (or about 0.3 percent of crude oil production). Before 2026, the modeled market impacts are much smaller than the 2026 impacts as only the incremental requirements under the proposed NSPS OOOOb are assumed to be in effect. As regulatory costs are projected to decline after 2026, the modelled market impacts for years after 2026 are smaller than the peaks estimated for 2026. As regulatory costs are projected to decline after 2026, the modelled market impacts for years after 2026 are smaller than the peaks estimated for 2026. The energy impacts the EPA estimates from these rules may be under- or over-estimates of the true energy impacts associated with this action. For more information on the estimated energy effects, please refer to the RIA for this rulemaking. I. National Technology Transfer and Advancement Act (NTTAA) This proposed action for NSPS OOOOb and EG OOOOc involves technical standards.350 Therefore, the EPA conducted searches for the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review through the Enhanced National Standards Systems Network (NSSN) Database managed by the American National Standards Institute 350 The EPA is not proposing changes to previously conducted searches for 40 CFR part 60, subparts OOOO and OOOOa. Therefore, this section only describes proposed NSPS OOOOb and EG OOOOc standards and searches. E:\FR\FM\15NOP2.SGM 15NOP2 khammond on DSKJM1Z7X2PROD with PROPOSALS2 63262 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules (ANSI). Searches were conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 3A, 3B, 3C, 4, 6, 10, 15, 16, 16A, 18, 21, 22, and 25A of 40 CFR part 60, appendix A. No applicable voluntary consensus standards were identified for EPA Methods 1A, 2A, 2D, 21, and 22 and none were brought to its attention in comments. All potential standards were reviewed to determine the practicality of the voluntary consensus standards (VCS) for this rule. Two VCS were identified as an acceptable alternative to EPA test methods for the purpose of this proposed rule. First, ANSI/ASME PTC 19–10–1981, Flue and Exhaust Gas Analyses (Part 10) (manual portions only and not the instrumental portion) was identified to be used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A and 16A. This standard includes manual and instructional methods of analysis for carbon dioxide, carbon monoxide, hydrogen sulfide, nitrogen oxides, oxygen, and sulfur dioxide. Second, ASTM D6420–99 (2010), ‘‘Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/Mass Spectrometry’’ is an acceptable alternative to EPA Method 18 with the following caveats, only use when the target compounds are all known and the target compounds are all listed in ASTM D6420 as measurable. ASTM D6420 should never be specified as a total VOC Method. (ASTM D6420– 99 (2010) is not incorporated by reference in 40 CFR part 60.) The search identified 19 VCS that were potentially applicable for this proposed rule in lieu of EPA reference methods. However, these have been determined to not be practical due to lack of equivalency, documentation, validation of data and other important technical and policy considerations. For additional information, please see the September 10, 2021, memo titled, ‘‘Voluntary Consensus Standard Results for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review’’ in the public docket. The EPA plans to propose the regulatory language for NSPS OOOOb and EG OOOOc through a supplemental action. At that time, the EPA will include any appropriate incorporation by reference in accordance with requirements of 1 CFR 51.5 as discussed below. The EPA anticipates that the following ten standards would be incorporated by reference. • ASTM D86–96, Distillation of Petroleum Products (Approved April 10, 1996) covers the distillation of natural gasolines, motor gasolines, aviation gasolines, aviation turbine fuels, special VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 boiling point spirits, naphthas, white spirit, kerosines, gas oils, distillate fuel oils, and similar petroleum products, utilizing either manual or automated equipment. • ASTM D1945–03 (Reapproved 2010), Standard Test Method for Analysis of Natural Gas by Gas Chromatography covers the determination of the chemical composition of natural gases and similar gaseous mixtures within a certain range of composition. This test method may be abbreviated for the analysis of lean natural gases containing negligible amounts of hexanes and higher hydrocarbons, or for the determination of one or more components. • ASTM D3588–98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuel covers procedures for calculating heating value, relative density, and compressibility factor at base conditions for natural gas mixtures from compositional analysis. It applies to all common types of utility gaseous fuels. • ASTM D4891–89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion covers the determination of the heating value of natural gases and similar gaseous mixtures within a certain range of composition. • ASTM D6522–00 (Reapproved December 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers covers the determination of nitrogen oxides, carbon monoxide, and oxygen concentrations in controlled and uncontrolled emissions from natural gas-fired reciprocating engines, combustion turbines, boilers, and process heaters. • ASTM E168–92, General Techniques of Infrared Quantitative Analysis covers the techniques most often used in infrared quantitative analysis. Practices associated with the collection and analysis of data on a computer are included as well as practices that do not use a computer. • ASTM E169–93, General Techniques of Ultraviolet Quantitative Analysis (Approved May 15, 1993) provide general information on the techniques most often used in ultraviolet and visible quantitative analysis. The purpose is to render unnecessary the repetition of these descriptions of techniques in individual methods for quantitative analysis. PO 00000 Frm 00154 Fmt 4701 Sfmt 4702 • ASTM E260–96, General Gas Chromatography Procedures (Approved April 10, 1996) is a general guide to the application of gas chromatography with packed columns for the separation and analysis of vaporizable or gaseous organic and inorganic mixtures and as a reference for the writing and reporting of gas chromatography methods. • ASME/ANSI PTC 19.10–1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers measuring the oxygen or carbon dioxide content of the exhaust gas. • EPA–600/R–12/531, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards (Issued May 2012) is mandatory for certifying the calibration gases being used for the calibration and audit of ambient air quality analyzers and continuous emission monitors that are required by numerous parts of the CFR. The EPA determined that the ASTM and ASME/ANSI standards, notwithstanding the age of the standards, are reasonably available because it they are available for purchase from the following addresses: American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428–2959; or ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106 and the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016–5990. The EPA determined that the EPA standard is reasonably available because it is publicly available through the EPA’s website: https:// nepis.epa.gov/Adobe/PDF/ P100EKJR.pdf. J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations The EPA believes that this action does not have disproportionately high and adverse human health or environmental effects on minority populations, lowincome populations, and/or indigenous peoples, as specified in Executive Order 12898 (59 FR 7629, February 16, 1994). The documentation for this decision is contained in the RIA prepared under E.O. 12866 for this proposal. In Section 4 of the RIA, the EPA presents a qualitative discussion of the climate impacts of GHGs and environmental justice. The section also presents a set of limited quantitative environmental justice analyses focused on the current distribution of VOC and HAP emissions from oil and natural gas sector. These analyses evaluated baseline scenarios E:\FR\FM\15NOP2.SGM 15NOP2 Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / Proposed Rules khammond on DSKJM1Z7X2PROD with PROPOSALS2 and enabled us to characterize risks due to oil and natural gas VOC and HAP emissions prior to implementation of the proposed rule. These analyses potentially suggest that VOC and HAP emissions from the oil and natural gas sector may disproportionately impact vulnerable populations or overburdened communities under baseline scenarios; however, various uncertainties and data gaps remain, and should be taken into consideration when interpreting these results. Additionally, we lack key information that would be needed to characterize post-control risks under the proposed NSPS OOOOb and EG OOOOc or the regulatory alternatives analyzed in the RIA, preventing the EPA from VerDate Sep<11>2014 17:06 Nov 12, 2021 Jkt 256001 analyzing spatially differentiated outcomes. While a definitive assessment of the impacts of this proposed rule on minority populations, low-income populations, and/or indigenous peoples was not performed, the EPA believes that this action will achieve substantial methane, VOC, and HAP emission reductions and will further improve environmental justice community health and welfare. The EPA believes that any potential environmental justice populations that may experience disproportionate impacts in the baseline may realize disproportionate improvements in air quality resulting from emission reductions. In addition, the EPA provided the public, including those communities PO 00000 Frm 00155 Fmt 4701 Sfmt 9990 63263 disproportionately impacted by the burdens of pollution, opportunities for meaningful engagement with the EPA on this action. A summary of outreach activities conducted by the Agency and what we heard from communities is provided in section VI of this preamble. List of Subjects in 40 CFR Part 60 Environmental protection, Administrative practice and procedure, Air pollution control, Reporting and recordkeeping requirements. Michael S. Regan, Administrator. [FR Doc. 2021–24202 Filed 11–5–21; 4:15 pm] BILLING CODE 6560–50–P E:\FR\FM\15NOP2.SGM 15NOP2

Agencies

ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 86, Number 217 (Monday, November 15, 2021)]
[Proposed Rules]
[Pages 63110-63263]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-24202]



[[Page 63109]]

Vol. 86

Monday,

No. 217

November 15, 2021

Part II





 Environmental Protection Agency





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40 CFR Part 60





Standards of Performance for New, Reconstructed, and Modified Sources 
and Emissions Guidelines for Existing Sources: Oil and Natural Gas 
Sector Climate Review; Proposed Rule

Federal Register / Vol. 86 , No. 217 / Monday, November 15, 2021 / 
Proposed Rules

[[Page 63110]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2021-0317; FRL-8510-02-OAR]
RIN 2060-AV16


Standards of Performance for New, Reconstructed, and Modified 
Sources and Emissions Guidelines for Existing Sources: Oil and Natural 
Gas Sector Climate Review

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: This document comprises three distinct groups of actions under 
the Clean Air Act (CAA) which are collectively intended to 
significantly reduce emissions of greenhouse gases (GHGs) and other 
harmful air pollutants from the Crude Oil and Natural Gas source 
category. First, the EPA proposes to revise the new source performance 
standards (NSPS) for GHGs and volatile organic compounds (VOCs) for the 
Crude Oil and Natural Gas source category under the CAA to reflect the 
Agency's most recent review of the feasibility and cost of reducing 
emissions from these sources. Second, the EPA proposes emissions 
guidelines (EG) under the CAA, for states to follow in developing, 
submitting, and implementing state plans to establish performance 
standards to limit GHGs from existing sources (designated facilities) 
in the Crude Oil and Natural Gas source category. Third, the EPA is 
taking several related actions stemming from the joint resolution of 
Congress, adopted on June 30, 2021 under the Congressional Review Act 
(CRA), disapproving the EPA's final rule titled, ``Oil and Natural Gas 
Sector: Emission Standards for New, Reconstructed, and Modified Sources 
Review,'' Sept. 14, 2020 (``2020 Policy Rule''). This proposal responds 
to the President's January 20, 2021, Executive order (E.O.) titled 
``Protecting Public Health and the Environment and Restoring Science to 
Tackle the Climate Crisis,'' which directed the EPA to consider taking 
the actions proposed here.

DATES: 
    Comments. Comments must be received on or before January 14, 2022. 
Under the Paperwork Reduction Act (PRA), comments on the information 
collection provisions are best assured of consideration if the Office 
of Management and Budget (OMB) receives a copy of your comments on or 
before December 15, 2021.
    Public hearing: The EPA will hold a virtual public hearing on 
November 30, 2021 and December 1, 2021. See SUPPLEMENTARY INFORMATION 
for information on the hearing.

ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2021-0317 by any of the following methods:
     Federal eRulemaking Portal: https://www.regulations.gov/ 
(our preferred method). Follow the online instructions for submitting 
comments.
     Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2021-0317 in the subject line of the message.
     Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2021-0317.
     Mail: U.S. Environmental Protection Agency, EPA Docket 
Center, Docket ID No. EPA-HQ-OAR-2021-0317, Mail Code 28221T, 1200 
Pennsylvania Avenue NW, Washington, DC 20460.
     Hand/Courier Delivery: EPA Docket Center, WJC West 
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004. 
The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-
Friday (except Federal holidays).
    Instructions: All submissions received must include the Docket ID 
No. for this rulemaking. Comments received may be posted without change 
to https://www.regulations.gov/, including any personal information 
provided. For detailed instructions on sending comments and additional 
information on the rulemaking process, see the ``Public Participation'' 
heading of the SUPPLEMENTARY INFORMATION section of this document. Out 
of an abundance of caution for members of the public and our staff, the 
EPA Docket Center and Reading Room are closed to the public, with 
limited exceptions, to reduce the risk of transmitting COVID-19. Our 
Docket Center staff will continue to provide remote customer service 
via email, phone, and webform. We encourage the public to submit 
comments via https://www.regulations.gov/ or email, as there may be a 
delay in processing mail and faxes. Hand deliveries and couriers may be 
received by scheduled appointment only. For further information on EPA 
Docket Center services and the current status, please visit us online 
at https://www.epa.gov/dockets.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed 
action, contact Ms. Karen Marsh, Sector Policies and Programs Division 
(E143-05), Office of Air Quality Planning and Standards, U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711; telephone number: (919) 541-1065; fax number: (919) 541-0516; 
and email address: [email protected] or Ms. Amy Hambrick, Sector 
Policies and Programs Division (E143-05), Office of Air Quality 
Planning and Standards, Environmental Protection Agency, Research 
Triangle Park, North Carolina 27711, telephone number: (919) 541-0964; 
facsimile number: (919) 541-3470; email address: [email protected].

SUPPLEMENTARY INFORMATION:
    Participation in virtual public hearing. Please note that the EPA 
is deviating from its typical approach for public hearings, because the 
President has declared a national emergency. Due to the current Centers 
for Disease Control and Prevention (CDC) recommendations, as well as 
state and local orders for social distancing to limit the spread of 
COVID-19, the EPA cannot hold in-person public meetings at this time.
    The public hearing will be held via virtual platform on November 
30, 2021, and December 1, 2021, and will convene at 11:00 a.m. Eastern 
Time (ET) and conclude at 9:00 p.m. ET each day. On each hearing day, 
the EPA may close a session 15 minutes after the last pre-registered 
speaker has testified if there are no additional speakers. The EPA will 
announce further details at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. If the EPA receives a high 
volume of registrations for the public hearing, we may continue the 
public hearing on December 2, 2021. The EPA does not intend to publish 
a document in the Federal Register announcing the potential addition of 
a third day for the public hearing or any other updates to the 
information on the hearing described in this document. Please monitor 
https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry for any updates to the information described in this document, 
including information about the public hearing. For information or 
questions about the public hearing, please contact the public hearing 
team at (888) 372-8699 or by email at [email protected].
    The EPA will begin pre-registering speakers for the hearing upon 
publication of this document in the Federal Register. The EPA will 
accept registrations on an individual basis. To register to speak at 
the virtual hearing, follow the directions at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry or contact the 
public hearing team at (888) 372-

[[Page 63111]]

8699 or by email at [email protected]. The last day to pre-
register to speak at the hearing will be November 24, 2021. Prior to 
the hearing, the EPA will post a general agenda that will list pre-
registered speakers in approximate order at: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
    The EPA will make every effort to follow the schedule as closely as 
possible on the day of the hearing; however, please plan for the 
hearings to run either ahead of schedule or behind schedule.
    Each commenter will have 5 minutes to provide oral testimony. The 
EPA encourages commenters to provide the EPA with a copy of their oral 
testimony electronically (via email) by emailing it to 
[email protected] and [email protected]. The EPA also recommends 
submitting the text of your oral testimony as written comments to the 
rulemaking docket.
    The EPA may ask clarifying questions during the oral presentations 
but will not respond to the presentations at that time. Written 
statements and supporting information submitted during the comment 
period will be considered with the same weight as oral testimony and 
supporting information presented at the public hearing.
    If you require the services of an interpreter or a special 
accommodation such as audio description, please pre-register for the 
hearing with the public hearing team and describe your needs by 
November 22, 2021. The EPA may not be able to arrange accommodations 
without advanced notice.
    Docket. The EPA has established a docket for this rulemaking under 
Docket ID No. EPA-HQ-OAR-2021-0317. All documents in the docket are 
listed in https://www.regulations.gov/. Although listed, some 
information is not publicly available, e.g., Confidential Business 
Information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the internet and will be publicly available only in hard 
copy. With the exception of such material, publicly available docket 
materials are available electronically in https://www.regulations.gov/.
    Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2021-0317. The EPA's policy is that all comments received will be 
included in the public docket without change and may be made available 
online at https://www.regulations.gov/, including any personal 
information provided, unless the comment includes information claimed 
to be CBI or other information whose disclosure is restricted by 
statute. Do not submit information that you consider to be CBI or 
otherwise protected through https://www.regulations.gov/ or email. This 
type of information should be submitted by mail as discussed below.
    The EPA may publish any comment received to its public docket. 
Multimedia submissions (audio, video, etc.) must be accompanied by a 
written comment. The written comment is considered the official comment 
and should include discussion of all points you wish to make. The EPA 
will generally not consider comments or comment contents located 
outside of the primary submission (i.e., on the Web, cloud, or other 
file sharing system). For additional submission methods, the full EPA 
public comment policy, information about CBI or multimedia submissions, 
and general guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
    The https://www.regulations.gov/ website allows you to submit your 
comment anonymously, which means the EPA will not know your identity or 
contact information unless you provide it in the body of your comment. 
If you send an email comment directly to the EPA without going through 
https://www.regulations.gov/, your email address will be automatically 
captured and included as part of the comment that is placed in the 
public docket and made available on the internet. If you submit an 
electronic comment, the EPA recommends that you include your name and 
other contact information in the body of your comment and with any 
digital storage media you submit. If the EPA cannot read your comment 
due to technical difficulties and cannot contact you for clarification, 
the EPA may not be able to consider your comment. Electronic files 
should not include special characters or any form of encryption and be 
free of any defects or viruses. For additional information about the 
EPA's public docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets.
    The EPA is temporarily suspending its Docket Center and Reading 
Room for public visitors, with limited exceptions, to reduce the risk 
of transmitting COVID-19. Our Docket Center staff will continue to 
provide remote customer service via email, phone, and webform. We 
encourage the public to submit comments via https://www.regulations.gov/ as there may be a delay in processing mail and 
faxes. Hand deliveries or couriers will be received by scheduled 
appointment only. For further information and updates on EPA Docket 
Center services, please visit us online at https://www.epa.gov/dockets.
    The EPA continues to carefully and continuously monitor information 
from the CDC, local area health departments, and our Federal partners 
so that we can respond rapidly as conditions change regarding COVID-19.
    Submitting CBI. Do not submit information containing CBI to the EPA 
through https://www.regulations.gov/ or email. Clearly mark the part or 
all of the information that you claim to be CBI. For CBI information on 
any digital storage media that you mail to the EPA, mark the outside of 
the digital storage media as CBI and then identify electronically 
within the digital storage media the specific information that is 
claimed as CBI. In addition to one complete version of the comments 
that includes information claimed as CBI, you must submit a copy of the 
comments that does not contain the information claimed as CBI directly 
to the public docket through the procedures outlined in Instructions 
above. If you submit any digital storage media that does not contain 
CBI, mark the outside of the digital storage media clearly that it does 
not contain CBI. Information not marked as CBI will be included in the 
public docket and the EPA's electronic public docket without prior 
notice. Information marked as CBI will not be disclosed except in 
accordance with procedures set forth in 40 CFR part 2. Send or deliver 
information identified as CBI only to the following address: OAQPS 
Document Control Officer (C404-02), OAQPS, U.S. Environmental 
Protection Agency, Research Triangle Park, North Carolina 27711, 
Attention Docket ID No. EPA-HQ-OAR-2021-0317. Note that written 
comments containing CBI submitted by mail may be delayed and no hand 
deliveries will be accepted.
    Preamble acronyms and abbreviations. We use multiple acronyms and 
terms in this preamble. While this list may not be exhaustive, to ease 
the reading of this preamble and for reference purposes, the EPA 
defines the following terms and acronyms here:

ACE Affordable Clean Energy rule
AEO Annual Energy Outlook
AMEL alternate means of emissions limitation
ANGA American Natural Gas Alliance
ANSI American National Standards Institute
APCD air pollution control devices
API American Petroleum Institute
ARPA-E Advanced Research Projects Agency-Energy
ASME American Society of Mechanical Engineers

[[Page 63112]]

ASTM American Society for Testing and Materials
AVO audio, visual, olfactory
BACT best achievable control technology
BOEM Bureau of Ocean Energy Management
BLM Bureau of Land Management
BMP best management practices
boe barrels of oil equivalents
BSER best system of emission reduction
BTEX benzene, toluene, ethylbenzene, and xylenes
CAA Clean Air Act
CBI Confidential Business Information
CDC Center for Disease Control
CDX EPA's Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CH4 methane
cm centimeter
CPI consumer price index
CPI-U consumer price index urban
CO carbon monoxide
COPD chronic obstructive pulmonary disease
CO2 carbon dioxide
CO2 Eq. carbon dioxide equivalent
COA condition of approval
COS carbonyl sulfide
CRA Congressional Review Act
CS2 carbon disulfide
CVS closed vent systems
DC direct current
DOE Department of Energy
DOI Department of the Interior
DOT Department of Transportation
EAV equivalent annualized value
EDF Environmental Defense Fund
EG emission guidelines
ECOS Environmental Council of the States
EGU electricity generating units
EIA U.S. Energy Information Administration
EJ environmental justice
EO Executive Order
EPA Environmental Protection Agency
ERT Electronic Reporting Tool
FERC The U.S. Federal Energy Regulatory Commission
fpm feet per minute
GC gas chromatograph
GHGs greenhouse gases
GHGI Inventory of U.S. Greenhouse Gas Emissions and Sinks
GHGRP Greenhouse Gas Reporting Program
GRI Gas Research Institute
GWP global warning potential
HAP hazardous air pollutant(s)
HC hydrocarbons
HFC hydrofluorocarbons
H2S hydrogen sulfide
ICR Information Collection Request
IOGCC Interstate Oil and Gas Compact Commission
IPCC Intergovernmental Panel on Climate Change
IR infrared
IRFA initial regulatory flexibility analysis
kt kilotons
kg kilograms
low-e low emission
LDAR leak detection and repair
Mcf thousand cubic feet
MMT million metric tons
MRR monitoring, recordkeeping, and reporting
MW megawatt
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NCA4 2017-2018 Fourth National Climate Assessment
NEI National Emissions Inventory
NEMS National Energy Modeling System
NESHAP National Emissions Standards for Hazardous Air Pollutants
NGL natural gas liquid
NGO non-governmental organization
NOAA National Oceanic and Atmospheric Administration
NOX nitrogen oxides
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OCSLA The Outer Continental Shelf Lands Act
OAQPS Office of Air Quality Planning and Standards
OIG Office of the Inspector General
OGI optical gas imaging
OMB Office of Management and Budget
PE professional engineer
PFCs perfluorocarbons
PHMSA Pipeline and Hazardous Materials Safety Administration
PM particulate matter
PM2.5 PM with a diameter of 2.5 micrometers or less
ppb parts per billion
ppm parts per million
PRA Paperwork Reduction Act
PRD pressure release device
PRV pressure release valve
PSD Prevention of Significant Deterioration
psig pounds per square inch gauge
PTE potential to emit
PV present value
REC reduced emissions completion
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
RTC response to comments
SBAR Small Business Advocacy Review
SC-CH4 social cost of methane
SCF significant contribution finding
scf standard cubic feet
scfh standard cubic feet per hour
scfm standard cubic feet per minute
SF6 sulfur hexafluoride
SIP State Implementation Plan
SO2 sulfur dioxide
SOX sulfur oxides
tpy tons per year
D.C. Circuit U.S. Court of Appeals for the District of Columbia 
Circuit
TAR Tribal Authority Rule
TIP Tribal Implementation Plan
TSD technical support document
TTN Technology Transfer Network
UAS unmanned aircraft systems
UIC underground injection control
UMRA Unfunded Mandates Reform Act
U.S. United States
USGCRP U.S. Global Change Research Program
USGS U.S. Geologic Survey
VCS Voluntary Consensus Standards
VOC volatile organic compounds
VRD vapor recovery device
VRU vapor recovery unit

    Organization of this document. The information in this preamble is 
organized as follows:

I. Executive Summary
    A. Purpose of the Regulatory Action
    B. Summary of the Major Provisions of This Regulatory Action
    C. Costs and Benefits
II. General Information
    A. Does this action apply to me?
    B. How do I obtain a copy of this document, background 
information, other related information?
III. Air Emissions From the Crude Oil and Natural Gas Sector and 
Public Health and Welfare
    A. Impacts of GHGs, VOC and SO2 Emissions on Public 
Health and Welfare
    B. Oil and Natural Gas Industry and Its Emissions
IV. Statutory Background and Regulatory History
    A. Statutory Background of CAA Sections 111(b), 111(d) and 
General Implementing Regulations
    B. What is the regulatory history and litigation background of 
NSPS and EG for the oil and natural gas industry?
    C. Effect of the CRA
V. Related Emissions Reduction Efforts
    A. Related State Actions and Other Federal Actions Regulating 
Oil and Natural Gas Sources
    B. Industry and Voluntary Actions To Address Climate Change
VI. Environmental Justice Considerations, Implications, and 
Stakeholder Outreach
    A. Environmental Justice and the Impacts of Climate Change
    B. Impacted Stakeholders
    C. Outreach and Engagement
    D. Environmental Justice Considerations
VII. Other Stakeholder Outreach
    A. Educating the Public, Listening Sessions, and Stakeholder 
Outreach
    B. EPA Methane Detection Technology Workshop
    C. How is this information being considered in this proposal?
VIII. Legal Basis for Proposal Scope
    A. Recent History of the EPA's Regulation of Oil and Gas Sources 
and Congress's Response
    B. Implications of Congress's Disapproval of the 2020 Policy 
Rule
    C. Alternative Conclusion Affirming the Legal Interpretations in 
the 2016 Rule
    D. Impacts on Regulation of Methane Emissions From Existing 
Sources
IX. Overview of Control and Control Costs
    A. Control of Methane and VOC Emissions in the Crude Oil and 
Natural Gas Source Category--Overview
    B. How does EPA evaluate control costs in this action?
X. Summary of Proposed Action for NSPS OOOOa
    A. Amendments to Fugitive Emissions Monitoring Frequency
    B. Technical and Implementation Amendments
XI. Summary of Proposed NSPS OOOOb and EG OOOOc
    A. Fugitive Emissions From Well Sites and Compressor Stations

[[Page 63113]]

    B. Storage Vessels
    C. Pneumatic Controllers
    D. Well Liquids Unloading Operations
    E. Reciprocating Compressors
    F. Centrifugal Compressors
    G. Pneumatic Pumps
    H. Equipment Leaks at Natural Gas Processing Plants
    I. Well Completions
    J. Oil Wells With Associated Gas
    K. Sweetening Units
    L. Centralized Production Facilities
    M. Recordkeeping and Reporting
    N. Prevention of Significant Deterioration and Title V 
Permitting
XII. Rationale for Proposed NSPS OOOOb and EG OOOOc
    A. Proposed Standards for Fugitive Emissions From Well Sites and 
Compressor Stations
    B. Proposed Standards for Storage Vessels
    C. Proposed Standards for Pneumatic Controllers
    D. Proposed Standards for Well Liquids Unloading Operations
    E. Proposed Standards for Reciprocating Compressors
    F. Proposed Standards for Centrifugal Compressors
    G. Proposed Standards for Pneumatic Pumps
    H. Proposed Standards for Equipment Leaks at Natural Gas 
Processing Plants
    I. Proposed Standards for Well Completions
    J. Proposed Standards for Oil Wells With Associated Gas
    K. Proposed Standards for Sweetening Units
XIII. Solicitations for Comment on Additional Emission Sources and 
Definitions
    A. Abandoned Wells
    B. Pigging Operations and Related Blowdown Activities
    C. Tank Truck Loading
    D. Control Device Efficiency and Operation
    E. Definition of Hydraulic Fracturing
XIV. State, Tribal, and Federal Plan Development for Existing 
Sources
    A. Overview
    B. Components of EG
    C. Establishing Standards of Performance in State Plans
    D. Components of State Plan Submission
    E. Timing of State Plan Submissions and Compliance Times
    F. EPA Action on State Plans and Promulgation of Federal Plans
    G. Tribes and The Planning Process Under CAA Section 111(d)
XV. Prevention of Significant Deterioration and Title V Permitting
    A. Overview
    B. Applicability of Tailoring Rule Thresholds Under the PSD 
Program
    C. Implications for Title V Program
XVI. Impacts of This Proposed Rule
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the compliance costs?
    D. What are the economic and employment impacts?
    E. What are the benefits of the proposed standards?
XVII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act (NTTAA)
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

I. Executive Summary

A. Purpose of the Regulatory Action

    This proposed rulemaking takes a significant step forward in 
mitigating climate-destabilizing pollution and protecting human health 
by reducing GHG and VOC emissions from the Oil and Natural Gas 
Industry,\1\ specifically the Crude Oil and Natural Gas source 
category.\2\ The Oil and Natural Gas Industry is the United States' 
largest industrial emitter of methane, a highly potent GHG. Human 
activity-related emissions of methane are responsible for about one 
third of the warming due to well-mixed GHGs and constitute the second 
most important warming agent arising from human activity after carbon 
dioxide (a well-mixed gas is one with an atmospheric lifetime longer 
than a year or two, which allows the gas to be mixed around the world, 
meaning that the location of emission of the gas has little importance 
in terms of its impacts). According to the Intergovernmental Panel on 
Climate Change (IPCC), strong, rapid, and sustained methane reductions 
are critical to reducing near-term disruption of the climate system and 
are a vital complement to reductions in other GHGs that are needed to 
limit the long-term extent of climate change and its destructive 
impacts. The Oil and Natural Gas Industry also emits other harmful 
pollutants in varying concentrations and amounts, including carbon 
dioxide (CO2), VOC, sulfur dioxide (SO2), 
nitrogen oxide (NOX), hydrogen sulfide (H2S), 
carbon disulfide (CS2), and carbonyl sulfide (COS), as well 
as benzene, toluene, ethylbenzene, and xylenes (this group is commonly 
referred to as ``BTEX''), and n-hexane.
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    \1\ The EPA characterizes the Oil and Natural Gas Industry 
operations as being generally composed of four segments: (1) 
Extraction and production of crude oil and natural gas (``oil and 
natural gas production''), (2) natural gas processing, (3) natural 
gas transmission and storage, and (4) natural gas distribution.
    \2\ The EPA defines the Crude Oil and Natural Gas source 
category to mean (1) crude oil production, which includes the well 
and extends to the point of custody transfer to the crude oil 
transmission pipeline or any other forms of transportation; and (2) 
natural gas production, processing, transmission, and storage, which 
include the well and extend to, but do not include, the local 
distribution company custody transfer station. For purposes of this 
proposed rulemaking, for crude oil, the EPA's focus is on operations 
from the well to the point of custody transfer at a petroleum 
refinery, while for natural gas, the focus is on all operations from 
the well to the local distribution company custody transfer station 
commonly referred to as the ``city-gate''.
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    Under the authority of CAA section 111, this rulemaking proposes 
comprehensive standards of performance for GHG emissions (in the form 
of methane limitations) and VOC emissions for new, modified, and 
reconstructed sources in the Crude Oil and Natural Gas source category, 
including the production, processing, transmission and storage 
segments. For designated facilities,\3\ this rulemaking proposes EG 
containing presumptive standards for GHG in the form of methane 
limitations. When finalized, States shall utilize these EG to submit to 
the EPA plans that establish standards of performance for designated 
facilities and provide for implementation and enforcement of such 
standards. The EPA will provide support for States in developing their 
plans to reduce methane emissions from designated facilities within the 
Crude Oil and Natural Gas source category.
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    \3\ The term ``designated facility'' means ``any existing 
facility which emits a designated pollutant and which would be 
subject to a standard of performance for that pollutant if the 
existing facility were an affected facility.'' See 40 CFR 60.21a(b).
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    The EPA is proposing these actions in accordance with its legal 
obligations and authorities following a review directed by E.O. 13990, 
``Protecting Public Health and the Environment and Restoring Science to 
Tackle the Climate Crisis,'' issued on January 20, 2021. The EPA 
intends for these proposed actions to address the far-reaching harmful 
consequences and real economic costs of climate change. According to 
the IPCC AR6 assessment, ``It is unequivocal that human influence has 
warmed the atmosphere, ocean and land. Widespread and rapid changes in 
the atmosphere, ocean, cryosphere and biosphere have occurred.'' The 
IPCC AR6 assessment states these changes have led to increases in heat 
waves and wildfire weather, reductions in air quality, more intense 
hurricanes and

[[Page 63114]]

rainfall events, and rising sea level. These changes, along with future 
projected changes, endanger the physical survival, health, economic 
well-being, and quality of life of people living in the United States 
(U.S.), especially those in the most vulnerable communities.
    Methane is both the main component of natural gas and a potent GHG. 
One ton of methane in the atmosphere has 80 times the warming impact of 
a ton of CO2, and contributes to the creation of ground-
level ozone which is another greenhouse gas. Because methane has a 
shorter lifetime than CO2, it has a smaller relative 
impact--although still significantly greater than CO2--when 
considering longer time periods. One standard metric is the 100-year 
global warming potential (GWP), which is a measure of the climate 
impact of emissions of one ton a greenhouse gas over 100 years relative 
to the impact of the emissions of one ton of CO2. Even over 
this long timeframe, methane has a 100-year GWP of almost 30. The IPCC 
AR6 assessment found that ``Over time scales of 10 to 20 years, the 
global temperature response to a year's worth of current emissions of 
SLCFs (short lived climate forcer) is at least as large as that due to 
a year's worth of CO2 emissions.'' \4\ The IPCC estimated 
that, depending on the reference scenario, collective reductions in 
these SLCFs (methane, ozone precursors, and HFCs) could reduce warming 
by 0.2 degrees Celsius ([deg]C) (more than one-third of a degree 
Fahrenheit ([deg]F) in 2040 and 0.8 [deg]C (almost 1.5 [deg]F) by the 
end of the century, which is important in the context of keeping 
warming to well below 2 [deg]C (3.6 [deg]F). As methane is the most 
important SLCF, this makes methane mitigation one of the best 
opportunities for reducing near term warming. Emissions from human 
activities have already more than doubled atmospheric methane 
concentrations since 1750, and that concentration has been growing 
larger at record rates in recent years.\5\ In the absence of additional 
reduction policies, methane emissions are projected to continue rising 
through at least 2040.
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    \4\ However, the IPCC AR6 assessment cautioned that ``The 
effects of the SLCFs decay rapidly over the first few decades after 
pulse emission. Consequently, on time scales longer than about 30 
years, the net long-term temperature effects of sectors and regions 
are dominated by CO2.''
    \5\ Naik, V., S. Szopa, B. Adhikary, P. Artaxo, T. Berntsen, 
W.D. Collins, S. Fuzzi, L. Gallardo, A. Kiendler 41 Scharr, Z. 
Klimont, H. Liao, N. Unger, P. Zanis, 2021, Short-Lived Climate 
Forcers. In: Climate Change 42 2021: The Physical Science Basis. 
Contribution of Working Group I to the Sixth Assessment Report of 
the 43 Intergovernmental Panel on Climate Change [Masson-Delmotte, 
V., P. Zhai, A. Pirani, S.L. Connors, C. 44 P[eacute]an, S. Berger, 
N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. 
Lonnoy, J.B.R. 45 Matthews, T.K. Maycock, T. Waterfield, O. 
Yelek[ccedil]i, R. Yu and B. Zhou (eds.)]. Cambridge University 46 
Press. In Press.
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    Methane's radiative efficiency means that immediate reductions in 
methane emissions, including from sources in the Crude Oil and Natural 
Gas source category, can help reduce near-term warming. As natural gas 
is comprised primarily of methane, every natural gas leak, or 
intentional release of natural gas through venting or other processes, 
constitutes a release of methane. Reducing human-caused methane 
emissions, such as controlling natural gas leaks and releases as 
proposed in these actions, would contribute substantially to global 
efforts to limit temperature rise, aiding efforts to remain well below 
2 [deg]C above pre-industrial levels. See preamble section III for 
further discussion on the Crude Oil and Natural Gas Emissions and 
Climate Change, including discussion of the GHGs, VOCs, and 
SO2 Emissions on Public Health and Welfare.
    Methane and VOC emissions from the Crude Oil and Natural Gas source 
category result from a variety of industry operations across the supply 
chain. As natural gas moves through the necessarily interconnected 
system of exploration, production, storage, processing, and 
transmission that brings it from wellhead to commerce, emissions 
primarily result from intentional venting, unintentional gas carry-
through (e.g., vortexing from separator drain, improper liquid level 
settings, liquid level control valve on an upstream separator or 
scrubber does not seat properly at the end of an automated liquid 
dumping event, inefficient separation of gas and liquid phases occurs 
upstream of tanks allowing some gas carry-through), routine 
maintenance, unintentional fugitive emissions, flaring, malfunctions, 
abnormal process conditions, and system upsets. These emissions are 
associated with a range of specific equipment and practices, including 
leaking valves, connectors, and other components at well sites and 
compressor stations; leaks and vented emissions from storage vessels; 
releases from natural gas-driven pneumatic pumps and controllers; 
liquids unloading at well sites; and venting or under-performing 
flaring of associated gas from oil wells. But technical innovations 
have produced a range of technologies and best practices to monitor, 
eliminate or minimize these emissions, which in many cases have the 
benefit of reducing multiple pollutants at once and recovering saleable 
product. These technologies and best practices have been deployed by 
individual oil and natural gas companies, required by State 
regulations, or reflected in regulations issued by the EPA and other 
Federal agencies.
    In this action, the EPA has taken a comprehensive analysis of the 
available data from emission sources in the Crude Oil and Natural Gas 
source category and the latest available information on control 
measures and techniques to identify achievable, cost-effective measures 
to significantly reduce emissions, consistent with the requirements of 
section 111 of the CAA. If finalized and implemented, the actions 
proposed in this rulemaking would lead to significant and cost-
effective reductions in climate and health-harming pollution and 
encourage development and deployment of innovative technologies to 
further reduce this pollution in the Crude Oil and Natural Gas source 
category. The actions proposed in this rulemaking would:
     Update, strengthen, and expand current requirements under 
CAA section 111(b) for methane and VOC emissions from new, modified, 
and reconstructed facilities,
     establish new limits for methane, and VOC emissions from 
new, modified, and reconstructed facilities that are not currently 
regulated under CAA section 111(b),
     establish the first nationwide EG for States to limit 
methane pollution from existing designated facilities in the source 
category under CAA section 111(d), and
     take comment on additional sources of pollution that, with 
understanding gained from more information, may offer opportunities for 
emission reductions, which the EPA would present in a supplemental 
rulemaking proposal under both CAA section 111(b) and (d).
    In developing this proposal, the EPA drew on its own prior 
experience in regulating sources in the Crude Oil and Natural Gas 
source category under section 111 and other CAA programs; applied 
lessons learned from States' regulatory efforts, the emission reduction 
efforts of leading companies, and the EPA's long-standing voluntary 
emission reduction programs; and reviewed the latest available 
information about new and developing technologies, as well as, peer-
reviewed research from emission measurement campaigns across the U.S. 
Further, the EPA undertook extensive pre-proposal outreach to the 
public and to stakeholders, including three full days

[[Page 63115]]

of public listening sessions, roundtables with State energy and 
environmental regulators, a two-day workshop on innovative methane 
detection technologies, and a nonregulatory docket established in May 
2021 to receive written comments. Through this outreach, the EPA heard 
from diverse voices and perspectives including State and local 
governments, Tribal nations, communities affected by oil and gas 
pollution, environmental and public health organizations, and 
representatives of the oil and natural gas industry, all of which 
provided ideas and information that helped shape and inform this 
proposal.
    The EPA also considered community and environmental justice 
implications in the development of this proposal and sought to ensure 
equitable treatment and meaningful involvement of all people regardless 
of race, color, national origin, or income in the process. The EPA 
engaged and consulted representatives of frontline communities that are 
directly affected by and particularly vulnerable to the climate and 
health impacts of pollution from this source category through 
interactions such as webinars, listening sessions and meetings. These 
opportunities allowed the EPA to hear directly from the public, 
especially overburdened and underserved communities, on the development 
of the proposed rule and to factor these concerns into this proposal. 
For example, in addition to establishing EG that extend fugitive 
emission requirements to existing oil and natural gas facilities, the 
EPA is proposing to expand leak detection programs already in effect 
for new sources to include known sources of large emission events and 
proposing to require more frequent monitoring at sites with more 
emissions. The EPA is also taking comment on innovative mechanisms to 
ensure compliance and minimize emissions, including the possibility of 
providing a pathway for communities to detect and report large emitting 
events that may require follow-up and mitigation by owners and 
operators. The extensive pollution reduction measures in this proposal, 
if finalized, would collectively reduce a suite of harmful pollutants 
and their associated health impacts in communities adjacent to these 
emission sources. Further, to help ensure that the needs and 
perspectives of communities with environmental justice concerns are 
considered as States develop plans to establish and implement standards 
of performance for existing sources, the EPA is proposing to require 
that States demonstrate they have undertaken meaningful outreach and 
engagement with overburdened and underserved communities as part of 
their State plan submissions under the EPA. A full discussion of the 
Environmental Justice Considerations, Implications, and Stakeholder 
Outreach can be found in section VI of the preamble. A full discussion 
of Other Stakeholder Outreach is found in section VII of the preamble.
    As described in more detail below, the EPA recognizes that several 
States and other Federal agencies currently regulate the Oil and 
Natural Gas Industry. The EPA also recognizes that these State and 
other Federal agency regulatory programs have matured since the EPA 
began implementing the current NSPS requirements in 2012 and 2016. The 
EPA further acknowledges the technical innovations that the Oil and 
Natural Gas Industry has made during the past decade; this industry 
operates at a fast pace and changes constantly as technology evolves. 
The EPA commends these efforts and recognizes States for their 
innovative standards, alternative compliance options, and 
implementation strategies, and intends these proposed actions to build 
upon progress made by certain States and Federal agencies in reducing 
GHG and VOC emissions. See preamble section V for fuller discussion of 
Related State Actions and Other Federal Actions Regulating Oil and 
Natural Gas Sources and Industry and Voluntary Actions to Address 
Climate Change.
    The EPA believes that a broad ensemble of mutually leveraging 
efforts across all States and all Federal agencies is essential to 
meaningfully address climate change effectively. As the Federal agency 
with primary responsibility to protect human health and the 
environment, the EPA has the unique responsibility and authority to 
regulate harmful air pollutants emitted by the Crude Oil and Natural 
Gas source category. The EPA recognizes that States and other Federal 
agencies regulate in accordance with their respective legal authorities 
and within their respective jurisdictions but collectively do not fully 
and consistently address the range of sources and emission reduction 
measures contained in this proposal. Direct Federal regulation of 
methane from new, reconstructed, and modified sources in this category, 
combined with approved State plans that are consistent with the EPA's 
presumptive standards for designated facilities (existing sources), 
will help reduce both climate- and other health-harming pollution from 
a large number of sources that are either unregulated or from which 
additional, cost-effective reductions are available, level the 
regulatory playing field, and help promote technological innovation.
    Throughout this action, unless noted otherwise, the EPA is 
requesting comments on all aspects of the proposal to enable the EPA to 
develop a final rule that, consistent with our responsibilities under 
section 111 of the CAA, achieves the greatest possible reductions in 
methane and VOC emissions while remaining achievable, cost effective, 
and conducive to technological innovation. As a further step in the 
rulemaking process and to solicit additional public input, the EPA 
plans to issue a supplemental proposal and supplemental RIA for the 
supplemental proposal to provide regulatory text for the proposed NSPS 
OOOOb and EG OOOOc. In light of certain innovative elements of this 
proposed rule and the EPA's request for information that would support 
the regulation of additional sources in the Crude Oil and Natural Gas 
source category as part of this rulemaking, the EPA is considering 
including additional provisions in this supplemental proposal and RIA 
based on information and comment collected in response to this 
document.
    As noted later in this preamble, the supplemental proposal may 
address, among other issues: (1) Ways to mitigate methane from 
abandoned wells, (2) measures to reduce emissions from pipeline pigging 
operations and other pipeline blowdowns, (3) ways to minimize emissions 
from tank truck loading operations, and (4) ways to strengthen 
requirements to ensure proper operation and optimal performance of 
control devices. In addition, and as noted in the solicitations of 
comment in this document, the supplemental proposal may revisit and 
refine certain provisions of this proposal in response to information 
provided by the public. For instance, the EPA is seeking input on 
multiple aspects of the proposed approach for fugitive emissions 
monitoring at well sites, including the baseline emission threshold and 
other criteria (such as the presence of specific types of malfunction-
prone equipment) that should be used to determine whether a well site 
is required to undertake ongoing fugitive emissions monitoring; the 
methodology for calculating baseline methane emissions and whether it 
should account for malfunctions or improper operation of controls at 
storage vessels; and ways to ensure that emissions from wells owned by 
small businesses are addressed while still recognizing the greater 
challenges that small businesses with less dedicated staff and 
resources for

[[Page 63116]]

environmental compliance may have. The EPA is also seeking input on 
ways to ensure that captured associated gas is collected for a useful 
purpose rather than flared, and the feasibility of requiring broader 
use of zero-emitting technology for pneumatic pumps.
    Finally, the EPA is seeking comment and information on alternative 
measurement technologies, which we are proposing to allow in the rule. 
We have heard strong interest from various stakeholders on employing 
new tools for methane identification and quantification, particularly 
for large emission sources (commonly known as ``super-emitters''). 
Information provided in response to this proposal may be used to 
evaluate whether a change in BSER from the proposed quarterly OGI 
monitoring to a monitoring program using alternative measurement 
technologies is appropriate. Separate from the role of these 
alternative measurement technologies in a regulatory monitoring 
program, we are also soliciting comment on ways to structure a pathway 
for communities to identify large emission events which owners or 
operators would then be required to investigate, and mechanisms for the 
collection and public dissemination of this information, for possible 
further development as part of a supplemental proposal.
    This preamble includes comment solicitations/requests on several 
topics and issues. We have prepared a separate memorandum that presents 
these comment requests by section and topic as a guide to assist 
commenters in preparing comments. This memorandum can be obtained from 
the Docket for this action (see Docket ID No. EPA-HQ-OAR-2021-0317). 
The title of the memorandum is ``Standards of Performance for New, 
Reconstructed, and Modified Sources and Emissions Guidelines for 
Existing Sources: Oil and Natural Gas Sector Climate Review--Proposed 
Rule Summary of Comment Solicitations.''

B. Summary of the Major Provisions of This Regulatory Action

    This proposed rulemaking includes three distinct groups of actions 
under the CAA that are each severable from the other. First, pursuant 
to CAA 111(b)(1)(B), the EPA has reviewed, and is proposing revisions 
to, the standards of performance for the Crude Oil and Natural Gas 
source category published in 2016 and amended in 2020, codified at 40 
CFR part 60, subpart OOOOa--Standards of Performance for Crude Oil and 
Natural Gas Facilities for which Construction, Modification or 
Reconstruction Commenced After September 18, 2015 (2016 NSPS OOOOa). 
Specifically, the EPA is proposing to update, strengthen, and expand 
the current requirements under CAA section 111(b) for methane and VOC 
emissions from sources that commenced construction, modification, or 
reconstruction after November 15, 2021. These proposed standards of 
performance will be in a new subpart, 40 CFR part 60, subpart OOOOb 
(NSPS OOOOb), and include standards for emission sources previously not 
regulated under the 2016 NSPS OOOOa.
    Second, pursuant to CAA 111(d), the EPA is proposing the first 
nationwide EG for States to limit methane pollution from designated 
facilities in the Crude Oil and Natural Gas source category. The EG 
being proposed in this rulemaking will be in a new subpart, 40 CFR part 
60, subpart OOOOc (EG OOOOc). The EG are designed to inform States in 
the development, submittal, and implementation of State plans that are 
required to establish standards of performance for GHGs from their 
designated facilities in the Crude Oil and Natural Gas source category.
    Third, the EPA is taking several related actions stemming from the 
joint resolution of Congress, adopted on June 30, 2021 under the CRA, 
disapproving the EPA's final rule titled, ``Oil and Natural Gas Sector: 
Emission Standards for New, Reconstructed, and Modified Sources 
Review,'' 85 FR 57018 (Sept. 14, 2020) (``2020 Policy Rule''). As 
explained in Section X of this action (Summary of Proposed Action for 
NSPS OOOOa), the EPA is proposing amendments to the 2016 NSPS OOOOa to 
address (1) certain inconsistencies between the VOC and methane 
standards resulting from the disapproval of the 2020 Policy Rule, and 
(2) certain determinations made in the final rule titled ``Oil and 
Natural Gas Sector: Emission Standards for New, Reconstructed, and 
Modified Sources Reconsideration,'' 85 FR 57398 (September 15, 2020) 
(2020 Technical Rule), specifically with respect to fugitive emissions 
monitoring at low production well sites and gathering and boosting 
stations. With respect to the latter, as described below, the EPA is 
proposing to rescind provisions of the 2020 Technical Rule that were 
not supported by the record for that rule, or by our subsequent 
information and analysis. The regulatory text for these proposed 
amendments is included in the docket for this rulemaking at Docket ID 
EPA-HQ-OAR-2021-0317.
    In addition, in the final rule for this action, the EPA will update 
the NSPS OOOO and NSPS OOOOa provisions in the Code of Federal 
Regulations (CFR) to reflect the Congressional Review Act (CRA) 
resolution's disapproval of the final 2020 Policy Rule, specifically, 
the reinstatement of the NSPS OOOO and NSPS OOOOa requirements that the 
2020 Policy Rule repealed but that came back into effect immediately 
upon enactment of the CRA resolution. It should be noted that these 
requirements have come back into effect already even though the EPA has 
not yet updated the CFR text to reflect them.\6\ These updates to the 
CFR text are also included in the docket for this rulemaking at Docket 
ID EPA-HQ-OAR-2021-0317 for public awareness, but the EPA is not 
soliciting comment on them as they merely reflect current law. Under 5 
U.S.C. 553(b)(3)(B), notice and comment is not required ``when the 
agency for good cause finds . . . that notice and public procedure 
thereon are . . . unnecessary . . . ,'' \7\ and, as just noted, notice 
and comment is not necessary for these updates. The EPA is waiting to 
make these updates to the CFR text until the final rule simply because 
it would be more efficient and clearer to amend the CFR once at the end 
of this rulemaking process to account for all changes to the 2012 NSPS 
OOOO (77 FR 49490, August 16, 2012) and 2016 NSPS OOOOa at the same 
time.
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    \6\ See Congressional Review Act Resolution to Disapprove EPA's 
2020 Oil and Gas Policy Rule Questions and Answers (June 30, 2021) 
available at https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf.
    \7\ 5 U.S.C. 553(b)(3)(B) is applicable to rules promulgated 
under CAA section 111(b), under CAA section 307(d)(1) (flush 
language at end).
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    As CAA section 111(a)(1) requires, the standards of performance 
being proposed in this action reflect ``the degree of emission 
limitation achievable through the application of the best system of 
emission reduction [BSER] which (taking into account the cost of 
achieving such reduction and any non-air quality health and 
environmental impact and energy requirement) the Administrator 
determines has been adequately demonstrated.'' This action further 
proposes EG for designated facilities, under which States must submit 
plans which establish standards of performance that reflect the degree 
of emission limitation achievable through application of the BSER, as 
identified in the final EG. In this proposed rulemaking, we evaluated 
potential control measures available for the affected facilities, the 
emission reductions achievable through these measures, and employed 
multiple approaches to evaluate the reasonableness of control costs 
associated with the options under

[[Page 63117]]

consideration. For example, in evaluating controls for reducing VOC and 
methane emissions from new sources, we considered a control measure's 
cost-effectiveness under both a ``single pollutant cost-effectiveness'' 
approach and a ``multipollutant cost-effectiveness'' approach, to 
appropriately consider that the systems of emission reduction 
considered in this rule typically achieve reductions in multiple 
pollutants at once and secure a multiplicity of climate and public 
health benefits. For a detailed discussion of the EPA's consideration 
of this and other BSER statutory elements, please see sections IV and 
IX of this preamble.

  Table 1--Applicability Dates for Proposed Subparts Addressed in This
                             Proposed Action
------------------------------------------------------------------------
           Subpart                 Source type        Applicable dates
------------------------------------------------------------------------
40 CFR part 60, subpart OOOO  New, modified, or     After August 23,
                               reconstructed         2011 and on or
                               sources.              before September
                                                     18, 2015.
40 CFR part 60, subpart       New, modified, or     After September 18,
 OOOOa.                        reconstructed         2015 and on or
                               sources.              before November 15,
                                                     2021.
40 CFR part 60, subpart       New, modified, or     After November 15,
 OOOOb.                        reconstructed         2021.
                               sources.
40 CFR part 60, subpart       Existing sources....  On or before
 OOOOc.                                              November 15, 2021.
------------------------------------------------------------------------

1. Proposed Standards for New, Modified and Reconstructed Sources After 
November 15, 2021 (Proposed NSPS OOOOb)
    As described in sections XI and XII of this preamble, under the 
authority of CAA section 111(b)(1)(B) the EPA has reviewed the VOC, GHG 
(in the form of limitations on methane), and SO2 standards 
in the 2016 NSPS OOOOa (as amended in 2020 by the Technical Rule). 
Based on its review, the EPA is proposing revisions to the standards 
for certain emissions sources to reflect the updated BSER for those 
affected sources. Where our analyses show that the BSER for an affected 
source remains the same, the EPA is proposing to retain the current 
standard for that affected source. In addition, the EPA is proposing 
methane and VOC standards for several new sources that are currently 
unregulated. The proposed NSPS described above would apply to new, 
modified, and reconstructed emission sources across the Crude Oil and 
Natural Gas source category, including the production, processing, 
transmission, and storage segments, for which construction, 
reconstruction, or modification commenced after November 15, 2021, 
which is the date of publication of the proposed revisions to the NSPS. 
In particular, this action proposes to retain the 2016 NSPS OOOOa 
SO2 performance standard for sweetening units and the 2016 
OOOOa VOC and methane performance standards for well completions and 
centrifugal compressors; proposes revisions to strengthen the 2016 NSPS 
OOOOa VOC and methane standards addressing fugitive emissions from well 
sites and compressor stations, storage vessels, pneumatic controllers, 
reciprocating compressors, pneumatic pumps, and equipment leaks at 
natural gas processing plants; and proposes new VOC and methane 
standards for well liquids unloading operations and intermittent vent 
pneumatic controllers, and oil wells with associated gas previously not 
regulated in the 2016 NSPS OOOOa. A summary of the proposed BSER 
determination and proposed NSPS for new, modified, and reconstructed 
sources (NSPS OOOOb) is presented in Table 2. See sections XI and XII 
of this preamble for a complete discussion of BSER determination and 
proposed NSPS requirements.
    This proposal also solicits certain information relevant to the 
potential identification of additional emissions sources as affected 
facilities. Specifically, the EPA is evaluating the potential for 
establishing standards for abandoned and unplugged wells, blowdown 
emissions associated with pipeline pig launchers and receivers, and 
tank truck loading operations. While the EPA has assessed these sources 
based on currently available information, we have determined that we 
need additional information to evaluate BSER and to propose NSPS for 
these emissions sources. A full discussion of the solicitation for 
comment regarding these additional emission sources is found in section 
XIII of the preamble.
2. Proposed EG for Sources Constructed Prior to November 15, 2021 
(Proposed EG OOOOc)
    As described in sections XI and XII of this preamble, under the 
authority of CAA section 111(d), the EPA is proposing the first 
nationwide EG for GHG (in the form of methane limitations) for the 
Crude Oil and Natural Gas source category, including the production, 
processing, transmission, and storage segments (EG OOOOc). When the EPA 
establishes NSPS for a source category, the EPA is required to issue EG 
to reduce emissions of certain pollutants from existing sources in that 
same source category. In such circumstances, under CAA section 111(d), 
the EPA must issue regulations to establish procedures under which 
States submit plans to establish, implement, and enforce standards of 
performance for existing sources for certain air pollutants to which a 
Federal NSPS would apply if such existing source were a new source. 
Thus, the issuance of CAA section 111(d) final EG does not impose 
binding requirements directly on sources but instead provides 
requirements for states in developing their plans. Although State plans 
bear the obligation to establish standards of performance, under CAA 
sections 111(a)(1) and 111(d), those standards of performance must 
reflect the degree of emission limitation achievable through the 
application of the BSER as determined by the Administrator. As provided 
in section 111(d), a State may choose to take into account remaining 
useful life and other factors in applying a standard of performance to 
a particular source, consistent with the CAA, the EPA's implementing 
regulations, and the final EG.
    In this action, the EPA is proposing BSER determinations and the 
degree of limitation achievable through application of the BSER for 
certain existing equipment, processes, and activities across the Crude 
Oil and Natural Gas source category. Section XIV of this preamble 
discusses the components of EG, including the steps, requirements, and 
considerations associated with the development, submittal, and 
implementation of State, Tribal, and Federal plans, as appropriate. For 
the EG, the EPA is proposing to translate the degree of emission 
limitation achievable through application of the BSER (i.e., level of 
stringency) into presumptive standards that States may use in the 
development of State plans for specific designated facilities. By doing 
this, the EPA has formatted the proposed EG such that if a State 
chooses to adopt these

[[Page 63118]]

presumptive standards, once finalized, as the standards of performance 
in a State plan, the EPA could approve such a plan as meeting the 
requirements of CAA section 111(d) and the finalized EG, if the plan 
meets all other applicable requirements. In this way, the presumptive 
standards included in the EG serve a function similar to that of a 
model rule,\8\ because they are intended to assist States in developing 
their plan submissions by providing States with a starting point for 
standards that are based on general industry parameters and 
assumptions. The EPA believes that providing these presumptive 
standards will create a streamlined approach for States in developing 
plans and the EPA in evaluating State plans. However, the EPA's action 
on each State plan submission is carried out via rulemaking, which 
includes public notice and comment. Inclusion of presumptive standards 
in the EG does not seek to pre-determine the outcomes of any future 
rulemaking.
---------------------------------------------------------------------------

    \8\ The presumptive standards are not the same as a Federal plan 
under CAA section 111(d)(2). The EPA has an obligation to promulgate 
a Federal plan if a state fails to submit a satisfactory plan. In 
such circumstances, the final EG and presumptive standards would 
serve as a guide to the development of a Federal plan. See section 
XIV.F. for information on Federal plans.
---------------------------------------------------------------------------

    Designated facilities located in Indian country would not be 
encompassed within a State's CAA section 111(d) plan. Instead, an 
eligible Tribe that has one or more designated facilities located in 
its area of Indian country would have the opportunity, but not the 
obligation, to seek authority and submit a plan that establishes 
standards of performance for those facilities on its Tribal lands. If a 
Tribe does not submit a plan, or if the EPA does not approve a Tribe's 
plan, then the EPA has the authority to establish a Federal plan for 
that Tribe. A summary of the proposed EG for existing sources (EG 
OOOOc) for the oil and natural gas sector is presented in Table 3. See 
sections XI and XII of this preamble for a complete discussion of the 
proposed EG requirements.
    As discussed above for the proposed NSPS OOOOb, the EPA is 
considering including additional sources as affected facilities in a 
potential future supplemental rulemaking proposal \9\ under CAA section 
111(b). The EPA is also considering including these additional sources 
as designated facilities under the EG in OOOOc in a potential future 
supplemental rulemaking proposal under CAA section 111(d). As with the 
proposed NSPS OOOOb, the EPA is evaluating the potential for 
establishing EG applicable to abandoned and unplugged wells, blowdown 
emissions associated with pipeline pig launchers and receivers, and 
tank truck loading operations (assuming the EPA establishes NSPS for 
these emissions points). As described in section XIII of this preamble, 
the EPA is soliciting information to assist in this effort.
---------------------------------------------------------------------------

    \9\ A supplemental proposal would include an updated RIA.
---------------------------------------------------------------------------

3. Proposed Amendments to 2016 NSPS OOOOa, and CRA-Related CFR Updates
    The EPA is also proposing certain modifications to the 2016 NSPS 
OOOOa to address certain amendments to the VOC standards for sources in 
the production and processing segments finalized in the 2020 Technical 
Rule. Because the methane standards for the production and processing 
segments and all standards for the transmission and storage segment 
were removed from the 2016 NSPS OOOOa via the 2020 Policy Rule prior to 
the finalization of the 2020 Technical Rule, the latter amendments 
apply only to the 2016 NSPS OOOOa VOC standards for the production and 
processing segments. In this proposed rulemaking, the EPA also is 
proposing to apply some of the 2020 Technical Rule amendments to the 
methane standards for all industry segments and to VOC standards for 
the transmission and storage segment in the 2016 NSPS OOOOa. These 
amendments are associated with the requirements for well completions, 
pneumatic pumps, closed vent systems, fugitive emissions, alternative 
means of emission limitation (AMELs), onshore natural gas processing 
plants, as well as other technical clarifications and corrections. The 
EPA also is proposing to repeal the amendments in the 2020 Technical 
Rule that (1) exempted low production well sites from monitoring 
fugitive emissions and (2) changed monitoring of VOC emissions at 
gathering and boosting compressor stations from quarterly to 
semiannual, which currently apply only to VOC standards (not methane 
standards) from the production and processing segments. A summary of 
the proposed amendments to the 2016 OOOOa NSPS is presented in section 
X of this preamble.
    Lastly, in the final rule for this action, the EPA will update the 
NSPS OOOO and OOOOa provisions in the CFR to reflect the CRA 
resolution's disapproval of the final 2020 Policy Rule, specifically, 
the reinstatement of the OOOO and OOOOa requirements that the 2020 
Policy Rule repealed but that came back into effect immediately upon 
enactment of the CRA resolution. The EPA is waiting to make the updates 
to the CFR text until the final rule simply because it would be more 
efficient and clearer to amend the CFR once at the end of this 
rulemaking process to account for all changes to the 2012 NSPS OOOO and 
2016 NSPS OOOOa at the same time. In accordance with 5 U.S.C. 
553(b)(3)(B), the EPA is not soliciting comment on these updates.

 Table 2--Summary of Proposed BSER and Proposed Standards of Performance
                            for GHGS and VOC
                              [NSPS OOOOb]
------------------------------------------------------------------------
                                                   Proposed standards of
        Affected source           Proposed BSER     performance for GHGs
                                                          and VOCs
------------------------------------------------------------------------
Fugitive Emissions: Well Sites  Demonstrate        Perform survey to
 with Baseline Emissions >0 to   actual site        verify that actual
 <3 tpy \1\ Methane.             emissions are      site emissions are
                                 reflected in       reflected in
                                 calculation.       calculation.
Fugitive Emissions: Well Sites  Monitoring and     Quarterly OGI
 >=3 tpy Methane.                repair based on    monitoring following
                                 quarterly          appendix K.
                                 monitoring using   (Optional quarterly
                                 OGI \2\.           EPA Method 21
                                                    monitoring with 500
                                                    ppm defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.
(Co-proposal) Fugitive          Monitoring and     Semiannual OGI
 Emissions: Well Sites with      repair based on    monitoring following
 Baseline Emissions >=3 to <8    semiannual         appendix K.
 tpy Methane.                    monitoring using   (Optional semiannual
                                 OGI.               EPA Method 21
                                                    monitoring with 500
                                                    ppm defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.

[[Page 63119]]

 
(Co-proposal) Fugitive          Monitoring and     Quarterly OGI
 Emissions: Well Sites with      repair based on    monitoring following
 Baseline Emissions >=8 tpy      quarterly          appendix K.
 Methane.                        monitoring using   (Optional quarterly
                                 OGI.               EPA Method 21
                                                    monitoring with 500
                                                    ppm \3\ defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.
Fugitive Emissions: Compressor  Monitoring and     Quarterly OGI
 Stations.                       repair based on    monitoring following
                                 quarterly          appendix K.
                                 monitoring using   (Optional quarterly
                                 OGI.               EPA Method 21
                                                    monitoring with 500
                                                    ppm defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.
Fugitive Emissions: Well Sites  Monitoring and     Annual OGI monitoring
 and Compressor Stations on      repair based on    following appendix
 Alaska North Slope.             annual             K. (Optional annual
                                 monitoring using   EPA Method 21
                                 OGI.               monitoring with 500
                                                    ppm defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.
Fugitive Emissions: Well Sites  (Optional)         (Optional)
 and Compressor Stations.        Screening,         Alternative
                                 monitoring, and    bimonthly screening
                                 repair based on    with advanced
                                 bimonthly          measurement
                                 screening using    technology with
                                 an advanced        annual OGI
                                 measurement        monitoring following
                                 technology and     appendix K.
                                 annual
                                 monitoring using
                                 OGI.
Storage Vessels: A Single       Capture and route  95 percent reduction
 Storage Vessel or Tank          to a control       of VOC and methane.
 Battery with PTE \4\ of 6 tpy   device.
 or More of VOC.
Pneumatic Controllers: Natural  Use of zero-       VOC and methane
 Gas Driven that Vent to the     emissions          emission rate of
 Atmosphere.                     controllers.       zero.
Pneumatic Controllers: Alaska   Installation of    Natural gas bleed
 (at sites where onsite power    low-bleed          rate no greater than
 is not available--continuous    pneumatic          6 scfh.\5\
 bleed natural gas driven).      controllers.
Pneumatic Controllers: Alaska   Monitor and        OGI monitoring and
 (at sites where onsite power    repair through     repair of emissions
 is not available--              fugitive           from controller
 intermittent natural gas        emissions          malfunctions.
 driven).                        program.
Well Liquids Unloading........  Perform liquids    Each affected well
                                 unloading with     that unloads liquids
                                 zero methane or    employ techniques or
                                 VOC emissions.     technology(ies) that
                                 If this is not     eliminate or
                                 feasible for       minimize venting of
                                 safety or          emissions during
                                 technical          liquids unloading
                                 reasons, employ    events to the
                                 best management    maximum extent.
                                 practices to
                                 minimize venting.
                                                   Co Proposal Options:
                                                   Option One--Affected
                                                    facility would be
                                                    defined as every
                                                    well that undergoes
                                                    liquids unloading.
                                                   --If the method is
                                                    one that does not
                                                    result in any
                                                    venting to the
                                                    atmosphere, maintain
                                                    records specifying
                                                    the technology or
                                                    technique and record
                                                    instances where an
                                                    unloading event
                                                    results in
                                                    emissions.
                                                   --For unloading
                                                    technologies or
                                                    techniques that
                                                    result in venting to
                                                    the atmosphere,
                                                    implement BMPs \6\
                                                    to ensure that
                                                    venting is
                                                    minimized.
                                                   --Maintain BMPs as
                                                    records, and record
                                                    instances when they
                                                    were not followed.
                                                   Option Two--Affected
                                                    facility would be
                                                    defined as every
                                                    well that undergoes
                                                    liquids unloading
                                                    using a method that
                                                    is not designed to
                                                    eliminate venting.
                                                   --Wells that utilize
                                                    non-venting methods
                                                    would not be
                                                    affected facilities
                                                    that are subject to
                                                    the NSPS OOOOb.
                                                    Therefore, they
                                                    would not have
                                                    requirements other
                                                    than to maintain
                                                    records to document
                                                    that they used non-
                                                    venting liquids
                                                    unloading methods.
                                                   --The requirements
                                                    for wells that use
                                                    methods that vent
                                                    would be the same as
                                                    described above
                                                    under Option 1.
Wet Seal Centrifugal            Capture and route  Reduce emissions by
 Compressors (except for those   emissions from     95 percent.
 located at single well sites).  the wet seal
                                 fluid degassing
                                 system to a
                                 control device
                                 or to a process.
Reciprocating Compressors       Replace the        Replace the
 (except for those located at    reciprocating      reciprocating
 single well sites).             compressor rod     compressor rod
                                 packing based on   packing when
                                 annual             measured leak rate
                                 monitoring (when   exceeds 2 scfm based
                                 measured leak      on the results of
                                 rate exceeds 2     annual monitoring or
                                 scfm \7\) or       collect and route
                                 route emissions    emissions from the
                                 to a process.      rod packing to a
                                                    process through a
                                                    closed vent system
                                                    under negative
                                                    pressure.

[[Page 63120]]

 
Pneumatic Pumps: Natural Gas    A natural gas      A natural gas
 Processing Plants.              emission rate of   emission rate of
                                 zero.              zero from diaphragm
                                                    and piston pneumatic
                                                    pumps.
Pneumatic Pumps: Production     Route diaphragm    95 percent control of
 Segment.                        and piston         diaphragm and piston
                                 pneumatic pumps    pneumatic pumps if
                                 to an existing     there is an existing
                                 control device     control or process
                                 or process.        on site. 95 percent
                                                    control not required
                                                    if (1) routed to an
                                                    existing control
                                                    that achieves less
                                                    than 95 percent or
                                                    (2) it is
                                                    technically
                                                    infeasible to route
                                                    to the existing
                                                    control device or
                                                    process.
Pneumatic Pumps: Transmission   Route diaphragm    95 percent control of
 and Storage Segment.            pneumatic pumps    diaphragm pneumatic
                                 to an existing     pumps if there is an
                                 control device     existing control or
                                 or process.        process on site. 95
                                                    percent control not
                                                    required if (1)
                                                    routed to an
                                                    existing control
                                                    that achieves less
                                                    than 95 percent or
                                                    (2) it is
                                                    technically
                                                    infeasible to route
                                                    to the existing
                                                    control device or
                                                    process.
Well Completions: Subcategory   Combination of     Applies to each well
 1 (non-wildcat and non-         REC \8\ and the    completion operation
 delineation wells).             use of a           with hydraulic
                                 completion         fracturing.
                                 combustion
                                 device.
                                                   REC in combination
                                                    with a completion
                                                    combustion device;
                                                    venting in lieu of
                                                    combustion where
                                                    combustion would
                                                    present safety
                                                    hazards.
                                                   Initial flowback
                                                    stage: Route to a
                                                    storage vessel or
                                                    completion vessel
                                                    (frac tank, lined
                                                    pit, or other
                                                    vessel) and
                                                    separator.
                                                   Separation flowback
                                                    stage: Route all
                                                    salable gas from the
                                                    separator to a flow
                                                    line or collection
                                                    system, re-inject
                                                    the gas into the
                                                    well or another
                                                    well, use the gas as
                                                    an onsite fuel
                                                    source or use for
                                                    another useful
                                                    purpose that a
                                                    purchased fuel or
                                                    raw material would
                                                    serve. If
                                                    technically
                                                    infeasible to route
                                                    recovered gas as
                                                    specified above,
                                                    recovered gas must
                                                    be combusted. All
                                                    liquids must be
                                                    routed to a storage
                                                    vessel or well
                                                    completion vessel,
                                                    collection system,
                                                    or be re-injected
                                                    into the well or
                                                    another well.
                                                   The operator is
                                                    required to have
                                                    (and use) a
                                                    separator onsite
                                                    during the entire
                                                    flowback period.
Well Completions: Subcategory   Use of a           Applies to each well
 2 (exploratory and              completion         completion operation
 delineation wells and low-      combustion         with hydraulic
 pressure wells).                device.            fracturing.
                                                   The operator is not
                                                    required to have a
                                                    separator onsite.
                                                    Either: (1) Route
                                                    all flowback to a
                                                    completion
                                                    combustion device
                                                    with a continuous
                                                    pilot flame; or (2)
                                                    Route all flowback
                                                    into one or more
                                                    well completion
                                                    vessels and commence
                                                    operation of a
                                                    separator unless it
                                                    is technically
                                                    infeasible for a
                                                    separator to
                                                    function. Any gas
                                                    present in the
                                                    flowback before the
                                                    separator can
                                                    function is not
                                                    subject to control
                                                    under this section.
                                                    Capture and direct
                                                    recovered gas to a
                                                    completion
                                                    combustion device
                                                    with a continuous
                                                    pilot flame.
                                                   For both options (1)
                                                    and (2), combustion
                                                    is not required in
                                                    conditions that may
                                                    result in a fire
                                                    hazard or explosion,
                                                    or where high heat
                                                    emissions from a
                                                    completion
                                                    combustion device
                                                    may negatively
                                                    impact tundra,
                                                    permafrost, or
                                                    waterways.
Equipment Leaks at Natural Gas  LDAR \9\ with      LDAR with OGI
 Processing Plants.              bimonthly OGI.     following procedures
                                                    in appendix K.
Oil Wells with Associated Gas.  Route associated   Route associated gas
                                 gas to a sales     to a sales line. If
                                 line. If access    access to a sales
                                 to a sales line    line is not
                                 is not             available, the gas
                                 available, the     can be used as an
                                 gas can be used    onsite fuel source,
                                 as an onsite       used for another
                                 fuel source,       useful purpose that
                                 used for another   a purchased fuel or
                                 useful purpose     raw material would
                                 that a purchased   serve, or routed to
                                 fuel or raw        a flare or other
                                 material would     control device that
                                 serve, or routed   achieves at least 95
                                 to a flare or      percent reduction in
                                 other control      methane and VOC
                                 device that        emissions.
                                 achieves at
                                 least 95 percent
                                 reduction in
                                 methane and VOC
                                 emissions.
Sweetening Units..............  Achieve SO2        Achieve required
                                 emission           minimum SO2 emission
                                 reduction          reduction
                                 efficiency.        efficiency.
------------------------------------------------------------------------
\1\ tpy (tons per year).

[[Page 63121]]

 
\2\ OGI (optical gas imaging).
\3\ ppm (parts per million).
\4\ PTE (potential to emit).
\5\ scfh (standard cubic feet per hour).
\6\ BMP (best management practices).
\7\ scfm (standard cubic feet per minute).
\8\ REC (reduced emissions completion).
\9\ LDAR (leak detection and repair).


Table 3--Summary of Proposed BSER and Proposed Presumptive Standards for
                     GHGS From Designated Facilities
                               [EG OOOOc]
------------------------------------------------------------------------
                                                    Proposed presumptive
      Designated facility         Proposed BSER      standards for GHGs
------------------------------------------------------------------------
Fugitive Emissions: Well Sites  Demonstrate        Perform survey to
 >0 to <3 tpy Methane.           actual site        verify that actual
                                 emissions are      site emissions are
                                 reflected in       reflected in
                                 calculation.       calculation.
Fugitive Emissions: Well Sites  Monitoring and     Quarterly OGI
 >=3 tpy Methane.                repair based on    monitoring following
                                 quarterly          appendix K.
                                 monitoring using   (Optional quarterly
                                 OGI.               EPA Method 21
                                                    monitoring with 500
                                                    ppm defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.
(Co-proposal) Fugitive          Monitoring and     Semiannual OGI
 Emissions: Well Sites >=3 to    repair based on    monitoring following
 <8 tpy Methane.                 semiannual         appendix K.
                                 monitoring using   (Optional semiannual
                                 OGI.               EPA Method 21
                                                    monitoring with 500
                                                    ppm defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.
(Co-proposal) Fugitive          Monitoring and     Quarterly OGI
 Emissions: Well Sites >=8 tpy   repair based on    monitoring following
 Methane.                        quarterly          appendix K.
                                 monitoring using   (Optional quarterly
                                 OGI.               EPA Method 21
                                                    monitoring with 500
                                                    ppm defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.
Fugitive Emissions: Compressor  Monitoring and     Quarterly OGI
 Stations.                       repair based on    monitoring following
                                 quarterly          appendix K.
                                 monitoring using   (Optional quarterly
                                 OGI.               EPA Method 21
                                                    monitoring with 500
                                                    ppm defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.
Fugitive Emissions: Well Sites  Monitoring and     Annual OGI monitoring
 and Compressor Stations on      repair based on    following appendix
 Alaska North Slope.             annual             K. (Optional annual
                                 monitoring using   EPA Method 21
                                 OGI.               monitoring with 500
                                                    ppm defined as a
                                                    leak).
                                                   First attempt at
                                                    repair within 30
                                                    days of finding
                                                    fugitive emissions.
                                                    Final repair within
                                                    30 days of first
                                                    attempt.
Fugitive Emissions: Well Sites  (Optional)         (Optional)
 and Compressor Stations.        Screening,         Alternative
                                 monitoring, and    bimonthly screening
                                 repair based on    with advanced
                                 bimonthly          measurement
                                 screening using    technology with
                                 an advanced        annual OGI
                                 measurement        monitoring following
                                 technology and     appendix K.
                                 annual
                                 monitoring using
                                 OGI.
Storage Vessels: Tank Battery   Capture and route  95 percent reduction
 with PTE of 20 tpy or More of   to a control       of methane.
 Methane.                        device.
Pneumatic Controllers: Natural  Use of zero-       VOC and methane
 Gas Driven that Vent to the     emissions          emission rate of
 Atmosphere.                     controllers.       zero.
Pneumatic Controllers: Alaska   Installation of    Natural gas bleed
 (at sites where onsite power    low-bleed          rate no greater than
 is not available--continuous    pneumatic          6 scfh.
 bleed natural gas driven).      controllers.
Pneumatic Controllers: Alaska   Monitor and        OGI monitoring and
 (at sites where onsite power    repair through     repair of emissions
 is not available--              fugitive           from controller
 intermittent natural gas        emissions          malfunctions.
 driven).                        program.
Wet Seal Centrifugal            Capture and route  Reduce emissions by
 Compressors (except for those   emissions from     95 percent.
 located at single well sites).  the wet seal
                                 fluid degassing
                                 system to a
                                 control device
                                 or to a process.
Reciprocating Compressors       Replace the        Replace the
 (except for those located at    reciprocating      reciprocating
 single well sites).             compressor rod     compressor rod
                                 packing based on   packing when
                                 annual             measured leak rate
                                 monitoring (when   exceeds 2 scfm based
                                 measured leak      on the results of
                                 rate exceeds 2     annual monitoring,
                                 scfm) or route     or collect and route
                                 emissions to a     emissions from the
                                 process.           rod packing to a
                                                    process through a
                                                    closed vent system
                                                    under negative
                                                    pressure.
Pneumatic Pumps: Natural Gas    A natural gas      Zero natural gas
 Processing Plants.              emission rate of   emissions from
                                 zero.              diaphragm and piston
                                                    pneumatic pumps.
Pneumatic Pumps: Locations      Route diaphragm    95 percent control of
 Other Than Natural Gas          pumps to an        diaphragm pneumatic
 Processing Plants.              existing control   pumps if there is an
                                 device or          existing control or
                                 process.           process on site. 95
                                                    percent control not
                                                    required if (1)
                                                    routed to an
                                                    existing control
                                                    that achieves less
                                                    than 95 percent or
                                                    (2) it is
                                                    technically
                                                    infeasible to route
                                                    to the existing
                                                    control device or
                                                    process.
Equipment Leaks at Natural Gas  LDAR with          LDAR with OGI
 Processing Plants.              bimonthly OGI.     following procedures
                                                    in appendix K.

[[Page 63122]]

 
Oil Wells with Associated Gas.  Route associated   Route associated gas
                                 gas to a sales     to a sales line. If
                                 line. If access    access to a sales
                                 to a sales line    line is not
                                 is not             available, the gas
                                 available, the     can be used as an
                                 gas can be used    onsite fuel source,
                                 as an onsite       used for another
                                 fuel source,       useful purpose that
                                 used for another   a purchased fuel or
                                 useful purpose     raw material would
                                 that a purchased   serve, or routed to
                                 fuel or raw        a flare or other
                                 material would     control device that
                                 serve, or routed   achieves at least 95
                                 to a flare or      percent reduction in
                                 other control      methane and VOC
                                 device that        emissions.
                                 achieves at
                                 least 95 percent
                                 reduction in
                                 methane and VOC
                                 emissions.
------------------------------------------------------------------------

C. Costs and Benefits

    To satisfy requirements of E.O. 12866, the EPA projected the 
emissions reductions, costs, and benefits that may result from this 
proposed action. These results are presented in detail in the 
regulatory impact analysis (RIA) accompanying this proposal developed 
in response to E.O. 12866. The RIA focuses on the elements of the 
proposed rule that are likely to result in quantifiable cost or 
emissions changes compared to a baseline without the proposal that 
incorporates changes to regulatory requirements induced by the CRA 
resolution. We estimated the cost, emissions, and benefit impacts for 
the 2023 to 2035 period. We present the present value (PV) and 
equivalent annual value (EAV) of costs, benefits, and net benefits of 
this action in 2019 dollars.
    The initial analysis year in the RIA is 2023 as we assume the 
proposed rule will be finalized towards the end of 2022. The NSPS will 
take effect immediately and impact sources constructed after 
publication of the proposed rule. The EG will take longer to go into 
effect as States will need to develop implementation plans in response 
to the rule and have them approved by the EPA. We assume in the RIA 
that this process will take three years, and so EG impacts will begin 
in 2026. The final analysis year is 2035, which allows us to provide 
ten years of projected impacts after the EG is assumed to take effect.
    The cost analysis presented in the RIA reflects a nationwide 
engineering analysis of compliance cost and emissions reductions, of 
which there are two main components. The first component is a set of 
representative or model plants for each regulated facility, segment, 
and control option. The characteristics of the model plant include 
typical equipment, operating characteristics, and representative 
factors including baseline emissions and the costs, emissions 
reductions, and product recovery resulting from each control option. 
The second component is a set of projections of activity data for 
affected facilities, distinguished by vintage, year, and other 
necessary attributes (e.g., oil versus natural gas wells). Impacts are 
calculated by setting parameters on how and when affected facilities 
are assumed to respond to a particular regulatory regime, multiplying 
activity data by model plant cost and emissions estimates, differencing 
from the baseline scenario, and then summing to the desired level of 
aggregation. In addition to emissions reductions, some control options 
result in natural gas recovery, which can then be combusted in 
production or sold. Where applicable, we present projected compliance 
costs with and without the projected revenues from product recovery.
    The EPA expects climate and health benefits due to the emissions 
reductions projected under this proposed rule. The EPA estimated the 
global social benefits of CH4 emission reductions expected 
from this proposed rule using the SC-CH4 estimates presented 
in the ``Technical Support Document: Social Cost of Carbon, Methane, 
and Nitrous Oxide Interim Estimates under E.O. 13990 (IWG 2021)''. 
These SC-CH4 estimates are interim values developed under 
E.O. 13990 for use in benefit-cost analyses until updated estimates of 
the impacts of climate change can be developed based on the best 
available science and economics.
    Under the proposed rule, the EPA expects that VOC emission 
reductions will improve air quality and are likely to improve health 
and welfare associated with exposure to ozone, PM2.5, and 
HAP. Calculating ozone impacts from VOC emissions changes requires 
information about the spatial patterns in those emissions changes. In 
addition, the ozone health effects from the proposed rule will depend 
on the relative proximity of expected VOC and ozone changes to 
population. In this analysis, we have not characterized VOC emissions 
changes at a finer spatial resolution than the national total. In light 
of these uncertainties, we present an illustrative screening analysis 
in Appendix B of the RIA based on modeled oil and natural gas VOC 
contributions to ozone concentrations as they occurred in 2017 and do 
not include the results of this analysis in the estimate of benefits 
and net benefits projected from this proposal.
    The projected national-level emissions reductions over the 2023 to 
2035 period anticipated under the proposed requirements are presented 
in Table 4. Table 5 presents the PV and EAV of the projected benefits, 
costs, and net benefits over the 2023 to 2035 period under the proposed 
requirements using discount rates of 3 and 7 percent.

 Table 4--Projected Emissions Reductions Under the Proposed Rule, 2023-
                               2035 Total
------------------------------------------------------------------------
                                                    Emissions reductions
                     Pollutant                        (2023-2035 total)
------------------------------------------------------------------------
Methane (million short tons) a....................                    41
VOC (million short tons)..........................                    12
Hazardous Air Pollutant (million short tons)......                  0.48

[[Page 63123]]

 
Methane (million metric tons CO2 Eq.) b...........                   920
------------------------------------------------------------------------
a To convert from short tons to metric tons, multiply the short tons by
  0.907. Alternatively, to convert metric tons to short tons, multiply
  metric tons by 1.102.
b CO2 Eq. calculated using a global warming potential of 25.


    Table 5--Benefits, Costs, Net Benefits, and Emissions Reductions of the Proposed Rule, 2023 Through 2035
                                [Dollar Estimates in Millions of 2019 Dollars] a
----------------------------------------------------------------------------------------------------------------
                                                      3 percent discount rate         7 percent discount rate
                                                 ---------------------------------------------------------------
                                                                    Equivalent                      Equivalent
                                                   Present value   annual value    Present value   annual value
----------------------------------------------------------------------------------------------------------------
Climate Benefits b..............................         $55,000          $5,200  ..............  ..............
Net Compliance Costs............................           7,200             680           6,300             760
    Compliance Costs............................          13,000           1,200          10,000           1,200
    Product Recovery............................           5,500             520           3,900             470
Net Benefits....................................          48,000           4,500          49,000           4,500
                                                 ---------------------------------------------------------------
Non-Monetized Benefits..........................    Climate and ozone health benefits from reducing 41 million
                                                             short tons of methane from 2023 to 2035.
                                                  PM2.5 and ozone health benefits from reducing 12 million short
                                                                 tons of VOC from 2023 to 2035 c.
                                                  HAP benefits from reducing 480 thousand short tons of HAP from
                                                                           2023 to 2035.
                                                                       Visibility benefits.
                                                                    Reduced vegetation effects.
----------------------------------------------------------------------------------------------------------------
a Values rounded to two significant figures. Totals may not appear to add correctly due to rounding.
b Climate benefits are based on reductions in methane emissions and are calculated using four different
  estimates of the social cost of methane (SC-CH4) (model average at 2.5 percent, 3 percent, and 5 percent
  discount rates; 95th percentile at 3 percent discount rate). For the presentational purposes of this table, we
  show the benefits associated with the average SC-CH4 at a 3 percent discount rate, but the Agency does not
  have a single central SC-CH4 point estimate. We emphasize the importance and value of considering the benefits
  calculated using all four SC-CH4 estimates; the present value (and equivalent annual value) of the additional
  benefit estimates ranges from $22 billion to $150 billion ($2.4 billion to $14 billion) over 2023 to 2035 for
  the proposed option. Please see Table 3-5 and Table 3-7 of the RIA for the full range of SC-CH4 estimates. As
  discussed in Section 3 of the RIA, a consideration of climate benefits calculated using discount rates below 3
  percent, including 2 percent and lower, are also warranted when discounting intergenerational impacts. All net
  benefits are calculated using climate benefits discounted at 3 percent.
c A screening-level analysis of ozone benefits from VOC reductions can be found in Appendix B of the RIA, which
  is included in the docket.

II. General Information

A. Does this action apply to me?

    Categories and entities potentially affected by this action 
include:

                          Table 6--Industrial Source Categories Affected by This Action
----------------------------------------------------------------------------------------------------------------
              Category                 NAICS code 1                  Examples of regulated entities
----------------------------------------------------------------------------------------------------------------
Industry...........................            211120  Crude Petroleum Extraction.
                                               211130  Natural Gas Extraction.
                                               221210  Natural Gas Distribution.
                                               486110  Pipeline Distribution of Crude Oil.
                                               486210  Pipeline Transportation of Natural Gas.
Federal Government.................  ................  Not affected.
State/local/Tribal government......  ................  Not affected.
----------------------------------------------------------------------------------------------------------------
1 North American Industry Classification System (NAICS).

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be affected by this 
action. Other types of entities not listed in the table could also be 
affected by this action. To determine whether your entity is affected 
by this action, you should carefully examine the applicability criteria 
found in the final rule. If you have questions regarding the 
applicability of this action to a particular entity, consult the person 
listed in the FOR FURTHER INFORMATION CONTACT section, your air 
permitting authority, or your EPA Regional representative listed in 40 
CFR 60.4 (General Provisions).

[[Page 63124]]

B. How do I obtain a copy of this document, background information, and 
other related information?

    In addition to being available in the docket, an electronic copy of 
the proposed action is available on the internet. Following signature 
by the Administrator, the EPA will post a copy of this proposed action 
at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. Following publication in the Federal Register, the EPA will 
post the Federal Register version of the final rule and key technical 
documents at this same website. A redline version of the regulatory 
language that incorporates the proposed changes described in section X 
for NSPS OOOO and NSPS OOOOa is available in the docket for this action 
(Docket ID No. EPA-HQ-OAR-2021-0317). The EPA plans to propose the 
regulatory language for NSPS OOOOb and EG OOOOc through a supplemental 
action.

III. Air Emissions From the Crude Oil and Natural Gas Sector and Public 
Health and Welfare

A. Impacts of GHGs, VOCs and SO2 Emissions on Public Health 
and Welfare

    As noted previously, the Oil and Natural Gas Industry emits a wide 
range of pollutants, including GHGs (such as methane and 
CO2), VOCs, SO2, NOX, H2S, 
CS2, and COS. See 49 FR 2636, 2637 (January 20, 1984). As 
noted below, to this point, the EPA has focused its regulatory efforts 
on GHGs, VOC, and SO2.\10\
---------------------------------------------------------------------------

    \10\ We note that the EPA's focus on GHGs (in particular 
methane), VOC, and SO2 in these analyses, does not in any 
way limit the EPA's authority to promulgate standards that would 
apply to other pollutants emitted from the Crude Oil and Natural Gas 
source category, if the EPA determines in the future that such 
action is appropriate.
---------------------------------------------------------------------------

1. Climate Change Impacts From GHGs Emissions
    Elevated concentrations of GHGs are and have been warming the 
planet, leading to changes in the Earth's climate including changes in 
the frequency and intensity of heat waves, precipitation, and extreme 
weather events; rising seas; and retreating snow and ice. The changes 
taking place in the atmosphere as a result of the well-documented 
buildup of GHGs due to human activities are changing the climate at a 
pace and in a way that threatens human health, society, and the natural 
environment. Human induced GHGs, largely derived from our reliance on 
fossil fuels, are causing serious and life-threatening environmental 
and health impacts.
    Extensive additional information on climate change is available in 
the scientific assessments and the EPA documents that are briefly 
described in this section, as well as in the technical and scientific 
information supporting them. One of those documents is the EPA's 2009 
Endangerment and Cause or Contribute Findings for GHGs Under Section 
202(a) of the CAA (74 FR 66496, December 15, 2009).\11\ In the 2009 
Endangerment Findings, the Administrator found under section 202(a) of 
the CAA that elevated atmospheric concentrations of six key well-mixed 
GHGs--CO2, CH4, N2O, 
hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur 
hexafluoride (SF6)--``may reasonably be anticipated to 
endanger the public health and welfare of current and future 
generations'' (74 FR 66523, December 15, 2009), and the science and 
observed changes have confirmed and strengthened the understanding and 
concerns regarding the climate risks considered in the Finding. The 
2009 Endangerment Findings, together with the extensive scientific and 
technical evidence in the supporting record, documented that climate 
change caused by human emissions of GHGs threatens the public health of 
the U.S. population. It explained that by raising average temperatures, 
climate change increases the likelihood of heat waves, which are 
associated with increased deaths and illnesses (74 FR 66497, December 
15, 2009). While climate change also increases the likelihood of 
reductions in cold-related mortality, evidence indicates that the 
increases in heat mortality will be larger than the decreases in cold 
mortality in the U.S. (74 FR 66525, December 15, 2009). The 2009 
Endangerment Findings further explained that compared to a future 
without climate change, climate change is expected to increase 
tropospheric ozone pollution over broad areas of the U.S., including in 
the largest metropolitan areas with the worst tropospheric ozone 
problems, and thereby increase the risk of adverse effects on public 
health (74 FR 66525, December 15, 2009). Climate change is also 
expected to cause more intense hurricanes and more frequent and intense 
storms of other types and heavy precipitation, with impacts on other 
areas of public health, such as the potential for increased deaths, 
injuries, infectious and waterborne diseases, and stress-related 
disorders (74 FR 66525, December 15, 2009). Children, the elderly, and 
the poor are among the most vulnerable to these climate-related health 
effects (74 FR 66498, December 15, 2009).
---------------------------------------------------------------------------

    \11\ In describing these 2009 Findings in this proposal, the EPA 
is neither reopening nor revisiting them.
---------------------------------------------------------------------------

    The 2009 Endangerment Findings also documented, together with the 
extensive scientific and technical evidence in the supporting record, 
that climate change touches nearly every aspect of public welfare \12\ 
in the U.S. with resulting economic costs, including: Changes in water 
supply and quality due to increased frequency of drought and extreme 
rainfall events; increased risk of storm surge and flooding in coastal 
areas and land loss due to inundation; increases in peak electricity 
demand and risks to electricity infrastructure; and the potential for 
significant agricultural disruptions and crop failures (though offset 
to some extent by carbon fertilization). These impacts are also global 
and may exacerbate problems outside the U.S. that raise humanitarian, 
trade, and national security issues for the U.S. (74 FR 66530, December 
15, 2009).
---------------------------------------------------------------------------

    \12\ The CAA states in section 302(h) that ``[a]ll language 
referring to effects on welfare includes, but is not limited to, 
effects on soils, water, crops, vegetation, manmade materials, 
animals, wildlife, weather, visibility, and climate, damage to and 
deterioration of property, and hazards to transportation, as well as 
effects on economic values and on personal comfort and well-being, 
whether caused by transformation, conversion, or combination with 
other air pollutants.'' 42 U.S.C. 7602(h).
---------------------------------------------------------------------------

    In 2016, the Administrator similarly issued Endangerment and Cause 
or Contribute Findings for GHG emissions from aircraft under section 
231(a)(2)(A) of the CAA (81 FR 54422, August 15, 2016).\13\ In the 2016 
Endangerment Findings, the Administrator found that the body of 
scientific evidence amassed in the record for the 2009 Endangerment 
Findings compellingly supported a similar endangerment finding under 
CAA section 231(a)(2)(A), and also found that the science assessments 
released between the 2009 and the 2016 Findings, ``strengthen and 
further support the judgment that GHGs in the atmosphere may reasonably 
be anticipated to endanger the public health and welfare of current and 
future generations.'' (81 FR 54424, August 15, 2016).
---------------------------------------------------------------------------

    \13\ In describing these 2016 Findings in this proposal, the EPA 
is neither reopening nor revisiting them.
---------------------------------------------------------------------------

    Since the 2016 Endangerment Findings, the climate has continued to 
change, with new records being set for several climate indicators such 
as global average surface temperatures, GHG concentrations, and sea 
level rise. Moreover, heavy precipitation events

[[Page 63125]]

have increased in the eastern U.S. while agricultural and ecological 
drought has increased in the western U.S. along with more intense and 
larger wildfires.\14\ These and other trends are examples of the risks 
discussed the 2009 and 2016 Endangerment Findings that have already 
been experienced. Additionally, major scientific assessments continue 
to demonstrate advances in our understanding of the climate system and 
the impacts that GHGs have on public health and welfare both for 
current and future generations. These updated observations and 
projections document the rapid rate of current and future climate 
change both globally and in the U.S. These assessments include:
---------------------------------------------------------------------------

    \14\ See later in this section for specific examples. An 
additional resource for indicators can be found at https://www.epa.gov/climate-indicators.
---------------------------------------------------------------------------

     U.S. Global Change Research Program's (USGCRP) 2016 
Climate and Health Assessment \15\ and 2017-2018 Fourth National 
Climate Assessment (NCA4). \16\ \17\
---------------------------------------------------------------------------

    \15\ USGCRP, 2016: The Impacts of Climate Change on Human Health 
in the United States: A Scientific Assessment. Crimmins, A., J. 
Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, 
N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. 
Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change 
Research Program, Washington, DC, 312 pp.
    \16\ USGCRP, 2017: Climate Science Special Report: Fourth 
National Climate Assessment, Volume I [Wuebbles, D.J., D.W. Fahey, 
K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)]. 
U.S. Global Change Research Program, Washington, DC, USA, 470 pp, 
doi: 10.7930/J0J964J6.
    \17\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
---------------------------------------------------------------------------

     IPCC's 2018 Global Warming of 1.5 [deg]C,\18\ 2019 Climate 
Change and Land,\19\ and the 2019 Ocean and Cryosphere in a Changing 
Climate \20\ assessments, as well as the 2021 IPCC Sixth Assessment 
Report (AR6).\21\
---------------------------------------------------------------------------

    \18\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special 
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission 
pathways, in the context of strengthening the global response to the 
threat of climate change, sustainable development, and efforts to 
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. P[ouml]rtner, 
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. 
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. 
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. 
Waterfield (eds.)].
    \19\ IPCC, 2019: Climate Change and Land: an IPCC special report 
on climate change, desertification, land degradation, sustainable 
land management, food security, and greenhouse gas fluxes in 
terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V. 
Masson-Delmotte, H.-O. P[ouml]rtner, D.C. Roberts, P. Zhai, R. 
Slade, S. Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S. 
Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E. 
Huntley, K. Kissick, M. Belkacemi, J. Malley, (eds.)].
    \20\ IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere 
in a Changing Climate [H.-O. P[ouml]rtner, D.C. Roberts, V. Masson-
Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A. 
Alegr[iacute]a, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M. Weyer 
(eds.)].
    \21\ IPCC, 2021: Summary for Policymakers. In: Climate Change 
2021: The Physical Science Basis. Contribution of Working Group I to 
the Sixth Assessment Report of the Intergovernmental Panel on 
Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. 
Connors, C. P[eacute]an, S. Berger, N. Caud, Y. Chen, L. Goldfarb, 
M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. 
Maycock, T. Waterfield, O. Yelek[ccedil]i, R. Yu and B. Zhou 
(eds.)]. Cambridge University Press. In Press.
---------------------------------------------------------------------------

     The NAS 2016 Attribution of Extreme Weather Events in the 
Context of Climate Change,\22\ 2017 Valuing Climate Damages: Updating 
Estimation of the Social Cost of Carbon Dioxide,\23\ and 2019 Climate 
Change and Ecosystems \24\ assessments.
---------------------------------------------------------------------------

    \22\ National Academies of Sciences, Engineering, and Medicine. 
2016. Attribution of Extreme Weather Events in the Context of 
Climate Change. Washington, DC: The National Academies Press. 
https://dio.org/10.17226/21852.
    \23\ National Academies of Sciences, Engineering, and Medicine. 
2017. Valuing Climate Damages: Updating Estimation of the Social 
Cost of Carbon Dioxide. Washington, DC: The National Academies 
Press. https://doi.org/10.17226/24651.
    \24\ National Academies of Sciences, Engineering, and Medicine. 
2019. Climate Change and Ecosystems. Washington, DC: The National 
Academies Press. https://doi.org/10.17226/25504.
---------------------------------------------------------------------------

     National Oceanic and Atmospheric Administration's (NOAA) 
annual State of the Climate reports published by the Bulletin of the 
American Meteorological Society,\25\ most recently in August of 2020.
---------------------------------------------------------------------------

    \25\ Blunden, J., and D.S. Arndt, Eds., 2020: State of the 
Climate in 2019. Bull. Amer. Meteor. Soc, S1-S429, https://doi.org/10.1175/2020BAMSStateoftheClimate.1.
---------------------------------------------------------------------------

     EPA Climate Change and Social Vulnerability in the United 
States: A Focus on Six Impacts (2021).\26\
---------------------------------------------------------------------------

    \26\ EPA. 2021. Climate Change and Social Vulnerability in the 
United States: A Focus on Six Impacts. U.S. Environmental Protection 
Agency, EPA 430-R-21-003.
---------------------------------------------------------------------------

    The most recent information demonstrates that the climate is 
continuing to change in response to the human-induced buildup of GHGs 
in the atmosphere. These recent assessments show that atmospheric 
concentrations of GHGs have risen to a level that has no precedent in 
human history and that they continue to climb, primarily as a result of 
both historic and current anthropogenic emissions, and that these 
elevated concentrations endanger our health by affecting our food and 
water sources, the air we breathe, the weather we experience, and our 
interactions with the natural and built environments. For example, 
atmospheric concentrations of one of these GHGs, CO2, 
measured at Mauna Loa in Hawaii and at other sites around the world 
reached 414 ppm in 2020 (nearly 50 percent higher than pre-industrial 
levels),\27\ and has continued to rise at a rapid rate. Global average 
temperature has increased by about 1.1 degrees Celsius ([deg]C) (2.0 
degrees Fahrenheit ([deg]F)) in the 2011-2020 decade relative to 1850-
1900.\28\ The years 2014-2020 were the warmest seven years in the 1880-
2020 record, contributing to the warmest decade on record with a 
decadal temperature of 0.82 [deg]C (1.48 [deg]F) above the 20th 
century.\29\ \30\ The IPCC determined (with medium confidence) that 
this past decade was warmer than any multi-century period in at least 
the past 100,000 years.\31\ Global average sea level has risen by about 
8 inches (about 21 centimeters (cm)) from 1901 to 2018, with the rate 
from 2006 to 2018 (0.15 inches/year or 3.7 millimeters (mm)/year) 
almost twice the rate over the 1971 to 2006 period, and three times the 
rate of the 1901 to 2018 period.\32\ The rate of sea level rise over 
the 20th century was higher than in any other century in at least the 
last 2,800 years.\33\ Higher CO2 concentrations have led to 
acidification of the surface ocean in recent decades to an extent 
unusual in the past 2 million years, with negative impacts on marine 
organisms that use calcium carbonate to build shells or skeletons.\34\ 
Arctic sea ice extent continues to decline in all months of the year; 
the most rapid reductions occur in September (very likely almost a 13 
percent decrease per decade between 1979 and 2018) and are 
unprecedented in at least 1,000 years.\35\ Human-induced climate change 
has led to heatwaves and heavy precipitation becoming more frequent and 
more intense, along with increases in

[[Page 63126]]

agricultural and ecological droughts \36\ in many regions.\37\
---------------------------------------------------------------------------

    \27\ https://climate.nasa.gov/vital-signs/carbon-dioxide/.
    \28\ IPCC, 2021.
    \29\ NOAA National Centers for Environmental Information, State 
of the Climate: Global Climate Report for Annual 2020, published 
online January 2021, retrieved on February 10, 2021 from https://www.ncdc.noaa.gov/sotc/global/202013.
    \30\ Blunden, J., and D.S. Arndt, Eds., 2020: State of the 
Climate in 2019. Bull. Amer. Meteor. Soc, S1-S429, https://doi.org/10.1175/2020BAMSStateoftheClimate.1.
    \31\ IPCC, 2021.
    \32\ IPCC, 2021.
    \33\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
    \34\ IPCC, 2021.
    \35\ IPCC, 2021.
    \36\ These are drought measures based on soil moisture.
    \37\ IPCC, 2021.
---------------------------------------------------------------------------

    The assessment literature demonstrates that modest additional 
amounts of warming may lead to a climate different from anything humans 
have ever experienced. The present-day CO2 concentration of 
414 ppm is already higher than at any time in the last 2 million 
years.\38\ If concentrations exceed 450 ppm, they would likely be 
higher than any time in the past 23 million years:\39\ at the current 
rate of increase of more than 2 ppm a year, this would occur in about 
15 years. While GHGs are not the only factor that controls climate, it 
is illustrative that 3 million years ago (the last time CO2 
concentrations were this high) Greenland was not yet completely covered 
by ice and still supported forests, while 23 million years ago (the 
last time concentrations were above 450 ppm) the West Antarctic ice 
sheet was not yet developed, indicating the possibility that high GHGs 
concentrations could lead to a world that looks very different from 
today and from the conditions in which human civilization has 
developed. If the Greenland and Antarctic ice sheets were to melt 
substantially, sea levels would rise dramatically--the IPCC estimated 
that over the next 2,000 years, sea level will rise by 7 to 10 feet 
even if warming is limited to 1.5 [deg]C (2.7 [deg]F), from 7 to 20 
feet if limited to 2 [deg]C (3.6 [deg]F), and by 60 to 70 feet if 
warming is allowed to reach 5 [deg]C (9 [deg]F) above preindustrial 
levels.\40\ For context, almost all of the city of Miami is less than 
25 feet above sea level, and the NCA4 stated that 13 million Americans 
would be at risk of migration due to 6 feet of sea level rise. 
Moreover, the CO2 being absorbed by the ocean has resulted 
in changes in ocean chemistry due to acidification of a magnitude not 
seen in 65 million years,\41\ putting many marine species--particularly 
calcifying species--at risk.
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    \38\ IPCC, 2021.
    \39\ IPCC, 2013.
    \40\ IPCC, 2021.
    \41\ IPCC, 2018.
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    The NCA4 found that it is very likely (greater than 90 percent 
likelihood) that by mid-century, the Arctic Ocean will be almost 
entirely free of sea ice by late summer for the first time in about 2 
million years.\42\ Coral reefs will be at risk for almost complete (99 
percent) losses with 1 [deg]C (1.8 [deg]F) of additional warming from 
today (2 [deg]C or 3.6 [deg]F since preindustrial). At this 
temperature, between 8 and 18 percent of animal, plant, and insect 
species could lose over half of the geographic area with suitable 
climate for their survival, and 7 to 10 percent of rangeland livestock 
would be projected to be lost.\43\
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    \42\ USGCRP, 2018.
    \43\ IPCC, 2018.
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    Every additional increment of temperature comes with consequences. 
For example, the half degree of warming from 1.5 to 2 [deg]C (0.9 
[deg]F of warming from 2.7 [deg]F to 3.6 [deg]F) above preindustrial 
temperatures is projected on a global scale to expose 420 million more 
people to frequent extreme heatwaves, and 62 million more people to 
frequent exceptional heatwaves (where heatwaves are defined based on a 
heat wave magnitude index which takes into account duration and 
intensity--using this index, the 2003 French heat wave that led to 
almost 15,000 deaths would be classified as an ``extreme heatwave'' and 
the 2010 Russian heatwave which led to thousands of deaths and 
extensive wildfires would be classified as ``exceptional''). It would 
increase the frequency of sea-ice-free Arctic summers from once in a 
hundred years to once in a decade. It could lead to 4 inches of 
additional sea level rise by the end of the century, exposing an 
additional 10 million people to risks of inundation, as well as 
increasing the probability of triggering instabilities in either the 
Greenland or Antarctic ice sheets. Between half a million and a million 
additional square miles of permafrost would thaw over several 
centuries. Risks to food security would increase from medium to high 
for several lower income regions in the Sahel, southern Africa, the 
Mediterranean, central Europe, and the Amazon. In addition to food 
security issues, this temperature increase would have implications for 
human health in terms of increasing ozone concentrations, heatwaves, 
and vector-borne diseases (for example, expanding the range of the 
mosquitoes which carry dengue fever, chikungunya, yellow fever, and the 
Zika virus, or the ticks which carry Lyme. babesiosis, or Rocky 
Mountain Spotted Fever).\44\ Moreover, every additional increment in 
warming leads to larger changes in extremes, including the potential 
for events unprecedented in the observational record. Every additional 
degree will intensify extreme precipitation events by about 7 percent. 
The peak winds of the most intense tropical cyclones (hurricanes) are 
projected to increase with warming. In addition to a higher intensity, 
the IPCC found that precipitation and frequency of rapid 
intensification of these storms has already increased, while the 
movement speed has decreased, and elevated sea levels have increased 
coastal flooding, all of which make these tropical cyclones more 
damaging.\45\
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    \44\ IPCC, 2018.
    \45\ IPCC, 2021.
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    The NCA4 also evaluated a number of impacts specific to the U.S. 
Severe drought and outbreaks of insects like the mountain pine beetle 
have killed hundreds of millions of trees in the western U.S. Wildfires 
have burned more than 3.7 million acres in 14 of the 17 years between 
2000 and 2016, and Federal wildfire suppression costs were about a 
billion dollars annually.\46\ The National Interagency Fire Center has 
documented U.S. wildfires since 1983, and the ten years with the 
largest acreage burned have all occurred since 2004.\47\ Wildfire smoke 
degrades air quality increasing health risks, and more frequent and 
severe wildfires due to climate change would further diminish air 
quality, increase incidences of respiratory illness, impair visibility, 
and disrupt outdoor activities, sometimes thousands of miles from the 
location of the fire. Meanwhile, sea level rise has amplified coastal 
flooding and erosion impacts, requiring the installation of costly pump 
stations, flooding streets, and increasing storm surge damages. Tens of 
billions of dollars of U.S. real estate could be below sea level by 
2050 under some scenarios. Increased frequency and duration of drought 
will reduce agricultural productivity in some regions, accelerate 
depletion of water supplies for irrigation, and expand the distribution 
and incidence of pests and diseases for crops and livestock. The NCA4 
also recognized that climate change can increase risks to national 
security, both through direct impacts on military infrastructure, but 
also by affecting factors such as food and water availability that can 
exacerbate conflict outside U.S. borders. Droughts, floods, storm 
surges, wildfires, and other extreme events stress nations and people 
through loss of life, displacement of populations, and impacts on 
livelihoods.\48\
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    \46\ USGCRP, 2018
    \47\ NIFC (National Interagency Fire Center). 2021. Total 
wildland fires and acres (1983-2020). Accessed August 2021. 
www.nifc.gov/fireInfo/fireInfo_stats_totalFires.html.
    \48\ USGCRP, 2018.
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    Some GHGs also have impacts beyond those mediated through climate 
change. For example, elevated concentrations of carbon dioxide 
stimulate plant growth (which can be positive in the case of beneficial 
species, but negative in terms of weeds and invasive species, and can 
also lead to a reduction in plant

[[Page 63127]]

micronutrients) \49\ and cause ocean acidification. Nitrous oxide 
depletes the levels of protective stratospheric ozone.\50\
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    \49\ Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F. 
Garofalo, A.S. Khan, I. Loladze, A.A. P[eacute]rez de Le[oacute]n, 
A.Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety, 
Nutrition, and Distribution. The Impacts of Climate Change on Human 
Health in the United States: A Scientific Assessment. U.S. Global 
Change Research Program, Washington, DC, 189-216. https://dx.doi.org/10.7930/J0ZP4417
    \50\ WMO (World Meteorological Organization), Scientific 
Assessment of Ozone Depletion: 2018, Global Ozone Research and 
Monitoring Project--Report No. 58, 588 pp., Geneva, Switzerland, 
2018.
---------------------------------------------------------------------------

    As methane is the primary GHG addressed in this proposal, it is 
relevant to highlight some specific trends and impacts specific to 
methane. Concentrations of methane reached 1879 parts per billion (ppb) 
in 2020, more than two and a half times the preindustrial concentration 
of 722 ppb.\51\ Moreover, the 2020 concentration was an increase of 
almost 13 ppb over 2019--the largest annual increase in methane 
concentrations of the period since the early 1990s, continuing a trend 
of rapid rise since a temporary pause ended in 2007.\52\ Methane has a 
high radiative efficiency--almost 30 times that of carbon dioxide per 
ppb (and therefore, 80 times as much per unit mass).\53\ In addition, 
methane contributes to climate change through chemical reactions in the 
atmosphere that produce tropospheric ozone and stratospheric water 
vapor. Human emissions of methane are responsible for about one third 
of the warming due to well-mixed GHGs, the second most important human 
warming agent after carbon dioxide.\54\ Because of the substantial 
emissions of methane, and its radiative efficiency, methane mitigation 
is one of the best opportunities for reducing near term warming.
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    \51\ Blunden et al., 2020.
    \52\ NOAA, https://gml.noaa.gov/webdata/ccgg/trends/ch4/ch4_annmean_gl.txt, accessed August 19th, 2021.
    \53\ IPCC, 2021.
    \54\ IPCC, 2021.
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    The tropospheric ozone produced by the reaction of methane in the 
atmosphere has harmful effects for human health and plant growth in 
addition to its climate effects.\55\ In remote areas, methane is an 
important precursor to tropospheric ozone formation.\56\ Approximately 
50 percent of the global annual mean ozone increase since preindustrial 
times is believed to be due to anthropogenic methane.\57\ Projections 
of future emissions also indicate that methane is likely to be a key 
contributor to ozone concentrations in the future.\58\ Unlike 
NOX and VOC, which affect ozone concentrations regionally 
and at hourly time scales, methane emissions affect ozone 
concentrations globally and on decadal time scales given methane's long 
atmospheric lifetime when compared to these other ozone precursors.\59\ 
Reducing methane emissions, therefore, will contribute to efforts to 
reduce global background ozone concentrations that contribute to the 
incidence of ozone-related health effects.\60\ The benefits of such 
reductions are global and occur in both urban and rural areas.
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    \55\ Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik, 
R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air 
Quality. In Impacts, Risks, and Adaptation in the United States: 
Fourth National Climate Assessment, Volume II [Reidmiller, D.R., 
C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, pp. 512-538. doi: 10.7930/NCA4. 2018. 
CH13
    \56\ U.S. EPA. 2013. ``Integrated Science Assessment for Ozone 
and Related Photochemical Oxidants (Final Report).'' EPA-600-R-10-
076F. National Center for Environmental Assessment--RTP Division. 
Available at https://www.epa.gov/ncea/isa/.
    \57\ Myhre, G., D. Shindell, F.-M. Br[eacute]on, W. Collins, J. 
Fuglestvedt, J. Huang, D. Koch, J.-F. Lamarque, D. Lee, B. Mendoza, 
T. Nakajima, A. Robock, G. Stephens, T. Takemura and H. Zhang, 2013: 
Anthropogenic and Natural Radiative Forcing. In: Climate Change 
2013: The Physical Science Basis. Contribution of Working Group I to 
the Fifth Assessment Report of the Intergovernmental Panel on 
Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, 
S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley 
(eds.)]. Cambridge University Press, Cambridge, United Kingdom and 
New York, NY, USA. Pg. 680.
    \58\ Ibid.
    \59\ Ibid.
    \60\ USGCRP, 2018.
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    These scientific assessments and documented observed changes in the 
climate of the planet and of the U.S. present clear support regarding 
the current and future dangers of climate change and the importance of 
GHG mitigation.
2. VOC
    Many VOC can be classified as HAP (e.g., benzene),\61\ which can 
lead to a variety of health concerns such as cancer and noncancer 
illnesses (e.g., respiratory, neurological). Further, VOC are one of 
the key precursors in the formation of ozone. Tropospheric, or ground-
level, ozone is formed through reactions of VOC and NOX in 
the presence of sunlight. Ozone formation can be controlled to some 
extent through reductions in emissions of the ozone precursors VOC and 
NOX. Recent observational and modeling studies have found 
that VOC emissions from oil and natural gas operations can impact ozone 
levels.\62\ \63\ \64\ \65\ A significantly expanded body of scientific 
evidence shows that ozone can cause a number of harmful effects on 
health and the environment. Exposure to ozone can cause respiratory 
system effects such as difficulty breathing and airway inflammation. 
For people with lung diseases such as asthma and chronic obstructive 
pulmonary disease (COPD), these effects can lead to emergency room 
visits and hospital admissions. Studies have also found that ozone 
exposure is likely to cause premature death from lung or heart 
diseases. In addition, evidence indicates that long-term exposure to 
ozone is likely to result in harmful respiratory effects, including 
respiratory symptoms and the development of asthma. People most at risk 
from breathing air containing ozone include children; people with 
asthma and other respiratory diseases; older adults; and people who are 
active outdoors, especially outdoor workers. An estimated 25.9 million 
people have asthma in the U.S., including almost 7.1 million children. 
Asthma disproportionately affects children, families with lower 
incomes, and minorities, including Puerto Ricans, Native Americans/
Alaska Natives, and African Americans.\66\
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    \61\ Benzene Integrated Risk Information System (IRIS) 
Assessment: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=276.
    \62\ Benedict, K. B., Zhou, Y., Sive, B. C., Prenni, A. J., 
Gebhart, K. A., Fischer, E. V., . . . & Collett Jr, J. L. 2019. 
Volatile organic compounds and ozone in Rocky Mountain National Park 
during FRAPPE. Atmospheric Chemistry and Physics, 19(1), 499-521.
    \63\ Lindaas, J., Farmer, D. K., Pollack, I. B., Abeleira, A., 
Flocke, F., & Fischer, E. V. 2019. Acyl peroxy nitrates link oil and 
natural gas emissions to high ozone abundances in the Colorado Front 
Range during summer 2015. Journal of Geophysical Research: 
Atmospheres, 124(4), 2336-2350.
    \64\ McDuffie, E. E., Edwards, P. M., Gilman, J. B., Lerner, B. 
M., Dub[eacute], W. P., Trainer, M., . . . & Brown, S. S. 2016. 
Influence of oil and gas emissions on summertime ozone in the 
Colorado Northern Front Range. Journal of Geophysical Research: 
Atmospheres, 121(14), 8712-8729.
    \65\ Tzompa[hyphen]Sosa, Z. A., & Fischer, E. V. 2021. Impacts 
of emissions of C2[hyphen]C5 alkanes from the US oil and gas sector 
on ozone and other secondary species. Journal of Geophysical 
Research: Atmospheres, 126(1), e2019JD031935.
    \66\ National Health Interview Survey (NHIS) Data, 2011. https://www.cdc.gov/asthma/nhis/2011/data.htm.
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    In the EPA's 2020 Integrated Science Assessment (ISA) for Ozone and 
Related Photochemical Oxidants,\67\ the EPA estimates the incidence of 
air pollution effects for those health endpoints above where the ISA 
classified as either causal or likely-to-be-causal. In brief, the ISA 
for ozone found short-term (less than one month) exposures to ozone to 
be

[[Page 63128]]

causally related to respiratory effects, a ``likely to be causal'' 
relationship with metabolic effects and a ``suggestive of, but not 
sufficient to infer, a causal relationship'' for central nervous system 
effects, cardiovascular effects, and total mortality. The ISA reported 
that long-term exposures (one month or longer) to ozone are ``likely to 
be causal'' for respiratory effects including respiratory mortality, 
and a ``suggestive of, but not sufficient to infer, a causal 
relationship'' for cardiovascular effects, reproductive effects, 
central nervous system effects, metabolic effects, and total mortality. 
An example of quantified incidence of ozone health effects can be found 
in the Regulatory Impact Analysis for the Final Revised Cross-State Air 
Pollution Rule (CSAPR) Update.
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    \67\ Integrated Science Assessment (ISA) for Ozone and Related 
Photochemical Oxidants (Final Report). U.S. Environmental Protection 
Agency, Washington, DC, EPA/600/R-20/012, 2020.
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    Scientific evidence also shows that repeated exposure to ozone can 
reduce growth and have other harmful effects on sensitive plants and 
trees. These types of effects have the potential to impact ecosystems 
and the benefits they provide.
3. SO2
    Current scientific evidence links short-term exposures to 
SO2, ranging from 5 minutes to 24 hours, with an array of 
adverse respiratory effects including bronchoconstriction and increased 
asthma symptoms. These effects are particularly important for 
asthmatics at elevated ventilation rates (e.g., while exercising or 
playing).
    Studies also show an association between short-term exposure and 
increased visits to emergency departments and hospital admissions for 
respiratory illnesses, particularly in at-risk populations including 
children, the elderly, and asthmatics.
    SO2 in the air can also damage the leaves of plants, 
decrease their ability to produce food--photosynthesis--and decrease 
their growth. In addition to directly affecting plants, SO2, 
when deposited on land and in estuaries, lakes, and streams, can 
acidify sensitive ecosystems resulting in a range of harmful indirect 
effects on plants, soils, water quality, and fish and wildlife (e.g., 
changes in biodiversity and loss of habitat, reduced tree growth, loss 
of fish species). Sulfur deposition to waterways also plays a causal 
role in the methylation of mercury.\68\
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    \68\ U.S. EPA. Integrated Science Assessment (ISA) for Oxides of 
Nitrogen and Sulfur Ecological Criteria (2008 Final Report). U.S. 
Environmental Protection Agency, Washington, DC, EPA/600/R-08/082F, 
2008.
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B. Oil and Natural Gas Industry and Its Emissions

    This section generally describes the structure of the Oil and 
Natural Gas Industry, the interconnected production, processing, 
transmission and storage, and distribution segments that move product 
from well to market, and types of emissions sources in each segment and 
the industry's emissions.
1. Oil and Natural Gas Industry--Structure
    The EPA characterizes the oil and natural gas industry's operations 
as being generally composed of four segments: (1) Extraction and 
production of crude oil and natural gas (``oil and natural gas 
production''), (2) natural gas processing, (3) natural gas transmission 
and storage, and (4) natural gas distribution.\69\ \70\ The EPA 
regulates oil refineries as a separate source category; accordingly, as 
with the previous oil and gas NSPS rulemakings, for purposes of this 
proposed rulemaking, for crude oil, the EPA's focus is on operations 
from the well to the point of custody transfer at a petroleum refinery, 
while for natural gas, the focus is on all operations from the well to 
the local distribution company custody transfer station commonly 
referred to as the ``city-gate.'' \71\
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    \69\ The EPA previously described an overview of the sector in 
section 2.0 of the 2011 Background Technical Support Document to 40 
CFR part 60, subpart OOOO, located at Docket ID Item No. EPA-HQ-OAR-
2010-0505-0045, and section 2.0 of the 2016 Background Technical 
Support Document to 40 CFR part 60, subpart OOOOa, located at Docket 
ID Item No. EPA-HQ-OAR-2010-0505-7631.
    \70\ While generally oil and natural gas production includes 
both onshore and offshore operations, 40 CFR part 60, subpart OOOOa 
addresses onshore operations.
    \71\ For regulatory purposes, the EPA defines the Crude Oil and 
Natural Gas source category to mean (1) Crude oil production, which 
includes the well and extends to the point of custody transfer to 
the crude oil transmission pipeline or any other forms of 
transportation; and (2) Natural gas production, processing, 
transmission, and storage, which include the well and extend to, but 
do not include, the local distribution company custody transfer 
station. The distribution segment is not part of the defined source 
category.
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a. Production Segment
    The oil and natural gas production segment includes the wells and 
all related processes used in the extraction, production, recovery, 
lifting, stabilization, and separation or treatment of oil and/or 
natural gas (including condensate). Although many wells produce a 
combination of oil and natural gas, wells can generally be grouped into 
two categories, oil wells and natural gas wells. Oil wells comprise two 
types, oil wells that produce crude oil only and oil wells that produce 
both crude oil and natural gas (commonly referred to as ``associated'' 
gas). Production equipment and components located on the well pad may 
include, but are not limited to, wells and related casing heads; tubing 
heads; ``Christmas tree'' piping, pumps, compressors; heater treaters; 
separators; storage vessels; pneumatic devices; and dehydrators. 
Production operations include well drilling, completion, and 
recompletion processes, including all the portable non-self-propelled 
apparatuses associated with those operations.
    Other sites that are part of the production segment include 
``centralized tank batteries,'' stand-alone sites where oil, 
condensate, produced water, and natural gas from several wells may be 
separated, stored, or treated. The production segment also includes 
gathering pipelines, gathering and boosting compressor stations, and 
related components that collect and transport the oil, natural gas, and 
other materials and wastes from the wells to the refineries or natural 
gas processing plants.
    Of these products, crude oil and natural gas undergo successive, 
separate processing. Crude oil is separated from water and other 
impurities and transported to a refinery via truck, railcar, or 
pipeline. As noted above, the EPA treats oil refineries as a separate 
source category, accordingly, for present purposes, the oil component 
of the production segment ends at the point of custody transfer at the 
refinery.\72\
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    \72\ See 40 CFR part 60, subparts J and Ja, and 40 CFR part 63, 
subparts CC and UUU.
---------------------------------------------------------------------------

    The separated, unprocessed natural gas is commonly referred to as 
field gas and is composed of methane, natural gas liquids (NGL), and 
other impurities, such as water vapor, H2S, CO2, 
helium, and nitrogen. Ethane, propane, butane, isobutane, and pentane 
are all considered NGL and often are sold separately for a variety of 
different uses. Natural gas with high methane content is referred to as 
``dry gas,'' while natural gas with significant amounts of ethane, 
propane, or butane is referred to as ``wet gas.'' Natural gas typically 
is sent to gas processing plants in order to separate NGLs for use as 
feedstock for petrochemical plants, burned for space heating and 
cooking, or blended into vehicle fuel.
b. Processing Segment
    The natural gas processing segment consists of separating certain 
hydrocarbons (HC) and fluids from the natural gas to produce ``pipeline 
quality'' dry natural gas. The degree and

[[Page 63129]]

location of processing is dependent on factors such as the type of 
natural gas (e.g., wet or dry gas), market conditions, and company 
contract specifications. Typically, processing of natural gas begins in 
the field and continues as the gas is moved from the field through 
gathering and boosting compressor stations to natural gas processing 
plants, where the complete processing of natural gas takes place. 
Natural gas processing operations separate and recover NGL or other 
non-methane gases and liquids from field gas through one or more of the 
following processes: oil and condensate separation, water removal, 
separation of NGL, sulfur and CO2 removal, fractionation of 
NGL, and other processes, such as the capture of CO2 
separated from natural gas streams for delivery outside the facility.
c. Transmission and Storage Segment
    Once natural gas processing is complete, the resulting natural gas 
exits the natural gas process plant and enters the transmission and 
storage segment where it is transmitted to storage and/or distribution 
to the end user.
    Pipelines in the natural gas transmission and storage segment can 
be interstate pipelines, which carry natural gas across state 
boundaries, or intrastate pipelines, which transport the gas within a 
single state. Basic components of the two types of pipelines are the 
same, though interstate pipelines may be of a larger diameter and 
operated at a higher pressure. To ensure that the natural gas continues 
to flow through the pipeline, the natural gas must periodically be 
compressed, thereby increasing its pressure. Compressor stations 
perform this function and are usually placed at 40- to 100-mile 
intervals along the pipeline. At a compressor station, the natural gas 
enters the station, where it is compressed by reciprocating or 
centrifugal compressors.
    Another part of the transmission and storage segment are 
aboveground and underground natural gas storage facilities. Storage 
facilities hold natural gas for use during peak seasons. The main 
difference between underground and aboveground storage sites is that 
storage takes place in storage vessels constructed of non-earthen 
materials in aboveground storage. Underground storage of natural gas 
typically occurs in depleted natural gas or oil reservoirs and salt 
dome caverns. One purpose of this storage is for load balancing 
(equalizing the receipt and delivery of natural gas). At an underground 
storage site, typically other processes occur, including compression, 
dehydration, and flow measurement.
d. Distribution Segment
    The distribution segment provides the final step in delivering 
natural gas to customers.\73\ The natural gas enters the distribution 
segment from delivery points located along interstate and intrastate 
transmission pipelines to business and household customers. The 
delivery point where the natural gas leaves the transmission and 
storage segment and enters the distribution segment is a local 
distribution company's custody transfer station, commonly referred to 
as the ``city-gate.'' Natural gas distribution systems consist of over 
2 million miles of piping, including mains and service pipelines to the 
customers. If the distribution network is large, compressor stations 
may be necessary to maintain flow; however, these stations are 
typically smaller than transmission compressor stations. Distribution 
systems include metering stations and regulating stations, which allow 
distribution companies to monitor the natural gas as it flows through 
the system.
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    \73\ The distribution segment is not included in the definition 
of the Crude Oil and Natural Gas source category that is currently 
regulated under 40 CFR part 60, subpart OOOOa.
---------------------------------------------------------------------------

2. Oil and Natural Gas Industry--Emissions
    The oil and natural gas industry sector is the largest source of 
industrial methane emissions in the U.S.\74\ Natural gas is comprised 
primarily of methane; every natural gas leak or intentional release 
through venting or other industrial processes constitutes a release of 
methane. Methane is a potent greenhouse gas; over a 100-year timeframe, 
it is nearly 30 times more powerful at trapping climate warming heat 
than CO2, and over a 20-year timeframe, it is 83 times more 
powerful.\75\ Because methane is a powerful greenhouse gas and is 
emitted in large quantities, reductions in methane emissions provide a 
significant benefit in reducing near-term warming. Indeed, one third of 
the warming due to GHGs that we are experiencing today is due to human 
emissions of methane. Additionally, the Crude Oil and Natural Gas 
sector emits, in varying concentrations and amounts, a wide range of 
other health-harming pollutants, including VOCs, SO2, 
NOX, H2S, CS2, and COS. The year 2016 
modeling platform produced by U.S. EPA estimated about 3 million tons 
of VOC are emitted by oil and gas-related sources.\76\
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    \74\ H.R. Rep. No. 117-64, 4 (2021) (Report by the House 
Committee on Energy and Commerce concerning H.J. Res. 34, to 
disapprove the 2020 Policy Rule) (House Report).
    \75\ IPCC, 2021.
    \76\ https://www.epa.gov/sites/default/files/2020-11/documents/2016v1_emismod_tsd_508.pdf.
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    Emissions of methane and these co-pollutants occur in every segment 
of the Crude Oil and Natural Gas source category. Many of the processes 
and equipment types that contribute to these emissions are found in 
every segment of the source category and are highly similar across 
segments. Emissions from the crude oil portion of the regulated source 
category result primarily from field production operations, such as 
venting of associated gas from oil wells, oil storage vessels, and 
production-related equipment such as gas dehydrators, pig traps, and 
pneumatic devices. Emissions from the natural gas portion of the 
industry can occur in all segments. As natural gas moves through the 
system, emissions primarily result from intentional venting through 
normal operations, routine maintenance, unintentional fugitive 
emissions, flaring, malfunctions, and system upsets. Venting can occur 
through equipment design or operational practices, such as the 
continuous and intermittent bleed of gas from pneumatic controllers 
(devices that control gas flows, levels, temperatures, and pressures in 
the equipment). In addition to vented emissions, emissions can occur 
from leaking equipment (also referred to as fugitive emissions) in all 
parts of the infrastructure, including major production and processing 
equipment (e.g., separators or storage vessels) and individual 
components (e.g., valves or connectors). Flares are commonly used 
throughout each segment in the Oil and Natural Gas Industry as a 
control device to provide pressure relief to prevent risk of explosions 
and to destroy methane, which has a high global warming potential, and 
convert it to CO2 which has a lower global warming 
potential, and to also control other air pollutants such as VOC.
    ``Super-emitting'' events, sites, or equipment, where a small 
proportion of sources account for a large proportion of overall 
emissions, can occur throughout the Oil and Natural Gas Industry and 
have been observed to occur in the equipment types and activities 
covered by this proposed action. There are a number of definitions for 
the term ``super-emitter.'' A 2018 National Academies of Sciences, 
Engineering, and Medicine report \77\ on methane discussed three 
categories of ``high-emitting'' sources:
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    \77\ https://www.nap.edu/download/24987#.

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[[Page 63130]]

     Routine or ``chronic'' high-emitting sources, which 
regularly emit at higher rates relative to ``peers'' in a sample. 
Examples include large facilities, or large emissions at smaller 
facilities caused by poor design or operational practices.
     Episodic high-emitting sources, which are typically large 
in nature and are generally intentional releases from known maintenance 
events at a facility. Examples include gas well liquids unloading, well 
workovers and maintenance activities, and compressor station or 
pipeline blowdowns.
     Malfunctioning high-emitting sources, which can be either 
intermittent or prolonged in nature and result from malfunctions and 
poor work practices. Examples include malfunctioning intermittent 
pneumatic controllers and stuck open dump valves. Another example is 
well blowout events. For example, a 2018 well blowout in Ohio was 
estimated to have emitted over 60,000 tons of methane.\78\
---------------------------------------------------------------------------

    \78\ Pandey et al. (2019). Satellite observations reveal extreme 
methane leakage from a natural gas well blowout. PNAS December 26, 
2019 116 (52) 26376-26381.
---------------------------------------------------------------------------

    Super-emitters have been observed at many different scales, from 
site-level to component-level, across many research studies.\79\ 
Studies will often develop a study-specific definition such as a top 
percentile of emissions in a study population (e.g., top 10 percent), 
emissions exceeding a certain threshold (e.g., 26 kg/day), emissions 
over a certain detection threshold (e.g., 1-3 g/s) or as facilities 
with the highest proportional emission rate.\80\ For certain equipment 
types and activities, the EPA's GHG emission estimates include the full 
range of conditions, including ``super-emitters.'' For other 
situations, where data are available, emissions estimates for abnormal 
events are calculated separately and included in the Inventory of U.S. 
Greenhouse Gas Emissions and Sinks (``GHGI'') (e.g., Aliso Canyon leak 
event).\81\ Given the variability of practices and technologies across 
oil and gas systems and the occurrence of episodic events, it is 
possible that the EPA's estimates do not include all methane emissions 
from abnormal events. The EPA continues to work through its stakeholder 
process to review new data from the EPA's Greenhouse Gas Reporting 
Program (``GHGRP'') petroleum and natural gas systems source category 
(40 CFR part 98, subpart W, also referred to as ``GHGRP subpart W'') 
and research studies to assess how emissions estimates can be improved. 
Because lost gas, whether through fugitive emissions, unintentional gas 
carry through, or intentional releases, represents lost earning 
potential, the industry benefits from capturing and selling emissions 
of natural gas (and methane). Limiting super-emitters through actions 
included in this rule such as reducing fugitive emissions, using lower 
emitting equipment where feasible, and employing best management 
practices will not only reduce emissions but reduce the loss of revenue 
from this valuable commodity.
---------------------------------------------------------------------------

    \79\ See for example, Brandt, A., Heath, G., Cooley, D. (2016) 
Methane leaks from natural gas systems follow extreme distributions. 
Environ. Sci. Technol., DOI: 10.1021/acs.est.6b04303; Zavala-Araiza, 
D., Alvarez, R.A., Lyon, D.R., Allen, D.T., Marchese, A.J., 
Zimmerle, D.J., & Hamburg, S.P. (2017). Super-emitters in natural 
gas infrastructure are caused by abnormal process conditions. Nature 
communications, 8, 14012; Mitchell, A., et al. (2015), Measurements 
of Methane Emissions from Natural Gas Gathering Facilities and 
Processing Plants: Measurement Results. Environmental Science & 
Technology, 49(5), 3219-3227; Allen, D., et al. (2014), Methane 
Emissions from Process Equipment at Natural Gas Production Sites in 
the United States: Pneumatic Controllers. Environmental Science & 
Technology.
    \80\ Caulton et al. (2019). Importance of Super-emitter Natural 
Gas Well Pads in the Marcellus Shale. Environ. Sci. Technol. 2019, 
53, 4747-4754; Zavala-Araiza, D., Alvarez, R., Lyon, D, et al. 
(2016). Super-emitters in natural gas infrastructure are caused by 
abnormal process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012; Lyon, et al. (2016). Aerial 
Surveys of Elevated Hydrocarbon Emissions from Oil and Gas 
Production Sites. Environ. Sci. Technol. 2016, 50, 4877-4886. 
https://pubs.acs.org/doi/10.1021/acs.est.6b00705; and Zavala-Araiza 
D, et al. (2015). Toward a functional definition of methane 
superemitters: Application to natural gas production sites. 49 
ENVTL. SCI. & TECH. 8167, 8168 (2015). https://pubs.acs.org/doi/10.1021/acs.est.5b00133.
    \81\ The EPA's emission estimates in the GHGI are developed with 
the best data available at the time of their development, including 
data from the Greenhouse Gas Reporting Program (GHGRP) in 40 CFR 
part 98, subpart W, and from recent research studies. GHGRP subpart 
W emissions data used in the GHGI are quantified by reporters using 
direct measurements, engineering calculations, or emission factors, 
as specified by the regulation. The EPA has a multi-step data 
verification process for GHGRP subpart W data, including automatic 
checks during data-entry, statistical analyses on completed reports, 
and staff review of the reported data. Based on the results of the 
verification process, the EPA follows up with facilities to resolve 
mistakes that may have occurred.
---------------------------------------------------------------------------

    Below we provide estimated emissions of methane, VOC, and 
SO2 from Oil and Natural Gas Industry operation sources.
    Methane emissions in the U.S. and from the Oil and Natural Gas 
industry. Official U.S. estimates of national level GHG emissions and 
sinks are developed by the EPA for the GHGI in fulfillment of 
commitments under the United Nations Framework Convention on Climate 
Change. The GHGI, which includes recent trends, is organized by 
industrial sector. The oil and natural gas production, natural gas 
processing, and natural gas transmission and storage sectors emit 28 
percent of U.S. anthropogenic methane. Table 7 below presents total 
U.S. anthropogenic methane emissions for the years 1990, 2010, and 
2019.
    In accordance with the practice of the EPA GHGI, the EPA GHGRP, and 
international reporting standards under the UN Framework Convention on 
Climate Change, the 2007 IPCC Fourth Assessment Report value of the 
methane 100-year GWP is used for weighting emissions in the following 
tables. The 100-year GWP value of 25 for methane indicates that one ton 
of methane has approximately as much climate impact over a 100-year 
period as 25 tons of carbon dioxide. The most recent IPCC AR6 
assessment has estimated a slightly larger 100-year GWP of methane of 
almost 30 (specifically, either 27.2 or 29.8 depending on whether the 
value includes the carbon dioxide produced by the oxidation of methane 
in the atmosphere). As mentioned earlier, because methane has a shorter 
lifetime than carbon dioxide, the emissions of a ton of methane will 
have more impact earlier in the 100-year timespan and less impact later 
in the 100-year timespan relative to the emissions of a 100-year GWP-
equivalent quantity of carbon dioxide: When using the AR6 20-year GWP 
of 81, which only looks at impacts over the next 20 years, the total US 
emissions of methane in 2019 would be equivalent to about 2140 MMT 
CO2.

                                    Table 7--U.S. Methane Emissions by Sector
                          [Million metric tons carbon dioxide equivalent (MMT CO2 EQ.)]
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2010            2019
----------------------------------------------------------------------------------------------------------------
Oil and Natural Gas Production, and Natural Gas Processing and               189             176             182
 Transmission and Storage.......................................
Landfills.......................................................             177             124             114
Enteric Fermentation............................................             165             172             179

[[Page 63131]]

 
Coal Mining.....................................................              96              82              47
Manure Management...............................................              37              55              62
Other Oil and Gas Sources.......................................              46              17              15
Wastewater Treatment............................................              20              19              18
Other Methane Sources \82\......................................              46              47              42
                                                                 -----------------------------------------------
    Total Methane Emissions.....................................             777             692             660
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2019 (published April 14,
  2021), calculated using GWP of 25. Note: Totals may not sum due to rounding.

    Table 8 below presents total methane emissions from natural gas 
production through transmission and storage and petroleum production, 
for years 1990, 2010, and 2019, in MMT CO2 Eq. (or million 
metric tons CO2 Eq.) of methane.
---------------------------------------------------------------------------

    \82\ Other sources include rice cultivation, forest land, 
stationary combustion, abandoned oil and natural gas wells, 
abandoned coal mines, mobile combustion, composting, and several 
sources emitting less than 1 MMT CO2 Eq. in 2019.

                     Table 8--U.S. Methane Emissions From Natural Gas and Petroleum Systems
                                                  [MMT CO2 EQ.]
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2010            2019
----------------------------------------------------------------------------------------------------------------
Natural Gas Production..........................................              63              97              94
Natural Gas Processing..........................................              21              10              12
Natural Gas Transmission and Storage............................              57              30              37
Petroleum Production............................................              48              39              38
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2019 (published April 14,
  2021), calculated using GWP of 25. Note: Totals may not sum due to rounding.

    Global GHG Emissions. For additional background information and 
context, we used 2018 World Resources Institute Climate Watch data to 
make comparisons between U.S. oil and natural gas production and 
natural gas processing and transmission and storage emissions and the 
emissions inventories of entire countries and regions.\83\ The U.S. 
methane emissions from oil and natural gas production and natural gas 
processing and transmission and storage constitute 0.4 percent of total 
global emissions of all GHGs (48,601 MMT CO2 Eq.) from all sources.\84\ 
Ranking U.S. emissions of methane from oil and natural gas production 
and natural gas processing and transmission and storage against total 
GHG emissions for entire countries (using 2018 Climate Watch data), 
shows that these emissions are comparatively large as they exceed the 
national-level emissions totals for all GHGs and all anthropogenic 
sources for Colombia, the Czech Republic, Chile, Belgium, and over 160 
other countries. What that means is that the U.S. emits more of a 
single GHG--methane--from a single sector--the oil and gas sector--than 
the total combined GHGs emitted by 164 out of 194 total countries. 
Furthermore, U.S. emissions of methane from oil and natural gas 
production and natural gas processing and transmission and storage are 
greater than the sum of total emissions of 64 of the lowest-emitting 
countries and territories, using the 2018 Climate Watch data set.
---------------------------------------------------------------------------

    \83\ The Climate Watch figures presented here come from the PIK 
PRIMAP-hist dataset included on Climate Watch. The PIK PRIMAP-hist 
dataset combines the United Nations Framework Convention on Climate 
Change (UNFCCC) reported data where available and fills gaps with 
other sources. It does not include land use change and forestry but 
covers all other sectors. https://www.climatewatchdata.org/ghg-emissions?end_year=2018&source=PIK&start_year=1990.
---------------------------------------------------------------------------

    As illustrated by the domestic and global GHGs comparison data 
summarized above, the collective GHG emissions from the Crude Oil and 
Natural Gas source category are significant, whether the comparison is 
domestic (where this sector is the largest source of methane emissions, 
accounting for 28 percent of U.S. methane and 3 percent of total U.S. 
emissions of all GHGs), global (where this sector, accounting for 0.4 
percent of all global GHG emissions, emits more than the total national 
emissions of over 160 countries, and combined emissions of over 60 
countries), or when both the domestic and global GHG emissions 
comparisons are viewed in combination. Consideration of the global 
context is important. GHG emissions from U.S. Oil and Natural Gas 
production and natural gas processing and transmission and storage will 
become globally well-mixed in the atmosphere, and thus will have an 
effect on the U.S. regional climate, as well as the global climate as a 
whole for years and indeed many decades to come. No single GHG source 
category dominates on the global scale. While the Crude Oil and Natural 
Gas source category, like many (if not all) individual GHG source 
categories, could appear small in comparison to total emissions, in 
fact, it is a very important contributor in terms of both absolute 
emissions, and in comparison to other source categories globally or 
within the U.S.
    The IPCC AR6 assessment determined that ``From a physical science 
perspective, limiting human-induced global warming to a specific level 
requires limiting cumulative CO2 emissions, reaching at 
least net zero CO2 emissions, along with strong reductions 
in other GHG emissions.'' The report also singled out the importance of 
``strong and sustained CH4 emission reductions'' in part due 
to the short lifetime of methane leading to the near-term cooling from 
reductions in methane emissions, which can offset the warming that will 
result due to reductions in emissions of cooling aerosols such as 
SO2. Therefore, reducing methane emissions globally is an 
important facet in any strategy to limit warming. In the oil and gas 
sector,

[[Page 63132]]

methane reductions are highly achievable and cost-effective using 
existing and well-known solutions and technologies that actually result 
in recovery of saleable product.
    VOC and SO2 emissions in the U.S. and from the oil and 
natural gas industry. Official U.S. estimates of national level VOC and 
SO2 emissions are developed by the EPA for the National 
Emissions Inventory (NEI), for which States are required to submit 
information under 40 CFR part 51, subpart A. Data in the NEI may be 
organized by various data points, including sector, NAICS code, and 
Source Classification Code. Tables 9 and 10 below present total U.S. 
VOC and SO2 emissions by sector, respectively, for the year 
2017, in kilotons (kt) (or thousand metric tons). The oil and natural 
gas sector represents the top anthropogenic U.S. sector for VOC 
emissions after removing the biogenics and wildfire sectors in Table 9 
(about 20% of the total VOC emitting by anthropogenic sources). About 
2.5 percent of the total U.S. anthropogenic SO2 comes from 
the oil and natural gas sector.

                  Table 9--U.S. VOC Emissions by Sector
                                  [kt]
------------------------------------------------------------------------
                         Sector                                2017
------------------------------------------------------------------------
Biogenics--Vegetation and Soil..........................          25,823
Fires--Wildfires........................................           4,578
Oil and Natural Gas Production, and Natural Gas                    2,504
 Processing and Transmission............................
Fires--Prescribed Fires.................................           2,042
Solvent--Consumer and Commercial Solvent Use............           1,610
Mobile--On-Road non-Diesel Light Duty Vehicles..........           1,507
Mobile--Non-Road Equipment--Gasoline....................           1,009
Other VOC Sources \85\..................................           4,045
                                                         ---------------
    Total VOC Emissions.................................          43,118
------------------------------------------------------------------------
Emissions from the 2017 NEI (released April 2020). Note: Totals may not
  sum due to rounding.


                 Table 10--U.S. SO2 Emissions by Sector
                                  [kt]
------------------------------------------------------------------------
                         Sector                                2017
------------------------------------------------------------------------
Fuel Combustion--Electric Generation--Coal..............           1,319
Fuel Combustion--Industrial Boilers, Internal Combustion             212
 Engines--Coal..........................................
Mobile--Commercial Marine Vessels.......................             183
Industrial Processes--Not Elsewhere Classified..........             138
Fires--Wildfires........................................             135
Industrial Processes--Chemical Manufacturing............             123
Oil and Natural Gas Production and Natural Gas                        65
 Processing and Transmission............................
Other SO2 Sources \86\..................................             551
                                                         ---------------
    Total SO2 Emissions.................................           2,726
------------------------------------------------------------------------
Emissions from the 2017 NEI (released April 2020). Note: Totals may not
  sum due to rounding.

    Table 11 below presents total VOC and SO2 emissions from 
oil and natural gas production through transmission and storage, for 
the year 2017, in kt. The contribution to the total anthropogenic VOC 
emissions budget from the oil and gas sector has been increasing in 
recent NEI cycles. In the 2017 NEI, the oil and gas sector makes up 
about 25 percent of the total VOC emissions from anthropogenic sources. 
The SO2 emissions have been declining in just about every 
anthropogenic sector, but the oil and gas sector is an exception where 
SO2 emissions have been slightly increasing or remaining 
steady in some cases in recent years.
---------------------------------------------------------------------------

    \85\ Other sources include remaining sources emitting less than 
1,000 kt VOC in 2017.
    \86\ Other sources include remaining sources emitting less than 
100 kt SO2 in 2017.

   Table 11--U.S. VOC and SO2 Emissions From Natural Gas and Petroleum
                                 Systems
                                  [kt]
------------------------------------------------------------------------
                 Sector                         VOC             SO2
------------------------------------------------------------------------
Oil and Natural Gas Production..........           2,478              41
Natural Gas Processing..................              12              23
Natural Gas Transmission and Storage....              14               1
------------------------------------------------------------------------
Emissions from the 2017 NEI, (published April 2020), in kt (or thousand
  metric tons). Note: Totals may not sum due to rounding.


[[Page 63133]]

IV. Statutory Background and Regulatory History

A. Statutory Background of CAA Sections 111(b), 111(d) and General 
Implementing Regulations

    The EPA's authority for this rule is CAA section 111, which governs 
the establishment of standards of performance for stationary sources. 
This section requires the EPA to list source categories to be 
regulated, establish standards of performance for air pollutants 
emitted by new sources in that source category, and establish EG for 
States to establish standards of performance for certain pollutants 
emitted by existing sources in that source category.
    Specifically, CAA section 111(b)(1)(A) requires that a source 
category be included on the list for regulation if, ``in [the EPA 
Administrator's] judgment it causes, or contributes significantly to, 
air pollution which may reasonably be anticipated to endanger public 
health or welfare.'' This determination is commonly referred to as an 
``endangerment finding'' and that phrase encompasses both of the 
``causes or contributes significantly to'' component and the ``endanger 
public health or welfare'' component of the determination. Once a 
source category is listed, CAA section 111(b)(1)(B) requires that the 
EPA propose and then promulgate ``standards of performance'' for new 
sources in such source category. CAA section 111(a)(1) defines a 
``standard of performance'' as ``a standard for emissions of air 
pollutants which reflects the degree of emission limitation achievable 
through the application of the best system of emission reduction which 
(taking into account the cost of achieving such reduction and any non-
air quality health and environmental impact and energy requirements) 
the Administrator determines has been adequately demonstrated.'' As 
long recognized by the D.C. Circuit, ``[b]ecause Congress did not 
assign the specific weight the Administrator should accord each of 
these factors, the Administrator is free to exercise his discretion in 
this area.'' New York v. Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992). 
See also Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 
1999) (``Lignite Energy Council'') (``Because section 111 does not set 
forth the weight that be [sic] should assigned to each of these 
factors, we have granted the agency a great degree of discretion in 
balancing them'').
    In determining whether a given system of emission reduction 
qualifies as ``the best system of emission reduction . . . adequately 
demonstrated,'' or ``BSER,'' CAA section 111(a)(1) requires that the 
EPA take into account, among other factors, ``the cost of achieving 
such reduction.'' As described in the proposal \87\ for the 2016 Rule 
(85 FR 35824, June 3, 2016), the U.S. Court of Appeals for the District 
of Columbia Circuit (the D.C. Circuit) has stated that in light of this 
provision, the EPA may not adopt a standard the cost of which would be 
``exorbitant,'' \88\ ``greater than the industry could bear and 
survive,'' \89\ ``excessive,'' \90\ or ``unreasonable.'' \91\ These 
formulations appear to be synonymous, and for convenience, in this 
rulemaking, as in previous rulemakings, we will use reasonableness as 
the standard, so that a control technology may be considered the ``best 
system of emission reduction . . . adequately demonstrated'' if its 
costs are reasonable, but cannot be considered the BSER if its costs 
are unreasonable. See 80 FR 64662, 64720-21 (October 23, 2015).
---------------------------------------------------------------------------

    \87\ 80 FR 56593, 56616 (September 18, 2015).
    \88\ Lignite Energy Council, 198 F.3d at 933.
    \89\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 
1975).
    \90\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \91\ Id.
---------------------------------------------------------------------------

    CAA section 111(a) does not provide specific direction regarding 
what metric or metrics to use in considering costs, affording the EPA 
considerable discretion in choosing a means of cost consideration.\92\ 
In this rulemaking, we evaluated whether a control cost is reasonable 
under a number of approaches that we find appropriate for assessing the 
types of controls at issue. For example, in evaluating controls for 
reducing VOC and methane emissions from new sources, we considered a 
control's cost effectiveness under both a ``single pollutant cost-
effectiveness'' approach and a ``multipollutant cost-effectiveness'' 
approach, in order to appropriately take into account that the systems 
of emission reduction considered in this rule typically achieve 
reductions in multiple pollutants at once and secure a multiplicity of 
climate and public health benefits.\93\ We also evaluated costs at a 
sector level by assessing the projected new capital expenditures 
required under the proposal (compared to overall new capital 
expenditures by the sector) and the projected compliance costs 
(compared to overall annual revenue for the sector) if the rule were to 
require such controls. For a detailed discussion of these cost 
approaches, please see section IX of the proposal preamble.
---------------------------------------------------------------------------

    \92\ See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C. 
Cir. 2001) (where CAA section 213 does not mandate a specific method 
of cost analysis, the EPA may make a reasoned choice as to how to 
analyze costs).
    \93\ We believe that both the single and multipollutant 
approaches are appropriate for assessing the reasonableness of the 
multipollutant controls considered in this action. The EPA has 
considered similar approaches in the past when considering multiple 
pollutants that are controlled by a given control option. See e.g., 
80 FR 56616-56617; 73 FR 64079-64083 and EPA Document ID Nos. EPA-
HQ-OAR-2004-0022-0622, EPA-HQ-OAR-2004-0022-0447, EPA-HQ-OAR-2004-
0022-0448.
---------------------------------------------------------------------------

    As defined in CAA section 111(a), the ``standard of performance'' 
that the EPA develops, based on the BSER, is expressed as a performance 
level (typically, a rate-based standard). CAA section 111(b)(5) 
precludes the EPA from prescribing a particular technological system 
that must be used to comply with a standard of performance. Rather, 
sources can select any measure or combination of measures that will 
achieve the standard.
    CAA section 111(h)(1) authorizes the Administrator to promulgate 
``a design, equipment, work practice, or operational standard, or 
combination thereof'' if in his or her judgment, ``it is not feasible 
to prescribe or enforce a standard of performance.'' CAA section 
111(h)(2) provides the circumstances under which prescribing or 
enforcing a standard of performance is ``not feasible,'' such as, when 
the pollutant cannot be emitted through a conveyance designed to emit 
or capture the pollutant, or when there is no practicable measurement 
methodology for the particular class of sources.\94\ CAA section 
111(b)(1)(B) requires the EPA to ``at least every 8 years review and, 
if appropriate, revise'' performance standards unless the 
``Administrator determines that such review is not appropriate in light 
of readily available information on the efficacy'' of the standard.
---------------------------------------------------------------------------

    \94\ The EPA notes that design, equipment, work practice or 
operational standards established under CAA section 111(h) (commonly 
referred to as ``work practice standards'') reflect the ``best 
technological system of continuous emission reduction'' and that 
this phrasing differs from the ``best system of emission reduction'' 
phrase in the definition of ``standard of performance'' in CAA 
section 111(a)(1). Although the differences in these phrases may be 
meaningful in other contexts, for purposes of evaluating the sources 
and systems of emission reduction at issue in this rulemaking, the 
EPA has applied these concepts in an essentially comparable manner.
---------------------------------------------------------------------------

    As mentioned above, once the EPA lists a source category under CAA 
section 111(b)(1)(A), CAA section 111(b)(1)(B) provides the EPA 
discretion to determine the pollutants and sources to be regulated. In 
addition, concurrent with the 8-year review (and though not a mandatory 
part of the 8-year review), the EPA may examine whether to add 
standards for pollutants or emission

[[Page 63134]]

sources not currently regulated for that source category.
    Once the EPA establishes NSPS in a particular source category, the 
EPA is required in certain circumstances to issue EG to reduce 
emissions from existing sources in that same source category. 
Specifically, CAA section 111(d) requires that the EPA prescribe 
regulations to establish procedures under which States submit plans to 
establish, implement, and enforce standards of performance for existing 
sources for certain air pollutants to which a Federal NSPS would apply 
if such existing source were a new source. The EPA addresses this CAA 
requirement both through its promulgation of general implementing 
regulations for section 111(d) as well as specific EG. The EPA first 
published general implementing regulations in 1975, 40 FR 53340 
(November 17, 1975) (codified at 40 CFR part 60, subpart B), and has 
revised its section 111(d) implementing regulations several times, most 
recently on July 8, 2019, 84 FR 32520 (codified at 40 CFR part 60, 
subpart Ba).\95\ In accordance with CAA section 111(d), States are 
required to submit plans pursuant to these regulations to establish 
standards of performance for existing sources for any air pollutant: 
(1) The emission of which is subject to a Federal NSPS; and (2) which 
is neither a pollutant regulated under CAA section 108(a) (i.e., 
criteria pollutants such as ground-level ozone and particulate matter, 
and their precursors, like VOC) \96\ or a HAP regulated under CAA 
section 112. See also definition of ``designated pollutant'' in 40 CFR 
60.21a(a). The EPA's general implementing regulations use the term 
``designated facility'' to identify those existing sources that may be 
subject to regulation under this provision of CAA section 111(d). See 
40 CFR 60.21a(b).
---------------------------------------------------------------------------

    \95\ Subpart Ba provides for the applicability of its provisions 
upon final publication of an EG if such EG is published after July 
8, 2019. Sec.  60.20a(a). The EPA acknowledges that the D.C. Circuit 
has vacated certain timing provisions within subpart Ba. Am. Lung 
Assoc. v. EPA, 985 F.3d 914 (D.C. Cir. 2021), petition for cert. 
pending, No. 20-1778 (filed June 23, 2001) (Am. Lung Assoc.). 
However, the court did not vacate the applicability provision, 
therefore subpart Ba applies to any EG finalized from this proposal. 
The Agency plans to undertake rulemaking to address the provisions 
vacated under the court's decision in the near future.
    \96\ VOC are not listed as CAA section 108(a) pollutants, but 
they are regulated precursors to photochemical oxidants (e.g., 
ozone) and particulate matter (PM), both of which are listed CAA 
section 108(a) pollutants, and VOC therefore fall within the CAA 
108(a) exclusion. Accordingly, promulgation of NSPS for VOC does not 
trigger the application of CAA section 111(d).
---------------------------------------------------------------------------

    While States are authorized to establish standards of performance 
for designated facilities, there is a fundamental obligation under CAA 
section 111(d) that such standards of performance reflect the degree of 
emission limitation achievable through the application of the BSER, as 
determined by the Administrator. This obligation derives from the 
definition of ``standard of performance'' under CAA section 111(a)(1), 
which makes no distinction between new-source and existing-source 
standards. The EPA identifies the degree of emission limitation 
achievable through application of the BSER as part of its EG. See 40 
CFR 60.22a(b)(5). While standards of performance must generally reflect 
the degree of emission limitation achievable through application of the 
BSER, CAA section 111(d)(1) also requires that the EPA regulations 
permit the States, in applying a standard of performance to a 
particular source, to take into account the source's remaining useful 
life and other factors.
    After the EPA issues final EG per the requirements under CAA 
section 111(d) and 40 CFR part 60, subpart Ba, States are required to 
submit plans that establish standards of performance for the designated 
facilities as defined in the EPA's guidelines and that contain other 
measures to implement and enforce those standards. The EPA's final EG 
issued under CAA section 111(d) do not impose binding requirements 
directly on sources, but instead provide requirements for States in 
developing their plans and criteria for assisting the EPA when judging 
the adequacy of such plans. Under CAA section 111(d), and the EPA's 
implementing regulations, a State must submit its plan to the EPA for 
approval, the EPA will evaluate the plan for completeness in accordance 
with enumerated criteria, and then will act on that plan via a 
rulemaking process to either approve or disapprove the plan in whole or 
in part. If a State does not submit a plan, or if the EPA does not 
approve a State's plan because it is not ``satisfactory,'' then the EPA 
must establish a Federal plan for that State.\97\ If EPA approves a 
State's plan, the provisions in the state plan become federally 
enforceable against the designated facility responsible for compliance 
in the same manner as the provisions of an approved State 
implementation plan under CAA section 110. If no designated facility is 
located within a State, the State must submit to the EPA a letter 
certifying to that effect in lieu of submitting a State plan. See 40 
CFR 60.23a(b).
---------------------------------------------------------------------------

    \97\ CAA section 111(d)(2)(A).
---------------------------------------------------------------------------

    Designated facilities located in Indian country would not be 
addressed by a State's CAA section 111(d) plan. Instead, an eligible 
Tribe that has one or more designated facilities located in its area of 
Indian country \98\ would have the opportunity, but not the obligation, 
to seek authority and submit a plan that establishes standards of 
performance for those facilities on its Tribal lands.\99\ If a Tribe 
does not submit a plan, or if the EPA does not approve a Tribe's plan, 
then the EPA has the authority to establish a Federal plan for that 
Tribe.\100\
---------------------------------------------------------------------------

    \98\ The EPA is aware of many oil and natural gas operations 
located in Indian Country.
    \99\ See 40 CFR part 49, subpart A.
    \100\ CAA section 111(d)(2)(A).
---------------------------------------------------------------------------

B. What is the regulatory history and litigation background of NSPS and 
EG for the oil and natural gas industry?
1. 1979 Listing of Source Category
    Subsequent to the enactment of the CAA of 1970, the EPA took action 
to develop standards of performance for new stationary sources as 
directed by Congress in CAA section 111. By 1977, the EPA had 
promulgated NSPS for a total of 27 source categories, while NSPS for an 
additional 25 source categories were then under development.\101\ 
However, in amending the CAA that year, Congress expressed 
dissatisfaction that the EPA's pace was too slow. Accordingly, the 1977 
CAA Amendments included a new subsection (f) in section 111, which 
specified a schedule for the EPA to list additional source categories 
under CAA section 111(b)(1)(A) and prioritize them for regulation under 
CAA section 111(b)(1)(B).
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    \101\ See 44 FR 49222 (August 21, 1979).
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    In 1979, as required by CAA section 111(f), the EPA published a 
list of source categories, which included ``Crude Oil and Natural Gas 
Production,'' for which the EPA would promulgate standards of 
performance under CAA section 111(b). See Priority List and Additions 
to the List of Categories of Stationary Sources, 44 FR 49222 (August 
21, 1979) (``1979 Priority List''). That list included, in the order of 
priority for promulgating standards, source categories that the EPA 
Administrator had determined, pursuant to CAA section 111(b)(1)(A), 
contribute significantly to air pollution that may reasonably be 
anticipated to endanger public health or welfare. See 44 FR 49223 
(August 21, 1979); see also 49 FR 2636-37 (January 20, 1984).

[[Page 63135]]

2. 1985 NSPS for VOC and SO2 Emissions From Natural Gas 
Processing Units
    On June 24, 1985 (50 FR 26122), the EPA promulgated NSPS for the 
Crude Oil and Natural Gas source category that addressed VOC emissions 
from equipment leaks at onshore natural gas processing plants (40 CFR 
part 60, subpart KKK). On October 1, 1985 (50 FR 40158), the EPA 
promulgated additional NSPS for the source category to regulate 
SO2 emissions from onshore natural gas processing plants (40 
CFR part 60, subpart LLL).
3. 2012 NSPS OOOO Rule and Related Amendments
    In 2012, pursuant to its duty under CAA section 111(b)(1)(B) to 
review and, if appropriate, revise the 1985 NSPS, the EPA published the 
final rule, ``Standards of Performance for Crude Oil and Natural Gas 
Production, Transmission and Distribution,'' 77 FR 49490 (August 16, 
2012) (40 CFR part 60, subpart OOOO) (``2012 NSPS OOOO''). The 2012 
rule updated the SO2 standards for sweetening units and the 
VOC standards for equipment leaks at onshore natural gas processing 
plants. In addition, it established VOC standards for several oil and 
natural gas-related operations emission sources not covered by 40 CFR 
part 60, subparts KKK and LLL, including natural gas well completions, 
centrifugal and reciprocating compressors, certain natural gas operated 
pneumatic controllers in the production and processing segments of the 
industry, and storage vessels in the production, processing, and 
transmission and storage segments.
    In 2013, 2014, and 2015 the EPA amended the 2012 NSPS OOOO rule in 
order to address implementation of the standards. ``Oil and Natural Gas 
Sector: Reconsideration of Certain Provisions of New Source Performance 
Standards,'' 78 FR 58416 (September 23, 2013) (``2013 NSPS OOOO'') 
(concerning storage vessel implementation); ``Oil and Natural Gas 
Sector: Reconsideration of Additional Provisions of New Source 
Performance Standards,'' 79 FR 79018 (December 31, 2014) (``2014 NSPS 
OOOO'') (concerning well completion); ``Oil and Natural Gas Sector: 
Definitions of Low Pressure Gas Well and Storage Vessel,'' 80 FR 48262 
(August 12, 2015) (``2015 NSPS OOOO'') (concerning low pressure gas 
wells and storage vessels).
    The EPA received petitions for both judicial review and 
administrative reconsiderations for the 2012, 2013, and 2014 NSPS OOOO 
rules. The EPA denied reconsideration for some issues, see 
``Reconsideration of the Oil and Natural Gas Sector: New Source 
Performance Standards; Final Action,'' 81 FR 52778 (August 10, 2016), 
and, as noted below, granted reconsideration for other issues. As 
explained below, all litigation related to NSPS OOOO is currently in 
abeyance.
4. 2016 NSPS OOOOa Rule and Related Amendments
    Regulatory action. On June 3, 2016, the EPA published a final rule 
titled ``Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources; Final Rule,'' at 81 FR 35824 (40 
CFR part 60, subpart OOOOa) (``2016 Rule'' or ``2016 NSPS 
OOOOa'').^{102 103} The 2016 NSPS OOOOa rule established NSPS 
for sources of GHGs and VOC emissions for certain equipment, processes, 
and operations across the Oil and Natural Gas Industry, including in 
the transmission and storage segment. 81 FR at 35832. The EPA explained 
that the 1979 listing identified the source category broadly enough to 
include that segment and, in the alternative, if the listing had 
limited the source category to the production and processing segments, 
the EPA affirmatively expanded the source category to include the 
transmission and storage segment on grounds that operations in those 
segments are a sequence of functions that are interrelated and 
necessary for getting the recovered gas ready for distribution. 81 FR 
at 35832. In addition, because this rule was the first time that the 
EPA had promulgated NSPS for GHG emissions from the Crude Oil and 
Natural Gas source category, the EPA predicated those NSPS on a 
determination that it had a rational basis to regulate GHG emissions 
from the source category. 81 FR at 35843. In response to comments, the 
EPA explained that it was not required to make an additional pollutant-
specific finding that GHG emissions from the source category contribute 
significantly to dangerous air pollution, but in the alternative, the 
EPA did make such a finding, relying on the same information that it 
relied on when determining that it had a rational basis to promulgate a 
GHGs NSPS. 81 FR at 35843.
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    \102\ The June 3, 2016, rulemaking also included certain final 
amendments to 40 CFR part 60, subpart OOOO, to address issues on 
which the EPA had granted reconsideration.
    \103\ The EPA review which resulted in the 2016 NSPS OOOOa rule 
was instigated by a series of directives from then-President Obama 
targeted at reducing GHGs, including methane: The President's 
Climate Action Plan (June 2013); the President's Climate Action 
Plan: Strategy to Reduce Methane Emissions (``Methane Strategy'') 
(March 2014); and the President's goal to address, propose and set 
standards for methane and ozone-forming emissions from new and 
modified sources in the sector (January 2015, https://obamawhitehouse.archives.gov/the-press-office/2015/01/14/fact-sheet-Administration-takes-steps-forward-climate-action-plan-anno-1).
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    Specifically, the 2016 NSPS OOOOa addresses the following emission 
sources:
     Sources that were unregulated under the 2012 NSPS OOOO 
(hydraulically fractured oil well completions, pneumatic pumps, and 
fugitive emissions from well sites and compressor stations);
     Sources that were regulated under the 2012 NSPS OOOO for 
VOC emissions, but not for GHG emissions (hydraulically fractured gas 
well completions and equipment leaks at natural gas processing plants); 
and
     Certain equipment that is used across the source category, 
of which the 2012 NSPS OOOO regulated emissions of VOC from only a 
subset (pneumatic controllers, centrifugal compressors, and 
reciprocating compressors, with the exception of those compressors 
located at well sites).
    On March 12, 2018 (83 FR 10628), the EPA finalized amendments to 
certain aspects of the 2016 NSPS OOOOa requirements for the collection 
of fugitive emission components at well sites and compressor stations, 
specifically (1) the requirement that components on a delay of repair 
must conduct repairs during unscheduled or emergency vent blowdowns, 
and (2) the monitoring survey requirements for well sites located on 
the Alaska North Slope.
    Petitions for judicial review and to reconsider. Following 
promulgation of the 2016 NSPS OOOOa rule, several states and industry 
associations challenged the rule in the D.C. Circuit. The Administrator 
also received five petitions for reconsideration of several provisions 
of the final rule. Copies of the petitions are posted in Docket ID No. 
EPA-HQ-OAR-2010-0505.\104\ As noted below, the EPA granted 
reconsideration as to several issues raised with respect to the 2016 
NSPS OOOOa rule and finalized certain modifications discussed in the 
next section. As explained below, all litigation challenging the 2016 
NSPS OOOOa rule is currently stayed.
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    \104\ See Docket ID Item Nos.: EPA-HQ-OAR-2010-0505-7682, EPA-
HQ-OAR-2010-0505-7683, EPA-HQ-OAR-2010-0505-7684, EPA-HQ-OAR-2010-
0505-7685, EPA-HQ-OAR-2010-0505-7686.
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5. 2020 Policy and Technical Rules
    Regulatory action. In September 2020, the EPA published two final 
rules to amend 2012 NSPS OOOO and 2016 NSPS OOOOa. The first is titled, 
``Oil

[[Page 63136]]

and Natural Gas Sector: Emission Standards for New, Reconstructed, and 
Modified Sources Review.'' 85 FR 57018 (September 14, 2020). Commonly 
referred to as the 2020 Policy Rule, it first rescinded the regulations 
applicable to the transmission and storage segment on the basis that 
the 1979 listing limited the source category to the production and 
processing segments and that the transmission and storage segment is 
not ``sufficiently related'' to the production and processing segments, 
and therefore cannot be part of the same source category. 85 FR at 
57027, 57029. In addition, the 2020 Policy Rule rescinded methane 
requirements for the industry's production and processing segments on 
two separate bases. The first was that such standards are redundant to 
VOC standards for these segments. 85 FR at 57030. The second was that 
the rule interpreted section 111 to require, or at least authorize the 
Administrator to require, a pollutant-specific ``significant 
contribution finding'' (SCF) as a prerequisite to a NSPS for a 
pollutant, and to require that such finding be supported by some 
identified standard or established set of criteria for determining 
which contributions are ``significant.'' 85 FR at 57034. The rule went 
on to conclude that the alternative significant-contribution finding 
that the EPA made in the 2016 Rule for GHG emissions was flawed because 
it accounted for emissions from the transmission and storage segment 
and because it was not supported by criteria or a threshold. 85 FR at 
57038.\105\
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    \105\ Following the promulgation of the 2020 Policy Rule, the 
EPA promulgated a final rule that identified a standard or criteria 
for determining which contributions are ``significant,'' which the 
D.C. Circuit vacated. ``Pollutant-Specific Significant Contribution 
Finding for Greenhouse Gas Emissions From New, Modified, and 
Reconstructed Stationary Sources: Electric Utility Generating Units, 
and Process for Determining Significance of Other New Source 
Performance Standards Source Categories.'' 86 FR 2542 (Jan. 13, 
2021), vacated by California v. EPA, No. 21-1035 (D.C. Cir.) (Order, 
April 5, 2021, Doc. #1893155).
---------------------------------------------------------------------------

    Published on September 15, 2020, the second of the two rules is 
titled, ``Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources Reconsideration.'' Commonly 
referred to as the 2020 Technical Rule, this second rule made further 
amendments to the 2016 NSPS OOOOa following the 2020 Policy Rule to 
eliminate or reduce certain monitoring obligations and to address a 
range of issues in response to administrative petitions for 
reconsideration and other technical and implementation issues brought 
to the EPA's attention since the 2016 NSPS OOOOa rulemaking. 
Specifically, the 2020 Technical Rule exempted low-production well 
sites from fugitives monitoring (previously required semiannually), 
required semiannual monitoring at gathering and boosting compressor 
stations (previously quarterly), streamlined recordkeeping and 
reporting requirements, allowed compliance with certain equivalent 
State requirements as an alternative to NSPS fugitive requirements, 
streamlined the application process to request the use of new 
technologies to monitor for fugitive emissions, addressed storage tank 
batteries for applicability determination purposes and finalized 
several technical corrections. Because the 2020 Technical Rule was 
issued the day after the EPA's rescission of methane regulations in the 
2020 Policy Rule, the amendments made in the 2020 Technical Rule 
applied only to the requirements to regulate VOC emissions from this 
source category. The 2020 Policy Rule amended 40 CFR part 60, subparts 
OOOO and OOOOa, as finalized in 2016. The 2020 Technical Rule amended 
the 40 CFR part 60, subpart OOOOa, as amended by the 2020 Policy Rule.
    Petitions to reconsider. The EPA received three petitions for 
reconsideration of the 2020 rulemakings. Two of the petitions sought 
reconsideration of the 2020 Policy Rule. As discussed below, on June 
30, 2021, the President signed into law S.J. Res. 14, a joint 
resolution under the CRA disapproving the 2020 Policy Rule, and as a 
result, the petitions for reconsideration on the 2020 Policy Rule are 
now moot. All three petitions sought reconsideration of certain 
elements of the 2020 Technical Rule.
    Litigation. Several States and non-governmental organizations 
challenged the 2020 Policy Rule as well as the 2020 Technical Rule. All 
petitions for review regarding the 2020 Policy Rule were consolidated 
into one case in the D.C. Circuit. State of California, et al. v. EPA, 
No. 20-1357. On August 25, 2021, after the enactment of the joint 
resolution of Congress disapproving the 2020 Policy Rule (explained in 
section VIII below), the court granted petitioners motion to 
voluntarily dismiss their cases. Id. ECF Dkt #1911437. All petitions 
for review regarding the 2020 Technical Rule were consolidated into a 
different case in the D.C. Circuit. Environmental Defense Fund, et al. 
v. EPA, No. 20-1360 (D.C. Cir.). On February 19, 2021, the court issued 
an order granting a motion by the EPA to hold in abeyance the 
consolidated litigation over the 2020 Technical Rule pending EPA's 
rulemaking actions in response to E.O. 13990 and pending the conclusion 
of EPA's potential reconsideration of the 2020 Technical Rule. Id. ECF 
Dkt #1886335.
    As mentioned above, the EPA received petitions for judicial review 
regarding the 2012, 2013, and 2014 NSPS OOOO rules as well as the 2016 
NSPS OOOOa rule. The challenges to the 2012 NSPS OOOO rule (as amended 
by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) were consolidated. 
American Petroleum Institute v. EPA, No. 13-1108 (D.C. Cir.). The 
majority of those cases were further consolidated with the consolidated 
challenges to the 2016 NSPS OOOOa rule. West Virginia v. EPA, No. 16-
1264 (D.C. Cir.), see specifically ECF Dkt #1654072. As such, West 
Virginia v. EPA includes challenges to the 2012 NSPS OOOO rule (as 
amended by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) as well as 
challenges to the 2016 NSPS OOOOa rule.\106\ On December 10, 2020, the 
court granted a joint motion of the parties in West Virginia v. EPA to 
hold that case in abeyance until after the mandate has issued in the 
case regarding challenges to the 2020 Technical Rule. West Virginia v. 
EPA, ECF Dkt #1875192.
---------------------------------------------------------------------------

    \106\ When the EPA issued the 2016 NSPS OOOOa rule, a challenge 
to the 2012 NSPS OOOO rule for failing to regulate methane was 
severed and assigned to a separate case, NRDC v. EPA, No. 16-1425 
(D.C. Cir.), pending judicial review of the 2016 NSPS OOOOa in 
American Petroleum Institute v. EPA, No. 13-1108 (D.C. Cir.).
---------------------------------------------------------------------------

C. Congressional Review Act (CRA) Joint Resolution of Disapproval

    On June 30, 2021, the President signed into law a joint resolution 
of Congress, S.J. Res. 14, adopted under the CRA,\107\ disapproving the 
2020 Policy Rule.\108\ By the terms of the CRA, the signing into law of 
the CRA joint resolution of disapproval means that the 2020 Policy Rule 
is ``treated as though [it] had never taken effect.'' 5 U.S.C. 801(f). 
As a result, the VOC and methane standards for the transmission and 
storage segment, as well as the methane standards for the production 
and processing segments--all of which had been rescinded in the 2020 
Policy Rule--remain in effect. In addition, the EPA's authority and 
obligation to require the States to regulate existing sources of 
methane in the Crude Oil and

[[Page 63137]]

Natural Gas source category under section 111(d) of the CAA also 
remains in effect.
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    \107\ The Congressional Review Act was adopted in Subtitle E of 
the Small Business Regulatory Enforcement Fairness Act of 1996.
    \108\ ``Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources Review,'' 85 FR 57018 (Sept. 14, 
2020) (``2020 Policy Rule'').
---------------------------------------------------------------------------

    The CRA resolution did not address the 2020 Technical Rule; 
therefore, those amendments remain in effect with respect to the VOC 
standards for the production and processing segments in effect at the 
time of its enactment. As part of this rulemaking, in sections VIII and 
X the EPA discusses the impact of the CRA resolution, and identifies 
and proposes appropriate changes to reinstate the regulatory text that 
had been rescinded by the 2020 Policy Rule and to resolve any 
discrepancies in the regulatory text between the 2016 NSPS OOOOa Rule 
and 2020 Technical Rule.

V. Related Emissions Reduction Efforts

    This section summarizes related State actions and other Federal 
actions regulating oil and natural gas emissions sources and summarizes 
industry and voluntary efforts to reduce climate change. The proposed 
NSPS OOOOb and EG OOOOc include specific measures that build on the 
experience and knowledge the Agency and industry have gained through 
voluntary programs, as well as the leadership of the States in 
pioneering new regulatory programs. The proposed NSPS OOOOb and EG 
OOOOc consists of reasonable, proven, cost-effective technologies and 
practices that reflect the evolutionary nature of the Oil and Natural 
Gas Industry and proactive regulatory and voluntary efforts. The EPA 
intends that the requirements proposed in this document will spur all 
industry stakeholders in all parts of the country to apply these 
readily available and cost-effective measures.

A. Related State Actions and Other Federal Actions Regulating Oil and 
Natural Gas Sources

    The EPA recognizes that several States and other Federal agencies 
currently regulate the Oil and Natural Gas Industry. The EPA also 
recognizes that these State and other Federal agency regulatory 
programs have matured since the EPA began implementing its 2012 NSPS 
and subsequent 2016 NSPS. The EPA further acknowledges the technical 
innovations that the Oil and Natural Gas Industry has made during the 
past decade; this industry is fast-paced and constantly changing based 
on the latest technology. The EPA commends these efforts and recognizes 
States for their innovative standards, alternative compliance options, 
and implementation strategies. The EPA recognizes that any one effort 
will not be enough to address the increasingly dangerous impacts of 
climate change on public health and welfare and believes that 
consistent Federal regulation of the Crude Oil and Natural Gas source 
category plays an important role. To have a meaningful impact on 
climate change and its impact to human health and the environment, a 
multifaceted approach needs to be taken to ensure methane reductions 
will be realized. The EPA also recognizes that States and other Federal 
agencies regulate in accordance with their own authorities and within 
their own respective jurisdictions, and collectively do not fully 
address the range of sources and emission reduction measures contained 
in this proposal. Direct Federal regulation of methane from new sources 
combined with the approved State plans that are consistent with the 
EPA's EG for existing sources will bring national consistency to level 
the regulatory playing field, help promote technological innovation, 
and reduce both climate- and other health-harming pollution from a 
large number of sources that are either currently unregulated or where 
additional cost-effective reductions can be obtained. The EPA is 
committed to working within its authority to provide opportunities to 
align its programs with other existing State and Federal programs to 
reduce unnecessary regulatory redundancy where appropriate.
    Among assessing various studies and emissions data, the EPA 
reviewed many current and proposed State regulatory programs to 
identify potential regulatory options that could be considered for 
BSER.\109\ For example, the EPA reviewed California, Colorado, and 
Canadian regulations, as well as a pending proposed rule in New Mexico, 
that require non-emitting pneumatic devices at certain facilities and 
in certain circumstances. The EPA also examined California, Colorado, 
New Mexico (proposed), Pennsylvania, Wyoming, and the Bureau of Land 
Management (BLM) standards for liquids unloading events. Some of these 
States have led the way in regulating emissions sources that were not 
yet subject to requirements under the NSPS OOOOa. For example, Colorado 
requires the use of best management practices to minimize hydrocarbon 
emissions and the need for well venting associated with downhole well 
maintenance and liquids unloading, unless venting is necessary for 
safety. Other States, such as New Mexico, are evaluating similar 
requirements. Other States have requirements for emission sources 
currently regulated under NSPS OOOOa that are more stringent. For 
example, California and Colorado require continuous bleed natural gas-
driven pneumatic controllers be non-emitting, with specified 
exceptions. We recognize that, in some cases, the EPA's proposed NSPS 
and/or EG may be more stringent than existing programs and, in other 
cases, may be less stringent than existing programs. After careful 
review and consideration of State regulatory programs in place and 
proposed State regulations, we are proposing NSPS and EG that, when 
implemented, will reduce emissions of harmful air pollutants, promote 
gas capture and beneficial use, and provide opportunity for flexibility 
and expanded transparency in order to yield a consistent and 
accountable national program that provides a clear path for States and 
other Federal agencies to further partner to ensure their programs work 
in conjunction with each other.
---------------------------------------------------------------------------

    \109\ The NSPS OOOOb and EG TSD provides a high-level summary of 
the state programs that the agency assessed for purposes of this 
proposal.
---------------------------------------------------------------------------

    As an example of how the EPA strives to work with sources in States 
that have overlapping regulations for the Oil and Natural Gas Industry, 
the 2020 Technical Rule included approval of certain State programs as 
alternatives to certain requirements in the Federal NSPS. Subject to 
certain caveats, the EPA deemed certain fugitive emissions standards 
for well sites and compressor stations located in specific States 
equivalent to the NSPS in an effort to reduce any regulatory burden 
imposed by duplicative State and Federal regulations. See 40 CFR 
60.5399a. The EPA worked extensively with States and reviewed many 
details of many State programs in this effort. Further, the 2020 
Technical Rule amended 40 CFR part 60, subpart OOOOa, to incorporate a 
process that allows other States not already listed in 40 CFR 60.5399a 
to request approval of their fugitive monitoring program as an 
alternative to the NSPS. The EPA is proposing to include a similar 
request and approval process in NSPS OOOOb. Further, the EPA plans to 
work closely with States as they develop their State plans pursuant to 
the EG to look for opportunities to reduce unnecessary administrative 
burden imposed by redundant and duplicative regulatory requirements and 
help States that want to establish more stringent standards.
    In addition to States, certain Federal agencies also regulate 
aspects of the oil and natural gas industry pursuant to their own 
authorities and have other established programs affecting the industry. 
The EPA believes that Federal regulatory actions and efforts will 
provide other environmental co-

[[Page 63138]]

benefits, but the EPA recognizes itself to be the Federal agency that 
has primary responsibility to protect human health and the environment 
and has been given the unique responsibility and authority by Congress 
to address the suite of harmful air pollutants associated with this 
source category. The EPA further believes that to have a meaningful 
impact to address the dangers of climate change, it is going to require 
an ``all hands-on deck'' effort across all States and all Federal 
agencies. The EPA has maintained an ongoing dialogue with its Federal 
partners during the development of this proposed rule to minimize any 
potential regulatory conflicts and to minimize confusion and regulatory 
burden on the part of owners and operators. The below description 
summarizes other agencies' regulations and other established Federal 
programs.
    The U.S. Department of the Interior (DOI) regulates the extraction 
of oil and gas from Federal lands. Bureaus within the DOI include BLM 
and the Bureau of Ocean Energy Management (BOEM). The BLM manages the 
Federal Government's onshore subsurface mineral estate--about 700 
million acres (30 percent of the U.S.)--for the benefit of the American 
public. The BLM maintains an oil and gas leasing program pursuant to 
the Mineral Leasing Act, the Mineral Leasing Act for Acquired Lands, 
the Federal Land Management and Policy Act, and the Federal Oil and Gas 
Royalty Management Act. Pursuant to a delegation of Secretarial 
authority, the BLM also oversees oil and gas operations on many Indian/
Tribal leases. The BLM's oil and gas operating regulations are found in 
43 CFR part 3160. An oil and gas operator's general environmental and 
safety obligations are found at 43 CFR 3162.5. The BLM does not 
directly regulate emissions for the purposes of air quality. However, 
BLM does regulate venting and flaring of natural gas for the purposes 
of preventing waste. The governing Resource Management Plan may require 
lessees to follow State and the EPA emissions regulations. An operator 
may be required to control/mitigate emissions as a condition of 
approval (COA) on a drilling permit. The need for such a COA is 
determined by the environmental review process. The BLM's rules 
governing the venting and flaring of gas are contained in NTL-4A, which 
was issued in 1980. Under NTL-4A, limitations on royalty-free venting 
and flaring constitute the primary mechanism for addressing the surface 
waste of gas. In 2016, the BLM replaced NTL-4A with a new rule 
governing venting and flaring (``Waste Prevention Rule''). In addition 
to restricting royalty-free flaring, the rule set emissions standards 
for tanks and pneumatic equipment and established LDAR requirements. In 
2020, a U.S. District Court of Wyoming largely vacated that rule, 
thereby reinstating NTL-4A. More detailed information can be found at 
the BLM's website: https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/operations-and-production/methane-and-waste-prevention-rule.
    The BOEM manages the development of U.S. Outer Continental Shelf 
(offshore) energy and mineral resources. BOEM has air quality 
jurisdiction in the Gulf of Mexico \110\ and the North Slope Borough of 
Alaska.\111\ BOEM also has air jurisdiction in Federal waters on the 
Outer Continental Shelf 3-9 miles offshore (depending on State) and 
beyond. The Outer Continental Shelf Lands Act (OCSLA) section 5(a)(8) 
states, ``The Secretary of the Interior is authorized to prescribe 
regulations `for compliance with the national ambient air quality 
standards pursuant to the CAA . . . to the extent that activities 
authorized under [the Outer Continental Shelf Lands Act] significantly 
affect the air quality of any State.' '' The EPA and States have the 
air jurisdiction onshore and in State waters, and the EPA has air 
jurisdiction offshore in certain areas. More detailed information can 
be found at BOEM's website: https://www.boem.gov/.
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    \110\ The CAA gave BOEM air jurisdiction west of 87.5[deg] 
longitude in the Gulf of Mexico region.
    \111\ The Consolidated Appropriations Act of 2012 gave BOEM air 
jurisdiction in the North Slope Borough of Alaska.
---------------------------------------------------------------------------

    The U.S. Department of Transportation (DOT) manages the U.S. 
transportation system. Within DOT, the Pipeline and Hazardous Materials 
Safety Administration (PHMSA) is responsible for regulating and 
ensuring the safe and secure transport of energy and other hazardous 
materials to industry and consumers by all modes of transportation, 
including pipelines. While PHMSA regulatory requirements for gas 
pipeline facilities have focused on human safety, which has attendant 
environmental co-benefits, the ``Protecting our Infrastructure of 
Pipelines and Enhancing Safety Act of 2020'' (Pub. L. 116-260, Division 
R; ``PIPES Act of 2020''), which was signed into law on December 27, 
2020, revised PHMSA organic statutes to emphasize the centrality of 
environmental safety and protection of the environment in PHMSA 
decision making. For example, the PHMSA's Office of Pipeline Safety 
ensures safety in the design, construction, operation, maintenance, and 
incident response of the U.S.' approximately 2.6 million miles of 
natural gas and hazardous liquid transportation pipelines. When 
pipelines are maintained, the likelihood of environmental releases like 
leaks are reduced.\112\ In addition, the PIPES Act of 2020 contains 
several provisions that specifically address the minimization of 
releases of natural gas from pipeline facilities, such as a mandate 
that the Secretary of Transportation promulgate regulations related to 
gas pipeline LDAR programs. More detailed information can be found at 
PHMSA's website: https://www.phmsa.dot.gov/.
---------------------------------------------------------------------------

    \112\ See Final Report on Leak Detection Study to PHMSA. 
December 10, 2012. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf.
---------------------------------------------------------------------------

    The U.S. Department of Energy (DOE) develops oil and natural gas 
policies and funds research on advanced fuels and monitoring and 
measurement technologies. Specifically, the Advanced Research Projects 
Agency-Energy (ARPA-E) program advances high-potential, high-impact 
energy technologies that are too early for private-sector investment. 
APRA-E awardees are unique because they are developing entirely new 
technologies. More detailed information can be found at ARPA-E's 
website: https://arpa-e.energy.gov/. Also, the U.S. Energy Information 
Administration (EIA) compiles data on energy consumption, prices, 
including natural gas, and coal. More detailed information can be found 
at the EIA's website: https://www.eia.gov/.
    The U.S. Federal Energy Regulatory Commission (FERC) is an 
independent agency that regulates the interstate transmission of 
electricity, natural gas,\113\ and oil.\114\ FERC also reviews 
proposals to build liquefied natural gas terminals and interstate 
natural gas pipelines as well as licensing hydropower projects. The 
Commission's responsibilities for the crude oil industry include the 
following: Regulation of rates and practices of oil pipeline companies 
engaged in interstate transportation; establishment of equal service 
conditions to provide shippers with equal access to pipeline 
transportation; and establishment of reasonable rates for transporting 
petroleum and petroleum products by pipeline. The Commission's 
responsibilities for the natural gas industry include the following: 
Regulation of pipeline, storage, and

[[Page 63139]]

liquefied natural gas facility construction; regulation of natural gas 
transportation in interstate commerce; issuance of certificates of 
public convenience and necessity to prospective companies providing 
energy services or constructing and operating interstate pipelines and 
storage facilities; regulation of facility abandonment, establishment 
of rates for services; regulation of the transportation of natural gas 
as authorized by the Natural Gas Policy Act and OCSLA; and oversight of 
the construction and operation of pipeline facilities at U.S. points of 
entry for the import or export of natural gas. FERC has no jurisdiction 
over construction or maintenance of production wells, oil pipelines, 
refineries, or storage facilities. More detailed information can be 
found at FERC's website: https://www.ferc.gov/.
---------------------------------------------------------------------------

    \113\ https://www.ferc.gov/industries-data/natural-gas.
    \114\ https://www.ferc.gov/industries-data/oil.
---------------------------------------------------------------------------

B. Industry and Voluntary Actions To Address Climate Change

    Separate from regulatory requirements, some owners or operators of 
facilities in the Oil and Natural Gas Industry choose to participate in 
voluntary initiatives. Specifically, over 100 oil and natural gas 
companies participate in the EPA Natural Gas STAR and Methane Challenge 
partnership programs. Owners or operators also participate in a growing 
number of voluntary programs unaffiliated with the EPA voluntary 
programs. The EPA is aware of at least 19 such initiatives.\115\ Firms 
might participate in voluntary environmental programs for a variety of 
reasons, including attracting customers, employees, and investors who 
value more environmental-responsible goods and services; finding 
approaches to improve efficiency and reduce costs; and preparing for or 
helping inform future regulations.\116\ \117\
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    \115\ Highwood Emissions Management (2021). ``Voluntary 
Emissions Reduction Initiatives for Responsibly Sourced Oil and 
Gas.'' Available for download at: https://highwoodemissions.com/research/.
    \116\ Borck, J.C. and C. Coglianese (2009). ``Voluntary 
Environmental Programs: Assessing Their Effectiveness.'' Annual 
Review of Environment and Resources 34(1): 305-324.
    \117\ Brouhle, K., C. Griffiths, and A. Wolverton. (2009). 
``Evaluating the role of EPA policy levers: An examination of a 
voluntary program and regulatory threat in the metal-finishing 
industry.'' Journal of Environmental Economics and Management. 
57(2): 166-181.
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    The EPA's Natural Gas STAR Program started in 1993 and seeks to 
achieve methane emission reductions through implementation of cost-
effective best practices and technologies. Partner companies document 
their voluntary emission reduction activities and can report their 
accomplishments to the EPA annually. Natural Gas STAR includes over 90 
partners across the natural gas value chain. Through 2019 partner 
companies report having eliminated nearly 1.7 trillion cubic feet of 
methane emissions since 1993.
    The EPA's Methane Challenge Program was launched in 2016 and 
expands on the Natural Gas STAR Program with ambitious, quantifiable 
commitments and detailed, transparent reporting and partner 
recognition. Annually Methane Challenge partners submit facility-level 
reports that characterize the methane emission sources at their 
facilities and detail voluntary actions taken to reduce methane 
emissions. The EPA emphasizes the importance of transparency with the 
publication of these facility-level data. Although this program 
includes nearly 70 companies from all segments of the industry, most 
partners operate in the transmission and distribution segments.
    Other voluntary programs for the oil and natural gas industry are 
administered by diverse organizations, including trade associations and 
non-profits. While the field of voluntary initiatives continues to 
grow, it is difficult to understand the present, and potential future, 
impact these initiatives will have on reducing methane emissions as the 
majority of these initiatives publish aggregated program-level data. 
The EPA recognizes the voluntary efforts of industry in reducing 
methane emissions beyond what is required by current regulations and in 
significantly expanding the understanding of methane mitigation 
measures. While progress has been made, there is still considerable 
remaining need to further reduce methane emissions from the Industry.

VI. Environmental Justice Considerations, Implications, and Stakeholder 
Outreach

    To better inform this proposed rulemaking, the EPA assessed the 
characteristics of populations living near sources affected by the rule 
and conducted extensive outreach to overburdened and underserved 
communities and to environmental justice organizations. During our 
engagement with communities, concerns were raised regarding health 
effects of air pollutants, implications of climate change on lifestyle 
changes, water quality, or extreme heat events, and accessibility to 
data and information regarding sources near their homes. The EPA then 
considered this input along with other stakeholder input in designing 
the proposed rule. For example, one key issue identified through 
stakeholder input is the use of cutting-edge technologies for methane 
detection that can allow for rapid detection of high-emitting sources. 
As described below, the EPA is proposing to allow the use of such 
technologies in this rule, alongside a rigorous fugitive emissions 
monitoring program that is based on traditional OGI technology. Another 
key concern the Agency heard is addressing large emission sources 
faster, which, in addition to seeking more information on new detection 
technologies, the EPA is proposing to address with more frequent 
monitoring at sites with more emissions. The EPA also heard that 
adjacent communities are concerned about health impacts, and the EPA is 
proposing rigorous guidelines for pollution sources at existing 
facilities, methane standards for storage vessels, strengthened and 
expanded standards for pneumatic controllers, and standards for liquids 
unloading events that will further reduce emissions of those 
pollutants. These are just a few examples of how this proposed rule 
provides benefits to communities; section XII provides a full 
explanation and rationale of the proposed actions.
    E.O. 12898 directs the EPA to identify the populations of concern 
who are most likely to experience unequal burdens from environmental 
harms; specifically, minority populations, low-income populations, and 
indigenous peoples. 59 FR 7629 (February 16, 1994). Additionally, E.O. 
13985 was signed in 2021 to advance racial equity and support 
underserved communities--including people of color and others who have 
been historically underserved, marginalized, and adversely affected by 
persistent poverty and inequality--through Federal Government actions. 
86 FR 7009 (January 20, 2021). With respect to climate change, E.O. 
14008, titled ``Tackling Climate Change at Home and Abroad,'' was 
signed on January 27, 2021, stating that climate considerations shall 
be an essential element of United States foreign policy and national 
security, working in partnership with foreign governments, States, 
territories, and local governments, and communities potentially 
impacted by climate change. The EPA defines environmental justice (EJ) 
as the fair treatment and meaningful involvement of all people 
regardless of race, color, national origin, or income with respect to 
the development, implementation, and enforcement of environmental laws, 
regulations, and policies. The EPA further defines the term fair 
treatment to

[[Page 63140]]

mean that ``no group of people should bear a disproportionate burden of 
environmental harms and risks, including those resulting from the 
negative environmental consequences of industrial, governmental, and 
commercial operations or programs and policies'' (https://www.epa.gov/environmentaljustice). In recognizing that minority and low-income 
populations often bear an unequal burden of environmental harms and 
risks, the EPA continues to consider ways of protecting them from 
adverse public health and environmental effects of air pollution 
emitted from sources within the Oil and Natural Gas Industry that are 
addressed in this proposed rulemaking.

A. Environmental Justice and the Impacts of Climate Change

    In 2009, under the Endangerment and Cause or Contribute Findings 
for Greenhouse Gases Under Section 202(a) of the Clean Air Act 
(``Endangerment Finding'', 74 FR 66496), the Administrator considered 
how climate change threatens the health and welfare of the U.S. 
population.\118\ As part of that consideration, she also considered 
risks to minority and low-income individuals and communities, finding 
that certain parts of the U.S. population may be especially vulnerable 
based on their characteristics or circumstances. These groups include 
economically and socially disadvantaged communities, including those 
that have been historically marginalized or overburdened; individuals 
at vulnerable lifestages, such as the elderly, the very young, and 
pregnant or nursing women; those already in poor health or with 
comorbidities; the disabled; those experiencing homelessness, mental 
illness, or substance abuse; and/or Indigenous or minority populations 
dependent on one or limited resources for subsistence due to factors 
including but not limited to geography, access, and mobility.
---------------------------------------------------------------------------

    \118\ Earlier studies and reports can be found at https://www.epa.gov/cira/social-vulnerability-report.
---------------------------------------------------------------------------

    Scientific assessment reports produced over the past decade by the 
USGCRP,\119\ \120\ the IPCC,\121\ \122\ \123\ \124\ the National 
Academies of Science, Engineering, and Medicine,\125\ \126\ and the EPA 
\127\ add more evidence that the impacts of climate change raise 
potential EJ concerns. These reports conclude that less-affluent, 
traditionally marginalized and predominantly non-White communities can 
be especially vulnerable to climate change impacts because they tend to 
have limited resources for adaptation, are more dependent on climate-
sensitive resources such as local water and food supplies, or have less 
access to social and information resources. Some communities of color, 
specifically populations defined jointly by ethnic/racial 
characteristics and geographic location (e.g., African-American, Black, 
and Hispanic/Latino communities; Native Americans, particularly those 
living on Tribal lands and Alaska Natives), may be uniquely vulnerable 
to climate change health impacts in the U.S., as discussed below. In 
particular, the 2016 scientific assessment on the Impacts of Climate 
Change on Human Health \128\ found with high confidence that 
vulnerabilities are place- and time-specific, lifestages and ages are 
linked to immediate and future health impacts, and social determinants 
of health are linked to greater extent and severity of climate change-
related health impacts.
---------------------------------------------------------------------------

    \119\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
    \120\ USGCRP, 2016: The Impacts of Climate Change on Human 
Health in the United States: A Scientific Assessment. Crimmins, A., 
J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. 
Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. 
Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. 
Global Change Research Program, Washington, DC, 312 pp. https://dx.doi.org/10.7930/J0R49NQX.
    \121\ Oppenheimer, M., M. Campos, R. Warren, J. Birkmann, G. 
Luber, B. O'Neill, and K. Takahashi, 2014: Emergent risks and key 
vulnerabilities. In: Climate Change 2014: Impacts, Adaptation, and 
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of 
Working Group II to the Fifth Assessment Report of the 
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, 
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, 
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 
Cambridge University Press, Cambridge, United Kingdom and New York, 
NY, USA, pp. 1039-1099.
    \122\ Porter, J.R., L. Xie, A.J. Challinor, K. Cochrane, S.M. 
Howden, M.M. Iqbal, D.B. Lobell, and M.I. Travasso, 2014: Food 
security and food production systems. In: Climate Change 2014: 
Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral 
Aspects. Contribution of Working Group II to the Fifth Assessment 
Report of the Intergovernmental Panel on Climate Change [Field, 
C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. 
Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, 
E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 
White (eds.)]. Cambridge University Press, Cambridge, United Kingdom 
and New York, NY, USA, pp. 485-533.
    \123\ Smith, K.R., A. Woodward, D. Campbell-Lendrum, D.D. 
Chadee, Y. Honda, Q. Liu, J.M. Olwoch, B. Revich, and R. Sauerborn, 
2014: Human health: impacts, adaptation, and co-benefits. In: 
Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: 
Global and Sectoral Aspects. Contribution of Working Group II to the 
Fifth Assessment Report of the Intergovernmental Panel on Climate 
Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. 
Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. 
Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. 
Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, 
Cambridge, United Kingdom and New York, NY, USA, pp. 709-754.
    \124\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special 
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission 
pathways, in the context of strengthening the global response to the 
threat of climate change, sustainable development, and efforts to 
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. P[ouml]rtner, 
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. 
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. 
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. 
Waterfield (eds.)]. In Press.
    \125\ National Research Council. 2011. America's Climate 
Choices. Washington, DC: The National Academies Press. https://doi.org/10.17226/12781.
    \126\ National Academies of Sciences, Engineering, and Medicine. 
2017. Communities in Action: Pathways to Health Equity. Washington, 
DC: The National Academies Press. https://doi.org/10.17226/24624.
    \127\ EPA. 2021. Climate Change and Social Vulnerability in the 
United States: A Focus on Six Impacts. U.S. Environmental Protection 
Agency, EPA 430-R-21-003.
    \128\ USGCRP, 2016: The Impacts of Climate Change on Human 
Health in the United States: A Scientific Assessment.
---------------------------------------------------------------------------

    Per the NCA4, ``Climate change affects human health by altering 
exposures to heat waves, floods, droughts, and other extreme events; 
vector-, food- and waterborne infectious diseases; changes in the 
quality and safety of air, food, and water; and stresses to mental 
health and well-being.'' \129\ Many health conditions such as 
cardiopulmonary or respiratory illness and other health impacts are 
associated with and exacerbated by an increase in GHGs and climate 
change outcomes, which is problematic as these diseases occur at higher 
rates within vulnerable communities. Importantly, negative public 
health outcomes include those that are physical in nature, as well as 
mental, emotional, social, and economic.
---------------------------------------------------------------------------

    \129\ Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. 
Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 
2018: Human Health. In Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, pp. 539-571. doi: 10.7930/
NCA4.2018.CH14.
---------------------------------------------------------------------------

    The scientific assessment literature, including the aforementioned 
reports, demonstrates that there are myriad ways

[[Page 63141]]

in which these populations may be affected at the individual and 
community levels. Outdoor workers, such as construction or utility 
workers and agricultural laborers, who are frequently part of already 
at-risk groups, are exposed to poor air quality and extreme 
temperatures without relief. Furthermore, individuals within EJ 
populations of concern face greater housing and clean water insecurity 
and bear disproportionate economic impacts and health burdens 
associated with climate change effects. They also have less or limited 
access to healthcare and affordable, adequate health or homeowner 
insurance. The urban heat island effect can add additional stress to 
vulnerable populations in densely populated cities who do not have 
access to air conditioning.\130\ Finally, resiliency and adaptation are 
more difficult for economically disadvantaged communities: They tend to 
have less liquidity, individually and collectively, to move or to make 
the types of infrastructure or policy changes necessary to limit or 
reduce the hazards they face. They frequently face systemic, 
institutional challenges that limit their power to advocate for and 
receive resources that would otherwise aid in resiliency and hazard 
reduction and mitigation.
---------------------------------------------------------------------------

    \130\ USGCRP, 2016.
---------------------------------------------------------------------------

    The assessment literature cited in the EPA's 2009 Endangerment 
Finding, as well as Impacts of Climate Change on Human Health, also 
concluded that certain populations and people in particular stages of 
life, including children, are most vulnerable to climate-related health 
effects. The assessment literature produced from 2016 to the present 
strengthens these conclusions by providing more detailed findings 
regarding related vulnerabilities and the projected impacts youth may 
experience. These assessments--including the NCA4 (2018) and The 
Impacts of Climate Change on Human Health in the United States (2016)--
describe how children's unique physiological and developmental factors 
contribute to making them particularly vulnerable to climate change. 
Impacts to children are expected from air pollution, infectious and 
waterborne illnesses, and mental health effects resulting from extreme 
weather events. In addition, children are among those especially 
susceptible to allergens, as well as health effects associated with 
heat waves, storms, and floods. Additional health concerns may arise in 
low-income households, especially those with children, if climate 
change reduces food availability and increases prices, leading to food 
insecurity within households. More generally, these reports note that 
extreme weather and flooding can cause or exacerbate poor health 
outcomes by affecting mental health because of stress; contributing to 
or worsening existing conditions, again due to stress or also as a 
consequence of exposures to water and air pollutants; or by impacting 
hospital and emergency services operations.\131\ Further, in urban 
areas in particular, flooding can have significant economic 
consequences due to effects on infrastructure, pollutant exposures, and 
drowning dangers. The ability to withstand and recover from flooding is 
dependent in part on the social vulnerability of the affected 
population and individuals experiencing an event.\132\
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    \131\ Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. 
Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 
2018: Human Health. In Impacts, Risks, and Adaptation in the United 
States: Fourth National Climate Assessment, Volume II [Reidmiller, 
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. 
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research 
Program, Washington, DC, USA, pp. 539-571. doi: 10.7930/
NCA4.2018.CH14.
    \132\ National Academies of Sciences, Engineering, and Medicine 
2019. Framing the Challenge of Urban Flooding in the United States. 
Washington, DC: The National Academies Press. https://doi.org/10.17226/25381.
---------------------------------------------------------------------------

    The Impacts of Climate Change on Human Health (USGCRP, 2016) also 
found that some communities of color, low-income groups, people with 
limited English proficiency, and certain immigrant groups (especially 
those who are undocumented) live with many of the factors that 
contribute to their vulnerability to the health impacts of climate 
change. While difficult to isolate from related socioeconomic factors, 
race appears to be an important factor in vulnerability to climate-
related stress, with elevated risks for mortality from high 
temperatures reported for Black or African-American individuals 
compared to White individuals after controlling for factors such as air 
conditioning use. Moreover, people of color are disproportionately 
exposed to air pollution based on where they live, and 
disproportionately vulnerable due to higher baseline prevalence of 
underlying diseases such as asthma, so climate exacerbations of air 
pollution are expected to have disproportionate effects on these 
communities. Locations with greater health threats include urban areas 
(due to, among other factors, the ``heat island'' effect where built 
infrastructure and lack of green spaces increases local temperatures), 
areas where airborne allergens and other air pollutants already occur 
at higher levels, and communities experienced depleted water supplies 
or vulnerable energy and transportation infrastructure.
    The recent EPA report on climate change and social vulnerability 
\133\ examined four socially vulnerable groups (individuals who are low 
income, minority, without high school diplomas, and/or 65 years and 
older) and their exposure to several different climate impacts (air 
quality, coastal flooding, extreme temperatures, and inland flooding). 
This report found that Black and African-American individuals were 40% 
more likely to currently live in areas with the highest projected 
increases in mortality rates due to climate-driven changes in extreme 
temperatures, and 34% more likely to live in areas with the highest 
projected increases in childhood asthma diagnoses due to climate-driven 
changes in particulate air pollution. The report found that Hispanic 
and Latino individuals are 43% more likely to live in areas with the 
highest projected labor hour losses in weather-exposed industries due 
to climate-driven warming, and 50% more likely to live in coastal areas 
with the highest projected increases in traffic delays due to increases 
in high-tide flooding. The report found that American Indian and Alaska 
Native individuals are 48% more likely to live in areas where the 
highest percentage of land is projected to be inundated due to sea 
level rise, and 37% more likely to live in areas with high projected 
labor hour losses. Asian individuals were found to be 23% more likely 
to live in coastal areas with projected increases in traffic delays 
from high-tide flooding. Those with low income or no high school 
diploma are about 25% more likely to live in areas with high projected 
losses of labor hours, and 15% more likely to live in areas with the 
highest projected increases in asthma due to climate-driven increases 
in particulate air pollution, and in areas with high projected 
inundation due to sea level rise.
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    \133\ EPA. 2021. Climate Change and Social Vulnerability in the 
United States: A Focus on Six Impacts. U.S. Environmental Protection 
Agency, EPA 430-R-21-003.
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    Impacts of Climate Change on Indigenous Communities. Indigenous 
communities face disproportionate risks from the impacts of climate 
change, particularly those communities impacted by degradation of 
natural and cultural resources within established reservation 
boundaries and threats to traditional subsistence lifestyles. 
Indigenous communities whose health, economic well-being, and cultural 
traditions depend upon the natural

[[Page 63142]]

environment will likely be affected by the degradation of ecosystem 
goods and services associated with climate change. The IPCC indicates 
that losses of customs and historical knowledge may cause communities 
to be less resilient or adaptable.\134\ The NCA4 (2018) noted that 
while indigenous peoples are diverse and will be impacted by the 
climate changes universal to all Americans, there are several ways in 
which climate change uniquely threatens indigenous peoples' livelihoods 
and economies.\135\ In addition, there can be institutional barriers 
(including policy-based limitations and restrictions) to their 
management of water, land, and other natural resources that could 
impede adaptive measures.
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    \134\ Porter et al., 2014: Food security and food production 
systems.
    \135\ Jantarasami, L.C., R. Novak, R. Delgado, E. Marino, S. 
McNeeley, C. Narducci, J. Raymond-Yakoubian, L. Singletary, and K. 
Powys Whyte, 2018: Tribes and Indigenous Peoples. In Impacts, Risks, 
and Adaptation in the United States: Fourth National Climate 
Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. 
Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. 
Stewart (eds.)]. U.S. Global Change Research Program, Washington, 
DC, USA, pp. 572-603. doi: 10.7930/NCA4. 2018. CH15.
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    For example, indigenous agriculture in the Southwest is already 
being adversely affected by changing patterns of flooding, drought, 
dust storms, and rising temperatures leading to increased soil erosion, 
irrigation water demand, and decreased crop quality and herd sizes. The 
Confederated Tribes of the Umatilla Indian Reservation in the Northwest 
have identified climate risks to salmon, elk, deer, roots, and 
huckleberry habitat. Housing and sanitary water supply infrastructure 
are vulnerable to disruption from extreme precipitation events. 
Confounding general Native American response to natural hazards are 
limitations imposed by policies such as the Dawes Act of 1887 and the 
Indian Reorganization Act of 1934, which ultimately restrict Indigenous 
peoples' autonomy regarding land-management decisions through Federal 
trusteeship of certain Tribal lands and mandated Federal oversight of 
management decisions. Additionally, NCA4 noted that Indigenous peoples 
are subjected to institutional racism effects, such as poor 
infrastructure, diminished access to quality healthcare, and greater 
risk of exposure to pollutants. Consequently, Native Americans often 
have disproportionately higher rates of asthma, cardiovascular disease, 
Alzheimer's disease, diabetes, and obesity. These health conditions and 
related effects (e.g., disorientation, heightened exposure to 
PM2.5, etc.) can all contribute to increased vulnerability 
to climate-driven extreme heat and air pollution events, which also may 
be exacerbated by stressful situations, such as extreme weather events, 
wildfires, and other circumstances.
    NCA4 and IPCC's Fifth Assessment Report \136\ also highlighted 
several impacts specific to Alaskan Indigenous Peoples. Coastal erosion 
and permafrost thaw will lead to more coastal erosion, rendering winter 
travel riskier and exacerbating damage to buildings, roads, and other 
infrastructure--impacts on archaeological sites, structures, and 
objects that will lead to a loss of cultural heritage for Alaska's 
indigenous people. In terms of food security, the NCA4 discussed 
reductions in suitable ice conditions for hunting, warmer temperatures 
impairing the use of traditional ice cellars for food storage, and 
declining shellfish populations due to warming and acidification. While 
the NCA4 also noted that climate change provided more opportunity to 
hunt from boats later in the fall season or earlier in the spring, the 
assessment found that the net impact was an overall decrease in food 
security.
---------------------------------------------------------------------------

    \136\ Porter et al., 2014: Food security and food production 
systems.
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B. Impacted Stakeholders

    Based on analyses of exposed populations, the EPA has determined 
that this action, if finalized in a manner similar to what is proposed 
in this document, is likely to help reduce adverse effects of air 
pollution on minority populations, and/or low-income populations that 
have the potential for disproportionate impacts, as specified in E.O. 
12898 (59 FR 7629, February 16, 1994) and referenced in E.O. 13985 (86 
FR 7009, January 20, 2021). The EPA remains committed to engaging with 
communities and stakeholders throughout the development of this 
rulemaking and continues to invite comments on how the Agency can 
better achieve these goals through this action. For this proposed rule, 
we assessed emissions of HAP, criteria pollutants, and pollutants that 
cause climate change.
    For HAP emissions, we estimated cancer risks and the demographic 
breakdown of people living in areas with potentially elevated risk 
levels by performing dispersion modeling of the most recent NEI data 
from 2017, which indicates nationwide emissions of approximately 
110,000 tpy of over 40 HAP (including benzene, toluene, ethylbenzene, 
xylenes, and formaldehyde) from the Oil and Natural Gas Industry. Table 
12 gives the risk and demographic results for the Oil and Natural Gas 
Industry from this screening-level assessment. We estimate there are 
39,000 people with cancer risk greater than or equal to 100-in-1 
million attributable to oil and natural gas sources, with a maximum 
estimated risk of 200-in-1 million occurring in three census blocks (10 
people). We estimate there are about 143,000 people with estimated risk 
greater than or equal to 50-in-1 million, and about 6.8 million people 
with estimated cancer risk greater than 1-in-1 million. It is important 
to note that these estimates are subject to various types of 
uncertainty related to input parameters and assumptions, including 
emissions datasets, exposure modeling and the dose-response 
relationships.\137\
---------------------------------------------------------------------------

    \137\ See `Risk Report Template' at Docket ID No. EPA-HQ-OAR-
2021-0317.
---------------------------------------------------------------------------

    As shown in Table 12, Hispanic and Latino populations and young 
people (ages 0-17) are disproportionately represented in communities 
exposed to elevated cancer risks from oil and natural gas sources, 
while the proportion of people in other demographic groups with 
estimated risks above the specified levels is at or below the national 
average. The overall percent minority is about the same as the national 
average, but the percentage of people exposed to cancer risks greater 
than or equal to the 100-in-1 million and 50-in-1 million thresholds 
who are Hispanic or Latino is about 10 percentage points higher than 
the national average. The overall minority percentage is not elevated 
compared to the national average because the African-American 
percentage is much lower than the national average. The demographic 
group of people aged 0-17 is slightly higher than the national average.

[[Page 63143]]



                     Table 12--Cancer Risk and Demographic Population Estimates for 2017 NEI Nonpoint Oil and Natural Gas Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                             Risks >=100-in-1 million
                                              Risks >=50-in-1 million
                                               Risks >1-in-1 million        Nationwide
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Population                                      39,000
                                                      143,000
                                                     6,805,000            ..............
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                              Population               %      Population               %      Population               %               %
--------------------------------------------------------------------------------------------------------------------------------------------------------
Minority................................          13,268            34.1          52,154            36.5       2,010,161            29.5            39.9
African American........................             140             0.4           1,434             1.0         535,055             7.9            12.2
Native American.........................              77             0.2             465             0.3          59,087             0.9             0.7
Other and Multiracial...................           1,443             3.7           5,148             3.6         323,397             4.8             8.2
Hispanic or Latino......................          11,608            29.9          45,107            31.6       1,092,621            16.1            18.8
Age 0-17................................          10,679            27.5          37,487            26.2       1,463,907            21.5            22.6
Age >=65................................           4,272            11.0          17,188            12.0       1,085,067            15.9            15.7
Below the Poverty Level.................           2,000             5.1          13,455             9.4         902,472            13.2            13.4
Over 25 Without a High School Diploma...           2,788             7.2          11,320             7.9         488,372             7.2            12.1
Linguistically Isolated.................             808             2.1           4,418             3.1         179,739             2.6             5.4
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For criteria pollutants, we assessed exposures to ozone from Oil 
and Natural Gas Industry VOC emissions across races/ethnicities, ages, 
and sexes in a recent baseline (pre-control) air quality scenario. 
Annual air quality was simulated using a photochemical model for the 
year 2017, based on emissions from the most recent NEI. The analysis 
shows that the distribution of exposures for all demographic groups 
except Hispanic and Asian populations are similar to or below the 
national average or a reference population. Differences between 
exposures in Hispanic and Asian populations versus White or all 
populations are modest, and the results are subject to various types of 
uncertainty related to input parameters and assumptions.
    In addition to climate and air quality impacts, the EPA also 
conducted analyses to characterize potential impacts on domestic oil 
and natural gas production and prices and to describe the baseline 
distribution of employment and energy burdens. Section XVI.d describes 
the results for our analysis of prices and production. For the 
distribution of baseline employment, we assessed the demographic 
characteristics of (1) workers in the oil and gas sector and (2) people 
living in oil and natural gas intensive communities.\138\ Comparing 
workers in the oil and natural gas sector to workers in other sectors, 
oil and natural gas workers may have higher than average incomes, be 
more likely to have completed high school, and be disproportionately 
Hispanic. People in some oil and gas intensive communities concentrated 
in Texas, Oklahoma, and Louisiana have lower average income levels, 
lower rates of high school completion, and higher likelihood of being 
non-Whites or hispanic than people living in communities that are not 
oil and gas intensive. Regarding household energy burden, low-income 
households, Hispanic, and Black households' energy expenditures may 
comprise a disproportionate share of their total expenditures and 
income as compared to higher income, non-Hispanic, and non-Black 
households, respectively. Results are presented in detail in the RIA 
accompanying this proposal.
---------------------------------------------------------------------------

    \138\ For this analysis, oil and natural gas intensive 
communities are defined as the top 20% of communities with respect 
to the proportion of oil and natural gas workers.
---------------------------------------------------------------------------

    In a proximity analysis of Tribes living within 50 miles of 
affected sources, we found 112 unique Tribal lands (Federally 
recognized Reservations, Off-Reservation Trust Lands, and Census 
Oklahoma Tribal Statistical Areas (OTSA)) located within 50 miles of a 
source with 32 Tribes having one or more sources located on Tribal 
land.
    Finally, the EPA has also analyzed prior enforcement actions 
related to air pollution from storage vessels, and identified 
improvements in air quality resulting from these actions as 
particularly important in communities with EJ concerns (identified 
using EJSCREEN).\139\ In a 2021 analysis of resolved enforcement 
matters, the EPA determined that communities with EJ concerns 
experience a disproportionate level of air pollution burden from 
storage vessel emissions. Although only about 25 percent of storage 
vessels were located in these communities with EJ concerns, 67 percent 
of the total emission reductions of VOCs, methane, PM, and 
NOX (about 95 million pounds) achieved through these 
enforcement resolutions occurred in communities with EJ concerns. This 
analysis suggests that the provisions of this proposed rule requiring 
installation of controls at storage vessels and monitoring and 
mitigation of fugitive emissions and malfunctions at storage vessels, 
would have particular benefits for these communities.
---------------------------------------------------------------------------

    \139\ See Memorandum ``Analysis of Environmental Justice Impacts 
of EPA's Historical Oil and Gas Storage Vessel Enforcement 
Resolutions (40 CFR part 60 subpart OOOO and OOOOa),'' located at 
Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

C. Outreach and Engagement

    The EPA identified stakeholder groups likely to be interested in 
this action and engaged with them in several ways including through 
meetings, training webinars, and public listening sessions to share 
information with stakeholders about this action, on how stakeholders 
may comment on the proposed rule, and to hear their input about the 
industry and its impacts as we were developing this proposal. 
Specifically, on May 27, 2021, the EPA held a webinar-based training 
designed for communities affected by this rule.\140\ This training 
provided an overview of the Crude Oil and Natural Gas Industry and how 
it is regulated and offered information on how to participate in the 
rulemaking process. The EPA also held virtual public listening sessions 
June 15 through June 17, 2021, and heard various community and health 
related themes from speakers who participated.\141\ \142\ Community 
themes

[[Page 63144]]

included concerns about protecting communities adjacent to oil and gas 
activities, providing monitoring and data so communities know what is 
in the air they are breathing, and upholding Tribal trust 
responsibilities. Community speakers urged the EPA to adopt stringent 
measures to reduce oil and natural gas pollution, and frequently cited 
an analysis suggesting such measures could achieve reductions of 65 
percent below 2012 levels by 2025.
---------------------------------------------------------------------------

    \140\ https://www.epa.gov/sites/default/files/2021-05/documents/us_epa_training_webinar_on_oil_and_natural_gas_for_communities.5.27.2021.pdf.
    \141\ June 15, 2021 session: https://youtu.be/T8XwDbf-B8g; June 
16, 2021 session: https://www.youtube.com/watch?v=l23bKPF-5oc; June 
17, 2021 session: https://www.youtube.com/watch?v=R2AZrmfuAXQ.
    \142\ Full transcripts for the listening sessions are posted at 
EPA Docket ID No. EPA-HQ-OAR-2021-0295.
---------------------------------------------------------------------------

    Community Access to Emissions Information. Several stakeholders 
requested that the rule include requirements that provide communities 
with information, including fence line monitoring or ``better 
monitoring so people will know the air they are breathing.'' A few 
speakers expressed concerned about the correct placement of existing 
air monitors. Speakers from Texas described local air monitors 
monitoring meteorology and ozone, but not hazardous air pollutants, and 
called on the EPA to consider alternative monitoring for oil and 
natural gas sources such as fence-line monitors, along with guidance 
from the EPA to require monitors of oil and natural gas facilities in 
close proximity to parks, schools, and playgrounds.
    Health Concerns in Adjacent Communities. Speakers raised concerns 
about impacts on frontline communities and those communities adjacent 
to oil and natural gas operations. These stakeholders called on the EPA 
to propose and promulgate stricter standards or alternative 
requirements for sources adjacent to urban communities and close to 
where people live and work. Several speakers used the term ``energy 
sacrifice zone'' when discussing the disproportionate impacts of oil 
and natural gas operations on frontline communities. Speakers advocated 
that when developing this regulatory effort, consultation with 
frontline communities is essential, and some speakers cited a Center 
for Investigative Reporting report stating that 30,000 children in 
Arlington, Texas, attend school within half a mile of active oil and 
gas sites. Speakers discussed concerns about methane as a formaldehyde 
precursor and related health effects and cited examples of health 
effects including hydraulic fracturing chemicals being measured in 
blood or urine; increases in nosebleeds in people in areas of oil and 
natural gas development; headaches and cancer. These speakers included 
teenagers from Pennsylvania, who said they live within 1 mile of 33 
wellheads and 500 feet of a pipeline. Several people cited a February 
2018 blowout and explosion in Belmont County, Ohio, that was reported 
to release 60,000 tons of methane in 20 days and said that is more than 
some countries emit in a year. Speakers also expressed related 
environmental concerns such as water contamination and fresh drinking 
water being diverted for hydraulic fracturing. One speaker urged that 
information on local water use be provided in languages other than 
English, stating that in Big Spring (Howard County), Texas, the local 
government only provided information to use tap water ``at your own 
risk'' in English.
    Additional concerns raised by communities included: Local 
compressor stations having numerous planned and unplanned releases into 
adjacent communities, which appear to be during startup; whether the 
EPA will use a robust cost analysis to address the economic impacts of 
labor loss and gas costs resulting from any regulation; if plugged and 
abandoned wells included in this action, will this regulation apply to 
BLM land; will States be required to use the same emissions calculation 
used by the EPA for methane GWP; will there be disclosure of necessary 
data collection or technology to be used by the Oil and Natural Gas 
Industry to track and reduce methane emissions; and will the EPA 
consider the necessity of venting and flaring from a safety standpoint. 
Communities also discussed concerns about excess emissions from storage 
vessels and the need for clarifying the applicability of the standard 
in addition to improving enforceability and compliance at this type of 
facility.
    In addition to the trainings and listening sessions, the EPA 
engaged with community leaders potentially impacted by this proposed 
action by hosting a meeting with EJ community leaders on May 14, 2021. 
As noted above, the EPA provided the public with factual information to 
help them understand the issues addressed by this action. We obtained 
input from the public, including communities, about their concerns 
about air pollution from the oil and gas industry, including receiving 
stakeholder perspectives on alternatives. The EPA considered and 
weighed information from communities as the agency developed this 
proposed action.
    In addition to the engagement conducted prior to this proposal, the 
EPA is providing the public, including those communities 
disproportionately impacted by the burdens of pollution, opportunities 
to engage in the EPA's public comment period for this proposal, 
including by hosting public hearings. This public hearing will occur 
according to the schedule identified in the DATES and SUPPLEMENTARY 
INFORMATION section of this preamble to discuss:
     What impacts they are experiencing (i.e., health, noise, 
smells, economic),
     How the community would like the EPA to address their 
concerns,
     How the EPA is addressing those concerns in the 
rulemaking, and
     Any other topics, issues, concerns, etc. that the public 
may have regarding this proposal.
    For more information about the EPA's pre-proposal outreach 
activities, please see EPA Docket ID No. EPA-HQ-OAR-2021-0295. Please 
refer to EPA Docket ID No. EPA-HQ-OAR-2021-0317 for submitting public 
comments on this proposed rulemaking. For public input to be considered 
during the formal rulemaking, please submit comments on this proposed 
action to the formal regulatory docket at EPA Docket ID No. EPA-HQ-OAR-
2021-0317 so that the EPA may consider those comments during the 
development of the final rule.

D. Environmental Justice Considerations

    The EPA considered EJ implications in the development of this 
proposed rulemaking process, including the fair treatment and 
meaningful involvement of all people regardless of race, color, 
national origin, or income. As part of this process, the EPA engaged 
and consulted with frontline communities through interactions such as 
webinars, listening sessions and meetings. These opportunities gave the 
EPA a chance to hear directly from the public, especially overburdened 
and underserved communities, on the development of the proposed rule. 
The EPA considered these community concerns throughout our internal 
development process that resulted in this proposal which, if finalized 
in a manner similar to what is being proposed, will reduce emissions of 
harmful air pollutants, promote gas capture and beneficial use, and 
provide opportunity for flexibility and expanded transparency in order 
to yield a consistent and accountable national program. The EPA's 
proposed NSPS and EG are summarized in sections XI and XII below. 
Anticipated impacts of this action are discussed further in section XVI 
of this preamble.
    In recognizing that minority and low-income populations often bear 
an unequal burden of environmental harms and risks, the EPA continues 
to consider

[[Page 63145]]

ways to protect them from adverse public health and environmental 
effects of air pollution emitted from sources within the Oil and 
Natural Gas Industry that are addressed in this proposed rulemaking. 
For these reasons, in section XIV.C the EPA is proposing to include an 
additional requirement associated with the adoption and submittal of 
State plans pursuant to EG OOOOc (in addition to the current 
requirements of Subpart Ba) by requiring States to meaningfully engage 
with members of the public, including overburdened and underserved 
communities, during the plan development process and prior to adoption 
and submission of the plan to the EPA. The EPA is proposing this 
specific meaningful engagement requirement to ensure that the State 
plan development process is inclusive, effective, and accessible to 
all.
    Details of the EPA's assessment of EJ considerations can be found 
in the RIA for this action. The EPA seeks input on the EJ analyses 
contained in the RIA, as well as broader input on other health and 
environmental risks the Agency should assess in the comprehensive 
development of this proposed action. In particular, the EPA is 
soliciting comment on key assumptions underlying the EJ analysis as 
well as data and information that would enable the Agency to conduct a 
more nuanced analysis of HAP and criteria pollutant exposure and risk, 
given the inherent uncertainty regarding risk assessment. More broadly, 
the EPA seeks information, analysis, and comment on how the provisions 
of this proposed action would affect air pollution and health in 
communities with environmental justice concerns, and whether there are 
further provisions that EPA should consider as part of a supplemental 
proposal or a final rule that would enhance the health and 
environmental benefits of this rule for these communities.

VII. Other Stakeholder Outreach

A. Educating the Public, Listening Sessions, and Stakeholder Outreach

    The EPA began the development of this proposed action to reduce 
methane and other harmful pollutants from new and existing sources in 
the Crude Oil and Natural Gas source category with a public outreach 
effort to gather a broad range of stakeholder input. This effort 
included: Opening a public docket for pre-proposal input; \143\ holding 
training sessions providing overviews of the industry, the EPA's 
rulemaking process and how to participate in it; and convening 
listening sessions for the public, including a wide range of 
stakeholders. The EPA additionally held roundtables with State 
environmental commissioners through the Environmental Council of the 
States, and oil and gas commissioners and staff through the Interstate 
Oil and Gas Compact Commission (IOGCC), and met with non-governmental 
organizations (NGOs), industry, and the U.S. Climate Alliance, among 
others.\144\
---------------------------------------------------------------------------

    \143\ EPA Docket ID No. EPA-HQ-OAR-2021-0295.
    \144\ A full list of pre-proposal meetings the EPA participated 
in is included at EPA Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    In addition to the trainings and listening sessions noted in 
section VI above, on May 25 and 26, 2021, the EPA held webinar-based 
trainings designed for small business stakeholders \145\ and Tribal 
nations.\146\ The training provided an overview of the Oil and Natural 
Gas Industry and how it is regulated and offered information on how to 
participate in the rulemaking process. A combined total of more than 
100 small business stakeholders and Tribal nations participated. During 
the training, small business stakeholders expressed interest in 
learning more about the EPA's plan to either modify the 2016 NSPS OOOOa 
or take more substantial action in this proposal. For Tribal nations, 
the EPA has assessed potential impacts on Tribal nations and 
populations and has engaged with Tribal stakeholders to hear concerns 
associated with air pollution emitted from sources within the Oil and 
Natural Gas Industry that are addressed in this proposed rulemaking. 
Tribal members mentioned the need for the EPA to uphold its trust 
responsibilities, propose and promulgate rules that protect 
disproportionately impacted communities, and asked that the EPA 
allocate resources for Tribal governments to implement regulations 
through Tribal air quality programs.
---------------------------------------------------------------------------

    \145\ https://www.epa.gov/sites/default/files/2021-05/documents/oil_and_gas_training_webinar_small_businesses_05.25.21.pdf.
    \146\ https://www.epa.gov/sites/default/files/2021-05/documents/usepa_training_webinar_on_oil_and_natural_gas_for_tribes.5.26.2021.pdf.
---------------------------------------------------------------------------

    As noted above, the EPA also heard from a broad range of 
stakeholders during virtual public listening sessions held from June 15 
through June 17, 2021,\147\ which featured a total of 173 
speakers.\148\ Many speakers stressed the urgent need to address 
climate change and the importance of reducing methane pollution as part 
of the nation's overall response to climate change. In addition to the 
community perspectives described above, the Agency also heard from 
industry speakers who were generally supportive of the regulation and 
stressed the need to provide compliance flexibility and allow industry 
the ability to use cutting-edge tools, including measurement tools, to 
implement requirements. Technical comments from other speakers also 
focused on a need for robust methane monitoring and fugitive emissions 
monitoring, a need to strengthen standards for flares as a control for 
associated gas, and suggestions to improve compliance. The sections 
below provide additional details on the information presented by 
stakeholders during these listening sessions.
---------------------------------------------------------------------------

    \147\ June 15, 2021 session: https://youtu.be/T8XwDbf-B8g; June 
16, 2021 session: https://www.youtube.com/watch?v=l23bKPF-5oc; June 
17, 2021 session: https://www.youtube.com/watch?v=R2AZrmfuAXQ.
    \148\ Full transcripts for the listening sessions are posted in 
at EPA Docket ID No. EPA-HQ-OAR-2021-0295.
---------------------------------------------------------------------------

1. Technical Themes
    Measurement and Monitoring. Stakeholders advocated that the EPA 
modernize the rule by employing next-generation tools for methane 
identification and quantification, particularly for large emission or 
``super-emissions'' events. Stakeholders particularly focused on 
allowing the use of remote sensing to help industry more easily comply 
with monitoring requirements at well pads, which are numerous and 
geographically spread out in some States. Stakeholders specified the 
desire to use innovative remote sensing technologies to monitor 
fugitive emissions and large emission events, including aerial, truck-
based, satellite, and continuous monitoring. Several speakers focused 
on the need for regular monitoring, repair, and reporting, including 
ambient air monitoring in oil and natural gas development areas, as 
well as suggesting that the EPA pursue more robust methane monitoring 
for fugitive emissions, ensure that repair is completed, and pursue 
robust monitoring and reporting to verify the efficacy of the 
regulations.
    Implementation, Compliance, and Enforcement. Numerous stakeholders 
raised concerns about flaring of associated gas and advocated for more 
stringent standards to ensure that flares used as control devices 
perform effectively. One speaker, an OGI expert, noted seeing many 
flares that were not operating the way they were intended to and that 
were not adequately designed (e.g., unlit flares and ignition gas not 
being close enough to the waste gas stream to properly ignite). The 
speaker suggested that the EPA consider the concept of `thermal tuning' 
of flares by

[[Page 63146]]

using OGI to see if a plume of unburned hydrocarbons extends downwind 
from the flare, to ensure that flares are actually operating 
effectively; the speaker suggested that this use of OGI could be done 
in conjunction with fugitive emissions monitoring to make sure controls 
are working. Stakeholders further emphasized the need for recordkeeping 
of any inspections that are made (e.g., looking for flare damage from 
burned tips, lightning strikes). Some stakeholders also requested that 
the EPA consider reducing or eliminating flaring of associated gas and 
incentivizing capture. Lastly, one speaker raised concerns about 
flaring of associated gas in Texas and how flaring is permitted by the 
State. In response to these concerns, the EPA is proposing to reduce 
venting and flaring of associated gas and to require monitoring of 
flares to detect malfunctions. Further, the EPA is soliciting comment 
on whether to adopt additional measures to assure proper design and 
operation of control devices, including flares, as discussed in section 
XIII.
    Stakeholders raised other implementation, compliance, and 
enforcement concerns, including calls for the EPA to develop rules that 
are easy to apply and implement given States' limited budgets. 
Stakeholders cautioned that ``flexibility'' in a rule can be 
interpreted as a ``loophole,'' and opined that a rule that sets clear 
and uniform expectations will help avoid confusion. At the same time, 
speakers stated that a ``prescriptive checklist'' does not work in 
today's environment and recommended that the EPA modernize the 
regulatory approach. Several speakers, including speakers from Texas 
and North Dakota, raised concerns about the limited enforcement 
capacity of local and State governments, as well as the EPA and its 
regional officials and stated that this may result in implementation 
gaps. Speakers called on the EPA to have a third-party verification or 
audit requirements for fugitive emissions and cited to Texas's 
requirement for third-party audits to evaluate operator LDAR programs 
for highly reactive VOC. Speakers also cited to the public-facing 
Environmental Defense Fund (EDF) methane map \149\ with geotags of 
sources with observed hydrocarbon emissions, which provides operators 
an opportunity to respond to posted leak videos and measurements. 
Lastly, one speaker requested that the EPA not allow exemptions for 
start-up and shutdown emissions events. The EPA is soliciting comment 
on ways to utilize credible emissions information obtained from 
communities and others, as discussed in section XI.A.1.
---------------------------------------------------------------------------

    \149\ https://www.permianmap.org.
---------------------------------------------------------------------------

    Wells and Storage. Some stakeholders requested that the EPA 
consider a program for capping abandoned wells to ensure those wells 
are properly closed and not leaking. Speakers called on the EPA to 
consider abandoned and unplugged wells in the context of EJ communities 
adjacent to affected facilities and requested that the EPA incentivize 
appropriate well closure. In response to this input and to gather 
information that will be needed to inform possible future actions, the 
EPA is soliciting comment on ways to address abandoned wells, including 
potential closure requirements. See section XIII.B. Stakeholders also 
focused on marginal wells and asked that the EPA consider system-wide 
reductions be allowed, for example, at the basin level, and expressed 
challenges of retrofitting existing well sites and low production well 
sites where addition of control devices or closed vent systems would be 
necessary. Some speakers raised concern about ensuring that facilities 
are engineered for the basin or target formation from which they 
produce.
    Job Creation. Some speakers stated that this rulemaking is a job 
creation rule and encouraged a ``next generation'' approach to methane 
standards, such as incentivizing continuous monitoring. Other speakers 
cited a study about job creation in the methane mitigation 
industry.\150\
---------------------------------------------------------------------------

    \150\ Stakeholders submitted the following studies to the pre-
proposal docket: https://www.regulations.gov/comment/EPA-HQ-OAR-2021-0295-0016 and https://www.regulations.gov/comment/EPA-HQ-OAR-2021-0295-0017.
---------------------------------------------------------------------------

    Inventory, Loss Rates, and Methane Global Warming Potential. 
Several speakers criticized the EPA's emission inventories stating that 
the EPA is not using the correct data in its inventory, that the GHGI 
data is inaccurate because it relies on facility reporting of emissions 
from calculations and estimation methods rather than measurement and 
monitoring, and suggested that the EPA rely on monitoring and 
measurement of actual emissions and subsequently make the monitoring 
data publicly available. Speakers raised issues with differences in 
inventories across Federal agencies, contrasting DOE's Environmental 
Impact Statements and EPA's NEI. Stakeholders suggested that the EPA 
use data collected by EDF and other researchers, which calculated 
methane emissions to be 60 percent higher than the EPA's 
estimates.\151\ Speakers also mentioned the amount of methane that is 
lost from wells each year, providing varying estimates of these 
emissions. Lastly, stakeholders called on the EPA to use the 20-year 
GWP for methane, instead of the 100-year value the agency uses.
---------------------------------------------------------------------------

    \151\ Alvarez et al. 2018. Assessment of methane emissions from 
the U.S. oil and gas supply chain. Science 13 Jul 2018: Vol. 361, 
Issue 6398, pp. 186-188.
---------------------------------------------------------------------------

2. Climate and Other Themes
    Several speakers mentioned the effects of climate change from oil 
and natural gas methane emissions, such as impacts on farmland, 
wildfires, and transmission of tick-borne pathogens. Many speakers 
pointed out the extreme heat and drought that currently are affecting 
the western U.S. Stakeholders asked that the EPA examine the impacts of 
the Oil and Natural Gas Industry on small businesses that are not part 
of the regulated community, such as businesses that rely on outdoor 
recreation or water flow that could be affected by oil and natural gas 
operations. A speaker raised concerns about the impact of the industry 
on tourism, saying that 30 percent of their local economy relies on 
tourism and outdoor recreation. Lastly, a speaker discussed pipeline 
weatherization needs and suggested that the EPA and other Federal 
agencies account for seasonal variability.
    In addition to the public listening sessions, on June 29, 2021, the 
EPA met with environmental commissioners and staff through the 
Environmental Council of the States (ECOS). Subsequently, on July 12, 
2021, the EPA participated in a roundtable with members of the IOGCC. 
The discussions in both roundtables included air emissions monitoring 
technologies and interactions between the EPA's requirements and State 
rules. For the ECOS roundtable, the EPA also sought feedback on and 
implementation of the EPA's current NSPS; for the IOGCC roundtable, the 
EPA also requested feedback on compliance with the rules.
    Key themes from both roundtables included the following: Allowing 
for the use of broad types of methane detection technologies; improving 
and streamlining the EPA's AMEL process, such as by structuring it so 
it could apply broadly rather than on a site-by-site basis; requests 
that expanded aspects of States' rules be deemed equivalent to the 
EPA's rule, and requests that the EPA's rule complement State 
regulations in a way that would not interrupt the work of State 
agencies requiring them to request State legislative approvals. Other 
common themes were requests that the rule

[[Page 63147]]

provide flexibility and be easy to implement, particularly for marginal 
or low production wells owned by independent small businesses, and that 
the EPA coordinate its rules with those of other Federal agencies, 
notably the DOI's BLM.
    Other input included the need to fill gaps by addressing additional 
opportunities to reduce emissions beyond the 2016 NSPS OOOOa, concerns 
about the complexity of the calculation for the potential to emit for 
storage vessels, a desire that the EPA's rule not slow momentum of 
voluntary efforts to reduce emissions, and a desire for regulations 
that recognize geographic differences.

B. EPA Methane Detection Technology Workshop

    The EPA held a virtual public workshop on August 23 and 24, 2021, 
to hear perspectives on innovative technologies that could be used to 
detect methane emissions from the Oil and Natural Gas Industry.\152\ 
The workshop focused on methane-sensing technologies that are not 
currently approved for use in the NSPS for the Oil and Natural Gas 
Industry, and how those technologies could be applied in the Crude Oil 
and Natural Gas sector. Panelists provided twenty-four live 
presentations during the workshop. The panelists all had firsthand 
experience evaluating innovative methane-sensing technologies or had 
used these technologies to identify methane emissions and presented 
about their experience. The live presentations were broken into six 
panel sessions, each focused on a particular topic, e.g., satellite 
measurements, methane sensors, aerial technologies. At the end of each 
panel session, the set of panelists participated in a question-and-
answer session. In addition to the live presentations, the workshop 
included a virtual exhibit hall for technology vendors to provide video 
presentations on their innovative technologies, with a focus on 
technology capability, applicability, and data quality. Forty-two 
vendors participated in the virtual vendor hall.
---------------------------------------------------------------------------

    \152\ https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop.
---------------------------------------------------------------------------

    Nine hundred sixty stakeholders registered to participate in the 
workshop. The workshop was also livestreamed, so stakeholders who could 
not attend could watch the recorded livestream later at their 
convenience. The registrants included a wide range of stakeholders 
including, academics, methane detection technology end-user and 
vendors, governmental employees (local, State, and Federal), and NGOs.

C. How is this information being considered in this proposal?

    The EPA's pre-proposal outreach effort was intended to gather 
stakeholder input to assist the Agency with developing this 
proposal.\153\ The EPA recognizes that tackling the dangers of climate 
change will require an ``all-hands-on deck'' approach through 
regulatory, voluntary, and community programs and initiatives. 
Throughout the development of this proposed rule, the EPA considered 
the stakeholders' experiences and lessons learned to help inform how to 
better structure this proposal and consider ongoing challenges that 
will require continued collaboration with stakeholders. The EPA will 
continue to consider the information obtained in developing this 
proposal as we take the next steps on the proposed regulations.
---------------------------------------------------------------------------

    \153\ The EPA opened a non-regulatory docket for stakeholder to 
submit early input. That early input can be found at EPA Docket I.D. 
Number EPA-HQ-OAR-2021-0295.
---------------------------------------------------------------------------

    With this proposal, the EPA seeks further input from the public and 
from all stakeholders affected by this rule. Throughout this action, 
unless noted otherwise, the EPA is requesting comments on all aspects 
of this proposal, including on several themes raised in the pre-
proposal outreach (e.g., innovative technologies for methane detection 
and quantification). Please see section XI.A.1 of this preamble for 
specific solicitations for comment regarding advanced measurement 
technologies and section XIII for solicitations for comments on 
additional emission sources. For public input to be considered on this 
proposal,\154\ please submit comments on this proposed action to the 
regulatory docket at EPA Docket ID No. EPA-HQ-OAR-2021-0317 so that the 
EPA may consider those comments during the development of the final 
rule.
---------------------------------------------------------------------------

    \154\ Information submitted to the pre-proposal non-regulatory 
docket at Docket ID No. EPA-HQ-OAR-2021-0295 is not automatically 
part of the proposal record. For information and materials to be 
considered in the proposed rulemaking record, it must be resubmitted 
in the rulemaking docket at EPA Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

VIII. Legal Basis for Proposal Scope

    The EPA proposes in this rulemaking to revise certain NSPS and to 
promulgate additional NSPS for both methane and VOC emissions from new 
oil and gas sources in the production, processing, transmission and 
storage segments of the industry; and to promulgate EG to require 
States to regulate methane emissions from existing sources in those 
segments. The large amount of methane emissions from the Oil and 
Natural Gas Industry--by far, the largest methane-emitting industry in 
the nation--coupled with the adverse effects of methane on the global 
climate compel immediate regulatory action. This section explains EPA's 
legal justification for proceeding with this proposed action, including 
regulating methane and VOCs from sources in all segments of the source 
category. The EPA first describes the history of our regulatory actions 
for oil and gas sources in 2016 and 2020--including the key legal 
interpretations and factual determinations made--as well as Congress's 
action in 2021 in response. The EPA then explains the implications of 
Congress's action and why we would come to the same conclusion even if 
Congress had not acted.
    This proposal is in line with our 2016 NSPS OOOOa rule, which 
likewise regulated methane and VOCs from all three segments of the 
industry. The 2016 NSPS OOOOa rule explained that these three segments 
should be regulated as part of the same source category because they 
are an interrelated sequence of functions in which pollution is 
produced from the same types of sources that can be controlled by the 
same techniques and technologies. That rule further explained that the 
large amount of methane emissions, coupled with the adverse effects of 
GHG air pollution, met the applicable statutory standard for regulating 
methane emissions from new sources through NSPS. Furthermore, the rule 
explained, this regulation of methane emissions from new sources 
triggered the EPA's authority and obligation to set guidelines for 
States to develop standards to regulate the overwhelming majority of 
oil and gas sources, which the CAA categorizes as ``existing'' sources. 
In the 2020 Policy Rule, the Agency reversed course, concluding based 
upon new legal interpretations that the rule concluded the EPA had not 
made the proper determinations necessary to issue such regulations. 
This action eliminated the Agency's authority and obligation to issue 
EG for existing sources. In 2021, Congress adopted a joint resolution 
to disapprove the EPA's 2020 Policy Rule under the CRA. According to 
the terms of CRA, the 2020 Policy Rule is ``treated as though [it] had 
never taken effect,'' 5 U.S.C. 801(f), and as a result, the 2016 Rule 
is reinstated.
    In disapproving the 2020 Policy Rule under the CRA, Congress 
explicitly rejected the 2020 Policy Rule interpretations and embraced 
EPA's

[[Page 63148]]

rationales for the 2016 NSPS OOOOa rule. The House Committee on Energy 
& Commerce emphasized in its report that the source category ``is the 
largest industrial emitter of methane in the U.S.,'' and directed that 
``regulation of emissions from new and existing oil and gas sources, 
including those located in the production, processing, and transmission 
and storage segments, is necessary to protect human health and welfare, 
including through combatting climate change, and to promote 
environmental justice.'' H.R. Rep. No. 117-64, 3-5 (2021) (House 
Report). A statement from the Senate cosponsors likewise underscored 
that ``methane is a leading contributing cause of climate change,'' 
whose ``emissions come from all segments of the Oil and Gas Industry,'' 
and stated that ``we encourage EPA to strengthen the standards we 
reinstate and aggressively regulate methane and other pollution 
emissions from new, modified, and existing sources throughout the 
production, processing, transmission and storage segments of the Oil 
and Gas Industry under section 111 of the CAA.'' 167 Cong. Rec. S2282 
(April 28, 2021) (statement by Sen. Heinrich) (Senate Statement).\155\ 
The Senators concluded with a stark statement: ``The welfare of our 
planet and of our communities depends on it.'' Id. at S2283.
---------------------------------------------------------------------------

    \155\ Sen. Heinrich stated that he made this statement on behalf 
of ``[Majority [l]eader Chuck Schumer, Chairman Tom Carper of the 
Committee on Environment and Public Works, Senator Angus King, 
Senator Edward Markey and [himself],'' who he described as ``leading 
supporters and sponsors of S.J. Res. 14. . . .'' Senate Statement at 
S. 2282. Thus, the Senate Statement should be considered an 
authoritative piece of the legislative history. It should be noted 
that the Joint Resolution was referred to the Senate Committee on 
Environment and Public Works and discharged from the committee by 
petition pursuant to 5 U.S.C. 802(c), https://www.congress.gov/bill/117th-congress/senate-joint-resolution/14/all-actions. As a result, 
the resolution was not accompanied by a report from the Senate 
committee.
---------------------------------------------------------------------------

    This proposal comports with the EPA's CAA section 111 obligation to 
reduce dangerous pollution and responds to the urgency expressed by the 
current Congress. With this proposal, the EPA is taking additional 
steps in the regulation of the Crude Oil and Natural Gas source 
category to protect human health and the environment. Specifically, the 
agency is proposing to revise certain of those NSPS, to add NSPS for 
additional sources, and to propose EG that, if finalized, would impose 
a requirement on States to regulate methane emissions from existing 
sources. As the EPA explained in the 2016 Rule, this source category 
collectively emits massive quantities of the methane emissions that are 
among those driving the grave and growing threat of climate change, 
particularly in the near term. 81 FR 35834, June 3, 2016. As discussed 
in section III above, since that time, the science has repeatedly 
confirmed that climate change is already causing dire health, 
environmental, and economic impacts in communities across the United 
States.
    Because the 2021 CRA resolution automatically reinstated the 2016 
Rule, which itself determined that the Crude Oil and Natural Gas Source 
Category included the transmission and storage segment and that 
regulation of methane emissions was justified, the EPA is authorized to 
take the regulatory actions proposed in this rule. As explained below, 
we are reaffirming those determinations as clearly authorized under any 
reasonable interpretation of section 111. Because the reinstatement of 
the 2016 Rule provides the only necessary predicate for this rule, and 
because, as described, the interpretations underlying this rule are 
sound, the EPA is not reopening them here.

A. Recent History of the EPA's Regulation of Oil and Gas Sources and 
Congress's Response

1. 2016 NSPS OOOOa Rule
    As described above, the 2016 NSPS OOOOa rule extended the NSPS for 
VOCs for new sources in the Crude Oil and Natural Gas source category 
and also promulgated NSPS for methane emissions from new sources. This 
rule contained several interpretations that were the bases for these 
actions, and that are important for present purposes. First, the EPA 
confirmed its position in the 2012 NSPS OOOO rule that the scope of the 
oil and gas source category included the transmission and storage 
segment, in addition to the production and processing segments that the 
EPA had regulated since 1984. The agency stated that it believed these 
segments were included in the initial listing of the source category, 
and to the extent they were not, the agency determined to add them as 
appropriately encompassed within the regulated source category. The EPA 
based this latter conclusion on the structure of the industry. In 
particular, the EPA emphasized that ``[o]perations at production, 
processing, transmission, and storage facilities are a sequence of 
functions that are interrelated and necessary for getting the recovered 
gas ready for distribution,'' and further explained, ``[b]ecause they 
are interrelated, segments that follow others are faced with increases 
in throughput caused by growth in throughput of the segments preceding 
(i.e., feeding) them.'' 81 FR 35832, June 3, 2016. The EPA also 
recognized ``that some equipment (e.g., storage vessels, pneumatic 
pumps and compressors) are used across the oil and natural gas 
industry.'' Id. Having made clear that the Crude Oil and Natural Gas 
source category includes the transmission and storage segment, the EPA 
proceeded to promulgate NSPS for sources in that segment. Id. at 35826.
    Second, in promulgating NSPS for methane emissions for new sources 
in the source category, the EPA explained its decision to regulate GHGs 
for the first time from the source category. Noting that the plain 
language of CAA section 111 requires a significant-contribution 
analysis only when EPA regulates a new source category, not a new 
pollutant, the Agency stated that it ``interprets CAA section 
111(b)(1)(B) to provide authority to establish a standard for 
performance for any pollutant emitted by that source category as long 
as the EPA has a rational basis for setting a standard for the 
pollutant.'' 81 FR 35842, June 3, 2016. In the alternative, if a 
rational-basis analysis were deemed insufficient, the EPA explained 
that it also concluded that GHG emissions, in the form of methane 
emissions, from the regulated Crude Oil and Natural Gas source category 
significantly contribute to dangerous pollution. Id. at 81 FR 35843, 
and 35877. In making the rational basis and alternative significant 
contribution findings, the EPA focused on ``the high quantities of 
methane emissions from the Crude Oil and Natural Gas source category.'' 
Id. The EPA emphasized, among other things, that ``[t]he Oil and 
Natural Gas source category is the largest emitter of methane in the 
U.S., contributing about 29 percent of total U.S. methane emissions.'' 
Id. The EPA added that ``[t]he methane that this source category emits 
accounts for 3 percent of all U.S. GHG emissions . . . [and] GWP-
weighted emissions of methane from these sources are larger than 
emissions of all GHGs from about 150 countries.'' Id. The EPA concluded 
that ``the[se] facts . . . along with prior EPA analysis'' concerning 
the effect of GHG air pollution on public health and welfare, 
``including that found in the 2009 Endangerment Finding, provide a 
rational basis for regulating GHG emissions from affected oil and gas 
sources . . .'' as well as for concluding in the alternative that oil 
and gas methane significantly contributes to dangerous pollution. Id. 
at 35843.
    In addition, in the 2016 NSPS OOOOa Rule, EPA recognized that 
promulgation of NSPS for methane emissions under

[[Page 63149]]

section 111(b)(1)(B) triggered the requirement that EPA promulgate EG 
to require States to regulate methane emissions from existing sources 
under section 111(d)(1), and described the steps it was taking to lay 
the groundwork for that regulation. 81 FR at 35831.
2. 2020 Policy Rule
    The 2020 Policy Rule rescinded key elements of the 2016 NSPS OOOOa 
rule based on different factual assertions and statutory 
interpretations than in the 2016 Rule. Specifically, the 2020 Policy 
Rule stated that it ``contains two main actions,'' 85 FR 57019, 
September 14, 2020 which it identified as follows: ``First, the EPA is 
finalizing a determination that the source category includes only the 
production and processing segments of the industry and is rescinding 
the standards applicable to the transmission and storage segment of the 
industry. . . .'' Id. The rule justified this first action in part on 
the grounds that ``the processes and operations found in the 
transmission and storage segment are distinct from those found in the 
production and processing segments,'' because ``the purposes of the 
operations are different'' and because ``the natural gas that enters 
the transmission and storage segment has different composition and 
characteristics than the natural gas that enters the production and 
processing segments.'' Id. at 57028. ``Second, the EPA is separately 
rescinding the methane requirements of the NSPS applicable to sources 
in the production and processing segments.'' Id. EPA justified the 
rescission of the methane NSPS on two grounds. One was the EPA's 
``conclu[sion] that those methane requirements are redundant with the 
existing NSPS for VOC and, thus, establish no additional health 
protections.'' Id. at 57019. The second was a statutory interpretation: 
the EPA rejected the rational basis interpretation of the 2016 Rule, 
and stated that instead, ``[t]he EPA interprets [the relevant 
provisions in CAA section 111] . . . to require, or at least to 
authorize the Administrator to require, a pollutant-specific SCF as a 
predicate for promulgating a standard of performance for that air 
pollutant.'' Id. at 57035. The rule went on to ``determine that the SCF 
for methane that the EPA made in the alternative in the 2016 [NSPS 
OOOOa] Rule was invalid and did not meet this statutory standard,'' for 
two reasons: (i) ``[t]he EPA made that finding on the basis of methane 
emissions from the production, processing, and transmission and storage 
segments, instead of just the production and processing segments''; and 
(ii) ``the EPA failed to support that finding with either established 
criteria or some type of reasonably explained and intelligible standard 
or threshold for determining when an air pollutant contributes 
significantly to dangerous air pollution.'' Id. at 57019. The rule 
recognized that ``by rescinding the applicability of the NSPS . . . to 
methane emissions for [oil and gas] sources . . . existing sources . . 
. will not be subject to regulation under CAA section 111(d).'' Id. at 
57040.
3. CRA Resolution Disapproving the 2020 Policy Rule and Reinstating the 
2016 NSPS OOOOa Rule
    On June 30, 2021, the President signed into law a joint resolution 
adopted by Congress under the CRA disapproving the 2020 Policy Rule. By 
the terms of the CRA, this disapproval means that the 2020 Policy Rule 
is ``treated as though [it] had never taken effect.'' 5 U.S.C. 801(f). 
As a result, upon the disapproval, by operation of law, the 2016 NSPS 
OOOOa rule was reinstated, including the inclusion of the transmission 
and storage segment in the source category, the VOC NSPS for sources in 
that segment, and the methane NSPS for sources across the source 
category. And with the reinstatement of the methane NSPS, the EPA's 
obligation to issue EG to require States to regulate existing sources 
for methane emissions was reinstated as well. Moreover, the CRA bars an 
agency from promulgating ``a new rule that is substantially the same 
as'' a disapproved rule. 5 U.S.C. 801(b)(2).
    The accompanying legislative history, specifically a House 
Committee report (H.R. Rep. 117-64) and a statement on the Senate floor 
by the sponsors of the CRA resolution (Senate Statement at S2282-83), 
provides additional specificity regarding Congress's intent in 
disapproving 2020 Policy Rule and reinstating the 2016 Rule with regard 
to the scope of the source category and the regulation of methane.
a. Regulation of Transmission and Storage Sources
    The House Report rejected the 2020 Policy Rule's removal of the 
transmission and storage segment from the Crude Oil and Natural Gas 
Source Category, and its rescission of the VOC and methane NSPS 
promulgated in the 2012 NSPS OOOO and 2016 NSPS OOOOa rules for 
transmission and storage sources. House Report at 7; 85 FR 57029, 
September 14, 2020 (2020 Policy Rule). The Report recognized that in 
authorizing the EPA to list for regulation ``categories of sources'' 
under section 111(b)(1)(A) of the CAA, Congress ``provided the EPA with 
wide latitude to determine the scope of a source category . . . and to 
expand the scope of an already-listed source category if the agency 
later determines that it is reasonable to do so.'' House Report at 7. 
The Report stated that in the 2016 NSPS OOOOa, ``EPA correctly 
determined that the equipment and operations at production, processing, 
and transmission and storage facilities are a sequence of functions 
that are interrelated and necessary for the overall purpose of 
extracting, processing, and transporting natural gas for 
distribution.'' Id.; see 81 FR 35832, June 3, 2016 (2016 Rule). The 
Report added that the 2016 NSPS OOOOa also ``correctly determined that 
the types of equipment used and the emissions profile of the natural 
gas in the transmission and storage segments do not so distinctly 
differ from the types of equipment used and the emissions profile of 
the natural gas in the production and processing segments as to require 
that the EPA create a separate source category listing.'' House Report 
at 7; see 81 FR 35832, June 3, 2016. The Report went on to reject the 
2020 Policy Rule's basis for excluding the transmission and storage 
segment, finding that the functions of the various segments in the 
Crude Oil and Natural Gas sector are all ``interrelated and necessary 
for the overall purpose'' of the industry, House Report at 7, and that 
EPA correctly determined in 2016 that the source types and emissions 
found in the transmission and storage segment are sufficiently similar 
to production and processing as to justify regulating these segments in 
a single source category. Id.
    The Senate Statement was also explicit that the 2020 Policy Rule 
erred in rescinding NSPS for sources in the transmission and storage 
segment:

[T]he resolution clarifies our intent that EPA should regulate 
methane and other pollution emissions from all oil and gas sources, 
including production, processing, transmission, and storage segments 
under the authority of section 111 of the CAA. In addition, we 
intend that section 111 . . . obligates and provides EPA with the 
legal authority to regulate existing sources of methane emissions in 
all of these segments.

Senate Statement at S2283 (paragraphing revised).
b. Regulation of Methane--Redundancy
    The House Report and Senate Statement made clear Congress's view 
that in light of the large amount of methane emissions from oil and gas 
sources and their impact on global climate, the EPA must regulate those

[[Page 63150]]

emissions under section 111. House Report at 5; Senate Statement at 
S2283. Both pieces of legislative history specifically rejected the 
2020 Policy Rule's rescission of the methane NSPS. House Report at 7; 
Senate Statement at S2283. Moreover, the legislative history 
specifically rejected the statutory interpretations of section 111 that 
formed the bases of EPA's 2020 rationales for rescinding the methane 
NSPS. House Report at 7-10; see Senate Statement at S2283; see 85 FR 
57033, 57035-38 (September 14, 2020).
    The House Report began by recognizing the critical importance of 
regulating methane emissions from oil and gas sources, emphasizing both 
the potency of methane in driving global warming, and the massive 
amounts of methane emitted each year by the oil and gas industry. House 
Report at 3-4. The House Report was clear that the amount of these 
emissions and their impact compelled regulatory action. Id. at 5. The 
Senate Statement was equally clear:

[M]ethane is a leading contributing cause of climate change. It is 
28 to 36 times more powerful than carbon dioxide in raising the 
Earth's surface temperature when measured over a 100-year time scale 
and about 84 times more powerful when measured over a 20-year 
timeframe.
    Industrial sources emit GHG in great quantities, and methane 
emissions from all segments of the Oil and Gas Industry are 
especially significant in their contribution to overall emissions 
levels and surface temperature rise. . . .
    In fact, with the congressional adoption of this resolution, we 
encourage EPA to strengthen the standards we reinstate and 
aggressively regulate methane and other pollution emissions from 
new, modified, and existing sources throughout the production, 
processing, transmission, and storage segments of the Oil and Gas 
Industry under section 111 of the Clean Air Act.
    The welfare of our planet and of our communities depend on it.

Senate Statement at S2283.
    Turning to the 2020 Policy Rule, the House Report rejected the 
rule's position that the methane NSPS were redundant to the VOC NSPS, 
and therefore unnecessary. House Report at 7. The House Report rejected 
the 2020 Policy Rule's ``redundancy'' rationale, explaining that in the 
2016 NSPS OOOOa, the EPA had consciously ``formulated [the two sets of 
NSPS so as] to impose the same requirements for the same types of 
equipment,'' and that the co-extensive nature of the NSPS mean that 
``sources could comply with them in an efficient manner,'' not that the 
NSPS were redundant. Id. The House report further rejected the 2020 
Policy Rule's assertion that it need not take into account the 
implications of regulating methane for existing sources, calling it a 
``fundamental misinterpretation of section 111, and the critical 
importance of section 111(d) in Congress [sic: Congress's] scheme.'' 
House Report at 8 & n. 27 (The EPA's 2020 ``misinterpretation . . . was 
glaring and enormously consequential'' because it precluded regulation 
of methane from existing sources). The House Report emphasized that 
``existing sources emit the vast majority of methane in the oil and gas 
sector,'' id. and pointed out that while the 2016 NSPS ``covered 
roughly 60,000 wells constructed since 2015[, t]here are more than 
800,000 existing wells in operation. . . .''Id. n.28.
    The Senate Statement also made clear that the resolution of 
disapproval ``reaffirms that the CAA requires EPA to act to protect 
Americans from sources of . . . methane,'' ``reject[s] the [2020 Policy 
Rule's] misguided legal interpretations,'' and ``clarifies our intent 
that EPA should regulate methane . . . from all oil and gas sources. . 
. .'' Senate Statement at 2283.
c. Regulation of Methane--Significant Contribution Finding
    The legislative history was explicit that, contrary to the EPA's 
statutory interpretation in the 2020 Policy Rule, section 111 of the 
CAA, by its plain language, does not require, or authorize the EPA to 
require, as a prerequisite for promulgating NSPS for a particular air 
pollutant from a listed source category, a separate finding by the EPA 
that emissions of the pollutant from the source category contribute 
significantly to dangerous air pollution. House Report at 9-10; Senate 
Statement at S2283. The House Report rejected this interpretation. It 
made clear that instead, consistent with the EPA's statements in the 
2016 NSPS OOOOa and the plain language of the CAA, section 111 requires 
that the agency must make a SCF only at ``the first step of the 
process, the listing of the source category,'' and further requires 
that this finding ``must apply to the impact of the `category of 
sources' on `air pollution' '' as opposed to individual pollutants. 
House Report at 9. The House Report went on to explain that this 
provision ``does not require the EPA to make a SCF for individual air 
pollutants emitted from the source category, nor does it even mention 
individual air pollutants,'' id. at 9. The House Report went on to 
explain in some detail the meaning that the EPA should give to section 
111, which, consistent with the 2016 Rule, is that section 111 
authorizes the agency to promulgate NSPS for particular pollutants as 
long as it has a rational basis for doing so. House Report at 8-9. The 
report explained that after the EPA lists a source category for 
regulation under section 111(b)(1)(A), it is required to determine for 
which pollutants to promulgate NSPS, and this determination is subject 
to CAA section 307(d)(9)(A) (``In the case of review of any [EPA] 
action . . . to which [section 307(d)] applies, the court may reverse 
any such action found to be arbitrary, capricious, an abuse of 
discretion, or otherwise not in accordance with law'').\156\ The Report 
further noted that the U.S. Supreme Court affirmed this interpretation 
in American Electric Power Co. Inc. v. Connecticut, 564 U.S. 410, 427 
(2011) (American Electric Power) (``EPA may not decline to regulate 
carbon-dioxide emissions from powerplants if refusal to act would be 
`arbitrary, capricious, an abuse of discretion, or otherwise not in 
accordance with law'' (citing section 307(d)(9)(A)). The Report went on 
to note that the 2016 NSPS OOOOa had stated that the EPA was authorized 
to promulgate a NSPS for a particular pollutant if it had a ``rational 
basis'' for doing so, and the Report emphasized that this ``rational 
basis'' standard is ``fully consistent with'' the arbitrary and 
capricious standard under section 307(d)(9)(A) of the CAA. House Report 
at 9.\157\
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    \156\ Section 307(d) applies to the promulgation of NSPS, under 
section 307(d)(1)(C).
    \157\ The House Report dismissed the 2020 Policy Rule's 
criticism of the rational basis test as unduly vague by noting that 
a court could enforce it. House Report at 11.
---------------------------------------------------------------------------

    The House Report further explained that, in contrast, the 2020 
Policy Rule's statutory interpretation of section 111 to require a 
pollutant-specific SCF as a predicate for promulgating NSPS was 
foreclosed by ``the plain language of'' section 111--noting that this 
interpretation ignored the distinction between the text of section 111 
and that of other CAA provisions which do explicitly require a 
pollutant-specific cause-or-contribution finding. Id. at 10. Moreover, 
the Report added, ``[g]iven that the statute is not ambiguous, the EPA 
cannot interpret section 111 to authorize the EPA to exercise 
discretion to require . . . a pollutant-specific SCF as a predicate for 
promulgating a [NSPS] for the pollutant.'' Id. at 10. The Report went 
on to note several other supports for its statutory interpretation, 
including the legislative history of section 111. Id. at 10-11.
    The Senate Statement took the same approach, stating: ``we do not 
intend that section 111 of [the] CAA requires EPA to make a pollutant-
specific

[[Page 63151]]

significant contribution finding before regulating emissions of a new 
pollutant from a listed source category. . . .'' Senate Statement at 
S2283.\158\
---------------------------------------------------------------------------

    \158\ Both the House Report and the Senate Statement recognized 
that EPA could, if it chose to, make a finding that a particular 
pollutant contributes significantly to dangerous air pollution, in 
order, for example, to inform the public about the risks of a 
pollutant. House Report at 10, Senate Statement at S2283. However, 
the House Report made clear that ``it is the rational basis 
determination as to the risk a pollutant poses to endangerment of 
human health or welfare [and not any such SCF] that remains the 
statutory basis for the EPA's action.'' House Report at 10.
---------------------------------------------------------------------------

    The House Report also expressly disapproved of the 2020 Policy 
Rule's interpretation of section 111 to require that the SCF must be 
based on some ``identif[ied] standard or established set of criteria,'' 
and not the facts-and-circumstances approach that EPA has used in 
making that finding for the source category. House Report at 10-11; see 
2020 Policy Rule at 57038. The Report stated, ``[i]t is fully 
appropriate for EPA to exercise its discretion to employ a facts-and-
circumstances approach, particularly in light of the wide range of 
source categories and the air pollutants they emit that EPA must 
regulate under section 111.'' House Report at 11.
    Finally, in reinstating the methane regulations, the legislative 
history for the CRA resolution clearly expressed the intent that the 
EPA proceed with regulation of existing sources. The House Report was 
explicit in this regard, stating that ``[p]assage of the resolution of 
disapproval indicates Congress' support and desire to immediately 
reinstate . . . EPA's statutory obligation to regulate existing oil and 
natural gas sources under [CAA] section 111(d).'' House Report at 3; 
see id. at 11-12. The report added that upon enactment of the 
resolution of disapproval, ``the Committee strongly encourages the EPA 
to take swift action to . . . fulfill its statutory obligation to issue 
existing source guidelines under [CAA] section 111(d).'' Id. The Senate 
Statement was substantially similar. Senate Statement at S2283 (``By 
adopting this resolution of disapproval, it is our view that Congress 
reaffirms that the CAA requires EPA to act to protect Americans from 
sources of climate pollution like methane, which endangers the public's 
health and welfare. . . . [W]e intend that [CAA] section 111 . . . 
obligates and provides EPA with the legal authority to regulate 
existing sources of methane emissions in [the Crude Oil and Natural Gas 
source category].'').

B. Effect of Congress's Disapproval of the 2020 Policy Rule

    Under the CRA, the disapproved 2020 Policy Rule is ``treated as 
though [it] had never taken effect.'' 5 U.S.C. 801(f). As a result, the 
preceding regulation, the 2016 NSPS OOOOa rule, was automatically 
reinstated, and treated as though it had never been revised by the 2020 
Policy Rule. Moreover, the CRA bars EPA from promulgating ``a new rule 
that is substantially the same as'' a disapproved rule. 5 U.S.C. 
801(b)(2), for example, a rule that deregulates methane emissions from 
the production and processing sectors or deregulates the transmission 
and storage sector entirely.
    The legislative history of the CRA gives further content to 
Congress's disapproval and the bar on substantially similar rulemaking. 
The legislative history rejected the EPA's statutory interpretations of 
section 111 in the 2020 Policy Rule and endorsed the legal 
interpretations contained in the 2016 NSPS OOOOa rule. Specifically, 
Congress expressed its intent that the transmission and storage segment 
be included in the source category, that sources in that segment remain 
subject to NSPS, and that all oil and gas sources be subject to NSPS 
for methane emissions.\159\
---------------------------------------------------------------------------

    \159\ See generally ``Federal-State Unemployment Compensation 
Program; Establishing Appropriate Occupations for Drug Testing of 
Unemployment Compensation Applicants Under the Middle-Class Tax 
Relief and Job Creation Act of 2012: Final Rule,'' 84 FR 53037, 
53083 (Oct. 4, 2019) (citing legislative history of CRA resolution 
disapproving prior rule in explaining scope of new rule).
---------------------------------------------------------------------------

    The EPA is now proceeding to propose additional requirements to 
reduce emissions from oil and gas sources, consistent with the 
statutory factors the EPA is required to consider under section 111 and 
with section 111's overarching purpose of protecting against pollution 
that endangers health and welfare. While the reinstatement of the 2016 
Rule through the CRA joint resolution of disapproval provides the 
predicate for this action, the EPA notes that, for the reasons 
discussed next, the EPA would reject the positions concerning legal 
interpretations taken in the 2020 Policy Rule and reaffirm the 
positions the Agency took in the 2016 Rule even absent the CRA 
resolution. The EPA provides this information for the purposes of 
informing the public and is not re-opening these positions for comment.

C. Affirming the Legal Interpretations in the 2016 NSPS OOOOa Rule

    The Agency has reviewed all of the information and analyses in the 
2016 NSPS OOOOa and 2020 Policy Rule, and fully reaffirms the positions 
it took in the 2016 Rule and rejects the positions taken in the 2020 
Policy Rule.\160\ For this rulemaking, the EPA has reviewed its prior 
actions, along with newly available information, including recent 
information concerning the dangers posed by climate change and the 
impact of methane emissions, as described in section III above. Based 
on this review, the EPA affirms the statutory interpretations 
underlying the 2016 Rule and rejects the different interpretations 
informing the congressionally voided 2020 Policy Rule. This section 
explains the EPA's views. These views are confirmed by Congress's 
reasoning in the legislative history of the CRA resolution and so, for 
convenience, this section occasionally refers to that legislative 
history.
---------------------------------------------------------------------------

    \160\ Under F.C.C. v. Fox Television Stations, Inc., 556 U.S. 
502 (2009), an agency may revise its policy, but must demonstrate 
that the new policy is permissible under the statute and is 
supported by good reasons, taking into account the record of the 
previous rule. To the extent that this standard applies in this 
action--where Congress has disapproved the 2020 Policy Rule--the EPA 
believes the explanations provided here satisfy the standard.
---------------------------------------------------------------------------

    In particular, the EPA reaffirms that the Crude Oil and Natural Gas 
Source Category appropriately includes the transmission and storage 
segment, along with the production and processing segments. The EPA has 
broad discretion in determining the scope of the source category, and 
the 2016 Rule correctly identified the most important aspect of the 
industry, which is the interrelatedness of the segments and their 
common purpose in completing the multi-step process to prepare natural 
gas for marketing. 81 FR 35832, June 3, 2016. The 2020 Policy Rule's 
objection that the chemical composition of natural gas changes as it 
moves from the production and processing segments to the transmission 
and storage segment, 85 FR 57028, September 14, 2020, misses the mark 
because in every segment methane predominates and the refining of 
natural gas in the processing segment, which is what changes its 
chemical composition, is appropriately viewed simply as one of the 
steps in the marketing of the gas. Further, while it is true that some 
of the equipment in each segment differs from the equipment in the 
other segments, as the 2020 Policy Rule pointed out, 85 FR 57029 
(September 14, 2020), that too simply results from the fact that the 
segments represent different steps in the process of preparing natural 
gas for marketing. The more salient fact is that most of the polluting 
equipment, such as storage

[[Page 63152]]

vessels, pneumatic pumps, and compressors, are found throughout the 
segments and emit the same pollutants that can be controlled by the 
same techniques and technologies, 81 FR 35832 (June 3, 2016), 
underscoring the interrelated functionality of the segments and the 
appropriateness of regulating them together as part of a single source 
category. The scope of the source category as defined in 2016, and 
proposed to be affirmed in this rule, is well within the reasonable 
bounds of the EPA's past practice in defining source categories, which 
sometimes even contain sources that are located in multiple distinct 
industries. See 40 CFR part 60, subpart Db (industrial-commercial-
institutional steam generating units), 40 CFR part 60, subpart IIII 
(stationary compression ignition internal combustion engines). In this 
regard, the House Report correctly noted that ``even the presence of 
large distinctions in equipment type and emissions profile across two 
segments would not necessarily preclude EPA from regulating those 
segments as a single source category, so long as the EPA could identify 
some meaningful relationship between them,'' House Report at 7, as the 
EPA did in the 2016 Rule. Thus, the 2020 Policy Rule failed to 
articulate appropriate reasons to change the scope of the source 
category from what the EPA determined in the 2016 Rule. Having properly 
identified the scope of the source category as including the 
transmission and storage segment in the 2016 Rule, the EPA lawfully 
promulgated NSPS for sources in that segment.
    The EPA also affirms that the 2016 Rule established an appropriate 
basis for promulgating methane NSPS from oil and gas sources, and that 
the 2020 Policy Rule erred on all grounds in rescinding the methane 
NSPS. The importance of taking action at this time, in accordance with 
the requirements of CAA section 111, to reduce the enormous amount of 
methane emissions from oil and gas sources, in light of the impacts on 
the climate of this pollution, cannot be overstated. As stated in 
section I, the Oil and Natural Gas Industry is the largest industrial 
emitter of methane in the U.S. Human emissions of methane, a potent 
GHG, are responsible for about one third of the warming due to well-
mixed GHGs, the second most important human warming agent after carbon 
dioxide. According to the IPCC, strong, rapid, and sustained methane 
reductions are critical to reducing near-term disruption of the climate 
system and a vital complement to CO2 reductions critical in 
limiting the long-term extent of climate change and its destructive 
impacts.\161\ The EPA previously determined, in the 2016 NSPS OOOOa 
rule, both that it had a rational basis to regulate methane emissions 
from the source category, and, in the alternative, that methane 
emissions from the Crude Oil and Natural Gas Source Category, 
contribute significantly to dangerous air pollution. 81 FR 35842-43, 
(June 3, 2016). The EPA is not reopening those determinations for 
comment in the present rulemaking.
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    \161\ See preamble section III for further discussion on the 
Crude Oil and Natural Gas Emissions and Climate Change, including 
discussion of the GHGs, VOCs and SO2 Emissions on Public 
Health and Welfare.
---------------------------------------------------------------------------

    Contrary to the statements in the 2020 Policy Rule, the methane 
NSPS promulgated in the 2016 Rule cannot be said to be redundant with 
the VOC NSPS and therefore unnecessary. The large contribution of 
methane emissions from the source category to dangerous air pollution 
driving the grave and growing threat of climate change means that, in 
the agency's judgment, it would be highly irresponsible and also 
arbitrary and capricious under CAA section 307(d)(9)(A) for the EPA to 
decline to promulgate NSPS for methane emissions from the source 
category. See American Electric Power, 564 U.S. at 426-27. The fact 
that the EPA designed the methane NSPS so that sources could comply 
with them efficiently, through the same actions that the sources needed 
to take to comply with the VOC NSPS, did not thereby create redundancy. 
Further, the fact that methane NSPS but not the VOC NSPS trigger the 
regulatory requirements for existing sources makes clear that the two 
sets of requirements are not redundant. Indeed, if EPA had only 
regulated VOCs, it would only have been authorized to regulate new and 
modified sources, which comprise a small subset of polluting sources. 
By contrast, because the 2016 Rule also regulated methane, EPA was 
authorized and obligated to regulate hundreds of thousands of 
additional ``existing'' sources that comprise the vast majority of 
polluting sources. Accordingly, methane regulation was not 
``redundant'' of VOC regulation. The 2020 Policy Rule's contrary 
position was based on a misinterpretation of CAA section 111 which 
overlooked that the provision integrates requirements for new and 
existing sources. See Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433 n.48 
(D.C. Cir. 1980) (CAA section 111(b)(1)(A) listing of a source category 
is based on emissions from new and existing sources).
    The EPA also reaffirms the 2016 Rule's statutory interpretation 
that the EPA is authorized to promulgate a NSPS for an air pollutant 
under CAA section 111(b)(1)(B) in a situation in which the EPA has 
previously determined that the source category causes or contributes 
significantly to dangerous air pollution and where the EPA has a 
rational basis for regulating the particular air pollutant in question 
that is emitted by the source category. 81 FR 35842 (June 3, 2016). The 
2016 Rule noted the precedent in prior agency actions for the position 
that--following the listing of a source category--the EPA need provide 
only a rational basis for its exercise of discretion for which 
pollutants to regulate under section 111(b)(1)(B). See id. (citing 
National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) 
(court discussed, but did not review, the EPA's reasons for not 
promulgating standards for NOX, SO2, and CO from 
lime plants). In addition, the Supreme Court in American Electric Power 
provided support for the rational basis statutory interpretation. 564 
U.S. at 426-27 (``EPA [could] decline to regulate carbon-dioxide 
emissions altogether at the conclusion of its . . . [CAA section 111] 
rulemaking,'' and such a decision ``would not escape judicial review,'' 
under the ``arbitrary and capricious'' standard of section 
307(d)(9)(A)). As the House Report noted, the EPA's rational basis 
interpretation ``is fully consistent with the provision[s] of section 
111 and the section 307(d)(9) `arbitrary and capricious' standard.'' 
House Report at 9.
    The 2020 Policy Rule correctly noted that the CAA section 
111(b)(1)(B) requirement that the EPA ``shall promulgate . . . 
standards [of performance]'' for air pollutants, coupled with the CAA 
section 111(a)(1) definition for ``standard of performance'' as, in 
relevant part, a ``standard for emissions of air pollutants,'' does not 
by its terms require that EPA promulgate NSPS for every air pollutant 
from the source category. But the rule erred in seeking to graft the 
CAA section 111(b)(1)(A) requirement for a SCF into CAA section 
111(b)(1)(B). The language of CAA section 111(b)(1)(A) is clear: It 
requires the EPA Administrator to ``include a category of sources in 
[the list for regulation] if in his judgment it causes, or contributes 
to, air pollution which may reasonably be anticipated to endanger 
public health or welfare.'' (Emphasis added.) Congress thus specified 
that the required SCF is made

[[Page 63153]]

on a category basis, not a pollutant-specific basis, and that once that 
finding is made (as it was for the Crude Oil and Natural Gas source 
category in 1979), the EPA may establish standards for pollutants 
emitted by the source category. In determining for which air pollutants 
to promulgate standards of performance, the EPA must act rationally, 
which, as noted above, essentially must ensure that the action does not 
fail the ``arbitrary and capricious'' standard under CAA section 
307(d)(9)(A). The 2020 Policy Rule's objections to the rational basis 
standard on grounds that is ``vague and not guided by any statutory 
criteria,'' 85 FR 57034 (September 14, 2020), is incorrect. In making a 
rational basis determination, the EPA has considered the amount of the 
air pollutant emitted by the source category, both in absolute terms 
and by drawing comparisons, as well as the availability of control 
technologies. See National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 
(D.C. Cir. 1980) (discussing EPA's reasons for not promulgating 
standards for NOX, SO2 and CO from lime plants); 
80 FR 64510, 64530 (October 23, 2015) (rational basis determination for 
GHGs from fossil fuel-fired electricity generating power plants); 73 FR 
35838, 35859-60 (June 24, 2008) (providing reasons why the EPA was not 
promulgating GHG standards for petroleum refineries). Courts routinely 
review rules under the ``arbitrary and capricious'' standard, as noted 
in the House Report, at 11.
    When the EPA is required to make an endangerment finding, the EPA 
also affirms that that finding should be made in consideration of the 
particular facts and circumstances, not a predetermined threshold. 
Accordingly, the EPA rejects the 2020 Policy Rule's position to the 
contrary. Section 111(b)(1)(A) of the CAA does not require that the SCF 
for the source category be based on ``established criteria'' or 
``standard or threshold.'' See Coal. for Responsible Regulation, Inc. 
v. EPA, 684 F.3d 102, 122-23 (D.C. Cir. 2012) (``the inquiry [into 
whether an air pollutant endangers] necessarily entails a case-by-case, 
sliding-scale approach. . . . EPA need not establish a minimum 
threshold of risk or harm before determining whether an air pollutant 
endangers''). During the 50 years that it has made listing decisions, 
the EPA has always relied on the individual facts and circumstances. 
See Alaska Dep't of Envtl. Conservation, 540 U.S. 461, 487 (2004) 
(explaining, in a case under the CAA, ``[w]e normally accord particular 
deference to an agency interpretation of longstanding duration'' 
(internal quotation marks omitted) (citing Barnhart v. Walton, 535 U.S. 
212, 220 (2002)). This approach is appropriate because Congress 
intended that CAA section 111 apply to a wide range of source 
categories and pollutants, from wood heaters to emergency backup 
engines to petroleum refineries. In that context, it reasonable to 
interpret section 111 to allow EPA the discretion to determine how best 
to assess significant contribution and endangerment based on the 
individual circumstances of each source category. On this point, as 
well, the EPA is in full agreement with the statements in the House 
Report. House Report at 9-10.
    Finally, under CAA section 111(d)(1), once the EPA promulgates NSPS 
for certain air pollutants, including GHGs, the EPA is required to 
promulgate regulations, which the EPA terms EG, 40 CFR 60.22a, that in 
turn require States to promulgate standards of performance for existing 
sources of those air pollutants. The EPA agrees with the House Report 
and Senate statement that it is imperative to regulate methane 
emissions from the existing oil and gas sources that comprise the vast 
majority of polluting sources expeditiously under the authority of CAA 
section 111(d) and is proceeding with the process to do so in this 
rulemaking by publishing proposed EG. See section III.B.2. In 2019, the 
GHGI estimates for oil and natural gas production, and natural gas 
processing and transmission and storage segments that methane emissions 
equate to 182 MMT CO2 Eq.\162\ In the U.S. the EPA has 
identified over 15,000 oil and gas owners and operators, around 1 
million producing onshore oil and gas wells, about 5,000 gathering and 
boosting facilities, over 650 natural gas processing facilities, and 
about 1,400 transmission compression facilities.
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    \162\ The 100-year GWP value of 25 for methane indicates that 
one ton of methane has approximately as much climate impact over a 
100-year period as 25 tons of CO2. The most recent IPCC 
AR6 assessment has estimated a slightly larger 100-year GWP of 
methane of almost 30 (specifically, either 27.2 or 29.8 depending on 
whether the value includes the CO2 produced by the 
oxidation of methane in the atmosphere). As mentioned earlier, 
because methane has a shorter lifetime than CO2, the 
emissions of a ton of methane will have more impact earlier in the 
100-year timespan and less impact later in the 100-year timespan 
relative to the emissions of a 100-year GWP-equivalent quantity of 
CO2. See preamble section III for further discussion on 
the Crude Oil and Natural Gas Emissions and Climate Change, 
including discussion of the GHGs, VOCs and SO2 Emissions 
on Public Health and Welfare.
---------------------------------------------------------------------------

    Some stakeholders have raised issues concerning the scope of 
pollutants subject to CAA section 111(d) by arguing that the exclusion 
in CAA section 111(d) for HAP covers not only those pollutants listed 
for regulation under CAA section 112, but also precludes the EPA from 
regulating a source category under CAA section 111(d) for any pollutant 
if that source category has been regulated under CAA section 112. The 
EPA agrees with its longstanding legal interpretation spanning multiple 
Administrations that the 111(d) exclusion does not preclude the agency 
from regulating a non-HAP pollutant from a source category under 
section 111(d) even if that source category is regulated under section 
112. See American Lung Ass'n v. EPA, 980 F.3d 914, 980 (D.C. Cir. 2019) 
(referring to ``EPA's three-decade-old . . . reading of the statutory 
amendments''), petition for cert. pending No. 20-1530 (filed April 29, 
2021); 70 FR 15994, 16029 (March 29, 2005) (Clean Air Mercury Rule); 80 
FR 64662, 64710 (Oct. 23, 2015) (Clean Power Plan); 84 FR 32520 (July 
8, 2019) (Affordable Clean Energy Rule). The House Report agreed with 
this interpretation, noting that the contrary position is flawed 
because it ignores the overall statutory structure that Congress 
created in the CAA and would create regulatory gaps in which the EPA 
would not be able to regulate existing sources for some pollutants 
(such as methane) under CAA section 111(d) if those sources (but not 
pollutants) were already regulated for different pollutants under CAA 
section 112. House Report at 11-12. Moreover, the D.C. Circuit recently 
considered this precise issue and held that the EPA may both regulate a 
source category for HAP under CAA section 112 and regulate that same 
source category for different pollutants under CAA section 111(d). Am. 
Lung Assoc., 985 F.3d at 977-988. Accordingly, both Congress and the 
court have come to the same conclusion after reviewing the statutory 
language, a conclusion that is aligned with the EPA's longstanding 
position. We therefore proceed in the proposal to propose EGs for 
existing sources in the oil and gas source category.

IX. Overview of Control and Control Costs

A. Control of Methane and VOC Emissions in the Crude Oil and Natural 
Gas Source Category--Overview

    As described in this action, the EPA reviewed the standards in the 
2016 NSPS OOOOa pursuant to CAA section 111(b)(1)(B). Based on this 
review, the EPA is proposing revisions to the standards for a number of 
affected facilities to reflect the updated BSER for those affected 
facilities. Where our analyses show that the BSER for an

[[Page 63154]]

affected facility remains the same, the EPA is proposing to retain the 
current standard for that affected facility. In addition to the actions 
on the standards in the 2016 NSPS OOOOa described in this section, the 
EPA is proposing standards for GHGs (in the form of limitation on 
methane) and VOCs for a number of new sources that are currently 
unregulated. The proposed NSPS OOOOb would apply to new, modified, and 
reconstructed emission sources across the Crude Oil and Natural Gas 
source category for which construction, reconstruction, or modification 
is commenced after November 15, 2021.
    Further, pursuant to CAA section 111(d), the EPA is proposing EG, 
which include presumptive standards for GHGs (in the form of 
limitations on methane) (designated pollutant), for certain existing 
emission sources across the Crude Oil and Natural Gas source category 
in the proposed EG OOOOc. While the proposed requirements in NSPS OOOOb 
would apply directly to new sources, the proposed requirements in EG 
OOOOc are for States to use in the development of plans that establish 
standards of performance that will apply to existing sources 
(designated facilities).

B. How does EPA evaluate control costs in this action?

    Section 111 of the CAA requires that the EPA consider a number of 
factors, including cost, in determining ``the best system of emission 
reduction . . . adequately demonstrated.'' CAA section 111(a)(1). The 
D.C. Circuit has long recognized that ``[CAA] section 111 does not set 
forth the weight that [ ] should [be] assigned to each of these 
factors;'' therefore, ``[the court has] granted the agency a great 
degree of discretion in balancing them.'' Lignite Energy Council v. 
EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) (``Lignite Energy Council''). 
In Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973) 
(``Essex Chemical''), the court noted that ``it is not unlikely that 
the industry and the EPA will disagree on the economic costs of various 
control techniques'' and that it ``has no desire or special ability to 
settle such a dispute.'' Id. at 437. Rather, the court focused its 
review on ``whether the standards as set are the result of reasoned 
decision-making.'' Id. at 434. A standard that ``is the result of the 
exercise of reasoned discretion by the Administrator [ ] cannot be 
upset by this Court.'' Id. at 437.
    As noted, CAA section 111 requires that the EPA consider cost in 
determining such system (i.e., ``BSER''), but it does not prescribe any 
criteria for such consideration. The courts have recognized that the 
EPA has ``considerable discretion under [CAA] section 111,'' Lignite 
Energy Council, 198 F.3d at 933, on how it considers cost under CAA 
section 111(a)(1). For example, in Essex Chemical, the D.C. Circuit 
stated that to be ``adequately demonstrated,'' the system must be 
``reasonably reliable, reasonably efficient, and . . . reasonably 
expected to serve the interests of pollution control without becoming 
exorbitantly costly in an economic or environmental way.'' 486 F.2d at 
433. The court has reiterated this limit in subsequent case law, 
including Lignite Energy Council, in which it stated: ``EPA's choice 
will be sustained unless the environmental or economic costs of using 
the technology are exorbitant.'' 198 F.3d at 933. In Portland Cement 
Association v. Train, the court elaborated by explaining that the 
inquiry is whether the costs of the standard are ``greater than the 
industry could bear and survive.'' \163\ 513 F.2d 506, 508 (D.C. Cir. 
1975). In Sierra Club v. Costle, the court provided a substantially 
similar formulation of the cost factor: ``EPA concluded that the 
Electric Utilities' forecasted cost was not excessive and did not make 
the cost of compliance with the standard unreasonable. This is a 
judgment call with which we are not inclined to quarrel.'' 657 F.2d 
298, 343 (D.C. Cir. 1981). We believe that these various formulations 
of the cost factor--``exorbitant,'' ``greater than the industry could 
bear and survive,'' ``excessive,'' and ``unreasonable''--are 
synonymous; the D.C. Circuit has made no attempt to distinguish among 
them. For convenience, in this rulemaking, we will use the term 
``reasonable'' to describe that our evaluation of costs is well within 
the boundaries established by this case law.
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    \163\ The 1970 Senate Committee Report on the Clean Air Act 
stated: ``The implicit consideration of economic factors in 
determining whether technology is `available' should not affect the 
usefulness of this section. The overriding purpose of this section 
would be to prevent new air pollution problems, and toward that end, 
maximum feasible control of new sources at the time of their 
construction is seen by the committee as the most effective and, in 
the long run, the least expensive approach.'' S. Comm. Rep. No. 91-
1196 at 16.
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    In evaluating whether the cost of a control is reasonable, the EPA 
considers various costs associated with such control, including capital 
costs and operating costs, and the emission reductions that the control 
can achieve. As discussed further below, the agency considers these 
costs in the context of the industry's overall capital expenditures and 
revenues. Cost-effectiveness analysis is also a useful metric, and a 
means of evaluating whether a given control achieves emission reduction 
at a reasonable cost. A cost-effectiveness analysis also allows 
comparisons of relative costs and outcomes (effects) of two or more 
options. In general, cost-effectiveness is a measure of the outcomes 
produced by resources spent. In the context of air pollution control 
options, cost-effectiveness typically refers to the annualized cost of 
implementing an air pollution control option divided by the amount of 
pollutant reductions realized annually. A cost-effectiveness analysis 
is not intended to constitute or approximate a benefit-cost analysis in 
which monetized benefits are compared to costs, but rather provides a 
metric to compare the relative cost and emissions impacts of various 
control options.
    The estimation and interpretation of cost-effectiveness values is 
relatively straightforward when an abatement measure is implemented for 
the purpose of controlling a single pollutant, such as for the controls 
included as presumptive standards in the proposed EG OOOOc to address 
methane emissions from existing sources in the Crude Oil and Natural 
Gas source category. In other circumstances, air pollution reduction 
programs require reductions in emissions of multiple pollutants, as 
with the NSPS for the Crude Oil and Natural Gas source category, which 
regulates both GHG and VOC. In such cases, multipollutant controls 
(controls that achieve reductions of both pollutants through the same 
techniques and technologies) may be employed, and consequently, there 
is a need for determining cost-effectiveness for a control option 
across multiple pollutants (or classes of multiple pollutants).
    During the rulemaking for NSPS OOOOa, we evaluated a number of 
approaches for considering the cost-effectiveness of the available 
multipollutant controls for reducing both methane and VOC emissions. 
See 80 FR 56593, 56616 (September 18, 2015). In that rulemaking, we 
used two approaches for considering the cost-effectiveness of control 
options that reduce both VOC and methane emissions; we are proposing to 
use these same two cost-effectiveness approaches, along with other 
factors discussed further below, in considering the cost of requiring 
control for the proposed NSPS OOOOb. One approach, which we refer to as 
the ``single pollutant cost-effectiveness approach,'' assigns all costs 
to the emission reduction of one pollutant and zero to all other 
concurrent reductions. If the cost is reasonable for reducing any of 
the

[[Page 63155]]

targeted pollutants alone, the cost of such control is clearly 
reasonable for the concurrent emission reduction of all the other 
regulated pollutants because they are being reduced at no additional 
cost. While this approach assigns all costs to only a portion of the 
emission reduction and thus may overstate the cost for that assigned 
portion, it does not overstate the overall cost. Instead, it 
acknowledges that the reductions of the other regulated pollutant are 
intended as opposed to incidental. This approach is simple and 
straightforward in application: If the multipollutant control is cost 
effective for reducing emissions of either of the targeted pollutants, 
it is clearly cost effective for reducing all other targeted emissions 
that are being achieved simultaneously.
    A second approach, which we term for the purpose of this rulemaking 
a ``multipollutant cost-effectiveness approach,'' apportions the 
annualized cost across the pollutant reductions addressed by the 
control option in proportion to the relative percentage reduction of 
each pollutant controlled. In the case of the Crude Oil and Natural Gas 
source category, both methane and VOC are reduced in equal proportions, 
relative to their respective baselines by the multipollutant control 
option (i.e., where control is 95 percent reduction, methane and VOC 
are both simultaneously reduced by 95 percent by the multipollutant 
control). As a result, under the multipollutant cost-effectiveness 
approach, half of the control costs are allocated to methane and the 
other half to VOC. Under this approach, control is cost effective if it 
is cost effective for both VOC and methane.
    We believe that both the single pollutant and multipollutant cost-
effectiveness approaches discussed above are appropriate for assessing 
the reasonableness of the multipollutant controls considered in this 
action for new sources. As such, in the individual BSER analyses in 
section XII below, if a device is cost-effective under either of these 
two approaches, we find it to be cost-effective. The EPA has considered 
similar approaches in the past when considering multiple pollutants 
that are controlled by a given control option.\164\ The EPA recognizes, 
however, not all situations where multipollutant controls are applied 
are the same, and that other types of approaches might be appropriate 
in other instances.
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    \164\ See, e.g., 73 FR 64079-64083 and EPA Document I.D. EPA-HQ-
OAR-2004-0022-0622, EPA-HQ-OAR-2004-0022-0447, EPA-HQ-OAR- 2004-
0022-0448.
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    As mentioned above, as part of its consideration of control costs 
in the individual BSER analyses in Section XII, the EPA evaluated cost-
effectiveness using the single pollutant and multipollutant cost-
effectiveness approaches. We estimated the cost-effectiveness values of 
the proposed control options using available information, including 
various studies, information submitted in previous rulemakings from the 
affected industry, and information provided by small businesses. The 
EPA provides the cost effectiveness estimates for reducing VOC and 
methane emissions for various control options considered in section 
XII. As discussed in that section, the EPA finds cost-effectiveness 
values up to $5,540/ton of VOC reduction to be reasonable for controls 
that we have identified as BSER in this proposal. These VOC values are 
within the range of what the EPA has historically considered to 
represent cost effective controls for the reduction of VOC emissions, 
including in the 2016 NSPS, based on the Agency's long history of 
regulating a wide range of industries. With respect to methane, the EPA 
finds the cost-effectiveness values up to $1,800/ton of methane 
reduction to be reasonable for controls that we have identified as BSER 
in this proposal. Unlike VOC, the EPA does not have a long regulatory 
history to draw upon in assessing the cost effectiveness of controlling 
methane, as the 2016 NSPS OOOOa was the first national standard for 
reducing methane emissions. However, as explained below, the EPA has 
previously determined that methane cost-effectiveness values for the 
controls identified as BSER for the 2016 NSPS OOOOa, which range up to 
$2,185/ton of methane reduction, represent reasonable costs for the 
industry as a whole to bear; and because the cost-effectiveness 
estimates for the proposed standards in this action are comparable to 
the cost-effectiveness values estimated for the controls that served as 
the basis (i.e., BSER) for the standards in the 2016 NSPS OOOOa, we 
consider the proposed standards to also be cost effective and 
reasonable.
    The BSER determinations from the 2016 NSPS OOOOa also support the 
EPA's conclusion that the cost-effectiveness values associated with the 
proposed standards in this action are reasonable. As mentioned above, 
for 2016 NSPS OOOOa, the highest estimate that the EPA considered cost 
effective for methane reduction was $2,185/ton, which was the estimate 
for converting a natural gas driven diaphragm pump to an instrument air 
pump at a gas processing plant. ^{165 166} 80 FR 56627; see 
also, NSPS OOOOa Final TSD at 93, Table 6-7. The EPA estimated that the 
cost-effectiveness of this option, a common practice at gas processing 
plants, could be up to $2,185/ton of methane reduction under the single 
pollutant cost-effectiveness approach and $1,093/ton under the 
multipollutant cost effectiveness approach; the EPA found ``the control 
to be cost effective under either approach.'' Id. Accordingly, the EPA 
finalized requirements in the 2016 NSPS OOOOa that require zero 
emissions from diaphragm pumps at gas processing plants, consistent 
with the Agency's BSER determination.
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    \165\ As discussed in section X.A, the EPA incorrectly stated in 
the 2020 Technical Rule that $738/ton of methane reduction was the 
highest cost-effectiveness value that the EPA determined to be 
reasonable for methane reduction in the 2016 NSPS OOOOa.
    \166\ While in that rulemaking the EPA found quarterly 
monitoring of fugitive emissions at well sites not cost effective at 
$1,960/ton of methane reduced using the single pollutant approach 
(and $980 using the multi-pollutant approach), the EPA emphasized 
that this conclusion was not intended to ``preclude the EPA from 
taking a different approach in the future including requiring more 
frequent monitoring (e.g., quarterly).'' 81 FR 35855-6 referencing 
Background Technical Support Document for the New Source Performance 
Standards 40 CFR part 60 subpart OOOOa (May 2016), at 49, Table 4-11 
and 52, Table 4-14. Further, several states have issued regulations 
and industry has voluntarily taken steps to reduce emissions. This 
combined with greater knowledge and understanding of the industry 
leads us to find these values cost-effective. As discussed in this 
section IX.B, cost-effectiveness is one--not the only--factor in 
EPA's consideration of control costs. In fact, in this action, the 
EPA is proposing different monitoring frequencies based on well site 
baseline emissions, even though the EPA found quarterly monitoring 
to be cost effective for all well sites. Please see section XII.A 
for a detailed discussion on this proposal.
---------------------------------------------------------------------------

    The 2016 NSPS OOOOa also requires 95 percent methane and VOC 
emission reduction from wet-seal centrifugal compressors. The BSER for 
this standard was capturing and routing the emissions to a control 
combustion device, a widely used control in the oil and gas sector for 
reducing emissions from storage vessels and pumps, in addition to 
centrifugal compressors. 80 FR 56620. The EPA estimated cost-
effectiveness values of up to $1,093/ton of methane reduction for this 
option. See NSPS OOOOa Final TSD at 114, Table 7-9. With respect to 
other controls identified as BSER in the 2016 NSPS OOOOa, their cost-
effectiveness estimates were comparable to or well below the estimates 
from the 2016 NSPS OOOOa rulemaking discussed above. In light of this, 
and because sources have been complying with the 2016 NSPS OOOOa for 
years, we believe that the cost-effectiveness values for the controls

[[Page 63156]]

identified as BSER for the 2016 NSPS OOOOa, which range up to $2,185/
ton of methane reduction, represent reasonable, rather than excessive, 
costs for the industry as a whole to bear. As shown in the individual 
BSER analyses in Section XII and the NSPS OOOOb and EG OOOOc TSD for 
this proposal, the cost-effectiveness values for the proposed standards 
in this action are comparable to the cost-effectiveness values for the 
standards in NSPS OOOOa. We, therefore, similarly consider the cost-
effectiveness values for the proposed standards to be reasonable. That 
the proposed standards reflect the kinds of controls that many 
companies and sources around the country are already implementing 
underscore the reasonableness of these control measures.
    In addition to evaluating the annual average cost-effectiveness of 
a control option, the EPA also considers the incremental costs 
associated with increasing the stringency of the standards from one 
level of control to another level of control that achieves more 
emission reductions. The incremental cost of control provides insight 
into how much it costs to achieve the next increment of emission 
reductions through application of each increasingly stringent control 
options, and thus is a useful tool for distinguishing among the effects 
of more and less stringent control options. For example, during the 
rulemaking for the 2012 NSPS OOOO, the EPA considered the incremental 
cost effectiveness of changing the originally promulgated standards for 
leaks at gas processing plants, which were based on NSPS subpart VV, to 
the more stringent NSPS subpart VVa-level program. See 76 FR 52738, 
52755 (August 23, 2011). The EPA generally finds the incremental cost-
effectiveness to be reasonable if it is consistent with the costs that 
the Agency considers reasonable in its evaluation of annual average 
cost-effectiveness.
    As shown in the NSPS OOOOb and EG OOOOc TSD for this action, the 
EPA estimated control costs both with and without savings from 
recovered gas that would otherwise be emitted. When determining the 
overall costs of implementation of the control technology and the 
associated cost-effectiveness, the EPA reasonably takes into account 
any expected revenues from the sale of natural gas product that would 
be realized as a result of avoided emissions that result from 
implementation of a control. Such a sale would offset regulatory costs 
and so should be included to accurately assess the overall costs and 
the cost-effectiveness of the standard. In our analysis we consider any 
natural gas that is either recovered or that is not emitted as a result 
of a control option as being ``saved.'' We estimate that one thousand 
standard cubic feet (Mcf) of natural gas is valued at $3.13 per 
Mcf.\167\ Our cost analysis then applies the monetary value of the 
saved natural gas as an offset to the control cost.\168\ This offset 
applies where, in our estimation, the monetary savings of the natural 
gas saved can be realized by the affected facility owner or operator 
and not where the owner or operator does not own the gas and would not 
likely realize the monetary value of the natural gas saved (e.g., 
transmission stations and storage facilities). Detailed discussions of 
these assumptions are presented in section 2 of the RIA associated with 
this action, which is in the docket.
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    \167\ This value reflects the forecasted Henry Hub price for 
2022 from: U.S. Energy Information Administration. Short-Term Energy 
Outlook. https://www.eia.gov/outlooks/steo/archives/may21.pdf. 
Release Date: May 11, 2021.
    \168\ While the EPA presents cost-effectiveness with and without 
cost savings, the BSER is determined based on the cost-effectiveness 
without cost savings in all cases.
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    We also completed two additional analyses to further inform our 
determination of whether the cost of control is reasonable, similar to 
compliance cost analyses we have completed for other NSPS.\169\ First, 
we compared the capital costs that would be incurred to comply with the 
proposed standards to the industry's estimated new annual capital 
expenditures. This analysis allowed us to compare the capital costs 
that would be incurred to comply with the proposed standards to the 
level of new capital expenditures that the industry is incurring in the 
absence of the proposed standards. We then determined whether the 
capital costs appear reasonable in comparison to the industry's current 
level of capital spending. Second, we compared the annualized costs 
that would be incurred to comply with the standards to the industry's 
estimated annual revenues. This analysis allowed us to evaluate the 
annualized costs as a percentage of the revenues being generated by the 
industry.
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    \169\ For example, see our compliance cost analysis in 
``Regulatory Impact Analysis (RIA) for Residential Wood Heaters NSPS 
Revision. Final Report.'' U.S. Environmental Protection Agency, 
Office of Air Quality Planning and Standards. EPA-452/R-15-001, 
February 2015.
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    The EPA has evaluated incremental capital costs in a manner similar 
to the analyses described above in prior new source performance 
standards, and in those prior standards, the Agency's determinations 
that the costs were reasonable were upheld by the courts. For example, 
the EPA estimated that the costs for the 1971 NSPS for coal-fired 
electric utility generating units were $19 million for a 600 MW plant, 
consisting of $3.6 million for particulate matter controls, $14.4 
million for sulfur dioxide controls, and $1 million for nitrogen oxides 
controls, representing a total 15.8 percent increase in capital costs 
above the $120 million cost of the plant.\170\ See 1972 Supplemental 
Statement, 37 FR 5767, 5769 (March 21, 1972). The D.C. Circuit upheld 
the EPA's determination that the costs associated with the final 1971 
standard were reasonable, concluding that the EPA had properly taken 
costs into consideration. Essex Chemical, 486 F. 2d at 440. Similarly, 
in Portland Cement Association v. Ruckelshaus, the D.C. Circuit upheld 
the EPA's consideration of costs for a standard of performance that 
would increase capital costs by about 12 percent, although the rule was 
remanded due to an unrelated procedural issue. 486 F.2d 375, 387-88 
(D.C. Cir. 1973). Reviewing the EPA's final rule after remand, the 
court again upheld the standards and the EPA's consideration of costs, 
noting that ``[t]he industry has not shown inability to adjust itself 
in a healthy economic fashion to the end sought by the Act as 
represented by the standards prescribed.'' Portland Cement Assn. v. 
Train, 513 F. 2d at 508.
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    \170\ Assuming these costs were denominated in 1971 dollars, 
converting the costs from 1971 to 2019 dollars using the Gross 
Domestic Product-Implicit Price Deflator, the costs for the 1971 
NSPS for coal-fired electric utility generating units were $94 
million for a 600 MW plant, consisting of $18 million for 
particulate matter controls, $71 million for sulfur dioxide 
controls, and $5 million for nitrogen oxides controls, representing 
a 15.8 percent increase in capital costs above the $590 million cost 
of the plant.
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    In this action, for the capital expenditures analysis, we divide 
the nationwide capital expenditures projected to be spent to comply 
with the proposed standards by an estimate of the total sector-level 
new capital expenditures for a representative year to determine the 
percentage that the nationwide capital cost requirements under the 
proposal represent of the total capital expenditures by the sector. We 
combine the compliance-related capital costs under the proposed 
standards for the NSPS and for the presumptive standards in the 
proposed EG to analyze the potential aggregate impact of the proposal. 
The EAV of the projected compliance-related capital expenditures over 
the 2023 to 2035 period is projected to be about $510 million in 2019 
dollars. We obtained new capital

[[Page 63157]]

expenditure data for relevant NAICS codes for 2018 from the U.S. Census 
2019 Annual Capital Expenditures Survey.\171\ Estimates of new capital 
expenditures are available for 2019, but we chose to use 2018 because 
the 2019 new capital expenditure data for pipeline transportation of 
natural gas (NAICS 4862) are withheld to avoid disclosing data for 
individual enterprises, and the withholding of that NAICS causes the 
totals for 2019 to be lower than for 2018. According to these data, new 
capital expenditures for the sector in 2018 were about $155 billion in 
2019 dollars. Comparing the EAV of the projected compliance-related 
capital expenditures under the proposal with the 2018 total sector-
level new capital expenditures yields a percentage of about 0.3 
percent, which is well below the percentage increase previously upheld 
by the courts, as discussed above.
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    \171\ U.S. Census Bureau, 2019 Annual Capital Expenditures 
Survey, Table 4b. Capital Expenditures for Structures and Equipment 
for Companies With Employees by Industry: 2018 Revised, https://www.census.gov/econ/aces/, accessed September 4, 2021.
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    For the comparison of compliance costs to revenues, we use the EAV 
of the projected compliance costs without and with projected revenues 
from product recovery under the proposal for the 2023 to 2035 period 
then divided the nationwide annualized costs by the annual revenues for 
the appropriate NAICS code(s) for a representative year to determine 
the percentage that the nationwide annualized costs represent of annual 
revenues. Like we do for capital expenditures, we combine the costs 
projected to be expended to comply with the standards for NSPS and the 
presumptive standards in the proposed EG to analyze the potential 
aggregate impact of the proposal. The EAV of the associated increase in 
compliance cost over the 2023 to 2035 period is projected to be about 
$1.2 billion without revenues from product recovery and about $760 
million with revenues from product recovery (in 2019 dollars). Revenue 
data for relevant NAICS codes were obtained from the U.S. Census 2017 
County Business Patterns and Economic Census, the most recent revenue 
figures available.\172\ According to these data, 2018 receipts for the 
sector were about $358 billion in 2019 dollars. Comparing the EAV of 
the projected compliance costs under the proposal with the sector-level 
receipts figure yields a percentage of about 0.3 percent without 
revenues from product recovery and about 0.2 percent with revenues from 
product recovery. More data and analysis supporting the comparison of 
capital expenditures and annualized costs projected to be incurred 
under the rule and the sector-level capital expenditures and receipts 
is presented in Chapter 15 of the TSD for this action, which is in the 
public docket.
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    \172\ 2017 County Business Patterns and Economic Census. The 
Number of Firms and Establishments, Employment, Annual Payroll, and 
Receipts by Industry and Enterprise Receipts Size: 2017, https://www.census.gov/programs-surveys/susb/data/tables.2017.html, accessed 
September 4. 2021.
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    In considering the costs of the control options evaluated in this 
action, the EPA estimated the control costs under various approaches, 
including annual average cost-effectiveness and incremental cost-
effectiveness of a given control. The EPA also performed two broad 
comparisons to consider the costs of control: First, we compared the 
projected compliance-related capital expenditures to recent sector-
level capital expenditures; second, we compared the projected total 
compliance costs to recent sector-level annual revenues. In its cost-
effectiveness analyses, the EPA recognized and took into account that 
these multi-pollutant controls reduce both VOC and methane emissions in 
equal proportions, as reflected in the single-pollutant and 
multipollutant cost effectiveness approaches. The EPA also considered 
cost saving from the natural gas recovered instead of vented due to the 
proposed controls. Based on all of the considerations described above, 
the EPA concludes that the costs of the controls that serve as the 
basis of the standards proposed in this action are reasonable. The EPA 
solicits comment on its approaches for considering control costs, as 
well as the resulting analyses and conclusions.

X. Summary of Proposed Action for NSPS OOOOa

    As described above in sections IV and VIII, the 2020 Policy Rule 
rescinded all NSPS regulating emissions of VOC and methane from sources 
in the natural gas transmission and storage segment of the Oil and 
Natural Gas Industry and NSPS regulating methane from sources in the 
industry's production and processing segments. As a result, the 2020 
Technical Rule only amended the VOC standards for the production and 
processing segments in the 2016 NSPS OOOOa, because those were the only 
standards that remained at the time that the 2020 Technical Rule was 
finalized. The 2020 Technical Rule included amendments to address a 
range of technical and implementation issues in response to 
administrative petitions for reconsideration and other issues brought 
to the EPA's attention since promulgating the 2016 NSPS. These 
included, among other issues, those associated with the implementation 
of the fugitive emissions requirements and pneumatic pump standards, 
provisions to apply for the use of an AMEL, provisions for determining 
applicability of the storage vessel standards, and modification to the 
engineer certifications. In 2018, the EPA proposed amendments to 
address these technical issues for both the methane and VOC standards 
in the 2016 NSPS OOOOa, and in some instances for sources in the 
transmission and storage segment. 83 FR 52056, October 15, 2018. 
However, because the methane standards and all standards for the 
transmission and storage segment were removed via the 2020 Policy Rule 
prior to the finalization of the 2020 Technical Rule, the final 
amendments in the 2020 Technical Rule apply only to the 2016 NSPS OOOOa 
VOC standards for the production and processing segments. Additionally, 
the 2020 Policy Rule amended the 2012 NSPS OOOO to remove the VOC 
requirements for sources in the transmission and storage segment, but 
the Technical Rule did not amend the 2012 NSPS OOOO.
    Under the CRA, a rule that is subject to a joint resolution of 
disapproval ``shall be treated as though such rule had never taken 
effect.'' 5 U.S.C. 801(f)(2). Thus, because it was disapproved under 
the CRA, the 2020 Policy Rule is treated as never having taken effect. 
As a result, the requirements in the 2012 NSPS OOOO and 2016 NSPS OOOOa 
that the 2020 Policy Rule repealed (i.e., the VOC and methane standards 
for the transmission and storage segment, as well as the methane 
standards for the production and processing segments) must be treated 
as being in effect immediately upon enactment of the joint resolution 
on June 30, 2021. Any new, reconstructed, or modified facility that 
would have been subject to the 2012 or 2016 NSPS (``affected 
facility'') but for the 2020 Policy Rule was subject to those NSPS as 
of that date. The CRA resolution did not address the 2020 Technical 
Rule; therefore, the amendments made in the 2020 Technical Rule, which 
apply only to the VOC standards for the production and processing 
segments in the 2016 NSPS OOOOa, remain in effect. As a result, sources 
in the production and processing segments are now subject to two 
different sets of standards:\173\ One

[[Page 63158]]

for methane based on the 2016 NSPS OOOOa, and one for VOC that include 
the amendments to the 2016 NSPS OOOOa made in the 2020 Technical Rule. 
Sources in the transmission and storage segment are subject to the 
methane and VOC standards as promulgated in either the 2012 NSPS OOOO 
or the 2016 NSPS OOOOa, as applicable.\174\ The EPA recognizes that 
certain amendments made to the VOC standards in the 2016 NSPS OOOOa in 
the 2020 Technical Rule, which addressed technical and implementation 
issues in response to administrative petitions for reconsideration and 
other issues brought to the EPA's attention since promulgating the 2016 
NSPS OOOOa rule could also be appropriate to address similar 
implementation issues associated with the methane standards for the 
production and processing segments and the methane and VOC standards 
for the transmission and storage segment. In fact, as mentioned above, 
such revisions were proposed in 2018 but not finalized because these 
standards were removed by the 2020 Policy Rule prior to the EPA's 
promulgation of the 2020 Technical Rule. In light of the above, the EPA 
is proposing to revise 40 CFR part 60, subpart OOOOa, to apply certain 
amendments made in the 2020 Technical Rule to the 2016 NSPS OOOOa for 
methane from the production and processing segments and/or the 2016 
NSPS OOOOa for methane and VOC from the transmission and storage 
segment, as specified in this section.
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    \173\ The only exception is storage vessels, for which the EPA 
did not promulgate methane standards in the 2016 NSPS OOOOa.
    \174\ For the EPA's full explanation of its initial guidance to 
stakeholders on the impact of the CRA, please see https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf.
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    In this action, the EPA is proposing amendments to the 2016 NSPS 
OOOOa to (1) rescind the revisions to the VOC fugitive emissions 
monitoring frequencies at well sites and gathering and boosting 
compressor stations in the 2020 Technical Rule as those revisions were 
not supported by the record for that rule, or by our subsequent 
information and analysis, and (2) adjust other modifications made in 
the 2020 Technical Rule to address technical and implementation issues 
that result from the CRA disapproval of the 2020 Policy Rule. The EPA 
is not reopening any of these prior rulemakings for any other purpose 
in this proposed action. Specifically, the EPA is not reopening any of 
the determinations made in the 2012 NSPS OOOO. In the final rule for 
this action, the EPA will update the NSPS OOOO and NSPS OOOOa 
regulatory text in the CFR to reflect the CRA resolution's disapproval 
of the final 2020 Policy Rule, specifically, the reinstatement of the 
NSPS OOOO and NSPS OOOOa requirements that the 2020 Policy Rule 
repealed but that came back into effect immediately upon enactment of 
the CRA resolution. In accordance with 5 U.S.C. 553(b)(3)(B), the EPA 
is not soliciting comment on these updates. Moreover, the EPA is not 
reopening the methane standards as finalized in the 2016 NSPS OOOOa, 
except as to the specific issues discussed below, nor is the EPA 
reopening any other portions of the 2016 Rule. The EPA is also not 
reopening any determinations made in the 2020 Technical Rule, except as 
to the specific issues discussed below. Finally, the reopening of 
determinations made with respect to the VOC standards in the 2020 
Technical Rule does not indicate any intent to also reopen the methane 
standards for the same affected facilities.

A. Amendments to Fugitive Emissions Monitoring Frequency

    The EPA is proposing to repeal its amendments in the 2020 Technical 
Rule that (1) exempted low production well sites from monitoring 
fugitive emissions and (2) changed from quarterly to semiannual 
monitoring of VOC emissions at gathering and boosting compressor 
stations. The EPA has authority to reconsider a prior action ``as long 
as `the new policy is permissible under the statute. . . , there are 
good reasons for it, and . . . the agency believes it to be better.' '' 
FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515, 129 S. Ct. 
1800, 173 L. Ed. 2d738 (2009).
    The 2016 NSPS OOOOa, as initially promulgated, required semiannual 
monitoring of VOC and methane emissions at all well sites, including 
low production well sites. It also required quarterly monitoring of 
compressor stations, including gathering and boosting compressor 
stations. After issuing the 2020 Policy Rule, which removed all methane 
standards applicable to the production and processing segments and all 
methane and VOC standards applicable to the transmission and storage 
segment, the EPA promulgated the 2020 Technical Rule that further 
amended the VOC standards in the production and processing segment. In 
particular, based on its revised cost analyses, the EPA exempted low 
production well sites from monitoring VOC fugitive emissions and 
changed the frequency of monitoring VOC fugitive emissions from 
quarterly to semiannually at gathering and boosting compressor 
stations. However, as a result of the CRA disapproval of the 2020 
Policy Rule, the low production well sites and the gathering and 
boosting compressor stations continue to be subject to semiannual and 
quarterly monitoring of methane emissions respectively. While it is 
possible for these affected facilities to comply with both the VOC and 
methane monitoring standards that are now in effect, as compliance with 
the more stringent standard would be deemed compliance with the other, 
the EPA reviewed its decisions to amend the VOC monitoring frequencies 
for these affected facilities as well as the underlying record and, for 
the reasons explained below, no longer believe that the amendments are 
appropriate. Therefore, the EPA is proposing to repeal these amendments 
and restore the semiannual and quarterly monitoring requirements for 
low production well sites and gathering and boosting compressor 
stations, as originally promulgated in the 2016 NSPS OOOOa, for both 
methane and VOC.
1. Low Production Well Sites
    As mentioned above, low production well sites are subject to 
semiannual monitoring of fugitive methane emissions. The EPA is 
proposing to repeal the amendment in the 2020 Technical Rule exempting 
low production well sites from monitoring fugitive VOC emissions 
because the analysis for the 2020 Technical Rule supports retaining the 
semiannual monitoring requirement when regulating both VOC and methane 
emissions. While the 2020 Technical Rule amended only the VOC standards 
in the production and processing segments, the EPA evaluated both 
methane and VOC reductions in its final technical support document 
(TSD) (2020 TSD), including the costs associated with different 
monitoring frequencies under the multipollutant approach,\175\ which 
the EPA considers a reasonable approach when regulating multiple 
pollutants. As shown in the 2020 TSD, under the multipollutant 
approach, the cost of semiannual monitoring at low production well 
sites is $850 per ton of methane and $3,058 per ton of VOC reduced, 
both of which are well within the range of what the

[[Page 63159]]

EPA considers to be cost effective.\176\ Nevertheless, the EPA stated 
in the 2020 Technical Rule that ``even if we had not rescinded the 
methane standards in the 2020 Policy Rule, we would still conclude that 
fugitive emissions monitoring, at any of the frequencies evaluated, is 
not cost effective for low production well sites.'' This statement, 
however, is inconsistent with the conclusions on what costs are 
reasonable for the control of methane emissions as discussed in this 
proposal in section IX. More importantly, as an initial matter, this 
statement was based on the EPA's observation in the 2020 Technical Rule 
that the $850 per ton of methane reduced is ``greater than the highest 
value for methane that the EPA determined to be reasonable in the 2016 
NSPS subpart OOOOa,'' which the EPA incorrectly identified as $738/ton; 
the record for the 2016 NSPS OOOOa shows that the EPA considered value 
as high as $2,185/ton to be cost effective for methane reduction. 80 FR 
56627; see also, NSPS OOOOa Final TSD at 93, Table 6-7. Further, even 
with the incorrect observation, the EPA did not conclude in the 2020 
Technical Rule that $850 per ton of methane reduced is therefore 
unreasonable. 85 FR 57420. In fact, the EPA reiterated its prior 
determination that ``a cost of control of $738 per ton of methane 
reduced did not appear excessive,'' and that value was only $112 less 
than the value that the EPA had incorrectly identified as the highest 
methane cost-effectiveness value from the 2016 NSPS OOOOa. As discussed 
above, in fact $738/ton is well within the costs that the EPA concludes 
to be reasonable in the 2016 NSPS OOOOa as well as in this document. 
Also, as explained in section XI.A.2, due to the wide variation in well 
characteristics, types of oil and gas products and production levels, 
gas composition, and types of equipment at well sites, there is 
considerable uncertainty regarding the relationship between the 
fugitive emissions and production levels. Accordingly, the EPA no 
longer believes that production levels provide an appropriate threshold 
for any exemption from fugitive monitoring. See section XI.A.2 for 
additional discussion on the proposed emission thresholds for well site 
fugitive emissions in place of production-based model plants. In light 
of the above, the EPA is proposing to remove the exemption of low 
production well sites from fugitive VOC emissions monitoring, thereby 
restoring the semiannual monitoring requirement established in the 2016 
NSPS OOOOa.
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    \175\ For purposes of the multipollutant approach, we assume 
that emissions of methane and VOC are controlled at the same time, 
therefore, half of the cost is apportioned to the methane emission 
reductions and half of the cost is apportioned to VOC emission 
reductions.
    \176\ See 2020 NSPS OOOOa Technical Rule TSD at Docket ID No. 
EPA-HQ-OAR-2017-0483-2291. See also section IX, which provides that 
the cost effectiveness values for the controls that we have 
identified as BSER in this action range from $2,200/ton to $5,800/
ton VOC reduction and $700/ton to $2,100/ton of methane reduction. 
As explained in that section, these controls reflect emission 
reduction technologies and methods that many owners and operators in 
the oil and gas industry have employed for years, either voluntarily 
or due to the 2012 and 2016 NSPS, as well as State or other 
requirements.
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2. Gathering and Boosting Compressor Stations
    The EPA is proposing to repeal its amendment to the VOC monitoring 
frequency for gathering and boosting compressor stations in the 2020 
Technical Rule because the EPA believes that amendment was made in 
error. In that rule, the EPA noted that, based on its revised cost 
analysis, quarterly monitoring has a cost effectiveness of $3,221/ton 
of VOC emissions and an incremental cost of $4,988/ton of additional 
VOC emissions reduced between the semiannual and quarterly monitoring 
frequencies. While the EPA observed that semiannual monitoring is more 
cost effective than quarterly, the EPA nevertheless acknowledged that 
``these values (total and incremental) are considered cost-effective 
for VOC reduction based on past EPA decisions, including the 2016 
rulemaking.'' 85 FR 57421, September 15, 2020. The EPA instead 
identified two additional factors to support its decision to forgo 
quarterly monitoring. First, the EPA stated that the ``Oil and Gas 
Industry is currently experiencing significant financial hardship that 
may weigh against the appropriateness of imposing the additional costs 
associated with more frequent monitoring.'' However, the EPA did not 
offer any data regarding the financial hardship, significant or 
otherwise, the industry was experiencing. While the rule cited to 
several articles on the impact of COVID-19 on the industry, the EPA did 
not discuss any aspect of any of the cited articles that led to its 
conclusion of ``significant financial hardship'' on the industry. Nor 
did the EPA explain how reducing the frequency of a monitoring 
requirement that had been in effect since 2016 would meaningfully 
affect the industry's economic circumstances in any way or weigh those 
considerations against the forgone emission reductions that would 
result from reducing monitoring frequency.
    Second, the EPA generally asserted that ``there are potential 
efficiencies, and potential cost savings, with applying the same 
monitoring frequencies for well sites and compressor stations.'' Again, 
the EPA did not describe what the potential efficiencies are or the 
extent of cost savings that would justify forgoing quarterly 
monitoring, or weigh those efficiencies and cost savings against the 
forgone emission reductions that would result from reducing the 
monitoring frequency for compressor stations. Nor did we explain why 
the Agency's 2016 BSER determination that quarterly monitoring was 
achievable and cost-effective was incorrect in light of these asserted 
efficiencies. On the contrary, based on the compliance records for the 
2016 NSPS OOOOa, there is no indication that compressor stations 
experienced hardship or difficulty in complying with the quarterly 
monitoring requirement. Further, as discussed in section XII.A.1.b, our 
analysis for NSPS OOOOb and EG OOOOc confirms that quarterly monitoring 
remains both achievable and cost-effective for compressor stations, and 
several State agencies also have rules that require quarterly 
monitoring at compressor stations. For the reasons stated above, the 
EPA concludes that it lacked justification and thus erred in revising 
the VOC monitoring frequency for gathering and boosting compressor 
stations from quarterly to semiannual. The EPA is therefore proposing 
to repeal that amendment, thereby restoring the quarterly monitoring 
requirement for gathering and boosting compressor stations, as 
established in the 2016 NSPS OOOOa.

B. Technical and Implementation Amendments

    In the following sections, the EPA describes a series of proposed 
amendments to 2016 NSPS OOOOa for methane to align the 2016 methane 
standards with the current VOC standards (which were modified by the 
2020 Technical Rule). We describe the supporting rationales that were 
provided in the 2020 Technical Rule for modifying the requirements 
applicable to the VOC standards, and explain why the amendments would 
also appropriately apply to the reinstated methane standards.
1. Well Completions
    In the 2020 Technical Rule, the EPA made certain amendments to the 
VOC standards for well completions in the 2016 NSPS OOOOa. For the same 
reasons provided in the 2020 Technical Rule and reiterated below, the 
EPA is proposing to apply the same amendments to the methane standards 
for well completions in the 2016 NSPS OOOOa.
    First, the EPA is proposing to amend the 2016 NSPS OOOOa methane 
standards for well completions to allow

[[Page 63160]]

the use of a separator at a nearby centralized facility or well pad 
that services the well affected facility during flowback, as long as 
the separator can be utilized as soon as it is technically feasible for 
the separator to function. The well completion requirements, as 
promulgated in 2016, had required that the owner or operator of a well 
affected facility have a separator on site during the entire flowback 
period. 81 FR 35901, June 3, 2016. In the 2020 Technical Rule, the EPA 
amended this provision to allow the separator to be at a nearby 
centralized facility or well pad that services the well affected 
facility during flowback as long as the separator can be utilized as 
soon as it is technically feasible for the separator to function. See 
40 CFR 60.5375a(a)(1)(iii). As explained in that rulemaking (85 FR 
57403) and previously in the 2016 NSPS OOOOa final rule preamble, 
``[w]e anticipate a subcategory 1 well to be producing or near other 
producing wells. We therefore anticipate reduced emission completion 
(REC) equipment (including separators) to be onsite or nearby, or that 
any separator brought onsite or nearby can be put to use.'' 81 FR 
35852, June 3, 2016. For the same reason, the EPA is proposing to make 
the same amendment to the methane standards for well completions.
    Additionally, the 2020 Technical Rule amended 40 CFR 
60.5375a(a)(1)(i) to clarify that the separator that is required during 
the initial flowback stage may be a production separator as long as it 
is also designed to accommodate flowback. As explained in the preamble 
to the final 2020 Technical Rule, when a production separator is used 
for both well completions and production, the production separator is 
connected at the onset of the flowback and stays on after flowback and 
at the startup of production. 85 FR 57403, September 15, 2020. For the 
same reason, the EPA is proposing the same clarification apply to the 
methane standards for well completions.
    The 2020 Technical Rule also amended the definition of flowback. In 
2016, the EPA defined ``flowback'' as the process of allowing fluids 
and entrained solids to flow from a well following a treatment, either 
in preparation for a subsequent phase of treatment or in preparation 
for cleanup and returning the well to production. Flowback also means 
the fluids and entrained solids that emerge from a well during the 
flowback process. The flowback period begins when material introduced 
into the well during the treatment returns to the surface following 
hydraulic fracturing or refracturing. The flowback period ends when 
either the well is shut in and permanently disconnected from the 
flowback equipment or at the startup of production. The flowback period 
includes the initial flowback stage and the separation flowback stage. 
81 FR 35934, June 3, 2016.
    The 2020 Technical Rule amended this definition by adding a 
clarifying statement that ``[s]creenouts, coil tubing cleanouts, and 
plug drill-outs are not considered part of the flowback process.'' 40 
CFR 60.5430a. In the proposal for the 2020 Technical Rule, the EPA 
explained that screenouts, coil tubing cleanouts, and plug drill outs 
are functional processes that allow for flowback to begin; as such, 
they are not part of the flowback. 83 FR 52082, October 15, 2018. In 
conjunction with this amendment, the 2020 Technical Rule added 
definitions for screenouts, coil tubing cleanouts, and plug drill outs. 
See 40 CFR 60.5430a. Specifically, a screenout is an attempt to clear 
proppant from the wellbore in order to dislodge the proppant out of the 
well. A coil tubing cleanout is a process where an operator runs a 
string of coil tubing to the packed proppant within a well and jets the 
well to dislodge the proppant and provide sufficient lift energy to 
flow it to the surface. A plug drill-out is the removal of a plug (or 
plugs) that was used to isolate different sections of the well. For the 
reason stated above, the EPA is proposing to apply the definitions of 
flowback, screenouts, coil tubing cleanouts, and plug drill outs that 
were finalized in the 2020 Technical Rule to the methane standards for 
well completions in the 2016 NSPS OOOOa.
    Finally, the 2020 Technical Rule amended specific recordkeeping and 
reporting requirements for the VOC standards for well completions, and 
the EPA is proposing to apply these amendments to the methane standards 
for well completions in the 2016 NSPS OOOOa. For the reasons explained 
in 83 FR 52082, the 2020 Technical Rule requires that for each well 
site affected facility that routes flowback entirely through one or 
more production separators, owners and operators must record and report 
only the following data elements:
     Well Completion ID;
     Latitude and longitude of the well in decimal degrees to 
an accuracy and precision of five (5) decimals of a degree using North 
American Datum of 1983;
     U.S. Well ID;
     The date and time of the onset of flowback following 
hydraulic fracturing or refracturing or identification that the well 
immediately starts production; and
     The date and time of the startup of production.
    While the 2020 Technical Rule removed certain reporting 
requirements (e.g., information about when a separator is hooked up or 
disconnected during flowback) as unnecessary or redundant, 85 FR 57403, 
the rule added a requirement that for periods where salable gas is 
unable to be separated, owners and operators must record and report the 
date and time of onset of flowback, the duration and disposition of 
recovery, the duration of combustion and venting (if applicable), 
reasons for venting (if applicable), and deviations.
    As explained in the preamble to the proposal for the 2020 Technical 
Rule, when a production separator is used for both well completions and 
production, the production separator is connected at the onset of the 
flowback and stays on after flowback and at the startup of production; 
in that event, certain reporting and recordkeeping requirements 
associated with well completions (e.g., information about when a 
separator is hooked up or disconnected during flowback) would be 
unnecessary. 83 FR 52082. Because these amendments to the recordkeeping 
and reporting requirements associated with well completion are 
independent of the specific pollutant being regulated, we are proposing 
these same amendments to the methane standards for well completions in 
the 2016 NSPS OOOOa.
2. Pneumatic Pumps
    In the 2020 Technical Rule, the EPA made certain amendments to the 
VOC standards for pneumatic pumps in the 2016 NSPS OOOOa. For the same 
reasons provided in the 2020 Technical Rule, along with further 
explanation provided below, the EPA is proposing to apply the same 
amendments to the methane standards for pneumatic pumps in the 2016 
NSPS OOOOa.
    First, the EPA is proposing to amend the 2016 NSPS OOOOa methane 
standards for pneumatic pumps to expand the technical infeasibility 
provision to apply to pneumatic pumps at greenfield sites. Under the 
2016 NSPS OOOOa, ``emissions from new, modified, and reconstructed 
natural gas-driven diaphragm pumps located at well sites [must] be 
reduced by 95 percent if either a control device or the ability to 
route to a process is already available onsite, unless it is 
technically infeasible at sites other than new developments (i.e., 
greenfield sites).'' 81 FR 35824 and 35844. For the 2016 NSPS OOOOa, 
the EPA concluded that circumstances that could otherwise make control 
of a pneumatic pump technically infeasible

[[Page 63161]]

at an existing location could be addressed in the design and 
construction of a greenfield site. 81 FR 35849 and 35850 (June 3, 
2016). Concerns raised in petitions for reconsideration on the 2016 
NSPS OOOOa explained that, even at greenfield sites, certain scenarios 
present circumstances where the control of a pneumatic pump may be 
technically infeasible despite the site being newly designed and 
constructed.\177\ These circumstances include, but are not limited to, 
site designs requiring high-pressure flares to which routing a low-
pressure pump discharge is not feasible and use of small boilers or 
process heaters that are insufficient to control pneumatic pump 
emissions or that could result in safety trips and burner flame 
instability. The EPA proposed to extend the technical infeasibility 
exemption to greenfield sites in 2018 and sought comment on these 
circumstances that could preclude control of a pneumatic pump at 
greenfield sites. While the EPA received comments both in favor of and 
opposing the application of the technical infeasibility exemption to 
greenfield sites, the commenters did not identify a reasoned basis for 
the EPA to decline to extend the exemption. See Response to Comments 
(RTC) for 2020 Technical Rule at 5-1 to 5-4 at Docket ID No. EPA-HQ-
OAR-2017-0483. Moreover, the EPA specifically sought information 
regarding the additional costs that would be incurred if owners and 
operators of greenfield sites were required to select a control that 
can accommodate pneumatic pump emissions in addition to the control's 
primary purpose at a new construction site, but no such information was 
provided.
---------------------------------------------------------------------------

    \177\ See proposal for 2020 Technical Rule at 83 FR 52061.
---------------------------------------------------------------------------

    The 2020 Technical Rule therefore expanded the technical 
infeasibility provision to apply to pneumatic pumps at all well sites, 
including new developments (greenfield sites), concluding that the 
extension was appropriate because the EPA identified circumstances 
where it may not be technically feasible to control pneumatic pumps at 
a greenfield site. The 2020 Technical Rule removed the reference to 
greenfield site in 40 CFR 60.5393a(b) and the associated definition of 
greenfield site at 40 CFR 60.5430a.
    In the final rule preamble for the 2016 NSPS OOOOa, the EPA stated 
we did not intend to require the installation of a control device at a 
well site for the sole purpose of controlling emissions from a 
pneumatic pump, but rather only required control of pneumatic pumps to 
the extent a control device or process would already be available on 
site. It is not the EPA's intent to require a greenfield site to 
install a control device specifically for controlling emissions from a 
pneumatic pump. It is our understanding that sites are designed to 
maximize operation and safety. This includes the placement of 
equipment, such as control devices. Because vented gas from pneumatic 
pumps is at low pressure, it may not be feasible to move collected gas 
through a closed vent system to a control device, depending on site 
design. Therefore, the EPA continues to conclude that, when determining 
technical feasibility at any site, such a determination should consider 
the routing of pneumatic pump emissions to the controls which are 
needed for the other processes at the site (i.e., not the pneumatic 
pump). The owner or operator must justify and provide professional or 
in-house engineering certification for any site where the control of 
pneumatic pump emissions is technically infeasible. As explained in the 
RTC for the 2020 Technical Rule, ``[t]he EPA believes that the 
requirement to certify an engineering assessment to demonstrate 
technical infeasibility provides protection against an owner or 
operator purposely designing a new site just to avoid routing emissions 
from a pneumatic pump to an onsite control device or to a process.'' 
\178\ For the reasons explained above, the EPA is proposing to align 
the methane standards in the 2016 NSPS OOOOa for controlling pneumatic 
pump emissions with the amendments made to the VOC standards in the 
2020 Technical Rule to allow for a well-justified determination of 
technical infeasibility at all well sites, including greenfield sites.
---------------------------------------------------------------------------

    \178\ See Docket ID No. EPA-HQ-OAR-2017-0483-2291. ``For 
example, consider the example provided by one commenter where a new 
site design requires only a high-pressure flare to control emergency 
and maintenance blowdowns and it is not feasible for a low-pressure 
pneumatic pump discharge to be routed to such a flare. The 
infeasibility determination would need not only demonstrate that it 
is not feasible for a low-pressure pneumatic pump discharge to be 
directly routed to the flare, it would also need to demonstrate that 
it is infeasible to design and install a low-pressure header to 
allow routing this discharge to such a flare system.'' RTC at 5-4.
---------------------------------------------------------------------------

    Second, the 2020 Technical Rule amended the 2016 NSPS OOOOa to 
specify that boilers and process heaters are not considered control 
devices for the purposes of the pneumatic pump standards. It is the 
EPA's understanding, based on information provided in reconsideration 
petitions \179\ submitted regarding the 2016 NSPS OOOOa and comments 
received on the proposal for the 2020 Technical Rule, that some boilers 
and process heaters located at well sites are not inherently designed 
for the control of emissions. While it is true that for some other 
sources (not pneumatic pumps), boilers and process heaters may be 
designed as control devices, that is generally not the operational 
purpose of this equipment at a well site. Instead, it is the EPA's 
understanding that boilers and process heaters operate seasonally, 
episodically, or otherwise intermittently as process devices, thus 
making the use of these devices as controls inefficient and non-
compliant with the continuous control requirements at 40 CFR 
60.5415a.\180\ Further, as explained in the 2020 Technical Rule, the 
fact that some boilers and process heaters located at well sites are 
not inherently designed to control emissions means that ``routing 
pneumatic pump emissions to these devices may result in frequent safety 
trips and burner flame instability (e.g., high temperature limit 
shutdowns and loss of flame signal).'' Id. The EPA determined that 
``requiring the technical infeasibility evaluation for every boiler and 
process heater located at a wellsite would result in unnecessary 
administrative burden since each such evaluation would be raising 
the[se] same concerns.'' 85 FR 57404 (September 15, 2020). Further, as 
described above, the EPA did not intend to require the installation of 
a control device for the sole purpose of controlling emissions from 
pneumatic pumps. Based on the EPA's understanding that boilers and 
process heaters located at well sites are designed and operated as 
process equipment (meaning they are not inherently designed for the 
control of emissions), the EPA also does not intend to require their 
continuous operation solely to control emissions from pneumatic pumps 
either. Therefore, the EPA is proposing to align the methane standards 
for pneumatic pumps with the 2020 Technical Rule to specify that 
boilers and process heaters are not considered control devices for the 
purposes of controlling pneumatic pump emissions. The EPA solicits 
comment on this alignment, including whether there are specific 
examples where boilers and process heaters are

[[Page 63162]]

currently used as control devices at well sites.
---------------------------------------------------------------------------

    \179\ See Docket ID No. EPA-HQ-OAR-2017-0483-0016.
    \180\ See Docket ID No. EPA-HQ-OAR-2017-0483-0016.
---------------------------------------------------------------------------

    Third, the EPA is proposing to align the certification requirements 
for the determination that it is technically infeasible to route 
emissions from a pneumatic pump to a control device or process. The 
2016 NSPS OOOOa required certification of technical infeasibility by a 
qualified third-party Professional Engineer (PE); however, the 2020 
Technical Rule allows this certification by either a PE or an in-house 
engineer, because in-house engineers may be more knowledgeable about 
site design and control than a third-party PE. The EPA continues to 
believe that certification by an in-house engineer is appropriate for 
this purpose. We are, therefore, proposing to align the methane 
standards in the 2016 NSPS OOOOa with the 2020 Technical Rule to allow 
certification of technical infeasibility by either a PE or an in-house 
engineer with expertise on the design and operation of the pneumatic 
pump. We are soliciting comment on this proposed alignment.
3. Closed Vent Systems (CVS)
    As in the 2020 Technical Rule, the EPA is proposing to allow 
multiple options for demonstrating that there are no detectable methane 
emissions from CVS. Additionally, the EPA is proposing to allow either 
a PE or an in-house engineer with expertise on the design and operation 
of the CVS to certify the design and operation will meet the 
requirement to route all vapors to the control device or back to the 
process.
    The methane standards in the 2016 NSPS OOOOa require that CVS be 
operated with no detectable emissions, as demonstrated through specific 
monitoring requirements associated with the specific affected 
facilities (i.e., pneumatic pumps, centrifugal compressors, 
reciprocating compressors, and storage vessels). Relevant here, the 
2016 NSPS OOOOa required this demonstration for both VOC and methane 
emissions through annual inspections using EPA Method 21 for CVS 
associated with pneumatic pumps, while requiring storage vessels to 
conduct monthly audio, visual, olfactory (AVO) monitoring. The 2020 
Technical Rule amended the VOC requirements for CVS for pneumatic pumps 
to align the requirements for pneumatic pumps and storage vessels by 
incorporating provisions allowing the option to demonstrate the 
pneumatic pump CVS is operated with no detectable emissions by either 
an annual inspection using EPA Method 21, monthly AVO monitoring, or 
OGI monitoring at the frequencies specified for fugitive emissions 
monitoring. The EPA is proposing to amend the methane standards to 
allow pneumatic pump affected facilities to permit these same options 
to demonstrate no detectable methane emissions from CVS either using 
annual Method 21 monitoring, as currently required by the 2016 NSPS 
OOOOa, or using either monthly AVO monitoring or OGI monitoring at the 
fugitive monitoring frequency. The EPA considers these detection 
options appropriate for CVS associated with pneumatic pumps because any 
of the three would detect methane as well as VOC emissions. We 
incorporated the option for monthly AVO monitoring in the 2020 
Technical Rule because pneumatic pumps and controlled storage vessels 
are commonly located at the same site and having separate monitoring 
requirements for a potentially shared CVS is overly burdensome and 
duplicative. 83 FR 52083 (October 15, 2018). We further incorporated 
the option for OGI monitoring because OGI is already being used for 
those sites that are subject to fugitive emissions monitoring and the 
CVS can readily be monitored during the fugitive emissions survey at no 
extra cost. 85 FR 57405. The EPA believes it is appropriate to maintain 
these options because not all well sites with controlled pneumatic 
pumps will be subject to fugitive emissions monitoring (e.g., pneumatic 
pumps located at existing well sites that have not triggered the 
fugitive monitoring requirements for new or modified well sites) and 
requiring either OGI or EPA Method 21 survey of the CVS for the 
pneumatic pump in the absence of fugitive emissions surveys would be 
unreasonable. It is possible for a new pneumatic pump to be subject to 
control at an existing well site that is not subject to the fugitive 
emissions requirements. Requiring either EPA Method 21 or OGI for the 
sole purpose of monitoring the CVS associated with the pneumatic pump 
would be too costly,\181\ therefore we continue to believe monthly AVO 
is an appropriate option for pneumatic pumps subject to the 2016 NSPS 
OOOOa.
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    \181\ Both OGI and EPA Method 21 have significant capital and 
annual costs, including the cost of specialized equipment and 
trained operators of that equipment. While the costs of these 
programs are justified for well site fugitive emission monitoring 
based on the assumption of a high component count from which 
emissions would be controlled, the CVS is only one of those many 
components. Thus, where well site fugitive monitoring is not 
otherwise required, the cost-effectiveness of OGI or EPA Method 21 
would be significantly higher for the CVS alone.
---------------------------------------------------------------------------

    Additionally, the 2020 Technical Rule amended the 2016 NSPS OOOOa 
to allow certification of the design and operation of CVS by an in-
house engineer with expertise on the design and operation of the CVS in 
lieu of a PE. This certification is necessary to ensure the design and 
operation of the CVS will meet the requirement to route all vapors to 
the control device or back to the process. As explained in the proposal 
for the 2020 Technical Rule, 83 FR 52079, the EPA allows CVS 
certification by either a PE or an in-house engineer because in-house 
engineers may be more knowledgeable about site design and control than 
a third-party PE. For the same reason, the EPA is proposing to amend 
the CVS requirements associated with methane emissions in the 
production and processing segments, and methane and VOC emissions in 
the transmission and storage segment, to allow certification of the 
design and operation of CVS by either a PE or an in-house engineer with 
expertise on the design and operation of the CVS.
4. Fugitive Emissions at Well Sites and Compressor Stations
a. Well Sites
    The EPA is proposing to exclude from fugitive emissions monitoring 
a well site that is or later becomes a ``wellhead only well site,'' 
which the 2020 Technical Rule defines as ``a well site that contains 
one or more wellheads and no major production and processing 
equipment.'' The 2016 NSPS OOOOa excludes well sites that contain only 
one or more wellheads from the fugitive emissions requirements because 
fugitive emissions at such well sites are extremely low. 80 FR 56611. 
As explained in that rulemaking, ``[s]ome well sites, especially in 
areas with very dry gas or where centralized gathering facilities are 
used, consist only of one or more wellheads, or `Christmas trees,' and 
have no ancillary equipment such as storage vessels, closed vent 
systems, control devices, compressors, separators and pneumatic 
controllers. Because the magnitude of fugitive emissions depends on how 
many of each type of component (e.g., valves, connectors, and pumps) 
are present, fugitive emissions from these well sites are extremely 
low.'' 80 FR 56611. The 2020 Technical Rule amended the 2016 NSPS OOOOa 
to exclude from fugitive emissions monitoring a well site that is or 
later becomes a ``wellhead only well site,'' which the 2020 Technical 
Rule defines as ``a well site that contains one or more wellheads and 
no major production and processing equipment.'' The 2020 Technical Rule 
defined ``major production and processing equipment''

[[Page 63163]]

as including reciprocating or centrifugal compressors, glycol 
dehydrators, heater/treaters, separators, and storage vessels 
collecting crude oil, condensate, intermediate hydrocarbon liquids, or 
produced water. We continue to believe that available information, 
including various studies,\182\ supports an exemption for well sites 
that do not have this major production and processing equipment. The 
2020 Technical Rule allows certain small ancillary equipment, such as 
chemical injection pumps, pneumatic controllers used to control well 
emergency shutdown valves, and pumpjacks, that are associated with, or 
attached to, the wellhead and ``Christmas tree'' to remain at a 
``wellhead only well site'' without being subject to the fugitive 
emissions monitoring requirements because they have very few fugitive 
emissions components that would leak, and therefore have limited 
potential for fugitive emissions. The emission reduction benefits of 
continuing monitoring at that point would be relatively low, and thus 
would not be cost-effective.
---------------------------------------------------------------------------

    \182\ See https://pubs.acs.org/doi/10.1021/acs.est.0c02927, 
https://data.permianmap.org/pages/flaring, and https://www.edf.org/sites/default/files/documents/PermianMapMethodology_1.pdf.
---------------------------------------------------------------------------

    For the reason stated above, the EPA is proposing to amend the 2016 
NSPS OOOOa to allow monitoring of methane fugitive emissions to stop 
when a wellsite contains only wellhead(s) and no major production and 
processing equipment, as provided in the 2020 Technical Rule.
b. Compressor Stations
    As discussed above, the 2016 NSPS OOOOa required quarterly 
monitoring of compressor stations for both VOC and methane emissions, 
and it also permitted waiver from one quarterly monitoring event when 
the average temperature is below 0 [deg]F for two consecutive months 
because it is technically infeasible for the OGI camera (and EPA Method 
21 instruments) to operate below this temperature. After the 2020 
Policy Rule rescinded the methane standards, the 2020 Technical Rule 
reduced the monitoring requirements for the VOC standards to require 
only semiannual monitoring and, in doing so, removed the waiver. Upon 
enactment of the CRA resolution, compressor stations again became 
subject to quarterly monitoring pursuant to the reinstated 2016 NSPS 
OOOOa methane standards, and the waiver as it applied to the methane 
standards was also reinstated. Consistent with our proposal to align 
the monitoring requirements for VOCs with the monitoring requirements 
for methane, the EPA is also proposing to reinstate the waiver for the 
VOC standards as specified in the 2016 NSPS OOOOa.
c. Well Sites and Compressor Stations on the Alaska North Slope
    The EPA is proposing to amend the 2016 NSPS OOOOa to require that 
new, reconstructed, and modified compressor stations located on the 
Alaska North Slope that startup (initially, or after reconstruction or 
modification) between September and March to conduct initial monitoring 
of methane emissions within 6 months of startup, or by June 30, 
whichever is later. The EPA made a similar amendment to the initial 
monitoring of methane and VOC emissions at well sites located on the 
Alaska North Slope in the March 12, 2018 amendments to the 2016 NSPS 
OOOOa (``2018 NSPS OOOOa Rule'').\183\ As explained in that action, 
such separate requirements were warranted due to the area's extreme 
cold temperatures, which for approximately half of the year are below 
the temperatures at which the monitoring instruments are designed to 
operate. The 2020 Technical Rule made this amendment for VOC emissions 
from gathering and boosting compressor stations located in the Alaska 
North Slope for this same reason.
---------------------------------------------------------------------------

    \183\ 83 FR 10628 (March 12, 2018).
---------------------------------------------------------------------------

    The EPA is also proposing to amend the 2016 NSPS OOOOa to require 
annual monitoring of methane and VOC emissions at all compressor 
stations located on the Alaska North Slope, with subsequent annual 
monitoring at least 9 months apart but no more than 13 months apart. In 
the 2018 NSPS OOOOa Rule, the EPA similarly amended the monitoring 
frequency for well sites located on the Alaska North Slope to annual 
monitoring to accommodate the extreme cold temperature. 83 FR 10628 
(March 12, 2018). For the same reason, in the 2020 Technical Rule, the 
EPA amended the 2016 NSPS OOOOa to require annual VOC monitoring at 
gathering and boosting compressor stations located on the Alaska North 
Slope because extreme cold temperatures make it technically infeasible 
to conduct OGI monitoring for over half of a year.\184\ Because the 
same difficulties would arise with respect to monitoring for fugitive 
methane emissions from gathering and boosting compressor stations or to 
monitoring of methane and VOC emissions from compressor stations in the 
transmission and storage segment, the EPA is proposing to amend the 
2016 NSPS OOOOa to require that all compressor stations located on the 
Alaska North Slope conduct annual monitoring of both methane and VOC 
emissions.
---------------------------------------------------------------------------

    \184\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-12434. See also FLIR Systems, Inc. product 
specifications for GF300/320 model OGI cameras at https://www.flir.com/ogi/display/?id=55671 and Thermo Fisher Scientific 
product specification for TVA-2020 at https://assets.thermofisher.com/TFS-Assets/LSG/Specification-Sheets/EPM-TVA2020.pdf.
---------------------------------------------------------------------------

    Further, the EPA is proposing to extend the deadline for conducting 
initial monitoring of both VOC and methane emissions from 60 days to 90 
days for all well sites and compressor stations located on the Alaska 
North Slope that startup or are modified between April and August. In 
the 2020 Technical Rule, the EPA made this amendment for initial VOC 
monitoring to allow the well site or gathering and boosting compressor 
station to reach normal operating conditions. 85 FR 57406. For the same 
reason, we are proposing to further amend the 2016 NSPS OOOOa to apply 
this same 90-day initial monitoring requirement to initial monitoring 
of fugitive methane and VOC emissions from all well sites and 
compressor stations located on the Alaska North Slope that startup or 
are modified between April and August.
d. Modification
    The 2016 NSPS OOOOa, as originally promulgated, provided that 
``[f]or purposes of the fugitive emissions standards at 40 CFR 
60.5397a, [a] well site also means a separate tank battery surface site 
collecting crude oil, condensate, intermediate hydrocarbon liquids, or 
produced water from wells not located at the well site (e.g., 
centralized tank batteries).'' 40 CFR 60.5430a. However, the original 
2016 NSPS OOOOa defined ``modification'' only with respect to a well 
site and was silent on what constitutes modification to a well site 
that is a separate tank battery surface site. Specifically, 40 CFR 
60.5365a(i), as promulgated in 2016, specified that, for the purposes 
of fugitive emissions components at a well site, a modification occurs 
when (1) a new well is drilled at an existing well site, (2) a well is 
hydraulically fractured at an existing well site, or (3) a well is 
hydraulically refractured at an existing well site. See 40 CFR 
60.5365a(i).
    Because this provision was silent on when modification occurs at a 
well site that is a separate tank battery surface site, the 2020 
Technical Rule added language to clarify that a modification of a well 
site that is a separate tank battery surface site occurs when (1) any 
of the actions listed above for well sites occurs

[[Page 63164]]

at an existing separate tank battery surface site, (2) a well modified 
as described above sends production to an existing separate tank 
battery surface site, or (3) a well site subject to the fugitive 
emissions requirements removes all major production and processing 
equipment such that it becomes a wellhead-only well site and sends 
production to an existing separate tank battery surface site. Because 
the 2020 Technical Rule amended only the VOC standards in the 2016 NSPS 
OOOOa, and since this definition of modification equally applies to 
fugitive methane emissions from a separate tank battery surface site, 
the EPA is proposing to apply this definition of modification for 
purposes of determining when modification occurs at a separate tank 
battery surface site triggering the methane standards for fugitive 
emissions at well sites.
e. Initial Monitoring for Well Sites and Compressor Stations
    The 2016 NSPS OOOOa, as originally promulgated, had required 
monitoring of methane and VOC fugitive emissions at well sites and 
compressor stations to begin within 60 days of startup (of production 
in the case of well sites) or modification. The 2020 Technical Rule 
extended this time frame to 90 days for well sites and gathering and 
boosting compressor stations in response to comments stating that well 
sites and compressor stations do not achieve normal operating 
conditions within the first 60 days of startup and suggesting that the 
EPA allow 90 days to 180 days. The EPA agreed that additional time to 
allow the well site or compressor station to reach normal operating 
conditions is warranted, considering the purpose of the initial 
monitoring is to identify any issues associated with installation and 
startup of the well site or compressor station. By providing sufficient 
time to allow owners and operators to conduct the initial monitoring 
survey during normal operating conditions, the EPA expects that there 
will be more opportunity to identify and repair sources of fugitive 
emissions, whereas a partially operating site may result in missed 
emissions that remain unrepaired for a longer period of time. 85 FR 
57406. These same reasons apply regardless of pollutant or the location 
of the compressor station; therefore, the EPA is proposing to further 
amend the 2016 NSPS OOOOa to extend the deadline for conducting initial 
monitoring from 60 to 90 days for monitoring both VOC and methane 
fugitive emissions at all well sites and compressor stations (except 
those on the Alaska North Slope which are separately regulated as 
discussed in section X.B.4.c).
f. Repair Requirements
    The 2020 Technical Rule made certain amendments to the 2016 NSPS 
OOOOa repair requirements associated with monitoring of fugitive VOC 
emissions at well sites and gathering and boosting compressor stations. 
For the same reasons provided in the 2020 Technical Rule and reiterated 
below, the EPA is proposing to similarly amend the 2016 NSPS OOOOa 
repair requirements associated with monitoring of methane emissions at 
well sites and gathering and boosting compressor stations and 
monitoring of VOC and methane fugitive emissions at compressor stations 
in the transmission and storage segment.
    Specifically, the EPA is proposing to require a first attempt at 
repair within 30 days of identifying fugitive emissions and final 
repair, including the resurvey to verify repair, within 30 days of the 
first attempt at repair. The 2016 NSPS OOOOa, as originally 
promulgated, required repair within 30 days of identifying fugitive 
emissions and a resurvey to verify that the repair was successful 
within 30 days of the repair. Stakeholders raised questions regarding 
whether emissions identified during the resurvey would result in 
noncompliance with the repair requirement. In the 2020 Technical Rule, 
the EPA clarified that repairs should be verified as successful prior 
to the repair deadline and added definitions for the terms ``first 
attempt at repair'' and ``repaired.'' Specifically, the definition of 
``repaired'' includes the verification of successful repair through a 
resurvey of the fugitive emissions component. The EPA is similarly 
proposing to apply these amendments to the repair requirements made in 
the 2020 Technical Rule to the repair requirements associated with 
monitoring of methane emissions at well sites and gathering and 
boosting compressor stations as well as monitoring of VOC and methane 
fugitive emissions at compressor stations in the transmission and 
storage segment and monitoring.
    In addition, the EPA is proposing that delayed repairs be completed 
during the ``next scheduled compressor station shutdown for 
maintenance, scheduled well shutdown, scheduled well shut-in, after a 
scheduled vent blowdown, or within 2 years, whichever is earliest.'' 
The proposed amendment would clarify that completion of delayed repairs 
is required during scheduled shutdown for maintenance, and not just any 
shutdown.
    In 2018 NSPS OOOOa Rule the EPA amended the 2016 NSPS OOOOa to 
specify that, where the repair of a fugitive emissions component is 
``technically infeasible, would require a vent blowdown, a compressor 
station shutdown, a well shutdown or well shut-in, or would be unsafe 
to repair during operation of the unit, the repair must be completed 
during the next scheduled compressor station shutdown, well shutdown, 
well shut-in, after a planned vent blowdown, or within 2 years, 
whichever is earlier.'' \185\ During the rulemaking for the 2020 
Technical Rule, the EPA received comments expressing concerns with 
requiring repairs during the next scheduled compressor station 
shutdown, without regard to whether the shutdown is for maintenance 
purposes. The commenters stated that repairs must be scheduled and that 
where a planned shutdown is for reasons other than scheduled 
maintenance, completion of the repairs during that shutdown may be 
difficult and disrupt gas transmission. The EPA agrees that requiring 
the completion of delayed repairs only during those scheduled 
compressor station shutdowns where maintenance activities are scheduled 
is reasonable and anticipates that these maintenance shutdowns occur on 
a regular schedule. Accordingly, in the 2020 Technical Rule the EPA 
further amended this provision by adding the term ``for maintenance'' 
to clarify that repair must be completed during the ``next scheduled 
compressor station shutdown for maintenance'' or other specified 
scheduled events, or within 2 years, whichever is the earliest. For the 
same reason, the EPA is proposing the same clarifying amendment to the 
delay of repair requirements for fugitive methane emissions at well 
sites and gathering and boosting compressor stations and fugitive VOC 
and methane fugitive emissions at compressor stations in the 
transmission and storage segment.
---------------------------------------------------------------------------

    \185\ 83 FR 10638, 40 CFR 60.5397a(h)(2).
---------------------------------------------------------------------------

g. Definitions Related to Fugitive Emissions at Well Sites and 
Compressor Stations
    The 2020 Technical Rule made certain amendments to the definition 
of a well site and the definition for startup of production as they 
relate to fugitive VOC emissions requirements at well sites. For the 
same reasons provided in the 2020 Technical Rule and reiterated below, 
the EPA is proposing to similarly amend these definitions as they 
relate to the fugitive methane emissions requirements at well sites.

[[Page 63165]]

    The 2020 Technical Rule amended the definition of well site, for 
purposes of VOC fugitive emissions monitoring, to exclude equipment 
owned by third parties and oilfield solid waste and wastewater disposal 
wells. The amended definition for ``well site'' excludes third party 
equipment from the fugitive emissions requirements by excluding ``the 
flange immediately upstream of the custody meter assembly and 
equipment, including fugitive emissions components located downstream 
of this flange.'' To clarify this exclusion, the 2020 Technical Rule 
defines ``custody meter'' as ``the meter where natural gas or 
hydrocarbon liquids are measured for sales, transfers, and/or royalty 
determination,'' and the ``custody meter assembly'' as ``an assembly of 
fugitive emissions components, including the custody meter, valves, 
flanges, and connectors necessary for the proper operation of the 
custody meter.'' This exclusion was added for several reasons, 
including consideration that owners and operators may not have access 
or authority to repair this third-party equipment and because the 
custody meter ``is used effectively as the cash register for the well 
site and provides a clear separation for the equipment associated with 
production of the well site, and the equipment associated with putting 
the gas into the gas gathering system.'' 83 FR 52077 (October 15, 
2018).
    The definition of a well site was also amended in the 2020 
Technical Rule to exclude Underground Injection Control (UIC) Class I 
oilfield disposal wells and UIC Class II oilfield wastewater disposal 
wells. The EPA had proposed to exclude UIC Class II oilfield wastewater 
disposal wells because of our understanding that they have negligible 
fugitive VOC and methane emissions. 83 FR 52077. Comments received on 
the 2020 Technical rulemaking effort further suggested, and the EPA 
agreed, that we also should exclude UIC Class I oilfield disposal wells 
because of their low VOC and methane emissions. Both types of disposal 
wells are permitted through UIC programs under the Safe Drinking Water 
Act for protection of underground sources of drinking water. For 
consistency, the 2020 Technical Rule adopted the definitions for UIC 
Class I oil field disposal wells and UIC Class II oilfield wastewater 
disposal wells under the Safe Drinking Water Act definitions in 
excluding them from the definition of a well site in the 2016 NSPS 
OOOOa. Specifically, the 2020 Technical Rule defined a UIC Class I 
oilfield disposal well as ``a well with a UIC Class I permit that meets 
the definition in 40 CFR 144.6(a)(2) and receives eligible fluids from 
oil and natural gas exploration and production operations.'' 
Additionally, the 2020 Technical Rule defines a UIC Class II oilfield 
wastewater disposal well as ``a well with a UIC Class II permit where 
wastewater resulting from oil and natural gas production operations is 
injected into underground porous rock formations not productive of oil 
or gas, and sealed above and below by unbroken, impermeable strata.'' 
As amended, UIC Class I and UIC Class II disposal wells are not 
considered well sites for the purposes of VOC fugitive emissions 
requirements. Because the 2020 Technical Rule, as finalized, addressed 
only VOC emissions in the production and processing segment, the EPA is 
proposing the same exclusion and definition of ``well site'' for the 
purposes of fugitive emissions monitoring of methane emissions at well 
sites.
    The EPA is also proposing to apply the definition for ``startup of 
production'' for purposes of well site fugitive emissions requirements 
for VOC to these requirements as they relate to methane. The 2016 NSPS 
OOOOa initially contained a definition for ``startup of production'' as 
it relates to the well completion standards that reduce emissions from 
hydraulically fractured wells. For that purpose, the term was defined 
as ``the beginning of initial flow following the end of flowback when 
there is continuous recovery of salable quality gas and separation and 
recovery of any crude oil, condensate or produced water.'' 81 FR 25936 
(June 3, 2016). The 2020 Technical Rule amended the definition of 
``startup of production'' to separately define the term as it relates 
to fugitive VOC emissions requirements at well sites. Specifically, ``. 
. .[f]or the purposes of the fugitive monitoring requirements of 40 CFR 
60.5397a, startup of production means the beginning of the continuous 
recovery of salable quality gas and separation and recovery of any 
crude oil, condensate or produced water'' 85 FR 57459 (September 15, 
2020). This separate definition clarifies that fugitive emissions 
monitoring applies to both conventional and unconventional 
(hydraulically fractured) wells. For this same reason, the EPA is 
proposing to apply this same definition of ``startup of production'' to 
fugitive emissions monitoring of methane emissions at well sites.
h. Monitoring Plan
    The 2016 NSPS OOOOa, as originally promulgated, required that each 
fugitive emissions monitoring plan include a site map and a defined 
observation path to ensure that the OGI operator visualizes all of the 
components that must be monitored during each survey. The 2020 
Technical Rule amended this requirement to allow the company to specify 
procedures that would meet this same goal of ensuring every component 
is monitored during each survey. While the site map and observation 
path are one way to achieve this, other options can also ensure 
monitoring, such as an inventory or narrative of the location of each 
fugitive emissions component. The EPA stated in the 2020 Technical Rule 
that ``these company-defined procedures are consistent with other 
requirements for procedures in the monitoring plan, such as the 
requirement for procedures for determining the maximum viewing distance 
and maintaining this viewing distance during a survey.'' 85 FR 57416 
(September 15, 2020). Because the same monitoring device is used to 
monitor both methane and VOC emissions, the same company-defined 
procedures for ensuring each component is monitored are appropriate. 
Therefore, the EPA is proposing to similarly amend the monitoring plan 
requirements for methane and for compressor stations to allow company 
procedures in lieu of a sitemap and an observation path.
i. Recordkeeping and Reporting
    The 2020 Technical Rule amended the 2016 NSPS OOOOa to streamline 
the recordkeeping and reporting requirements for the VOC fugitive 
emissions standards. The amendments removed the requirement to report 
or keep certain records that the EPA determined were redundant or 
unnecessary; in some instances, the rule replaced those requirements or 
added new requirements that could better demonstrate and ensure 
compliance, in particular where the underlying requirement was also 
amended (e.g., repair requirements). These amendments reflect 
consideration of the public comments received on the proposal for that 
rulemaking. The purpose and function of the recordkeeping and reporting 
requirements are equally applicable to methane and VOCs, and therefore, 
are not pollutant specific. For the same reasons the EPA streamlined 
these requirements in the 2020 Technical Rule,\186\ the EPA is 
proposing to apply these streamlined recordkeeping and reporting 
requirements for methane

[[Page 63166]]

emissions from sources subject to NSPS OOOOa.
---------------------------------------------------------------------------

    \186\ See 85 FR 57415 (September 15, 2020).
---------------------------------------------------------------------------

    For each collection of fugitive emissions components located at a 
well site or compressor station, the following amendments were made to 
the recordkeeping and reporting requirements in the 2020 Technical 
Rule:
     Revised the requirements in 40 CFR 60.5397a(d)(1) to 
require inclusion of procedures that ensure all fugitive emissions 
components are monitored during each survey within the monitoring plan.
     Removed the requirement to maintain records of a digital 
photo of each monitoring survey performed, captured from the OGI 
instrument used for monitoring when leaks are identified during the 
survey because the records of the leaks provide proof of the survey 
taking place.
     Removed the requirement to maintain records of the number 
and type of fugitive emissions components or digital photo of fugitive 
emissions components that are not repaired during the monitoring survey 
once repair is completed and verified with a resurvey.
     Required records of the date of first attempt at repair 
and date of successful repair.
     Revised reporting to specify the type of site (i.e., well 
site or compressor station) and when the well site changes status to a 
wellhead-only well site.
     Removed requirement to report the name or ID of operator 
performing the monitoring survey.
     Removed requirement to report the number and type of 
difficult-to-monitor and unsafe-to-monitor components that are 
monitored during each monitoring survey.
     Removed requirement to report the ambient temperature, sky 
conditions, and maximum wind speed.
     Removed requirement to report the date of successful 
repair.
     Removed requirement to report the type of instrument used 
for resurvey.
5. AMEL
    The 2020 Technical Rule made the following amendments to the 
provisions associated with applications for use of an AMEL for VOC work 
practice standards for well completions, reciprocating compressors, and 
the collection of fugitive emissions components located at well sites 
and gathering and boosting compressor stations. For the same reasons 
provided in the 2020 Technical Rule and reiterated below, the EPA is 
proposing to similarly amend the 2016 NSPS OOOOa provisions associated 
with applications for use of an AMEL for methane work practice 
standards at well sites and gathering and boosting compressor stations 
and VOC and methane work practice standards at compressor stations in 
the transmission and storage segment.
    The 2020 Technical Rule amended the AMEL application requirements 
to help streamline the process for evaluation and possible approval of 
advanced measurement technologies. The amendments included allowing 
submission of applications by, among others, owners and operators of 
affected facilities, manufacturers or vendors of leak detection 
technologies, or trade associations. The 2020 Technical Rule ``allows 
any person to submit an application for an AMEL under this provision.'' 
85 FR 57422 (September 15, 2020). However, the 2020 Technical Rule, 
like the 2016 NSPS OOOOa still requires that the application include 
sufficient information to demonstrate that the AMEL achieves emission 
reductions at least equivalent to the work practice standards in the 
rule. To that end, the 2020 Technical Rule ``requires applications for 
these AMEL to include site-specific information to demonstrate 
equivalent emissions reductions, as well as site-specific procedures 
for ensuring continuous compliance.'' Id. At a minimum, the application 
should include field data that encompass seasonal variations, which may 
be supplemented with modeling analyses, test data, and/or other 
documentation. The specific work practice(s), including performance 
methods, quality assurance, the threshold that triggers action, and the 
mitigation thresholds are also required as part of the AMEL 
application. For example, for a technology designed to detect fugitive 
emissions, information such as the detection criteria that indicate 
fugitive emissions requiring repair, the time to complete repairs, and 
any methods used to verify successful repair would be required.
    Since the 2020 Technical Rule changes to the AMEL provisions in the 
2016 NSPS OOOOa are procedural in the sense that they mostly speak to 
the ``minimum information that must be included in each application in 
order for the EPA to make a determination of equivalency and, thus, be 
able to approve an alternative'' the EPA believes that it is 
appropriate to retain those amendments. 85 FR 57422 (September 15, 
2020). If finalized, the application must demonstrate equivalence as 
explained above for both the reduction of methane and VOC emissions. 
Because the 2020 Technical Rule amended only the VOC standards in the 
2016 NSPS OOOOa, and since EPA believes that basis for promulgation of 
this provision for AMEL applications equally applies to work practices 
standards for methane emissions at facilities in the production and 
processing segments and VOC and methane emissions at facilities in the 
transmission and storage segment, the EPA is proposing to apply these 
application requirements for all applicants seeking an AMEL for the 
methane and VOC work practice standards in NSPS OOOOa.
6. Alternative Fugitive Emissions Standards Based on Equivalent State 
Programs
    The 2020 Technical Rule added a new section (at 40 CFR 60.5399a) 
which served two purposes. First, the new section outlined procedures 
for State, local, and Tribal authorities to seek the EPA's approval of 
their VOC fugitive emissions standards at well sites and gathering and 
boosting compressor stations as an alternative to the Federal 
standards. Second, the new section approved specific voluntary 
alternative standards for six States. For the same reasons provided in 
the 2020 Technical Rule and reiterated below, the EPA is proposing to 
similarly allow this new section to apply to fugitive emissions 
standards for methane fugitive emissions at well sites and gathering 
and boosting compressor stations, and VOC and methane fugitive 
emissions at compressor stations in the transmission and storage 
segment.
    The 2020 Technical Rule added this new section in part to allow the 
use of specific alternative fugitive emissions standards for VOC 
emissions for six State fugitive emissions programs that the EPA had 
concluded were at least equivalent to the fugitive emissions monitoring 
and repair requirements at 40 CFR 60.5397a(e), (f), (g), and (h) as 
amended in that rule.\187\ These approved alternative fugitive 
emissions standards may be used for certain individual well sites or 
gathering and boosting compressor stations that are subject to VOC 
fugitive emissions monitoring and repair so long as the source complies 
with specified Federal requirements applicable to each approved 
alternative State program and included in 40 CFR 60.5399a(f) through 
(n). For example, a well site that is subject to the requirements of 
Pennsylvania General Permit 5A, section G, effective August 8, 2018, 
could choose to comply with those

[[Page 63167]]

standards in lieu of the monitoring, repair, recordkeeping, and 
reporting requirements in the NSPS for fugitive emissions at well 
sites. However, in that example, the owner or operator must develop and 
maintain a fugitive emissions monitoring plan, as required in 40 CFR 
60.5397a(c) and (d), and must monitor all of the fugitive emissions 
components, as defined in 40 CFR 60.5430a, regardless of the components 
that must be monitored under the alternative standard (i.e., under 
Pennsylvania General Permit 5A, Section G in the example). 
Additionally, the facility choosing to use the EPA-approved alternative 
standard must submit, as an attachment to its annual report for NSPS 
OOOOa, the report that is submitted to its State in the format 
submitted to the State, or the information required in the report for 
NSPS OOOOa if the State report does not include site-level monitoring 
and repair information. If a well site is located in the State but is 
not subject to the State requirements for monitoring and repair (i.e., 
not obligated to monitor or repair fugitive emissions), then the well 
site must continue to comply with the Federal requirements of the NSPS 
at 40 CFR 60.5397a in its entirety.
---------------------------------------------------------------------------

    \187\ See memorandum, ``Equivalency of State Fugitive Emissions 
Programs for Well Sites and Compressor Stations to Final Standards 
at 40 CFR part 60, subpart OOOOa,'' located at Docket ID No. EPA-HQ-
OAR-2017-0483. January 17, 2020.
---------------------------------------------------------------------------

    In addition to providing the EPA-approved voluntary alternative 
fugitive emissions standards for well sites and gathering and boosting 
compressor stations located in California, Colorado, Ohio, 
Pennsylvania, and Texas, and well sites in Utah, the amendments in the 
2020 Technical Rule provide application requirements to request the EPA 
approval of an alternative fugitive emissions standards as State, 
local, and Tribal programs continue to develop. Applications for the 
EPA approval of alternative fugitive emissions standards based on 
State, local, or Tribal programs may be submitted by any interested 
person, including individuals, corporations, partnerships, 
associations, States, or municipalities. Similar to the application 
process for AMEL for advanced measurement technologies, the application 
must include sufficient information to demonstrate that the alternative 
fugitive emissions standards achieve emissions reductions at least 
equivalent to the fugitive emissions monitoring and repair requirements 
in the Federal NSPS. At a minimum, the application must include the 
monitoring instrument, monitoring procedures, monitoring frequency, 
definition of fugitive emissions requiring repair, repair requirements, 
recordkeeping, and reporting requirements. If any of the sections of 
the State regulations or permits approved as alternative fugitive 
emissions standards are changed at a later date, the State must follow 
the procedures outlined in 40 CFR 60.5399a to apply for a new 
evaluation of equivalency.
    As part of the 2018 proposed rule (83 FR 52056, October 15, 2018) 
that resulted in the 2020 Technical Rule, the EPA evaluated the 
specific State programs for both methane and VOC emissions at well 
sites, gathering and boosting compressor stations, and compressor 
stations in the transmission and storage segment as discussed in detail 
in a memorandum to that docket evaluating the equivalency of State 
fugitive emissions programs.\188\ The EPA is now proposing that all 
well sites and compressor stations located in and subject to the 
specified State regulations in 40 CFR 60.5399a may utilize these 
alternative fugitive emissions standards for both methane and VOC 
fugitive emissions. In the 2020 Technical Rule the EPA concluded that 
these monitoring, repair, recordkeeping, and reporting requirements 
were equivalent to the same types of requirements in the 2016 NSPS 
OOOOa for VOC at well sites and gathering and boosting compressor 
stations. See 85 FR 57424. The monitoring instrument (i.e., OGI or EPA 
Method 21) will detect, at the same time, both methane and VOC 
emissions without speciating these emissions. Therefore, detection of 
one of these pollutants is also detection of the other pollutant. For 
the same reasons provided in the 2020 Technical Rule, and explained in 
the associated State equivalency memos, the EPA proposes to find these 
same State fugitive emissions standards (as specified in 40 CFR 
60.5399a(f) through (n)) equivalent to the specified Federal methane 
fugitive emissions standards for well sites and gathering and boosting 
stations, and the methane and VOC fugitive emissions standards for 
compressor stations in the transmission and storage segment. The EPA is 
also proposing to allow State, local, and Tribal agencies to apply for 
the EPA approval of their fugitives monitoring program as an 
alternative to the Federal NSPS for methane. Put another way, the EPA 
is proposing to include methane throughout 40 CFR 60.5399a.
---------------------------------------------------------------------------

    \188\ See Docket ID Nos. EPA-HQ-OAR-2017-0483-0041 and EPA-HQ-
OAR-2017-0483-2277.
---------------------------------------------------------------------------

    The EPA recognizes that the determinations of equivalence included 
in the 2020 Technical Rule were based on the fugitive emissions 
monitoring requirements that existed at that time for the 2016 NSPS 
OOOOa which, based on other changes in the 2020 Technical Rule, 
included an exemption from monitoring for low production well sites and 
required semiannual monitoring at gathering and boosting compressor 
stations. As explained above, the EPA is proposing to repeal both of 
those changes, and require semiannual monitoring at all well sites, 
including those with low production, and quarterly monitoring at 
gathering and boosting compressor stations. These proposed changes to 
the 2016 NSPS OOOOa fugitive emissions requirements do not impact the 
EPA's conclusion that the six previously approved alternative State 
programs are equivalent to the Federal standards. Even so, the EPA is 
proposing regulatory changes within the alternative State program 
provisions in 2016 NSPS OOOOa to account for these proposed changes to 
the Federal standards. See the redline version of regulatory text in 
the docket at Docket ID No. EPA-HQ-OAR-2021-0317. These changes are 
intended to ensure that the previously approved alternative State 
programs continue to maintain equivalency with the Federal standards if 
NSPS OOOOa is revised as proposed here. With these changes, the EPA 
continues to find that the alternative State programs that were 
previously approved are still equivalent with, if not better than, the 
Federal requirements.
7. Onshore Natural Gas Processing Plants
a. Capital Expenditure
    The 2020 Technical Rule made certain amendments to the 2016 NSPS 
OOOOa definition of capital expenditure as it relates to modifications 
for VOC LDAR requirements at onshore natural gas processing plants. For 
the same reasons provided in the 2020 Technical Rule and reiterated 
below, the EPA is proposing to similarly amend this definition as it 
relates to the methane LDAR requirements at onshore natural gas 
processing plants.
    The 2020 Technical Rule amended the definition of ``capital 
expenditure'' at 40 CFR 50.5430a by replacing the equation used to 
determine the percent of replacement cost, ``Y.'' This amendment was 
necessary because, as originally promulgated, the equation for 
determining ``Y'' would result in an error, thus, making it difficult 
to determine whether a capital expenditure had occurred using the NSPS 
OOOOa equation. The 2020 Technical Rule replaced the equation with an 
equation that utilizes the consumer price indices, ``CPI'' because it 
more appropriately reflects inflation than the original equation. 
Specifically, the equation for ``Y'' as amended in the

[[Page 63168]]

2020 Technical Rule, is based on the CPI, where ``Y'' equals the CPI of 
the date of construction divided by the most recently available CPI of 
the date of the project, or ``CPIN/CPIPD.'' 
Further, the 2020 Technical Rule specifies that the ``annual average of 
the CPI for all urban consumers (CPI-U), U.S. city average, all items'' 
must be used for determining the CPI of the year of construction, and 
the ``CPI-U, U.S. city average, all items'' must be used for 
determining the CPI of the date of the project. This amendment 
clarified that the comparison of costs is between the original date of 
construction of the process unit (the affected facility) and the date 
of the project which adds equipment to the process unit. For these same 
reasons, the EPA is proposing that the definition of ``capital 
expenditure,'' as amended by the 2020 Technical Rule, also be used to 
determine whether modification had occurred and thus triggers the 
applicability of the methane LDAR requirements at onshore natural gas 
processing plants in the 2016 NSPS OOOOa.
b. Initial Compliance Period
    The 2020 Technical Rule amended the VOC standards for onshore 
natural gas processing plants to specify that the initial compliance 
deadline for the equipment leak standards is 180 days. The EPA is 
proposing to apply this clarification to the initial compliance 
deadline with the methane standards for equipment leaks at onshore 
natural gas processing plants.
    As explained in the 2020 Technical Rule, the EPA added a provision 
requiring compliance ``as soon as practicable, but no later than 180 
days after initial startup'' because that provision was in the NSPS for 
equipment leaks of VOC at onshore natural gas processing plants when it 
was first promulgated, specifically at 40 CFR 60.632(a) of part 60, 
subpart KKK (NSPS KKK). 85 FR 57408. This provision at 40 CFR 60.632(a) 
provides up to 180 days to come into compliance with NSPS KKK. In 2012, 
the EPA revised the standards in NSPS KKK with the promulgation of NSPS 
OOOO \189\ by lowering the leak definition for valves from 10,000 ppm 
to 500 ppm and requiring the monitoring of connectors. 77 FR 49490, 
49498. While the EPA did not mention that it was also amending the 180-
day compliance deadline in NSPS OOOO, this provision at 40 CFR 
60.632(a) was not included in NSPS OOOO and, in turn, was not included 
in NSPS OOOOa. During the rulemaking for NSPS OOOOa, the EPA declined a 
request to include this provision at 40 CFR 60.632(a) in NSPS OOOOa, 
explaining that such inclusion was not necessary because NSPS OOOOa 
already includes by reference a similar provision (i.e., 40 CFR 60.482-
1a(a)) which requires each owner or operator to ``demonstrate 
compliance . . . within 180 days of initial startup,'' 80 FR 56593, 
56647-8. However, in reassessing the issue during the rulemaking for 
the 2020 Technical Rule, the EPA noted that NSPS KKK includes both the 
provision in 40 CFR 60.632(a) and 40 CFR 60.482-1(a), which contains a 
provision that is the same as the one described above at 40 CFR 60.482-
1a(a), thus suggesting that 40 CFR 60.632(a) is not redundant or 
unnecessary. In fact, the absence of this provision in NSPS OOOO/OOOOa 
raised a question as to whether compliance is required within 30 days 
for equipment that is required to be monitored monthly. To clarify this 
confusion and remain consistent with NSPS KKK, the 2020 Technical Rule 
amended NSPS OOOOa to reinstate this provision at 40 CFR 60.632(a). For 
the same reasons explained above, the EPA is proposing to similarly 
apply this provision to compliance with methane standards for the 
equipment leaks at onshore natural gas processing plants.
---------------------------------------------------------------------------

    \189\ ``Standards of Performance for Crude Oil and Natural Gas 
Production, Transmission and Distribution for Which Construction, 
Modification or Reconstruction Commenced After August 23, 2011, and 
on or before September 18, 2015.''
---------------------------------------------------------------------------

    This provision clarifies that monitoring must begin as soon as 
practicable, but no later than 180 days after the initial startup of a 
new, modified, or reconstructed process unit at an onshore natural gas 
processing plant. Once started, monitoring must continue with the 
required schedule. For example, if pumps are monitored by month 3 of 
the initial startup period, then monthly monitoring is required from 
that point forward. This initial compliance period is different than 
the compliance requirements for newly added pumps and valves within a 
process unit that is already subject to a LDAR program. Initial 
monitoring for those newly added pumps and valves is required within 30 
days of the startup of the pump or valve (i.e., when the equipment is 
first in VOC service).
8. Technical Corrections and Clarifications
    The 2020 Technical Rule also revised the 2016 NSPS OOOOa for VOC 
emissions to include certain additional technical corrections and 
clarifications. In this action, the EPA is proposing to apply these 
same technical corrections and clarifications to the methane standards 
for production and processing segments and/or the methane and VOC 
standards for the transmission and storage segment in the 2016 NSPS 
OOOOa, as appropriate. Specifically, the EPA is proposing to:
     Revise 40 CFR 60.5385a(a)(1), 60.5410a(c)(1), 
60.5415a(c)(1), and 60.5420a(b)(4)(i) and (c)(3)(i) to clarify that 
hours or months of operation at reciprocating compressor facilities 
must be measured beginning with the date of initial startup, the 
effective date of the requirement (August 2, 2016), or the last rod 
packing replacement, whichever is latest.
     Revise 40 CFR 60.5393a(b)(3)(ii) to correctly cross-
reference paragraph (b)(3)(i) of that section.
     Revise 40 CFR 60.5397a(c)(8) to clarify the calibration 
requirements when Method 21 of appendix A-7 to part 60 is used for 
fugitive emissions monitoring.
     Revise 40 CFR 60.5397a(d)(3) to correctly cross-reference 
paragraphs (g)(3) and (4) of that section.
     Revise 40 CFR 60.5401a(e) to remove the word ``routine'' 
to clarify that pumps in light liquid service, valves in gas/vapor 
service and light liquid service, and pressure relief devices (PRDs) in 
gas/vapor service within a process unit at an onshore natural gas 
processing plant located on the Alaska North Slope are not subject to 
any monitoring requirements, whether the monitoring is routine or 
nonroutine.
     Revise 40 CFR 60.5410a(e) to correctly reference pneumatic 
pump affected facilities located at a well site as opposed to pneumatic 
pump affected facilities not located at a natural gas processing plant 
(which would include those not at a well site). This correction 
reflects that the 2016 NSPS OOOOa do not contain standards for 
pneumatic pumps at gathering and boosting compressor stations. 81 FR 
35850.
     Revise 40 CFR 60.5411a(a)(1) to remove the reference to 
paragraphs (a) and (c) of 40 CFR 60.5412a for reciprocating compressor 
affected facilities.
     Revise 40 CFR 60.5411a(d)(1) to remove the reference to 
storage vessels, as this paragraph applies to all the sources listed in 
40 CFR 60.5411a(d), not only storage vessels.
     Revise 40 CFR 60.5412a(a)(1) and (d)(1)(iv) to clarify 
that all boilers and process heaters used as control devices on 
centrifugal compressors and storage vessels must introduce the vent 
stream into the flame zone. Additionally, revise 40 CFR 
60.5412a(a)(1)(iv) and (d)(1)(iv)(D) to clarify that the vent stream 
must be introduced with the primary fuel or as the primary fuel to

[[Page 63169]]

meet the performance requirement option. This is consistent with the 
performance testing exemption in 40 CFR 60.5413a and continuous 
monitoring exemption in 40 CFR 60.5417a for boilers and process heaters 
that introduce the vent stream with the primary fuel or as the primary 
fuel.
     Revise 40 CFR 60.5412a(c) to correctly reference both 
paragraphs (c)(1) and (2) of that section, for managing carbon in a 
carbon adsorption system.
     Revise 40 CFR 60.5413a(d)(5)(i) to reference fused silica-
coated stainless steel evacuated canisters instead of a specific name 
brand product.
     Revise 40 CFR 60.5413a(d)(9)(iii) to clarify the basis for 
the total hydrocarbon span for the alternative range is propane, just 
as the basis for the recommended total hydrocarbon span is propane.
     Revise 40 CFR 60.5413a(d)(12) to clarify that all data 
elements must be submitted for each test run.
     Revise 40 CFR 60.5415a(b)(3) to reference all applicable 
reporting and recordkeeping requirements.
     Revise 40 CFR 60.5416a(a)(4) to correctly cross-reference 
40 CFR 60.5411a(a)(3)(ii).
     Revise 40 CFR 60.5417a(a) to clarify requirements for 
controls not specifically listed in paragraph (d) of that section.
     Revise 40 CFR 60.5422a(b) to correctly cross-reference 40 
CFR 60.487a(b)(1) through (3) and (b)(5).
     Revise 40 CFR 60.5422a(c) to correctly cross-reference 40 
CFR 60.487a(c)(2)(i) through (iv) and (c)(2)(vii) through (viii).
     Revise 40 CFR 60.5423a(b) to simplify the reporting 
language and clarify what data are required in the report of excess 
emissions for sweetening unit affected facilities.
     Revise 40 CFR 60.5430a to remove the phrase ``including 
but not limited to'' from the ``fugitive emissions component'' 
definition. During the 2016 NSPS OOOOa rulemaking, the EPA stated in a 
response to comment that this phrase is being removed,\190\ but did not 
do so in that rulemaking.
---------------------------------------------------------------------------

    \190\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-7632, Chapter 
4, page 4-319.
---------------------------------------------------------------------------

     Revise 40 CFR 60.5430a to remove the phrase ``at the sales 
meter'' from the ``low pressure well'' definition to clarify that when 
determining the low-pressure status of a well, pressure is measured 
within the flow line, rather than at the sales meter.
     Revise Table 3 of 40 CFR part 60, subpart OOOOa, to 
correctly indicate that the performance tests in 40 CFR 60.8 do not 
apply to pneumatic pump affected facilities.
     Revise Table 3 of 40 CFR part 60, subpart OOOOa, to 
include the collection of fugitive emissions components at a well site 
and the collection of fugitive emissions components at a compressor 
station in the list of exclusions for notification of reconstruction.
     Revise 40 CFR 60.5393a(f), 60.5410a(e)(8), 60.5411a(e), 
60.5415a(b) introductory text and (b)(4), 60.5416a(d), and 60.5420a(b) 
introductory text and (b)(13), and introductory text in 40 CFR 60.5411a 
and 60.5416a, to remove language associated with the administrative 
stay we issued under section 307(d)(7)(B) of the CAA in ``Oil and 
Natural Gas Sector: Emission Standards for New, Reconstructed, and 
Modified Sources; Grant of Reconsideration and Partial Stay'' (82 FR 
25730, June 5, 2017). The administrative stay was vacated by the D.C. 
Circuit on July 3, 2017.

XI. Summary of Proposed NSPS OOOOb and EG OOOOc

    This section presents a summary of the specific NSPS standards and 
EG presumptive standards the EPA is proposing for various types of 
equipment and emission points. More details of the rationale for these 
standards and requirements, including alternative compliance options 
and exemptions to the standards, are provided in section XII of this 
preamble and the TSD for this action in the public docket. As stated in 
section I, the EPA intends to provide draft regulatory text for the 
proposed NSPS OOOOb and EG OOOOc in a supplemental proposal.

A. Fugitive Emissions From Well Sites and Compressor Stations

    Fugitive emissions are unintended emissions that can occur from a 
range of equipment at any time. The magnitude of these emissions can 
also vary widely. The EPA has historically targeted fugitive emissions 
from the Crude Oil and Natural Gas source category through ground-based 
component level monitoring using OGI, or alternatively, EPA Method 21.
    The EPA is proposing the following monitoring requirements and 
presumptive standards for the collection of fugitive emissions 
components located at well sites and compressor stations. Additional 
details for the proposed standards and proposed presumptive standards 
are included in the following subsections. Information received through 
the various solicitations in this section may be used to evaluate if a 
change in the BSER is appropriate from the proposed requirements below, 
specifically consideration of alternative measurement technologies as 
the BSER. Any potential changes would be addressed through a 
supplemental proposal.
     Well sites with total site-level baseline methane 
emissions less than 3 tpy: Demonstration, based on a site-specific 
survey, that actual emissions are reflected in the baseline methane 
emissions calculation,
     Well sites with total site-level baseline methane 
emissions of 3 tpy or greater: Quarterly OGI or EPA Method 21 
monitoring,
     (Co-proposal) Well sites with total site-level baseline 
methane emissions of 3 tpy or greater and less than 8 tpy: Semiannual 
OGI or EPA Method 21 monitoring,
     (Co-proposal) Well sites with total site-level baseline 
methane emissions of 8 tpy or greater: Quarterly OGI or EPA Method 21 
monitoring,
     Compressor stations: Quarterly OGI or EPA Method 21 
monitoring,
     Well sites and compressor stations located on the Alaska 
North Slope: Annual monitoring, with separate initial monitoring 
requirements, and
     Alternative screening approach for all well sites and 
compressor stations: Bimonthly screening surveys using advanced 
measurement technology and annual OGI or EPA Method 21 monitoring at 
each individual well site or compressor station.
1. Definition of Fugitive Emissions Component
    A key factor in evaluating how to target fugitive emissions is 
clearly identifying the emissions of concern and the sources of those 
emissions. In the 2016 NSPS OOOOa, the EPA defined ``fugitive emissions 
component'' as ``any component with the potential to emit methane and 
VOCs'' and included several specific component types, ranging from 
valves and connectors, to openings on controlled storage vessels that 
were not regulated under NSPS OOOOa.
    However, data shows that the universe of components with potential 
for fugitive emissions is broader than the illustrative list included 
in the 2016 NSPS OOOOa, and that the majority of the largest emissions 
events occur from a subset of components that may not have been clearly 
included in the definition. Therefore, the EPA is proposing a new 
definition for ``fugitive emissions component'' to provide clarity that 
these sources of large emission events are covered.

[[Page 63170]]

    ``Fugitive emissions component'' is proposed to be any component 
that has the potential to emit fugitive emissions of methane and VOC at 
a well site or compressor station, including valves, connectors, PRDs, 
open-ended lines, flanges, all covers and closed vent systems, all 
thief hatches or other openings on a controlled storage vessel, 
compressors, instruments, meters, natural gas-driven pneumatic 
controllers or natural gas-driven pumps. However, natural gas 
discharged from natural gas-driven pneumatic controllers or natural 
gas-driven pumps are not considered fugitive emissions if the device is 
operating properly and in accordance with manufacturers specifications. 
Control devices, including flares, with emissions resulting from the 
device operating in a manner that is not in full compliance with any 
Federal rule, State rule, or permit, are also considered fugitive 
emissions components. This proposed definition includes the same 
components that were included in the 2016 NSPS OOOOa and adds sources 
of large emissions, such as malfunctioning controllers or control 
devices.
    The inclusion of specific component types in this proposed 
definition would allow the use of OGI, EPA Method 21, or an alternative 
screening technology to identify emissions that would either be 
repaired (i.e., leaks) or have a root cause analysis with corrective 
action (e.g., malfunctioning control device, unintentional gas carry 
through, venting from covers and openings on a controlled storage 
vessel, or malfunctioning natural gas-driven pneumatic controllers). 
Further, we are proposing that where a CVS is used to route emissions 
from an affected facility (i.e., centrifugal or reciprocating 
compressor, pneumatic pump, or storage vessel), the owner or operator 
would demonstrate there are no detectable emissions from the covers and 
CVS through the OGI (or EPA Method 21) monitoring conducted during the 
fugitive emissions survey. Where emissions are detected, corrective 
actions to complete all necessary repairs as soon as practicable would 
be required, and the emissions would be considered a potential 
violation of the no detectable emissions standard. In the case of a 
malfunction or operational upset of a control device or the equipment 
itself, where emissions are not expected to occur if the equipment is 
operating in compliance with the standards of the rule, this proposal 
would require the owner or operator to conduct a root cause analysis to 
determine why the emissions are present, take corrective action to 
complete all necessary repairs as soon as practicable and prevent 
reoccurrence of emissions, and report the malfunction or operational 
upset as a potential violation of the underlying standards for the 
source of the emissions. We are soliciting comment on whether to 
include the option to continue utilizing monthly AVO surveys as 
demonstrations of no detectable emissions from a CVS but are not 
proposing that option specifically. Because the EPA is proposing both 
NSPS and EG in this action, we anticipate that CVS associated with 
controlled pneumatic pumps will be located at well sites subject to 
fugitive emissions monitoring. Therefore, we do not believe the monthly 
AVO option is necessary. However, we are soliciting comment on whether 
there are circumstances where a CVS associated with a controlled 
pneumatic pump is located at a well site not otherwise subject to 
fugitive emissions monitoring and where OGI (or EPA Method 21) would be 
an additional burden.
    The EPA is soliciting comment on this proposed definition of 
``fugitive emissions component,'' including any additional components 
or characterization of components that should be included. Further, we 
are soliciting comment on the use of the fugitive emissions survey to 
identify malfunctions and other large emission sources where the 
equipment is not operating in compliance with the underlying standards, 
including the proposed requirement to perform a root cause analysis and 
to take corrective action to mitigate and prevent future malfunctions.
2. Fugitive Emissions From Well Sites
    The current NSPS for reducing fugitive VOC and methane emissions at 
well sites requires semiannual monitoring, except that a low production 
well site (one that produces at or below 15 barrels of oil equivalent 
(boe) per day) is exempt from VOC monitoring. As explained in section 
X.A.1, we are proposing to remove that exemption from NSPS OOOOa, as we 
have concluded that exemption was not justified by the underlying 
record and does not represent BSER. Further, based on our revised BSER 
analysis, which is summarized in section XII.A.1.a, the EPA is 
proposing updated standards for reducing fugitive VOC and methane 
emissions from the collection of fugitive emissions components located 
at new, modified, or reconstructed well sites (under the newly proposed 
NSPS OOOOb). Also, for the reasons discussed in section XII.A.2, the 
EPA is proposing to determine that the BSER analysis supports a 
presumptive standard for reducing methane emissions from the collection 
of fugitive emissions components located at existing well sites (under 
the newly proposed EG OOOOc) that is the same as what we are proposing 
for the NSPS (for NSPS OOOOb). Provided below is a summary of the 
proposed updated NSPS and the proposed EG.
a. NSPS OOOOb
    For new, modified, or reconstructed sources, we are proposing a 
fugitive emissions monitoring and repair program that includes 
monitoring for fugitive emissions with OGI in accordance with the 
proposed 40 CFR part 60, appendix K (``appendix K''), which is included 
in this action and outlines the proposed procedures that must be 
followed to identify emissions using OGI.\191\ We are also proposing 
that EPA Method 21 may be used as an alternative to OGI monitoring. We 
are further proposing that monitoring must begin within 90 days of 
startup of production (or startup of production after modification).
---------------------------------------------------------------------------

    \191\ ``Determination of Volatile Organic Compound and 
Greenhouse Gas Leaks Using Optical Gas Imaging'' located at Docket 
ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    Unlike in NSPS OOOOa which, as amended by the 2020 Technical Rule, 
set VOC monitoring frequency based on production level, the EPA is 
proposing that the OGI monitoring frequency be based on the site-level 
methane baseline emissions,\192\ as determined, in part, through 
equipment/component count emission factors. The EPA is proposing the 
calculation of the total site-wide methane emissions, including 
fugitive emissions from components, emissions from natural gas-driven 
pneumatic controllers, natural gas-driven pneumatic pumps, storage 
vessels, as well as other regulated and non-regulated emission sources. 
Specifically, we are proposing that owners or operators would calculate 
the site-level baseline methane emissions using a combination of 
population-based emission factors and storage vessel emissions. 
Further, the EPA proposes this calculation would be repeated every time 
equipment is added to or removed from the site. For each natural gas-
driven pneumatic pump, continuous bleed natural gas-driven pneumatic

[[Page 63171]]

controller, and intermittent bleed natural gas-driven pneumatic 
controller located at the well site, the owner or operator would apply 
the population emission factors for all components found in Table W-1A 
of GHGRP subpart W. For each piece of major production and processing 
equipment and each wellhead located at the well site, the owner or 
operator would first apply the default average component counts for 
major equipment found in Table W-1B and Table W-1C of GHGRP subpart W, 
and then apply the component-type emission factors for the population 
of valves, connectors, open-ended lines, and PRVs found in Table 2-8 of 
the 1995 Emissions Protocol.\193\ Finally, the owner or operator would 
use the calculated potential methane emissions after applying control 
(if applicable) for each storage vessel tank battery located at the 
well site. The sum of the emissions estimated for all equipment at the 
site would be used as the baseline methane emissions for determining 
the applicable monitoring frequency. The EPA proposes to use the 
default population emission factors found in Table W-1A of GHGRP 
subpart W and the default average component counts for major equipment 
found in Tables W-1B and W-1C of GHGRP subpart W because they are well-
vetted emission and activity factors used by the Agency. The EPA is not 
incorporating these emission factors directly into the proposed NSPS 
OOOOb or EG OOOOc because they could be the subject of future GHGRP 
subpart W revisions, and if revised, those revisions would be relevant 
to this calculation. For the individual components (e.g., valves and 
connectors), the EPA proposes to rely on the component-type emission 
factors found in Table 2-8 of the 1995 Emissions Protocol for purposes 
of quantifying emissions from major production and processing equipment 
and each wellhead located at the well site because these data have been 
relied upon in previous rulemakings for this sector, have been the 
subject of extensive public comment, and the EPA has determined that 
they are appropriate to use for purposes of this action.
---------------------------------------------------------------------------

    \192\ As shown in the TSD, the EPA analyzed the monitoring 
frequency for both methane and VOC under both the single pollutant 
approach and the multipollutant approach. Because the composition of 
gas at a well site is predominantly methane (approximately 70 
percent), a methane threshold represents the lowest threshold that 
is cost effective to control both VOC and methane emissions.
    \193\ EPA, Protocol for Equipment Leak Emission Estimates, EPA-
453/R-95-017, November 1995.
---------------------------------------------------------------------------

    The EPA requests comment on whether the proposed methodologies for 
calculating site-level baseline methane emissions are appropriate for 
these emission sources, and if not, what methodologies would be more 
appropriate. Specifically, the EPA recognizes the proposed calculation 
methodology assumes all equipment is operating as designed (e.g., 
controlled storage vessels with all vapors routed to a control that is 
actually achieving 95 percent reduction or greater). Therefore, we are 
soliciting comment on whether sites should use the uncontrolled PTE 
calculation for their storage vessels in their site-level baseline 
estimate to account for times when these vessels are not operating as 
designed, which is a known cause of large emission events of concern. 
Further, to that point, the EPA is soliciting comment on how to develop 
a factor that could be applied to the site-level baseline calculation 
that would account for large emission events, or any specific data that 
would provide a factor for these events. As we state throughout this 
preamble, large emission events are of specific concern and fugitive 
emissions monitoring is an effective tool for detecting these 
emissions, therefore, we acknowledge there is considerable interest 
from various stakeholders that these emission events are accounted for 
in our analyses. At this time, the EPA does not have enough information 
to develop a factor or determine how to best apply that factor. 
Information provided through this solicitation would allow us to 
consider additional revisions to this calculation methodology through a 
supplemental proposal.
    The EPA is also soliciting comment on whether providing direct 
major equipment population emission factors that can be combined with 
site-specific gas compositions would provide a more transparent and 
less burdensome means to develop the site-specific emissions estimates 
than using a combination of major equipment counts, specific component 
counts per major equipment, and component-level population emission 
factors. Furthermore, the EPA requests comment on whether site-level 
baseline methane emissions should be determined using a baseline 
emissions survey instead of the proposed methodology, and if so, what 
methodologies should be used to quantify emissions from the survey such 
as measurement or emission factors based on leaking component emission 
factors. The EPA also solicits comment on specific methodologies to 
support commenters' positions. The EPA also requests comment on whether 
there are additional production and processing equipment or emission 
sources that should be included in the site-level baseline methane 
emissions. For example, the EPA is aware that there could be emission 
sources such as engines, dehydrator venting, compressor venting, 
associated gas venting, and migration of gas outside of the wellbore at 
a well site. If such equipment or emission sources should be included 
in the site-level baseline, the EPA requests comment on methodologies 
for quantifying emissions for purposes of the baseline.
    Based on the analysis described in section XII.A.1, the potential 
for fugitive emissions is impacted more by the number and type of 
equipment at the site, and not by the volume of production. Therefore, 
the EPA believes it is more appropriate to use site-specific emissions 
estimates based on the number and type of equipment located at the 
individual site to determine the monitoring frequency. Table 13 
summarizes the proposed site-level baseline methane thresholds for the 
proposed monitoring frequencies, which according to our analysis would 
achieve the greatest cost-effective emission reductions.
    As noted below, the EPA solicits comment on all aspects of the 
proposed tiered approach to monitoring that is summarized in Table 13. 
Although we are proposing no routine OGI monitoring where site-level 
baseline methane emissions are below 3 tpy, the EPA is proposing to 
require these sites to demonstrate the actual emissions are accounted 
for in the calculation. This demonstration would include a survey, such 
as OGI, EPA Method 21 (including provisions for the use of a soap 
solution), or advanced measurement technologies. Given that this 
demonstration is designed to show actual emissions are below 3 tpy, and 
most survey techniques are not quantitative, the EPA anticipates that 
sources finding emissions will make repairs on equipment/components 
identified as leaking during the demonstration survey.
    The EPA acknowledges that the 2016 NSPS OOOOa and this proposal 
allow the use of EPA Method 21 as an alternative to OGI monitoring to 
detect fugitive emissions from the collection of fugitive emissions 
components under the proposed tiered approach to monitoring. However, 
as discussed in section XI.A.5, EPA Method 21 is not proposed as an 
alternative for follow-up OGI surveys under the proposed alternative 
screening approach using advanced measurement technologies when 
screening detects emissions. This is because EPA Method 21 is not able 
to find all sources of leaks and is therefore not an appropriate method 
for detection in these cases where large emissions events have been 
identified. Given this limitation, the EPA is soliciting comment on 
whether EPA Method 21 remains an appropriate

[[Page 63172]]

alternative to OGI for routine OGI surveys.

 Table 13--Proposed Well Site Monitoring Frequencies Based on Site-Level
                       Baseline Methane Emissions
------------------------------------------------------------------------
 Site-level baseline methane      Proposed OGI         Co-proposed OGI
     emissions threshold      monitoring frequency  monitoring frequency
------------------------------------------------------------------------
>0 and <3 tpy...............  No routine            No routine
                               monitoring required.  monitoring
                                                     required.
>=3 and <8 tpy..............  Quarterly...........  Semiannual.
>=8 tpy.....................  Quarterly...........  Quarterly.
------------------------------------------------------------------------

    Where quarterly monitoring is proposed, subsequent quarterly 
monitoring would occur at least 60 days apart. Where semiannual 
monitoring is co-proposed, subsequent semiannual monitoring would occur 
at least 4 months apart and no more than 7 months apart. We are 
proposing to retain the provision in the 2016 NSPS OOOOa that the 
quarterly monitoring may be waived when temperatures are below 0 [deg]F 
for two of three consecutive calendar months of a quarterly monitoring 
period.
    The EPA has previously required the use of OGI technology to detect 
fugitive emissions of methane and VOC from the oil and gas sector 
(i.e., well sites and compressor stations). However, the EPA had not 
developed a protocol for its use even though the EPA has previously 
mentioned the need for an OGI protocol during other rulemakings where 
OGI has been proposed for leak detection.\194\ In this document, the 
EPA is proposing a draft protocol for the use of OGI as appendix K to 
40 CFR part 60. The EPA notes that while this protocol is being 
proposed for use in the oil and gas sector, the applicability of the 
protocol is broader. The protocol is applicable to surveys of process 
equipment using OGI cameras in the entire oil and gas upstream and 
downstream sectors from production to refining to distribution where a 
subpart in those sectors references its use.
---------------------------------------------------------------------------

    \194\ The development of appendix K to 40 CFR part 60 was 
previously mentioned in both the proposal for the National Uniform 
Emission Standards for Storage Vessel and Transfer Operations, 
Equipment Leaks, and Closed Vent Systems and Control Devices; and 
Revisions to the National Uniform Emission Standards General 
Provisions (77 FR 17897, March 26, 2012) and the Petroleum Refinery 
Sector Risk and Technology Review and New Source Performance 
Standards (79 FR 36880, June 30, 2014).
---------------------------------------------------------------------------

    As part of the development of appendix K, the EPA conducted an 
extensive literature review on the technology development as well as 
observations on current application of OGI technology. Approximately 
150 references identify the technology, applications, and limitations 
of OGI. The EPA also commissioned multiple laboratory studies and OGI 
technology evaluations. Additionally, on November 9 and 10, 2020, the 
EPA held a virtual stakeholder workshop to gather input on development 
of a protocol for the use of OGI. The information obtained from these 
efforts was used to develop the TSD for appendix K, which provides 
technical analyses, experimental results, and other supplemental 
information used to evaluate and develop standardized procedures for 
the use of OGI technology in monitoring for fugitive emissions of VOCs, 
HAP, and methane from industrial environments.\195\
---------------------------------------------------------------------------

    \195\ Technical Support Document--Optical Gas Imaging Protocol 
(40 CFR part 60, Appendix K), available in the docket for this 
action.
---------------------------------------------------------------------------

    Appendix K outlines the proposed procedures that instrument 
operators must follow to identify leaks or fugitive emissions using a 
hand-held, field portable infrared camera. Additionally, appendix K 
contains proposed specifications relating to the required performance 
of qualifying infrared cameras, required operator training and 
verification, determination of an operating window for performing 
surveys, and requirements for a monitoring plan and recordkeeping. The 
EPA is requesting comment on all aspects of the draft OGI protocol 
being proposed as appendix K to 40 CFR part 60.\196\
---------------------------------------------------------------------------

    \196\ See appendix K in Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    As mentioned in section X.B.4.f, we are proposing that, once 
fugitive methane emissions are detected during the OGI survey, a first 
attempt at repair must be made within 30 days of detecting the fugitive 
emissions, with final repair, including resurvey to verify repair, 
completed within 30 days after the first attempt. These proposed repair 
requirements with respect to methane fugitive emissions are the same as 
those made in the 2020 Technical Rule for VOC fugitive emissions (and 
proposed in section X.B.4.f for methane in this action). Because large 
emission events contribute disproportionately to emissions, the EPA is 
soliciting comment on how to structure a requirement that would tier 
repair deadlines based on the severity of the fugitive emissions 
identified during the OGI (or EPA Method 21) surveys. In order for such 
a structure to work, there would need to be a way to qualify which 
fugitive emissions are smaller and which are larger, as the initial 
monitoring with OGI will not provide this information. One approach 
could be to define broad categories of leaks and make assumptions about 
the magnitude of emissions for those broad categories. For example, an 
open thief hatch would be considered a very large leak due to the 
surface opening size, and it would need to be remedied on the tightest 
timeframe, whereas a leaking connector would be considered a small leak 
based on historical emissions factors and could be repaired on a more 
lenient timeframe. The EPA is soliciting comments on how this approach 
could be structured, particularly the types of leaks that would fall 
into each broad category and the appropriate repair timeframes for each 
of the categories. The EPA is also soliciting comment on other 
approaches that could also be implemented for repairing fugitive 
emissions in a tiered structure. Finally, we are proposing to retain 
the requirement for owners and operators to develop a fugitive 
emissions monitoring plan that covers all the applicable requirements 
for the collection of fugitive emissions components located at a well 
site and includes the elements specified in the proposed appendix K 
when using OGI.
    The affected facilities include well sites with major production 
and processing equipment, and centralized tank batteries. As in the 
2020 Technical Rule, the EPA is proposing to not include ``wellhead 
only well sites,'' as affected facilities when the well site is a 
wellhead only well site at the date it becomes subject to the rule. 
Based on the proposed site-level baseline methane emissions calculation 
methodology, wellhead only sites would only calculate emissions from 
fugitive components (e.g., valves, connectors, flanges, and open-ended 
lines) that are located on the wellhead. We believe

[[Page 63173]]

these sites would not exceed the 3 tpy threshold to require routine 
monitoring. However, unlike the 2020 Technical Rule, the EPA is 
proposing that when a well site later removes all major production and 
processing equipment such that it becomes a wellhead only well site, it 
must recalculate the emissions in order to determine if a different 
frequency is then required. In this proposal, the definitions for 
``wellhead only well site'' and ``well site'' would be the same as 
those finalized in the 2020 Technical Rule. Specifically, ``wellhead 
only well site'' means ``for purposes of the fugitive emissions 
standards, a well site that contains one or more wellheads and no major 
production and processing equipment.'' The term ``major production and 
processing equipment'' refers to ``reciprocating or centrifugal 
compressors, glycol dehydrators, heater/treaters, separators, and 
storage vessels collecting crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water.'' The EPA is soliciting comment 
on whether any other equipment not included in this definition should 
be added in order to clearly specify what well sites are considered 
wellhead only sites. Specifically, the EPA is soliciting comment on the 
inclusion of natural gas-driven pneumatic controllers, natural gas-
driven pneumatic pumps, and pumpjack engines in the definition of 
``major production and processing equipment.'' A ``well site'' means 
one or more surface sites that are constructed for the drilling and 
subsequent operation of any oil well, natural gas well, or injection 
well. For purposes of the fugitive emissions standards, a well site 
includes a centralized production facility. Also, for purposes of the 
fugitive emissions standards, a well site does not include: (1) UIC 
Class II oilfield disposal wells and disposal facilities; (2) UIC Class 
I oilfield disposal wells; and (3) the flange immediately upstream of 
the custody meter assembly and equipment, including fugitive emissions 
components, located downstream of this flange.
    In addition to retaining the above definitions, the EPA is also 
proposing a new definition for ``centralized production facility'' for 
purposes of fugitive emissions requirements for well sites, where a 
``centralized tank battery'' is one or more permanent storage tanks and 
all equipment at a single stationary source used to gather, for the 
purpose of sale or processing to sell, crude oil, condensate, produced 
water, or intermediate hydrocarbon liquid from one or more offsite 
natural gas or oil production wells. This equipment includes, but is 
not limited to, equipment used for storage, separation, treating, 
dehydration, artificial lift, combustion, compression, pumping, 
metering, monitoring, and flowline. Process vessels and process tanks 
are not considered storage vessels or storage tanks. A centralized 
production facility is located upstream of the natural gas processing 
plant or the crude oil pipeline breakout station and is a part of 
producing operations. Additional discussion on centralized production 
facilities is included in section XI.L.
    The EPA is not proposing any change to the current definition of 
modification as it relates to fugitive emissions requirements at well 
sites or centralized production facilities. Specifically, modification 
occurs at a well site when: (1) A new well is drilled at an existing 
well site; (2) a well at an existing well site is hydraulically 
fractured; or (3) a well at an existing well site is hydraulically 
refractured. Similarly, modification occurs at a centralized production 
facility when (1) any of the actions above occur at an existing 
centralized production facility; (2) a well sending production to an 
existing centralized production facility is modified as defined above 
for well sites; or (3) a well site subject to the fugitive emissions 
standards for new sources removes all major production and processing 
equipment such that it becomes a wellhead only well site and sends 
production to an existing centralized production facility.
b. EG OOOOc
    For existing well sites (for EG OOOOc), we are proposing a 
presumptive standard that follows the same fugitive monitoring and 
repair program as for new sources. For the reasons discussed in section 
XII.A.2, the BSER analysis for existing sources supports proposing a 
presumptive standard for reducing methane emissions from the collection 
of fugitive emissions components located at existing well sites that is 
the same as what the EPA is proposing for new, reconstructed, or 
modified sources (for NSPS OOOOb). The EPA did not identify any factors 
specific to existing sources that would alter the analysis performed 
for new sources to make that analysis different for existing well 
sites. The EPA determined that the OGI technology, methane emission 
reductions, costs, and cost effectiveness discussed above for the 
collection of fugitive emissions components at new well sites are also 
applicable for the collection of fugitive emissions components at 
existing well sites. Further, the fugitive emissions requirements do 
not require the installation of controls on existing equipment or the 
retrofit of equipment, which can generally be an additional factor for 
consideration when determining the BSER for existing sources. 
Therefore, the EPA found is appropriate to use the analysis developed 
for the proposed NSPS OOOOb to also develop the BSER and proposed 
presumptive standards for the EG OOOOc.
    Based on the information available at this time, the EPA thinks the 
large number of existing well sites, many of which are not complex 
warrants soliciting comment on whether existing well sites (or a 
subcategory thereof) could have different emission profiles due to 
certain site characteristics or other factors that would suggest a 
different presumptive standard is appropriate. Further, we remain 
concerned about the burden of fugitive emissions monitoring 
requirements on small businesses. Therefore, we are requesting comment 
on regulatory alternatives for well sites that accomplish the stated 
objectives of the CAA and which minimize any significant economic 
impact of the proposed rule on small entities, including any 
information or data that pertain to the emissions impacts and costs of 
our proposal to remove the exemption from fugitive monitoring for well 
sites with low emissions, or would support alternative fugitive 
monitoring requirements for these sites. We are soliciting data that 
assess the emissions from low production well sites, and information on 
any factors that could make certain well sites less likely to emit VOC 
and methane, including geologic features, equipment onsite, production 
levels, and any other factors that could establish the basis for 
appropriate regulatory alternatives for these sites. Further, the EPA 
is aware there are a subset of existing well sites that are owned by 
individual homeowners, farmers, or companies with very few employees 
(well below the threshold defining a small business). For these owners, 
the EPA is concerned our analysis underestimates the actual burden 
imposed by these proposed standards. As an example, ownership may be 
limited to 1 or 2 wells located on an individual's property, for which 
the production is used for heating the home. The cost burden of 
conducting fugitive emissions surveys in this type of scenario has not 
fully be analyzed. Therefore, the EPA solicits comment and information 
that would allow us to

[[Page 63174]]

further evaluate the burden on the smallest companies to further 
propose appropriate standards at this subset (or other similar subsets) 
of well sites through a supplemental proposal.
    Finally, we are soliciting comment on all aspects of the proposed 
fugitive emissions requirements for both new and existing well sites, 
including whether we should use the tiering approach, whether the tiers 
we have defined are appropriate, and the monitoring requirements for 
each tier, including whether it would be cost-effective to monitor at 
more frequent intervals than proposed. The EPA may include revisions to 
this proposal for ground-based OGI monitoring at well sites if 
information is received that would warrant consideration of a different 
approach to establishing monitoring frequencies at well sites.
3. Fugitive Emissions from Compressor Stations
    The current NSPS for reducing fugitive emissions from the 
collection of fugitive emissions components located at a compressor 
station is a fugitive emissions monitoring and repair program requiring 
quarterly OGI monitoring.\197\ Based on our analysis, which is 
summarized in section XII.A.1.b, the EPA is proposing quarterly OGI 
monitoring requirement for both methane and VOC as it continues to 
reflect the BSER for reducing both emissions from fugitive components 
at new, modified, and reconstructed compressor stations. Likewise, the 
EPA is also proposing quarterly monitoring as a presumptive GHG 
standard (in the form of limitation on methane emissions) for the 
collection of fugitive emissions components located at existing 
compressor stations. The affected compressor stations include gathering 
and boosting, transmission, and storage compressor stations.
---------------------------------------------------------------------------

    \197\ Note that for gathering and boosting compressor stations, 
the EPA is proposing to rescind the 2020 Technical Rule amendment 
that changed the monitoring frequency to semiannual for VOC 
emissions. See section X.A.2 for more information.
---------------------------------------------------------------------------

a. NSPS OOOOb
    We are proposing that the quarterly monitoring using OGI be 
conducted in accordance with the proposed appendix K described above in 
section XI.A.2, which outlines procedures that must be followed to 
identify leaks using OGI. We are proposing to retain the current 
requirements that monitoring must begin within 90 days of startup of 
the station (or startup after modification), with subsequent quarterly 
monitoring occurring at least 60 days apart. Also, quarterly monitoring 
may be waived when temperatures are below 0 [deg]F for two of three 
consecutive calendar months of a quarterly monitoring period. We are 
also not proposing any change to the following repair-related 
requirements: Specifically, a first attempt at repair must be made 
within 30 days of detecting the fugitive emissions, with final repair, 
including resurvey to verify repair, completed within 30 days after the 
first attempt. In addition, owners and operators must develop a 
fugitive emissions monitoring plan that covers all the applicable 
requirements for the collection of fugitive emissions components 
located at a compressor station. In conjunction with the proposed 
requirement that monitoring be conducted in accordance with the 
proposed appendix K, we are proposing to require that the monitoring 
plan also include elements specified in the proposed appendix K when 
using OGI.
b. EG OOOOc
    For existing sources, we are proposing a presumptive standard that 
includes the same fugitive emissions monitoring and repair program as 
for new sources. For the reasons discussed in section XII.A.2, the BSER 
analysis for existing sources supports proposing a presumptive standard 
for reducing methane emissions from the collection of fugitive 
emissions components located at existing compressor stations that is 
the same as what the EPA is proposing for new, modified, or 
reconstructed sources (for NSPS OOOOb).
    Similar to well sites, we are soliciting comment on all aspects of 
the proposed quarterly monitoring for both new and existing compressor 
stations, including whether more frequent monitoring would be 
appropriate. We are also soliciting information on several additional 
topics. First, the EPA is soliciting comment and data to assess whether 
compressor stations should be subcategorized for the NSPS and/or the 
EG, which the EPA could consider through a supplemental proposal. For 
example, some industry stakeholders have asserted that station 
throughput directly correlates to the operating pressures, equipment 
counts, and condensate production, which would influence fugitive 
emissions at the station. They suggested that subcategorization based 
on design throughput capacity for the compressor station may be 
appropriate. We are specifically seeking information related to 
throughputs where fugitive emissions of methane are demonstrated to be 
minimal below a certain capacity. While this specific example was 
raised in the context of existing sources only, the EPA is also 
soliciting comment on whether new, modified, or reconstructed 
compressor stations could encounter the same issue and therefore 
warrant similar subcategorization.
    Next, for compressor stations, we are soliciting comment on delayed 
repairs by existing sources when parts are not readily available and 
must be special ordered. In comments submitted to the EPA as part of 
the stakeholder outreach conducted prior to this proposal, industry 
stakeholders stated that the EPA ``should acknowledge that existing 
sources are older pieces of equipment so there is a higher likelihood 
that replacement parts will not be readily available; therefore, a lack 
of available parts should be an appropriate cause to delay a repair.'' 
\198\ Industry stakeholders further explained that operators will need 
to special order replacement parts. Further, they stated in their 
comments that operators should be afforded 30 days to schedule the 
repair once they have received the replacement part. The EPA is 
soliciting comment and data to better understand the breadth of this 
issue with replacement parts for existing compressor stations. 
Additionally, we are soliciting comment on whether 30 days following 
receipt of the replacement part is appropriate for completing delayed 
repairs at existing compressor stations, whether there should be any 
limit on delays in repairs under these circumstances, and whether this 
compliance flexibility should be limited or disallowed based on the 
severity of the leak to be repaired.
---------------------------------------------------------------------------

    \198\ Document ID No. EPA-HQ-OAR-2021-0295-0033.
---------------------------------------------------------------------------

    We are also soliciting comment on the specific records that should 
be maintained and/or reported to justify delayed repairs as a result of 
part availability issues. Depending on the additional information 
received, the EPA may consider proposing changes to the proposed EG for 
compressor stations through a supplemental proposal.
    Finally, as discussed in section XI.A.2, the EPA is soliciting 
comment on whether the scheduling of repairs at compressor stations 
should be tiered based on severity of the emissions found. Please refer 
to section XI.A.3 for additional details on this solicitation for 
comment.
4. Well Sites and Compressor Stations on the Alaska North Slope
    For new, reconstructed, and modified well sites and compressor 
stations

[[Page 63175]]

located on the Alaska North Slope, based on the rationale provided in 
section X.B.4.c of this preamble, the EPA is proposing the same 
monitoring requirements as those in NSPS OOOOa (under newly proposed 
OOOOb). Also, the EPA is proposing to determine that the same technical 
infeasibility issues with weather conditions exist for existing well 
sites and compressor stations located on the Alaska North Slope. 
Therefore, the EPA is proposing a presumptive standard for reducing 
methane emissions from the collection of fugitive emissions components 
located at existing well sites and compressor stations located on the 
Alaska North Slope (under the newly proposed EG OOOOc) that is the same 
as what we are proposing for NSPS OOOOb.
    Specifically, the EPA is proposing to require annual monitoring of 
methane and VOC emissions at all well sites and compressor stations 
located on the Alaska North Slope, with subsequent annual monitoring at 
least 9 months apart but no more than 13 months apart. The EPA is also 
proposing to require that new, reconstructed, and modified well sites 
and compressor stations located on the Alaska North Slope that startup 
(initially, or after reconstruction or modification) between September 
and March to conduct initial monitoring of methane and VOC fugitive 
emissions within 6 months of startup, or by June 30, whichever is 
later. Finally, the EPA is proposing to require that new, 
reconstructed, and modified well sites and compressor stations located 
on the Alaska North Slope that startup (initially, or after 
reconstruction or modification) between April and August to conduct 
initial monitoring of methane and VOC fugitive emissions within 90 days 
of startup.
5. Alternative Screening Using Advanced Measurement Technologies
    For new, modified, or reconstructed sources (i.e., collection of 
fugitive emissions components located at well sites and compressor 
stations), the EPA is proposing an alternative fugitive emissions 
monitoring and repair program that includes bimonthly screening for 
large emission events using advanced measurement technologies followed 
with at least annual OGI in accordance with the proposed 40 CFR part 
60, appendix K (``appendix K''), which is included in this action and 
outlines the proposed procedures that must be followed to identify 
emissions using OGI.\199\ Additionally, we are proposing this same 
alternative screening using advanced measurement technologies as an 
alternative presumptive standard for existing sources.
---------------------------------------------------------------------------

    \199\ ``Determination of Volatile Organic Compound and 
Greenhouse Gas Leaks Using Optical Gas Imaging'' located at Docket 
ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    Specifically, the EPA is proposing to allow owners and operators 
the option to comply with this alternative fugitive emissions standard 
instead of the proposed ground based OGI surveys summarized in sections 
XI.A.2 and XI.A.3. The EPA proposes to require owners and operators 
choosing this alternative standard to do so for all affected well sites 
and compressor stations within a company-defined area. This company-
defined area could be a county, sub-basin, or other appropriate 
geographic area. Under this proposed alternative, the EPA proposes to 
require a screening survey on a bimonthly basis using a methane 
detection technology that has been demonstrated to achieve a minimum 
detection threshold of 10 kg/hr. This screening survey would be used to 
identify individual sites (i.e., well sites and compressor stations) 
where a follow-up ground-based OGI survey of all fugitive emissions 
components at the site is needed because fugitive emissions have been 
detected. Given the proposed minimum detection threshold of 10 kg/hr, 
which would constitute a significant emissions event, the EPA believes 
this follow-up OGI survey should be completed in an expeditious 
timeframe, therefore we are proposing to require this follow-up OGI 
survey of all fugitive emissions components at the site within 14 days 
of the screening survey. However, additional information is needed to 
fully evaluate the appropriateness of this deadline. Therefore, the EPA 
is soliciting comment on the proposed 14-day deadline for a follow-up 
OGI survey and information that would allow further evaluation of other 
potential deadlines to require.
    Next, for sites with emissions identified during screening and 
subject to this follow-up OGI survey, the EPA proposes that any 
fugitive emissions identified must be repaired, including those 
emissions identified during the screening survey. For purposes of this 
proposal, the EPA is proposing the same repair deadlines as those for 
the ground based OGI requirements discussed in sections XI.A.2 and 
XI.A.3, which are a first attempt at repair within 30 days of the OGI 
survey and final repair completed within 30 days of the first attempt. 
As noted in section XI.A.1, some equipment types with large emissions 
warrant a requirement for root cause analysis rather than simply 
repairing the emission source. The EPA solicits comment on how that 
root cause analysis with corrective action approach could be applied in 
this proposed alternative screening approach. Further, because large 
emission events, especially those identified during the screening 
surveys, contribute disproportionately to emissions, the EPA is also 
soliciting comment on how to structure a requirement that would tier 
repair deadlines based on the severity of the fugitive emissions when 
using this proposed alternative standard. See section XI.A.2 for 
additional discussion of this solicitation on tiered repairs.
    In addition to the bimonthly screening surveys proposed above, the 
EPA recognizes that component-level fugitive emissions may still be 
present at sites where the screening survey does not detect emissions. 
Therefore, in conjunction with these bimonthly screenings performed 
with the advanced measurement technology, the EPA is proposing to 
require a full OGI (or EPA Method 21) survey at least annually at each 
individual site utilizing the alternative screening standard. If the 
owner or operator performs an OGI survey in response to emissions found 
during the bimonthly screening survey, that OGI survey would count as 
the annual OGI survey; a second survey would not be required to comply 
with the annual OGI survey requirement and the clock would restart with 
the next annual survey due within 12 calendar months. The overall 
purpose of this annual OGI survey is to ensure that each individual 
site is surveyed with OGI at least annually, even where large emissions 
are not detected during the screening surveys using advanced 
measurement technology. The EPA is not allowing EPA Method 21 for use 
during the proposed follow-up OGI surveys when screening detects 
emissions because EPA Method 21 is not appropriate for detecting the 
sources of large emission events, such as malfunctioning control 
devices.
    Finally, the EPA is proposing to require that owners and operators 
include information specific to the alternative standard within their 
fugitive emissions monitoring plan. Since the 2016 NSPS OOOOa, owners 
and operators have been required to develop and maintain a fugitive 
emissions monitoring plan for all sites subject to the fugitive 
emissions requirements. This monitoring plan includes information 
regarding which sites are covered under the plan, which technology is 
being used (e.g., OGI or EPA Method 21), and site or company-

[[Page 63176]]

specific procedures that are employed to ensure compliant surveys. The 
EPA is proposing to add a requirement that the monitoring plan also 
address sites that are utilizing the proposed alternative standard. 
Specifically, the EPA is proposing a requirement to include the 
following information when the alternative standard is applied:
     Identification of the sites opting to comply with the 
alternative screening approach;
     General description of each site to be monitored, 
including latitude and longitude coordinates of the asset in decimal 
degrees to an accuracy and precision of five decimals of a degree using 
the North American Datum of 1983;
     Description of the measurement technology;
     Verification that the technology meets the 10 kg/hr 
methane detection threshold, including supporting data to demonstrate 
the sensitivity of the measurement technology as applied;
     Procedures for a daily verification check of the 
measurement sensitivity under field conditions (e.g., controlled 
releases);
     Standard operating procedures consistent with EPA's 
guidance \200\ and to include safety considerations, measurement 
limitations, personnel qualification/responsibilities, equipment and 
supplies, data and record management, and quality assurance/quality 
control (i.e., initial and ongoing calibration procedures, data quality 
indicators, and data quality objectives); and
---------------------------------------------------------------------------

    \200\ Guidance for Preparing Standard Operating Procedures 
(SOPs), EPA/600/B-07/001, April 2007, https://www.epa.gov/sites/default/files/2015-06/documents/g6-final.pdf.
---------------------------------------------------------------------------

     Procedures for conducting the screening.
    In the event that an owner or operator uses multiple technologies 
covered by one monitoring plan, the owner or operator would identify 
which technology is to be used on which site within the monitoring 
plan.
    In addition to the proposed requirements within the monitoring 
plan, the EPA is also proposing specific recordkeeping and reporting 
requirements associated with the follow-up OGI surveys that are 
consistent with the recordkeeping and reporting required for OGI 
surveys in NSPS OOOOa as amended in the 2020 Technical Rule. See 
section X.B.1.h and X.B.1.i. The EPA is soliciting comment on when 
notifications would be required for sites where the alternative 
standard is applied. Further, the EPA is soliciting comment on whether 
submission of the monitoring plan, and/or Agency approval before 
utilizing the alternative standard is necessary to ensure consistency 
in screening survey procedures in the absence of finalized methods or 
procedures.
    While the EPA is proposing the above alternative screening 
requirements, additional information is necessary to further refine the 
specific alternative work practice as it relates to the available 
technologies. Specific information is requested in the following 
paragraphs, and, if received, would allow the EPA to better analyze the 
BSER for fugitive emissions at well sites and compressor stations 
through a supplemental proposal.
    First, the EPA solicits comment on the use of 10 kg/hr as the 
minimum detection threshold for the advanced measurement technologies 
used in the alternative screening approach, including data that would 
support consideration of another detection threshold. The EPA also 
solicits comment on whether a matrix approach should be developed, 
instead of prescribing one detection threshold and screening frequency, 
and what that matrix should look like. In the matrix approach, the 
frequency of the screening surveys and regular OGI (or EPA Method 21) 
surveys would be based on the sensitivity of the technology, with the 
most sensitive detection thresholds having the least frequent screening 
and survey requirements and the least sensitive detection thresholds 
having the most frequent screening and survey requirements. For 
example, sites that are screened using a technology with a detection 
threshold of 1 kg/hr may require less frequent screening and may 
require an OGI survey less frequently than sites screened using a 
technology with a detection threshold of 50 kg/hr. We are also 
soliciting comment on the detection sensitivity of commercially 
available methane detection technologies based on conditions expected 
in the field, as well as factors that affect the detection sensitivity 
and how the detection sensitivity would change with these factors.
    Next, the EPA is soliciting comment on the standard operating 
procedures being used for commercially available technologies, 
including any manufacturer recommended data quality indicators and data 
quality objectives in use to validate these measurements. Additionally, 
for those commercially available technologies that quantify methane 
emissions rather than just detect methane, we are soliciting comment on 
the range of quantification based on conditions one would expect in the 
field.
    The EPA is seeking information that would allow us to further 
evaluate the potential costs and assumed emission reductions achieved 
through an alternative screening program. Therefore, the EPA is seeking 
information on the cost of screening surveys using different types of 
advanced measurement technologies, singularly or in combination, and 
factors that affect that cost (e.g., is it influenced by the number of 
sites and length of survey). Additionally, we are interested in 
understanding whether there would be opportunities for cost-sharing 
among operators and whether any aspect of regulation would be 
beneficial or required to facilitate such cost-sharing opportunities. 
We also solicit comment on whether these technologies and cost-sharing 
opportunities would allow for cost-effective monitoring at all sites 
owned or operated by the same company within a sub-basin or other 
discrete geographic area. Further, we seek comment on the current and 
expected availability of these advanced measurement technologies and 
the supporting personnel and infrastructure required to deploy them, 
how their cost and availability might be affected if demand for these 
technologies were to increase, and how quickly the use of these 
technologies could expand if they were integrated into this regulatory 
program either as a required element of fugitive monitoring or as this 
proposed alternative work practice.
    The EPA recognizes that the approach outlined above may not be 
suited to continuous monitoring technologies, such as network sensors 
or open-path technology. While these systems typically have the ability 
to meet the 10 kg/hr methane threshold discussed above \201\ the 
emissions from these well sites can be intermittent or tied to process 
events (e.g., pigging operations). We are concerned that the proposed 
alternative screening approach would trigger an OGI survey for every 
emission event, regardless of type, duration, or size, if a continuous 
monitoring technology is installed. This would disincentivize the use 
of continuous monitoring systems, which could be valuable tools in 
finding large emission sources sooner. While we believe that a 
framework for advanced measurement technologies that monitor sites 
continuously should be developed, we do not currently have all of the 
information that is necessary to develop

[[Page 63177]]

an equivalence demonstration for these monitors or to ensure the 
technology works appropriately over time. Therefore, we are soliciting 
comment on how an equivalence demonstration can be made for these 
continuous monitoring technologies.
---------------------------------------------------------------------------

    \201\ Alden et al., Single-Blind Quantification of Natural Gas 
Leaks from 1 km Distance Using Frequency Combs, Environmental 
Science and Technology, 2019, 53, 2908-2917.
---------------------------------------------------------------------------

    The framework for a continuous monitoring technology would need to 
cover the following items at a minimum: The number of monitors needed 
and the placement of the monitors; minimum response factor to methane; 
minimum detection level; frequency of data readings; how to interpret 
the monitor data to determine what emissions are a detection versus 
baseline emissions; how to determine allowable emissions versus leaks; 
the meteorological data criteria; measurement systems data quality 
indicators; calibration requirements and frequency of calibration 
checks; how downtime should be handled; and how to handle situations 
where the source of emissions cannot be identified even when the 
monitor registers a leak. We are soliciting comment on how to develop a 
framework that is flexible for multiple technologies while still 
ensuring that emissions are adequately detected and the monitors 
respond appropriately over time. Additionally, we are soliciting 
comment on whether these continuous monitors need to respond to other 
compounds as well as methane; how close a meteorological station must 
be to the monitored site; and whether OGI or EPA Method 21 surveys 
should still be required, and if so, at what frequency.
    At this time, the EPA does not have enough information to determine 
how this proposed alternative standard using advanced measurement 
technologies compares to the proposed BSER of OGI monitoring at well 
sites at a frequency that is based on the site baseline methane 
emissions as described in section XI.A.3.a, or to quarterly OGI 
monitoring at compressor stations. Information provided through this 
solicitation may be used to reevaluate BSER through a supplemental 
proposal.
6. Use of Information From Communities and Others
    As the EPA learned during the Methane Detection Technology 
Workshop, industry, researchers, and NGOs have utilized advanced 
methane detection systems to quickly identify large emission sources 
and target ground based OGI surveys. State and local governments, 
industry, researchers, and NGOs have been utilizing advanced 
technologies to better understand the detection of, source of, and 
factors that lead to large emission events. The EPA anticipates that 
the use of these techniques by a variety of parties, including 
communities located near oil and gas facilities or affected by oil and 
gas pollution, will continue to grow as these technologies become more 
widely available and decline in cost.
    The EPA is seeking comment on how to take advantage of the 
opportunities presented by the increasing use of these technologies to 
help identify and remediate large emission events (commonly known as 
``super-emitters''). Specifically, the EPA seeks comment on how to 
evaluate, design, and implement a program whereby communities and 
others could identify large emission events and, where there is 
credible information of such a large emission event, provide that 
information to owners and operators for subsequent investigation and 
remediation of the event. The EPA understands that these large emission 
events are often attributable to malfunctions or abnormal process 
conditions that should not be occurring at a well-operating, well-
maintained, and well-controlled facility that has implemented the 
various BSER measures identified in this proposal.
    We generally envision a program for finding large emission events 
that consists of a requirement that, if emissions are detected above a 
defined threshold by a community, a Federal or State agency, or any 
other third party, the owner or operator would be required to 
investigate the event, do a root cause analysis, and take appropriate 
action to mitigate the emissions, and maintain records and report on 
such events.
    We seek comment on all aspects of this concept, which would be 
developed further as part of a supplemental proposal. Among other 
things, the EPA is soliciting comment on an emissions threshold that 
could be used to define these large emission events, and which types of 
technologies would be suitable for identification of large emissions 
events. For example, there are some satellite systems capable of 
generally identifying emissions above 100 kg/hr with a spatial 
resolution which could allow identification of emission events from an 
individual site.\202\ Additionally there are other satellites systems 
available which have wider spatial resolution that can identify large 
methane emission events, and when combined with finer resolution 
platforms, could allow identification of emission events from an 
individual site. The EPA believes that any emissions visible by 
satellites should qualify as large emission events. However, the EPA 
solicits comment on whether the threshold for a large emission should 
be lower than what is visible by satellite.
---------------------------------------------------------------------------

    \202\ D.J. Varon, J. McKeever, D. Jervis, J.D. Maasakkers, S. 
Pandey, S. Houweling, I. Aben, T. Scarpelli, D.J. Jacob, Satellite 
Discovery of anomalously Large Methane Point Sources from Oil/Gas 
Production, available at https://doi.org/10.1029/2019GL083798, 
October 25, 2019.
---------------------------------------------------------------------------

    Second, in order to make this approach viable, the EPA would need 
to specify what actions an owner or operator must take when notified of 
a large emission event, including deadlines for taking such actions. 
These elements could include the specific steps the company would take 
to investigate the notification and mitigate the event, such as 
verifying the location of the emissions, conducting ground 
investigations to identify the specific emission source, conducting a 
root cause analysis, performing corrective action within a specific 
timeframe to mitigate the emissions, and preventing ongoing and future 
chronic or intermittent large emissions from that source. These steps 
could be incorporated into a fugitive emissions monitoring plan 
maintained by the owner or operator, and failure to take the actions 
specified by the owner or operator in the plan could be considered 
noncompliance. We seek comment on what specific follow-up actions or 
other procedures would be appropriate to require once a large emission 
event is identified, as well as appropriate deadlines for these 
actions.
    Third, the EPA would need to define guidelines for credible and 
actionable data. The EPA is soliciting comment on what these guidelines 
should entail and whether specific protocols (e.g., permissible 
detection technologies, data analytics, operator training, data 
reporting, public access, and data preservation) should govern the 
collection of such data and whether such data should conform to any 
type of certification. If specific certification or protocols are 
necessary, the EPA is soliciting comment on how that certification 
should be obtained.
    Fourth, we are also soliciting comment on best practices for the 
identification of the correct owner or operator of a facility 
responsible for such large emissions, since such information is 
necessary to halt such large-volume emission events, and how the 
community or other third-party should notify the owner or operator, as 
well as how the delegated authority should be made aware of such 
notification.
    Finally, we are soliciting comment on whether the EPA should 
develop a model plan for responding to notifications that companies 
could adopt instead of developing company- or site-specific plans, 
including what

[[Page 63178]]

elements should be included in that model plan.

B. Storage Vessels

1. NSPS OOOOb
    The current NSPS in subpart OOOOa for storage vessels is to reduce 
VOC emissions by 95 percent, and the standard applies to a single 
storage vessel with a potential for 6 or more tpy of VOC emissions. 
Based on our analysis, which is summarized in section XII.B.1, the EPA 
is proposing to retain the 95 percent reduction standard as it 
continues to reflect the BSER for reducing VOC emissions from new 
storage vessels. The EPA is also proposing to set GHG standards (in the 
form of limitations on methane emissions) for storage vessels in this 
action. Because the BSER for reducing VOC and methane emissions are the 
same, the proposed GHG standard is to reduce methane emissions by 95 
percent. The EPA continues to support the capture of gas vapors from 
storage vessels rather than the combustion of what can be an energy-
rich saleable product. We incentivize this by recognizing the use of 
vapor recovery as a part of the process, therefore the storage vessel 
emissions would not contribute to the site's potential-to-emit.
    Under the current NSPS for storage vessels, an affected facility is 
a single storage vessel with potential VOC emissions of 6 tpy or 
greater. The EPA is proposing to include a tank battery as a storage 
vessel affected facility. The EPA proposes to define a tank battery as 
a group of storage vessels that are physically adjacent and that 
receive fluids from the same source (e.g., well, process unit, 
compressor station, or set of wells, process units, or compressor 
stations) or which are manifolded together for liquid or vapor 
transfer.
    To determine whether a single storage vessel is an affected 
facility, the owner or operator would compare the 6 tpy VOC threshold 
to the potential emissions from that individual storage vessel; to 
determine whether a tank battery is an affected facility, the owner or 
operator would compare the 6 tpy VOC threshold to the aggregate 
potential emissions from the group of storage vessels. For new, 
modified, or reconstructed sources, if the potential VOC emissions from 
a storage vessel or tank battery exceeds the 6 tpy threshold, then it 
is a storage vessel affected facility and controls would be required. 
This is consistent with the EPA's initial determination in the 2012 
NSPS OOOO that controlling VOC emissions as low as 6 tpy from storage 
vessels is cost-effective. The proposed standard of 95 percent 
reduction of methane and VOC emissions, which is the same as the 
current VOC standard in the 2012 NSPS OOOO and 2016 NSPS OOOOa, can be 
achieved by capturing and routing the emissions utilizing a cover and 
closed vent system that routes captured emissions to a control device 
that achieves an emission reduction of 95 percent, or that routes 
captured emissions to a process.
    Finally, we are proposing specific provisions to clarify what 
circumstances constitute a modification of an existing storage vessel 
affected facility (single storage vessel or tank battery), and thus 
subject it to the proposed NSPS instead of the EG. The EPA is proposing 
that a single storage vessel or tank battery is modified when physical 
or operational changes are made to the single storage vessel or tank 
battery that result in an increase in the potential methane or VOC 
emissions. Physical or operational changes would be defined to include: 
(1) The addition of a storage vessel to an existing tank battery; (2) 
replacement of a storage vessel such that the cumulative storage 
capacity of the existing tank battery increases; and/or (3) an existing 
tank battery or single storage vessel that receives additional crude 
oil, condensate, intermediate hydrocarbons, or produced water 
throughput (from actions such as refracturing a well or adding a new 
well that sends these liquids to the tank battery). The EPA is 
proposing to require that the owner or operator recalculate the 
potential VOC emissions when any of these actions occur on an existing 
tank battery to determine if a modification has occurred. The existing 
tank battery will only become subject to the proposed NSPS if it is 
modified pursuant to this definition of modification and its potential 
VOC emissions exceed the proposed 6 tpy VOC emissions threshold.
2. EG OOOOc
    Based on our analysis, which is summarized in section XII.B.2, the 
EPA is proposing EG for existing storage vessels which include a 
presumptive GHG standard (in the form of limitation on methane 
emissions). For existing sources under the EG, the EPA is proposing to 
define a designated facility as an existing tank battery with potential 
methane emissions of 20 tpy or greater. The proposed definition of a 
tank battery in the EG is the same as the definition proposed for new 
sources; however, since the designated pollutant in the context of the 
EG is methane, determination of whether a tank battery is a designated 
facility would be based on its potential methane emissions only. Our 
analysis shows that it is cost effective to control an existing tank 
battery with potential methane emissions 20 tpy or higher. Similar to 
the proposed NSPS, we are proposing a presumptive standard that 
includes a 95 percent reduction of the methane emissions from each 
existing tank battery that qualifies as a designated facility. Such a 
standard could be achieved by capturing and routing the emissions by 
utilizing a cover and closed vent system that routes captured emissions 
to a control device that achieves an emission reduction of 95 percent, 
or routes emission back to a process.

C. Pneumatic Controllers

1. NSPS OOOOb
    The current NSPS OOOOa regulates certain continuous bleed natural 
gas driven pneumatic controllers, but includes different standards 
based on whether the pneumatic controller is located at an onshore 
natural gas processing plant. If the pneumatic controller is located at 
an onshore natural gas processing plant, then the current NSPS requires 
a zero bleed rate. If the pneumatic controller is located elsewhere, 
then the current NSPS requires the pneumatic controller to operate at a 
natural gas bleed rate no greater than 6 scfh. The current NSPS does 
not regulate intermittent vent natural gas driven pneumatic controllers 
at any location.
    Based on our analysis, which is summarized in section XII.C.1, the 
EPA is proposing pneumatic controller standards for NSPS OOOOb as 
follows. First, in addition to each single natural gas-driven 
continuous bleed pneumatic controller being an affected facility, the 
EPA proposes to define each natural gas-driven intermittent vent 
pneumatic controller as an affected facility. The EPA believes these 
pneumatic controllers should be covered by NSPS OOOOb because natural 
gas-driven intermittent devices represent a large majority of the 
overall population of pneumatic controllers and are responsible for the 
majority of emissions from these sources. We are proposing to define an 
intermittent vent natural gas-driven pneumatic controller as a 
pneumatic controller that is not designed to have a continuous bleed 
rate but is instead designed to only release natural gas to the 
atmosphere as part of the actuation cycle. This affected facility 
definition would apply at all sites, including natural gas processing 
plants.
    Second, we are proposing a requirement that all controllers

[[Page 63179]]

(continuous bleed and intermittent vent) must have a VOC and methane 
emission rate of zero. The proposed rule does not specify how this 
emission rate of zero must be achieved, but a variety of viable options 
are discussed in Section XII.C. including the use of pneumatic 
controllers that are not driven by natural gas such as air-driven 
pneumatic controllers and electric controllers, as well as natural gas 
driven controllers that are designed so that there are no emissions, 
such as self-contained pneumatic controllers. As noted above, the EPA 
is proposing that the definition of an affected facility would be each 
pneumatic controller that is driven by natural gas and that emits to 
the atmosphere. As such, pneumatic controllers that are not driven by 
natural gas would not be affected facilities, and thus would not be 
subject to the pneumatic controller requirements of NSPS OOOOb. 
Similarly, controllers that are driven by natural gas but that do not 
emit to the atmosphere would also not be affected facilities. In order 
to demonstrate that a particular pneumatic controller is not an 
affected facility, owners and operators should maintain documentation 
to show that such controllers are not natural gas driven such as 
documentation of the design of the system, and to ensure that they are 
operated in accordance with the design so that there are no emissions.
    In both NSPS OOOO and OOOOa, there is an exemption from the 
standards in cases where the use of a pneumatic controller affected 
facility with a bleed rate greater than the applicable standard is 
required based on functional needs, including but not limited to 
response time, safety, and positive actuation. The EPA is not 
maintaining this exemption in the proposed NSPS OOOOb, except for in 
very limited circumstances explained in section XII.C. As discussed in 
section XII.C., the reasons to allow for an exemption based on 
functional need in NSPS OOOO and OOOOa were based on the inability of a 
low-bleed controller to meet the functional requirements of an owner/
operator such that a high-bleed controller would be required in certain 
instances. Since we are now proposing that pneumatic controllers have a 
methane and VOC emission rate of zero, we do not believe that the 
reasons related to the use of low bleed controllers are still 
applicable. However, EPA is soliciting comment on whether owners/
operators believe that maintaining such an exemption based on 
functional need is appropriate, and if so why.
    The proposed rule includes an exemption from the zero-emission 
requirement for pneumatic controllers in Alaska at locations where 
power is not available. In these situations, the proposed standards 
require the use of a low-bleed controller instead of high-bleed 
controller. Further, in these situations (controllers in Alaska at 
location without power) the proposed rule includes the exemption that 
would allow the use of high-bleed controllers instead of low-bleed 
based on functional needs. Lastly, in these situations owners/operators 
must inspect intermittent vent controllers to ensure they are not 
venting during idle periods.
2. EG OOOOc
    In this action, the EPA is proposing to define designated 
facilities (existing sources) analogous to the affected facility 
definitions described above for pneumatic controllers under the NSPS. 
For the reasons discussed in section XII.C.2, the BSER analysis for 
existing sources supports proposing presumptive standards for reducing 
methane emissions from existing pneumatic controllers that are the same 
as those the EPA is proposing for new, modified, or reconstructed 
sources (for NSPS OOOOb).

D. Well Liquids Unloading Operations

    Well liquids unloading operations, which are currently unregulated 
under the NSPS OOOOa, refer to unloading of liquids that have 
accumulated over time in gas wells and are impeding or halting 
production. The EPA is proposing standards in the NSPS OOOOb to reduce 
methane and VOC emissions during liquids unloading operations.
1. NSPS OOOOb
    We are proposing standards to reduce VOC and methane emissions from 
each well that conducts a liquids unloading operation. Based on our 
analysis, which is summarized in section XII.D.1, we are proposing a 
standard under NSPS OOOOb that requires owners or operators to perform 
liquids unloading with zero methane or VOC emissions. In the event that 
it is technically infeasible or not safe to perform liquids unloading 
with zero emissions, the EPA is proposing to require that an owner or 
operator establish and follow BMPs to minimize methane and VOC 
emissions during liquids unloading events to the extent possible.
    The EPA is co-proposing two regulatory approach options to 
implement the rule requirements.
    For Option 1, the affected facility would be defined as every well 
that undergoes liquids unloading. This would mean that wells that 
utilize a non-emitting method for liquids unloading would be affected 
facilities and subject to certain reporting and recordkeeping 
requirements. These requirements would include records of the number of 
unloadings that occur and the method used. A summary of this 
information would also be required to be reported in the annual report. 
The EPA also recognizes that under some circumstances venting could 
occur when a selected liquids unloading method that is designed to not 
vent to the atmosphere is not properly applied (e.g., a technology 
malfunction or operator error). Under the proposed rule Option 1 owners 
and operators in this situation would be required to record and report 
these instances, as well as document and report the length of venting, 
and what actions were taken to minimize venting to the maximum extent 
possible.
    For wells that utilize methods that vent to the atmosphere, the 
proposed rule would require that owners or operators (1) Document why 
it is infeasible to utilize a non-emitting method due to technical, 
safety, or economic reasons; (2) develop BMPs that ensure that 
emissions during liquids unloading are minimized including, at a 
minimum, having a person on-site during the liquids unloading event to 
expeditiously end the venting when the liquids have been removed; (3) 
follow the BMPs during each liquids unloading event and maintain 
records demonstrating they were followed; and (4) report the number of 
liquids unloading events in an annual report, as well as the unloading 
events when the BMP was not followed. While the proposed rule would not 
dictate all of the specific practices that must be included, it would 
specify minimum acceptance criteria required for the types and nature 
of the practices. Examples of the types and nature of the required 
practice elements are provided in XII.D.1.e.
    For Option 2, the affected facility would be defined as every well 
that undergoes liquids unloading using a method that is not designed to 
totally eliminate venting. The significant difference in this option is 
that wells that utilize non-venting methods would not be affected 
facilities that are subject to the NSPS OOOOb. Therefore, they would 
not have requirements other than to maintain records to document that 
they used non-venting liquids unloading methods. The requirements for 
wells that use methods that vent would be the same as described above 
under Option 1. The EPA solicits comment on including information such 
as where the well stream was directed during unloading and emissions

[[Page 63180]]

manifested and whether an estimate of the VOC and methane emissions 
generated should be included in the annual report.
    There are several techniques owners and operators can choose from 
to unload liquids, including manual unloading, velocity tubing or 
velocity strings, beam or rod pumps, electric submergence pumps, 
intermittent unloading, gas lift (e.g., use of a plunger lift), foam 
agents, wellhead compression, and routing the gas to a sales line or 
back to a process. Although the unloading method employed by an owner 
or operator can itself be a method that can be employed in such a way 
that mitigates/eliminates venting of emissions from a liquids unloading 
event, indicating a particular method to meet a particular well's 
unloading needs is a production engineering decision. Based on 
available information, liquids unloading operations are often conducted 
in such a way that eliminates venting to the atmosphere and there are 
many options that include techniques and procedures that an owner or 
operator can choose from to achieve this standard (discussed in section 
XII.D.e of this preamble).
    However, the EPA recognizes that there may be reasons that a non-
venting method is infeasible for a particular well, and the proposed 
rule would allow for the use of BMPs to reduce the emissions to the 
maximum extent possible for such cases (discussed in section XII.D of 
this preamble). BMPs include, but are not limited to, following 
specific steps that create a differential pressure to minimize the need 
to vent a well to unload liquids and reducing wellbore pressure as much 
as possible prior to opening to atmosphere via storage tank, unloading 
through the separator where feasible, and requiring an operator to 
remain on-site throughout the unloading, and closure of all well head 
vents to the atmosphere and return of the well to production as soon as 
practicable. For example, where a plunger lift is used, the plunger 
lift can be operated so that the plunger returns to the top and the 
liquids and gas flow to the separator. Under this scenario, venting of 
the gas can be minimized and the gas that flows through the separator 
can be routed to sales. In situations where production engineers select 
an unloading technique that vents emissions or has the potential to 
vent emissions to the atmosphere, owners and operators already often 
implement BMPs in order to increase gas sales and reduce emissions and 
waste during these (often manual) liquids unloading activities.
2. EG OOOOc
    The EPA has determined that each well liquids unloading event 
represents a modification, which will make the well subject to new 
source standards under the NSPS for purposes of the liquids unloading 
standards.\203\ Therefore, after the effective date of NSPS OOOOb, the 
first time a well undergoes liquids unloading it will become subject to 
NSPS OOOOb. This will mean that there will never be a well that 
undergoes liquids unloading that will be existing. Therefore, we are 
not proposing presumptive standards under the subpart OOOOc EG.
---------------------------------------------------------------------------

    \203\ To clarify further, when a well liquids unloading event 
represents a modification, this does not make the whole well site a 
new source. Rather, the modification will make the well subject to 
NSPS for only the liquids unloading standards.
---------------------------------------------------------------------------

E. Reciprocating Compressors

1. NSPS OOOOb
    The current NSPS in subpart OOOOa for reducing VOC and methane 
emissions from reciprocating compressors is to replace the rod packing 
on or before 26,000 hours of operation or 36 calendar months, or to 
route emissions from the rod packing to a process through a closed vent 
system under negative pressure. The affected facility is each 
reciprocating compressor, with the exception of reciprocating 
compressors located at well sites. Based on the analysis in section 
XII.E.1, the proposed BSER for reducing GHGs and VOC from new 
reciprocating compressors is replacement of the rod packing based on an 
annual monitoring threshold. Under this proposal for the NSPS, we would 
continue to retain, as an alternative, the option of routing rod 
packing emissions to a process via a closed vent system under negative 
pressure. In this proposed updated standard, the owner or operator of a 
reciprocating compressor affected facility would be required to monitor 
the rod packing emissions annually using a flow measurement. When the 
measured leak rate exceeds 2 scfm (in pressurized mode), replacement of 
the rod packing would be required.
    As mentioned above, reciprocating compressors that are located at 
well sites are not affected facilities under the 2016 NSPS OOOOa. The 
EPA previously excluded them because we found the cost of control to be 
unreasonable. 81 FR 35878 (June 3, 2016). Our current analysis, as 
summarized in section XII.E.1, continues to support this exclusion for 
a subset of well sites so this proposal for NSPS OOOOb includes that 
same exclusion for well sites that are not centralized production 
facilities. See section XI.L for additional details on centralized 
production facilities. As described in that section, the EPA is 
proposing to apply the proposed standards to reciprocating compressors 
located at centralized production facilities.
2. EG OOOOc
    Based on the analysis in section XII.E.2, the EPA is proposing EG 
that include a presumptive GHG standard (in the form of limitation on 
methane emissions) for existing reciprocating compressors that is the 
same as the proposed NSPS, including applying these presumptive 
standards to reciprocating compressors located at existing centralized 
tank batteries.

F. Centrifugal Compressors

1. NSPS OOOOb
    The current NSPS in subpart OOOOa for wet seal centrifugal 
compressors is 95 percent reduction of GHGs and VOC emissions. The 
affected facility is each wet seal centrifugal compressor, with the 
exception of wet seal centrifugal compressors located at well sites. 
Based on the analysis in section XII.F.1, the BSER for reducing GHGs 
and VOC from new, reconstructed, or modified wet seal centrifugal 
compressors is the same as the current standard, which is 95 percent 
reduction of GHG and VOC emissions. The standard can be achieved by 
capturing and routing the emissions, using a cover and closed vent 
system, to a control device that achieves an emission reduction of 95 
percent, or by routing captured emissions to a process.
    As discussed above, wet seal centrifugal compressors that are 
located at well sites are not affected facilities under the 2016 NSPS 
OOOOa. The EPA previously excluded them because data available at the 
time did not suggest there were a large number of wet seal centrifugal 
compressors located at well sites. 81 FR 35878 (June 3, 2016). Our 
analysis continues to support this exemption for wet seal centrifugal 
compressors located at well sites that are not centralized production 
facilities. See section XI.L for additional details on centralized 
production facilities. As described in that section, the EPA is 
proposing to apply the proposed standards to centrifugal compressors 
located at centralized production facilities.
2. EG OOOOc
    Based on the analysis in section XII.F.2, the EPA is proposing EG 
that

[[Page 63181]]

include a presumptive GHG standard (in the form of limitation on 
methane emissions) for existing wet seal centrifugal compressors that 
is the same as the NSPS, including applying these presumptive standards 
to wet seal centrifugal compressors at existing centralized tank 
batteries.

G. Pneumatic Pumps

1. NSPS OOOOb
    The current NSPS in subpart OOOOa regulates individual natural gas 
driven diaphragm pneumatic pumps at well sites and at onshore natural 
gas processing plants. The current NSPS for a natural gas driven 
diaphragm pneumatic pump at well sites requires 95 percent control of 
GHGs and VOCs if there is an existing control device or process on site 
where emissions can be routed. There are two exceptions to the 95 
percent control requirement: (1) The existing control or process 
achieves less than 95 percent reduction; or (2) it is technically 
infeasible to route to the existing control device or process. In 
addition, the current NSPS in OOOOa specifies that boilers and process 
heaters are not considered control devices and that routing emissions 
from pneumatic pump discharges to boilers and process heaters is not 
considered routing to a process. For more discussion on the use of 
boilers and process heaters as control devices for pneumatic pump 
emissions, see section X.B.2 of this preamble. The current NSPS for a 
natural gas driven diaphragm pneumatic pump at an onshore natural gas 
processing plant is a natural gas emission rate of zero, based on 
natural gas as a surrogate for VOC and GHG, the two regulated 
pollutants.
    For NSPS OOOOb, we are proposing to expand the applicability of the 
standard currently in NSPS OOOOa in two ways. The first is by including 
all natural gas driven diaphragm pumps as affected facilities in the 
transmission and storage segment in addition to the production and 
natural gas processing segments. The second is that we are expanding 
the affected facility definition to include natural gas driven piston 
pumps in addition to diaphragm pumps. The proposed definition of an 
affected facility would continue to exclude lean glycol circulation 
pumps that rely on energy exchange with the rich glycol from the 
contractor.
    Based on our analysis, which is summarized in section XII.G.1, we 
are proposing to retain the current standard for a natural gas driven 
diaphragm pneumatic pump at well sites because the BSER for reducing 
VOC and methane emissions from such pumps at a well site continues to 
be routing to a combustion device or process, but only if the control 
device or process is already available on site. As before, the current 
analysis continues to show that it is not cost-effective to require the 
owner or operator of a pneumatic pump to install a new control device 
or process onsite to capture emissions solely for this purpose. 
Moreover, even where a control device or process is available onsite 
that would achieve at least 95 percent control, the EPA is aware that 
it may not be technically feasible in some instances to route the 
pneumatic pump to the control device or process. In this situation, the 
proposed rule would exempt the owner and operator from this requirement 
provided that they document the technical infeasibility and submit it 
in an annual report. Another circumstance is that it may be feasible to 
route the emissions to a control device, but the control cannot achieve 
95 percent control. In this instance, the proposed rule would exempt 
the owner or operator from the 95 percent requirement, provided that 
the owner or operator maintain records demonstrating the percentage 
reduction that the control device is designed to achieve. In this way, 
the standard would achieve emission reductions with regard to pneumatic 
pump affected facilities even if the only available control device 
cannot achieve a 95 percent reduction. For more discussion of the 
technical infeasibility aspects of the pneumatic pump requirements, see 
section X.B.2 of this preamble. We are proposing to expand these 
requirements to all diaphragm pumps at all sites in the production 
segment, as well as at all transmission and storage sites. In addition, 
we are proposing that these requirements would also include emissions 
from piston pneumatic pumps at all sites in the production segment.
    We are not proposing any change to the current standard of zero 
natural gas emission for natural gas driven diaphragm pneumatic pumps 
located at onshore natural gas processing plants, other than the 
expansion of the affected facility definition to include piston pumps. 
Our analysis discussed in section XII.G.1 demonstrates this standard is 
the BSER.
2. EG OOOOc
    The EPA is proposing EG that include presumptive methane standards 
that are the same as described above for the NSPS OOOOb for existing 
natural gas driven diaphragm pneumatic pumps located at well sites and 
all other sites in the production segment (except processing plants) 
and transmission and storage segment where an existing control device 
exists. However, unlike the proposed methane standards in NSPS OOOOb 
for natural gas driven piston pneumatic pumps at sites in the 
production segment, the proposed presumptive standards under EG OOOOc 
exclude piston pumps from the 95 percent control requirements. The 
EPA's proposed emissions guidelines also include a presumptive methane 
standard for pneumatic pumps located at onshore natural gas processing 
plants that is the same as the proposed NSPS described above.

H. Equipment Leaks at Natural Gas Processing Plants

    Based on our analysis, which is summarized in section XII.H.1, the 
EPA is proposing to update the NSPS for reducing VOC and methane 
emissions from equipment leaks at onshore natural gas processing 
plants. Further, based on the same analysis in section XII.H.1 and the 
EPA's understanding that it is appropriate to apply that same analysis 
to existing sources, the EPA is also proposing EG that include these 
same LDAR requirements as presumptive standards for reducing methane 
leaks from existing equipment at onshore natural gas processing plants.
    The EPA is proposing to expand the definition of an affected 
facility (referred to as a ``equipment within a process unit'') and 
establish a new standard for reducing equipment leaks of VOC and 
methane emissions from new, modified, and reconstructed process units 
at onshore natural gas processing plants. This proposed standard would 
require (1) the use of OGI monitoring to detect equipment leaks from 
pumps, valves, and connectors, and (2) retain the current requirements 
in the 2016 NSPS OOOOa (which adopts by reference specific provisions 
of 40 CFR part 60, subpart VVa (``NSPS VVa'')) for PRDs, open-ended 
valves or lines, and closed vent systems and equipment designated with 
no detectable emissions.
    First, we are proposing to remove a threshold that excludes certain 
equipment within a process unit from being subject to the equipment 
leaks standards for onshore natural gas processing plants. While the 
current definition of an affected facility includes all equipment, 
except compressors, that is in contact with a process fluid containing 
methane or VOCs (i.e., each pump, PRD, open-ended valve or line, valve, 
and flange or other connector), the standards apply only to equipment 
``in VOC service,''

[[Page 63182]]

which ``means the piece of equipment contains or contacts a process 
fluid that is at least 10 percent VOC by weight.'' We are proposing to 
remove this VOC concentration threshold from the LDAR requirements for 
the following reasons. First, a VOC concentration threshold bears no 
relationship to the LDAR for methane and is therefore not an 
appropriate threshold for determining whether LDAR for methane applies. 
Second, since there would be no threshold for requiring LDAR for 
methane, any equipment not in VOC service would still be required to 
conduct LDAR for methane even if not for VOC, thus rendering this VOC 
concentration threshold irrelevant.
    Second, for all pumps, valves, and connectors located within an 
affected process unit at an onshore natural gas processing plant, we 
are proposing to require the use of OGI to identify leaks from this 
equipment on a bimonthly frequency (i.e., once every other month), 
which according to our analysis is the BSER for identifying and 
reducing leaks from this equipment. OGI monitoring would be conducted 
in accordance with the proposed appendix K,\204\ which is included in 
this action and outlines the proposed procedures that must be followed 
to identify leaks using OGI. As an alternative to bimonthly monitoring 
using OGI, we are proposing to allow affected facilities the option to 
comply with the requirements of NSPS VVa, which are the current 
requirements in the 2016 NSPS OOOOa.\205\ As explained in XII.A, our 
analysis shows that the proposed standards, which use OGI, achieve 
equivalent reduction of VOC and methane emissions as the current 
standards, which are based on EPA Method 21, but at a lower cost. While 
we no longer consider EPA Method 21 to be the BSER for reducing methane 
and VOC emissions from equipment leaks at onshore natural gas 
processing plants, we are retaining NSPS VVa as an alternative for 
owners and operators who prefer using EPA Method 21.
---------------------------------------------------------------------------

    \204\ ``Determination of Volatile Organic Compound and 
Greenhouse Gas Leaks Using Optical Gas Imaging'' located at Docket 
ID No. EPA-HQ-OAR-2021-0317.
    \205\ It is important to note that the stay of the connector 
monitoring requirements in 40 CFR 60.482-11a does not apply to 
connectors located at onshore natural gas processing plants. 
Therefore, where sources choose to comply with the requirements of 
NSPS VVa in place of the proposed OGI requirements, the standards in 
40 CFR 60.482-11a are applicable to all connectors in the process 
unit.
---------------------------------------------------------------------------

    Third, we are proposing to require a first attempt at repair for 
all leaks identified with OGI within 5 days of detection, and final 
repair completed within 15 days of detection. We are also proposing 
definitions for ``first attempt at repair'' and ``repaired.'' The 
proposed definitions would apply to the equipment leaks standards at 
natural gas processing plants as well as to fugitive emissions 
requirements at well sites and compressor stations. The proposed 
definition of ``first attempt at repair'' is an action taken for the 
purpose of stopping or reducing fugitive emissions or equipment leaks 
to the atmosphere. First attempts at repair include, but are not 
limited to, the following practices where practicable and appropriate: 
Tightening bonnet bolts; replacing bonnet bolts; tightening packing 
gland nuts; or injecting lubricant into lubricated packing. The 
proposed definition for ``repaired'' is fugitive emissions components 
or equipment are adjusted, replaced, or otherwise altered, in order to 
eliminate fugitive emissions or equipment leaks as defined in the 
subpart and resurveyed to verify that emissions from the fugitive 
emissions components or equipment are below the applicable leak 
definition. Repairs can include replacement with low-emissions (``low-
e'') valves or valve packing, where commercially available, as well as 
drill-and-tap with a low-e injectable. These low-e equipment meet the 
specifications of API 622 or 624. Generally, a low-e valve or valve 
packing product will include a manufacturer written warranty that it 
will not emit fugitive emissions at a concentration greater than 100 
ppm within the first five years. Further, we are proposing to 
incorporate the delay of repair provisions that are in 40 CFR 60.482-9a 
of NSPS VVa (and incorporated into NSPS OOOOa). These provisions would 
allow the delay of repairs where it is technically infeasible to 
complete repairs within 15 days without a process unit shutdown and 
require repair completion before the end of the next process unit 
shutdown.
    Fourth, we are proposing to retain the current requirements in NSPS 
OOOOa for open-ended valves or lines, closed vent systems and equipment 
designated with no detectable emissions, and PRDs. For open-ended 
valves or lines, we propose to retain the requirements in 40 CFR 
60.482-6a of NSPS VVa. Specifically, we are proposing that each open-
ended valve or line in a new or existing process unit must be equipped 
with a closure device (i.e., cap, blind flange, plug, or a second 
valve) that seals the open end at all times except during operations 
requiring process fluid flow through the open-ended valve or line. The 
EPA is soliciting comment on requiring OGI monitoring (or EPA Method 21 
monitoring for those opting for that alternative) on these open-ended 
valves or lines equipped with closure devices to ensure no emissions 
are going to the atmosphere. Specifically, the EPA is soliciting 
information that would aid in determining what additional costs would 
be incurred from either OGI or EPA Method 21 monitoring and repair of 
leaking open-ended valves or lines, and information on leak rates and 
concentrations of emissions, where monitoring has been performed.
    While the EPA is proposing to retain the no detectable emission 
requirement in NSPS OOOOa for closed vent systems and equipment 
designated as having no detectable emissions (e.g., valves or PRDs), 
the EPA is also soliciting comment on whether bimonthly OGI monitoring 
according to the proposed appendix K is appropriate to demonstrate 
compliance with this requirement. The current NSPS requires the closed 
vent systems \206\ and the other equipment described above to operate 
with no detectable emissions, as demonstrated by an instrument reading 
of less than 500 ppm above background with EPA Method 21. On December 
22, 2008, the EPA issued a final rule titled, ``Alternative Work 
Practice to Detect Leaks from Equipment'' (AWP).\207\ In that final 
rule, the EPA did not permit the use of OGI for this equipment, 
stating, ``the AWP is not appropriate for monitoring closed vent 
system, leakless equipment, or equipment designated as non-leaking. 
While the AWP will identify leaks with larger mass emission rates, 
tests conducted with both the AWP and the current work practice 
indicate the AWP, at this time, does not identify very small leaks and 
may not be able to identify if non-leaking/leakless equipment are truly 
nonleaking because the detection sensitivity of the optical gas imaging 
instrument is not sufficient.'' 73 FR 78204 (December 22, 2008). The 
EPA is soliciting information that would support the use of OGI for 
closed vent systems and equipment designated with no detectable 
emissions at new and existing process units, including comment on 
applying the proposed bimonthly OGI monitoring requirement on this 
equipment in place

[[Page 63183]]

of the NSPS VVa annual EPA Method 21 monitoring.
---------------------------------------------------------------------------

    \206\ For purposes of this standard, the EPA is referring to 
closed vent systems used equipment within process units at onshore 
natural gas processing plants. Closed vent systems associated with 
controlled storage vessels, wet seal centrifugal compressors, 
reciprocating compressors and pneumatic pumps are not included in 
this discussion and would demonstrate compliance with the no 
detectable emissions standard by EPA Method 21 (except for storage 
vessels), monthly AVO, or OGI monitoring during the fugitive 
emissions survey.
    \207\ See 73 FR 78199 (December 22, 2008).
---------------------------------------------------------------------------

    Finally, the EPA is proposing to retain the emission standards for 
PRDs found in 40 CFR 60.482-4a of NSPS VVa. This provision requires 
that PRDs be operated with no detectable emissions, except during 
pressure releases at new and existing process units. As stated above, 
the EPA is soliciting comment on the use of OGI to demonstrate that 
PRDs are meeting this operational emission standard.
2. EG OOOOc
    The EPA is proposing EG that include a presumptive methane standard 
that is the same as described above for the NSPS OOOOb for equipment 
leaks at existing onshore natural gas processing plants. Based on the 
analysis in section XII.H.2, the BSER for reducing GHGs from equipment 
leaks at new and existing onshore natural gas processing plants are the 
same.

I. Well Completions

    Based on our understanding that there are no advances in 
technologies or practices, which is summarized in section XII.I, the 
EPA is proposing to retain the REC and completion combustion 
requirements for reducing methane and VOC emissions from well 
completions of hydraulically fractured or refractured oil and natural 
gas wells, as they continue to reflect the BSER. These proposed 
standards are the same as those for natural gas and oil wells regulated 
in the 2012 NSPS OOOO and 2016 NSPS OOOOa, as amended in the 2020 
Technical Rule for VOC and proposed in section X.B.1 for methane.\208\ 
Because of the nature of well completions, any completion (or 
recompletion) is considered a new or modified well affected facility, 
therefore, the EPA does not believe there are existing well affected 
facilities to which a EG OOOOc presumptive standard for well 
completions would apply.
---------------------------------------------------------------------------

    \208\ See Docket ID No. EPA-HQ-OAR-2021-0317 for proposed 
redline regulatory text for 40 CFR 60.5375a as a reference for the 
specific well completion standards proposed for NSPS OOOOb.
---------------------------------------------------------------------------

J. Oil Wells With Associated Gas

    Associated gas originates at wellheads that also produce 
hydrocarbon liquids and occurs either in a discrete gaseous phase at 
the wellhead or is released from the liquid hydrocarbon phase by 
separation. There are no current NSPS requirements for this emission 
source. The EPA is proposing standards in the NSPS OOOOb to reduce 
methane and VOC emissions resulting from the venting of associated gas 
from oil wells.
1. NSPS OOOOb
    We are proposing standards to reduce methane and VOC emissions from 
each oil well that produces associated gas. Based on our analysis, 
which is summarized in section XII.J, we are proposing a standard under 
NSPS OOOOb that requires owners or operators of oil wells to route 
associated gas to a sales line. In the event that access to a sales 
line is not available, we are proposing that the gas can be used as an 
onsite fuel source, used for another useful purpose that a purchased 
fuel or raw material would serve, or routed to a flare or other control 
device that achieves at least 95 percent reduction in methane and VOC 
emissions. As discussed in section XII.J, the EPA is soliciting comment 
on how ``access to a sales line'' should be defined. An affected 
facility would be defined as any oil well that produces associated gas. 
The proposed rule would require that when using a flare, the flare must 
meet the requirements in 40 CFR 60.18 and that monitoring, 
recordkeeping, and reporting be conducted to ensure that the flare is 
constantly achieving the required 95 percent reduction. As discussed in 
section XII.J, the EPA is soliciting comment on an alternative affected 
facility definition that would exclude oil wells that route all 
associated gas to a sales line. The EPA is also soliciting comment and 
information that would support requirements using other strategies to 
reduce venting and flaring of associated gas from oil wells. The EPA is 
specifically requesting comment on whether the proposed requirements 
will incentivize the sale or productive use of captured gas, and if 
not, other methods that the EPA could use to incentivize or require the 
sale or productive use instead of flaring.
2. EG OOOOc
    The EPA is proposing presumptive standards for existing oil wells 
in this action that are the same as discussed above for new sources.

K. Sweetening Units

    Based on our understanding that no advances in technologies or 
practices are available to reduce SO2 emissions from 
sweetening units, as described in section XII.K, the EPA is proposing 
to retain the standards as it continues to reflect the BSER. These 
proposed standards are the same as those for sweetening units regulated 
in the 2016 NSPS OOOOa, and as amended in the 2020 Technical Rule.\209\
---------------------------------------------------------------------------

    \209\ See Docket ID No. EPA-HQ-OAR-2021-0317 for proposed 
redline regulatory text for 40 CFR 60.5375a as a reference for the 
specific well completion standards proposed for NSPS OOOOb.
---------------------------------------------------------------------------

L. Centralized Production Facilities

    The EPA is also proposing a new definition for ``centralized 
production facility,'' which is one or more permanent storage tanks and 
all equipment at a single stationary source used to gather, for the 
purpose of sale or processing to sell, crude oil, condensate, produced 
water, or intermediate hydrocarbon liquid from one or more offsite 
natural gas or oil production wells. This equipment includes, but is 
not limited to, equipment used for storage, separation, treating, 
dehydration, artificial lift, combustion, compression, pumping, 
metering, monitoring, and flowline. Process vessels and process tanks 
are not considered storage vessels or storage tanks. A centralized 
production facility is located upstream of the natural gas processing 
plant or the crude oil pipeline breakout station and is a part of 
producing operations. The EPA is proposing this definition to (1) 
specify how the fugitive emissions requirement apply to centralized 
production facilities, (2) specify how exemptions related to 40 CFR 
part 60, subpart K, Ka, or Kb (``NSPS Kb) may apply, and (3) specify 
what standards would apply to reciprocating and centrifugal compressors 
located at these facilities.
    First, the EPA is proposing to specify how the fugitive emission 
requirements apply to centralized production facilities. The 2016 NSPS 
OOOOa, as originally promulgated, provided that ``[f]or purposes of the 
fugitive emissions standards at 40 CFR 60.5397a, [a] well site also 
means a separate tank battery surface site collecting crude oil, 
condensate, intermediate hydrocarbon liquids, or produced water from 
wells not located at the well site (e.g., centralized tank 
batteries).'' 40 CFR 60.5430a. The inclusion of centralized tank 
batteries in the definition of well site was used to clarify the 
boundary of a well site for purposes of the fugitive emissions 
requirements. Further, in the RTC \210\ for the 2016 NSPS OOOOa we 
stated, ``[o]ur intent is to limit the oil and gas production segment 
up to the point of custody transfer to an oil and natural gas mainline 
pipeline (including transmission pipelines) or a natural gas processing 
plant. Therefore, the collection of fugitive emissions components 
within this boundary are a part of the well site.'' The EPA continues 
to define these facilities as a type of well site but is proposing a 
separate definition to provide further

[[Page 63184]]

clarity, especially as it relates to when these facilities are 
modified, and thus become subject to the fugitive emissions 
requirements in NSPS OOOOb. The EPA has determined it is appropriate to 
rename this site as a centralized production facility and to provide 
the specific definition above to avoid confusion with the storage 
vessel affected facility, of which applicability is determined for a 
tank battery, and to better specify the facility name based on the 
basic function the site performs (i.e., production operations).
---------------------------------------------------------------------------

    \210\ See Document ID No. EPA-HQ-OAR-2010-0505-7632 at page 4-
194.
---------------------------------------------------------------------------

    Second, the EPA has received questions related to whether NSPS Kb 
would apply to the storage vessels at centralized production 
facilities. There is an exemption in NSPS Kb for storage vessels in the 
producing operations that are below a specific size. Specifically, 40 
CFR 60.110(b)(4) exempts ``vessels with a design capacity less than or 
equal to 1,589.874 m\3\ used for petroleum or condensate stored, 
processed, or treated prior to custody transfer.'' This exemption is a 
revision of an exemption originally promulgated in 40 CFR part 60, 
subpart K (``NSPS K''). NSPS K ``does not apply to storage vessels for 
the crude petroleum or condensate stored, processed, and/or treated at 
a drilling and production facility prior to custody transfer.'' 40 CFR 
60.110(b). In that final rule the EPA explained that, ``[t]he storage 
of crude oil and condensate at producing fields is specifically 
exempted from the standard.'' 39 FR 9312 (March 8, 1974). While 
``producing fields'' were not explicitly defined, NSPS K defined the 
terms ``custody transfer'' and ``drilling and production facility''. 
For purposes of NSPS K, custody transfer means ``the transfer of 
produced crude petroleum and/or condensate, after processing and/or 
treating in the producing operations, from storage tanks or automatic 
transfer facilities to pipelines or any other forms of 
transportation.'' 40 CFR 60.111(g). Drilling and production facility 
means ``all drilling and servicing equipment, wells, flow lines, 
separators, equipment, gathering lines, and auxiliary 
nontransportation-related equipment used in the production of crude 
petroleum but does not include natural gasoline plants.'' 40 CFR 
60.111(h). The definition of ``custody transfer'' was later also 
incorporated into 40 CFR part 60, subpart Ka (``NSPS Ka''), NSPS Kb, 
and 40 CFR part 63, subpart HH (National Emission Standards for 
Hazardous Air Pollutants from Oil and Natural Gas Production 
Facilities).
    Instead of a categorical exemption for storage vessels located at 
drilling and production facilities, NSPS Ka, and subsequently NSPS Kb, 
adopted threshold-based exemptions that are based on the capacity of an 
individual storage vessel used to store petroleum (crude oil) or 
condensate prior to custody transfer. In NSPS Ka, the EPA stated 
``[t]his exemption applies to storage between the time that the 
petroleum liquid is removed from the ground and the time that custody 
of the petroleum liquid is transferred from the well or producing 
operations to the transportation operations'' 45 FR 23377 (April 4, 
1980). In NSPS Kb, the EPA further stated that ``[t]he promulgated 
standards for petroleum liquid storage vessels specifically exempted 
vessels with a capacity less than 420,000 gallons and storing petroleum 
(crude oil) and condensate prior to custody transfer (production 
vessels). The emission controls that are applicable to the storage 
vessels included in the standards being proposed are not applicable to 
production vessels.'' 49 FR 29701.
    The EPA finds it inappropriate to use the controls required by NSPS 
K, Ka, and Kb on storage vessels located in the production segment, 
especially where flash emissions are prevalent. Specifically, the NSPS 
K, Ka, and Kb control requirements include provisions allowing the use 
of floating roofs to reduce emissions from storage tanks. Floating 
roofs are not designed to store liquid (or gases) under pressure. 
Pressurized liquid sent to a storage vessel from a well or separator or 
other process that operates above atmospheric pressure may contain 
dissolved gases. These gases will be released or ``flash'' from the 
liquid as the fluid comes to equilibrium with atmospheric pressure 
within the storage vessel. The flash gas will either be released from 
gaps in the seal system or from ``rim vents'' on the floating roof. The 
rim vent may be an open tube or may be fitted with a low-pressure 
relief valve, but it is specifically designed to allow any gas 
entrained or dissolved in the storage liquid to be released above the 
floating roof. That is, floating roofs are not designed to prevent the 
release of flash gas, they are only designed to limit the 
volatilization of a liquid that occurs when the storage liquid is 
directly exposed with unsaturated air. Since a significant portion of 
emissions from storage vessels at well sites or centralized production 
facilities are from flash gas, floating roofs are much less effective 
at reducing storage vessel emissions than venting these emissions 
through a CVS to a control or recovery device.
    Further, it is the EPA's understanding that these centralized 
production facilities carry out the same operations that would be 
conducted at the individual well sites. Therefore, the EPA is proposing 
a definition of ``centralized production facility'' that clearly 
specifies these facilities are located within the producing operations. 
Therefore, if all other conditions are met (i.e., vessels with a design 
capacity less than or equal to 1,589.874 m\3\ used for petroleum or 
condensate stored, processed, or treated prior to custody transfer), 
storage vessels at these centralized facilities would meet the 
exemption criteria for NSPS Kb.
    Alternatively, the EPA is soliciting comment on whether it would be 
more appropriate to specify within the proposed NSPS OOOOb and EG OOOOc 
that storage vessels at well sites and centralized production 
facilities are subject to the requirements in NSPS OOOOb and EG OOOOc 
instead of NSPS K, Ka, or Kb. This alternative approach would eliminate 
the need for sources to determine if the storage vessel meets the 
exemption criteria specified in those subparts and instead focus on 
appropriate controls for the storage vessels based on the location and 
type of emissions likely present (e.g., flash emissions).
    Finally, the EPA is now proposing to define centralized production 
facilities separately from well sites because the number and size of 
equipment, particularly reciprocating and centrifugal compressors, is 
larger than standalone well sites which would not be included in the 
proposed definition of ``centralized production facilities'' above. In 
the 2016 NSPS OOOOa, the EPA exempted reciprocating and centrifugal 
compressors located at well sites from the applicable compressor 
standards.
    Reciprocating compressors that are located at well sites are not 
affected facilities under the 2016 NSPS OOOOa. The EPA previously 
excluded them because we found the cost of control to be unreasonable. 
81 FR 35878. However, as mentioned above, the EPA believes the 
definition of ``well site'' in NSPS OOOOa may cause confusion regarding 
whether reciprocating compressors located at centralized production 
facilities are also exempt from the standards. In our current analysis, 
described in section XII.E, we find it is appropriate to apply the same 
emission factors to reciprocating compressors located at centralized 
production facilities as those used for reciprocating compressors at 
gathering and boosting compressor stations. Given the results of that 
analysis, the EPA is proposing to apply the proposed NSPS OOOOb and 
presumptive standards in EG OOOOc to

[[Page 63185]]

reciprocating compressors located at centralized production facilities. 
The new definition above is intended to apply the results of the EPA's 
analysis. We believe that this new definition is necessary in the 
context of reciprocating compressors to distinguish between these 
compressors at centralized production facilities where the EPA has 
determined that the standard should apply, and these compressors at 
standalone well sites where the EPA has determined that the standard 
should not apply. See section XII.E for more details of those proposed 
standards.
    Similarly, wet seal centrifugal compressors that are located at 
well sites are not affected facilities under the 2016 NSPS OOOOa. The 
EPA previously excluded them because data available at the time did not 
suggest there were a large number of wet seal centrifugal compressors 
located at well sites. 81 FR 35878. In our current analysis, described 
in section XII.F, we find it is appropriate to apply the same emission 
factors to wet seal centrifugal compressors located at centralized 
production facilities as those used for these same compressors at 
gathering and boosting compressor stations. Given the results of that 
analysis, the EPA is proposing to apply the proposed NSPS OOOOb and 
presumptive standards in EG OOOOc to wet seal centrifugal compressors 
located at centralized production facilities. See section XII.F for 
more details of those proposed standards.

M. Recordkeeping and Reporting

    The EPA is proposing to require electronic reporting of performance 
test reports, annual reports, and semiannual reports through the 
Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can 
be accessed through the EPA's Central Data Exchange (CDX) at https://cdx.epa.gov/.) A description of the electronic data submission process 
is provided in the memorandum Electronic Reporting Requirements for New 
Source Performance Standards (NSPS) and National Emission Standards for 
Hazardous Air Pollutants (NESHAP) Rules, available in the docket for 
this action. Performance test results collected using test methods that 
are supported by the EPA's Electronic Reporting Tool (ERT) as listed on 
the ERT website \211\ at the time of the test would be required to be 
submitted in the format generated through the use of the ERT or an 
electronic file consistent with the xml schema on the ERT website, and 
other performance test results would be submitted in portable document 
format (PDF) using the attachment module of the ERT. For semiannual and 
annual reports, the owner or operator would be required to use the 
appropriate spreadsheet template to submit information to CEDRI.
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    \211\ https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
---------------------------------------------------------------------------

    The EPA is also proposing to allow owners and operators the ability 
to seek extensions for submitting electronic reports for circumstances 
beyond the control of the facility, i.e., for a possible outage in CDX 
or CEDRI or for a force majeure event, in the time just prior to a 
report's due date. The EPA is providing these potential extensions to 
protect owners and operators from noncompliance in cases where they 
cannot successfully submit a report by the reporting deadline for 
reasons outside of their control. The decision to accept the claim of 
needing additional time to report is within the discretion of the 
Administrator.
    Electronic reporting is required in the amended 2016 NSPS OOOOa, 
and the EPA believes that the electronic submittal of these reports in 
the proposed NSPS OOOOb will increase the usefulness of the data 
contained in those reports, is in keeping with current trends in data 
availability, will further assist in the protection of public health 
and the environment, and will ultimately result in less burden on the 
regulated community. Electronic reporting can also eliminate paper-
based, manual processes, thereby saving time and resources, simplifying 
data entry, eliminating redundancies, minimizing data reporting errors, 
and providing data quickly and accurately to the affected facilities, 
air agencies, the EPA, and the public. Moreover, electronic reporting 
is consistent with the EPA's plan \212\ to implement E.O. 13563 and is 
in keeping with the EPA's agency-wide policy \213\ developed in 
response to the White House's Digital Government Strategy.\214\
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    \212\ EPA's Final Plan for Periodic Retrospective Reviews, 
August 2011. Available at: https://www.regulations.gov/document?D=EPA-HQ-OA-2011-0156-0154.
    \213\ E-Reporting Policy Statement for EPA Regulations, 
September 2013. Available at: https://www.epa.gov/sites/production/files/2016-03/documents/epa-ereporting-policy-statement-2013-09-30.pdf.
    \214\ Digital Government: Building a 21st Century Platform to 
Better Serve the American People, May 2012. Available at: https://obamawhitehouse.archives.gov/sites/default/files/omb/egov/digital-government/digital-government.html.
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    In addition to the annual and semiannual reporting requirement, the 
EPA is soliciting comment on what elements, if any, are appropriate for 
more frequent reporting, and what mechanism would be appropriate for 
the collection and public dissemination of this information. For 
example, it may be appropriate to make information related to large 
emission events public in a timelier manner than the annual reporting 
period. Therefore, the EPA is soliciting comment on the appropriate 
mechanism to use for this type of report, including how the data would 
be reported, who would manage that reporting system, the frequency at 
which the data should be reported, the potential benefits of more 
frequent reporting for reducing emissions, the associated burden with 
this type of reporting and ways to mitigate that burden, and other 
considerations that should be taken into account.

N. Prevention of Significant Deterioration and Title V Permitting

    The pollutant we are proposing to regulate is GHGs, not methane as 
a separately regulated pollutant. As explained in section XV of this 
preamble, we are proposing to add provisions to NSPS OOOOb and EG 
OOOOc, analogous to what was included in the 2016 NSPS OOOOa and other 
rules regulating GHGs from electric utility generating units, to make 
clear in the regulatory text that the pollutant regulated by this rule 
is GHGs. The proposed addition of these and other provisions is 
intended to address some of the potential implications on the CAA 
Prevention of Significant Deterioration (PSD) preconstruction permit 
program and the CAA title V operating permit program.

XII. Rationale for Proposed NSPS OOOOb and EG OOOOc

    The following sections provide the EPA's BSER analyses and the 
resulting proposed NSPS to reduce methane and VOC emissions and the 
resulting proposed EG, which include presumptive standards, to reduce 
methane emissions from across the Crude Oil and Natural Gas source 
category. Our general process for evaluating BSER for the emission 
sources discussed below included: (1) Identification of available 
control measures; (2) evaluation of these measures to determine 
emission reductions achieved, associated costs, non-air environmental 
impacts, energy impacts and any limitations to their application; and 
(3) selection of the control techniques that represent

[[Page 63186]]

BSER.\215\ As discussed in the 2016 NSPS OOOOa, the available control 
technologies will reduce both methane and VOC emissions at the same 
time. The revised BSER analysis we have undertaken for the sources 
addressed in the proposed NSPS OOOOb continues to support this 
conclusion. CAA Section 111 also requires the consideration of cost in 
determining BSER. Section IX describes how the EPA evaluates the cost 
of control for purposes of this rulemaking. Sections XII.A through 
XII.I provide the BSER analysis and the resulting proposed NSPS and EG 
for the individual emission sources contemplated in this action. Please 
note that there are minor differences in some values presented in 
various documents supporting this action. This is because some 
calculations have been performed independently (e.g., NSPS OOOOb and EG 
OOOOc TSD calculations for NSPS OOOOb and EG OOOOc focused on unit-
level cost-effectiveness and RIA calculations focused on national 
impacts) and include slightly different rounding of intermediate 
values.
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    \215\ In the context of developing the draft emissions 
guidelines contained herein, this general process also follows, and 
is intended to satisfy, certain requirements of EPA's implementing 
regulations for CAA section 111(d), namely the specific listed 
component of a draft EG contained in 40 CFR 60.22a(b)(2), and some 
elements of paragraph (b)(3).
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    For this proposed EG the EPA is proposing to translate the degree 
of emission limitation achievable through application of the BSER 
(i.e., level of stringency) into presumptive standards.\216\ As 
discussed in each of the EG-specific subsections below, the EPA's 
evaluation of BSER in the context of existing sources utilized much of 
the same information as our BSER analysis for the NSPS. This is because 
within the oil and natural gas industry many of the control measures 
that are available to reduce emissions of methane from existing sources 
are the same as those control measures available to reduce VOC and 
methane emissions from new, modified, and reconstructed sources. By 
extension, many of the methane emission reductions achieved by the 
available control options, as well as the associated costs, non-air 
environmental impacts, energy impacts, and limitations to their 
application, are very similar if not the same for new and existing 
sources. Any relevant differences between new and existing sources in 
the context of available control measures or any other factors are 
discussed in the EG-specific subsections below.
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    \216\ This is intended to satisfy certain elements of the 
requirements of EPA's implementing regulations found at 40 CFR 
60.22a(b)(3) and (5) with the exception of compliance times which 
the EPA discusses separately in section XVI.
---------------------------------------------------------------------------

    Where the EPA identified relevant distinctions between new and 
existing sources in the context of evaluating BSER, it was typically 
regarding the cost of control options. While many factors can cause 
differences in the cost of control between new and existing sources, 
the EPA would like to highlight two general concepts to illustrate how 
the oil and natural gas industry is unique. These concepts are the 
``size'' of the affected facility and the type of standards. First, 
affected facilities defined in any given NSPS can range from entire 
process units to individual pieces of equipment. For affected 
facilities comprised of an entire process unit, or very large processes 
or equipment, there can be significant differences between the cost of 
construction or modification for a new source as compared to the cost 
of a retrofit required for implementation of a control at an existing 
source. In the case of a new sources, there can be cost savings 
associated with the up-front planning for the installation of controls 
which cannot be achieved at existing sources that must instead retrofit 
already existing processes or equipment. This is particularly true of 
controls involving equipment changes or add-on control devices. In 
contrast, most affected facilities for which the EPA is proposing 
standards in NSPS OOOOb are more narrowly defined. For example, a 
pneumatic controller affected facility is generally defined as a single 
natural gas-driven pneumatic controller, which is a discrete and 
relatively small piece of equipment in a larger process. Another 
example is the reciprocating compressor affected facility which is 
defined as a single reciprocating compressor. As such, the EPA did not 
identify the same type of cost savings associated with the up-front 
planning of controls in the oil and gas sector as we might in the 
context of larger affected facilities. We believe this is one factor 
that led to costs being very similar for new and existing sources.
    Second, with regard to the type of standards, many of the standards 
proposed for NSPS OOOOb, and the presumptive standards proposed for EG 
OOOOc, are non-numerical standards, such as work practice standards, 
that require limited or no significant physical modifications. The EPA 
found that costs for these non-numerical standards would typically not 
differ between new and existing sources because the work practice could 
be implemented in both contexts without the need to first install or 
retrofit any equipment. Put another way, a work practice tends to 
operate in the same manner regardless of whether the site is new or 
existing, and existing sites typically do not need to take any 
preliminary steps in order to implement the work practice. For these 
reasons, many of the proposed presumptive standards for EG OOOOc 
discussed in the following sections mirror the proposed standards 
identified based on the BSER analyses for NSPS OOOOb.

A. Proposed Standards for Fugitive Emissions From Well Sites and 
Compressor Stations

1. NSPS OOOOb
    There are many potential sources of fugitive emissions throughout 
the Crude Oil and Natural Gas Production source category. Fugitive 
emissions occur when connection points are not fitted properly or when 
seals and gaskets start to deteriorate. Changes in pressure and 
mechanical stresses can also cause components or equipment to emit 
fugitive emissions. Poor maintenance or operating practices, such as 
improperly reseated pressure relief valves (PRVs) or worn gaskets and 
springs on thief hatches on controlled storage vessels are also 
potential causes of fugitive emissions. Additional sources of fugitive 
emissions include agitator seals, connectors, pump diaphragms, flanges, 
instruments, meters, open-ended lines, PRDs such as PRVs, pump seals, 
valves or controlled liquid storage tanks.
    In the 2021 GHGI, the methane emissions for 2019 from fugitive 
emissions in the Crude Oil and Natural Gas source category were 96,000 
metric tons methane for petroleum systems and 351,500 metric tons for 
natural gas systems. These levels represent 6 percent of the total 
methane emissions estimated from all petroleum systems sources (i.e., 
exploration through refining) and 5 percent of all methane emissions 
from natural gas systems (i.e., exploration through distribution). In 
addition, fugitive emissions may be represented in other categories of 
the GHGI production segment; for example, a portion of fugitive 
emissions (as defined in this action) is also expected to be related to 
fugitive emissions from tank thief hatches, and thief hatches on 
controlled storage vessels, and those emissions are included in the 
emissions estimates for storage vessels in the GHGI.
    In the 2016 NSPS OOOOa, the EPA promulgated standards to control 
GHGs (in the form of limitations on methane emissions) and VOC 
emissions from fugitive emissions components located at well sites and 
compressor stations. These standards required a fugitive

[[Page 63187]]

emissions monitoring and repair program, where well sites and 
compressor stations had to be monitored semiannually and quarterly, 
respectively.
a. Fugitive Emissions From Well Sites
    Oil and natural gas production practices and equipment vary from 
well site to well site. A well site can serve one well or multiple 
wells. Some production sites may include only a single wellhead that is 
extracting oil or natural gas from the ground, while other sites may 
include multiple wellheads with a number of operations such as 
production, extraction, recovery, lifting, stabilization, separation 
and/or treating of petroleum and/or natural gas (including condensate). 
In addition, the 2016 NSPS OOOOa definition of well site also includes 
centralized tank batteries for purposes of the fugitive emissions 
requirements because, like storage vessels at well sites, centralized 
tank batteries collect crude oil, condensate, intermediate hydrocarbon 
liquids, or produced water from wells; therefore, ``excluding tank 
batteries not located at the well site could incentivize some owners or 
operators to place new tank batteries further away from well sites to 
make use of such an exemption.'' \217\ The equipment to perform these 
production operations (including piping and associated components, 
compressors, generators, separators, storage vessels, and other 
equipment) has components that may be sources of fugitive emissions. 
Therefore, the number of components with the potential for fugitive 
emissions can vary depending on the number of wells and the number of 
major production and processing equipment at the site. Another factor 
that impacts the operations at a well site, and the resulting fugitive 
emissions potential, is the nature of the oil and natural gas being 
extracted. This can range from well sites that only extract and handle 
``dry'' natural gas to those that extract and handle heavy oil.
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    \217\ See Document ID No. EPA-HQ-OAR-2010-0505-7632 at page 4-
221.
---------------------------------------------------------------------------

    In both the 2016 NSPS OOOOa and subsequent amendments in the 2020 
Technical Rule, the EPA relied on a model plant approach to estimate 
emissions from well sites. Model plants were developed to provide a 
representation of well sites across the spectrum. Separate production-
based model plants using component counts to determine baseline 
emissions were developed. The basic approach used was to assign a 
number of specific equipment types for each well site model plant and 
then to estimate the number of components based on assigned numbers of 
components per equipment type. Primarily, the well site model plants 
utilized information from the DrillingInfo HPDI[supreg] database,\218\ 
the 1996 EPA/GRI Study,\219\ EPA's GHG Inventory, and GHGRP subpart W. 
Fugitive model plants were originally developed for the 2015 NSPS OOOOa 
proposed rule (80 FR 56614, September 18, 2015) and evolved over time 
in response to new information and public comments. More information on 
the history of the model plant development can be found in the 2015 
NSPS Proposal TSD,\220\ the 2016 NSPS Final TSD,\221\ the 2018 NSPS 
Proposal TSD,\222\ and the 2020 NSPS Final TSD.\223\
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    \218\ Drilling Information, Inc. 2014. DI Desktop. 2014 
Production Information Database.
    \219\ Gas Research Institute (GRI)/U.S. EPA. Research and 
Development, Methane Emissions from the Natural Gas Industry, Volume 
8: Equipment Leaks. June 1996 (EPA-600/R-96-080h).
    \220\ EPA-HQ-OAR-2010-0505-5021.
    \221\ EPA-HQ-OAR-2010-0505-7631.
    \222\ EPA-HQ-OAR-2017-0483-0040.
    \223\ EPA-HQ-OAR-2017-0483-2290.
---------------------------------------------------------------------------

    In this proposal, the EPA is shifting away from using model plants 
for well sites for the BSER analysis and is instead using an individual 
site-level emission-calculation approach in order to better 
characterize and take into account the differences at individual well 
sites that can lead to a vast range in the magnitude of fugitive 
emissions, which a model plant cannot do. Provided below is a more 
detailed explanation of the issues concerning the previous model plant 
approach, followed by a description of the site-specific baseline 
emission calculation approach, which is similar to the State of 
Colorado's LDAR program.
    In the 2020 Technical Rule, the EPA created separate model plants 
to represent fugitive emissions from low production well sites (those 
producing 15 boe or less per day) and non-low production well sites, as 
it was generally assumed that low producing sites would have fewer 
major production and processing equipment and thus lower fugitive 
emissions. This prior estimate of baseline emissions was calculated 
using model plant site designs with assumed populations of major 
production and processing equipment and fixed fugitive emissions 
component counts. While the estimated baseline emissions from the two 
model plants differ due to the difference in the assumed populations of 
major production and processing equipment and fixed fugitive emissions 
component counts, the estimated baseline emissions were intended to 
represent the baseline emissions for all well sites represented by each 
model plant. Since that rulemaking, further analysis of existing and 
new information indicates that there is significant variation in the 
well characteristics, type of oil and gas products and production 
levels, gas composition, operations, and types and quantity of 
equipment at well sites across the U.S. The TSD for this action further 
describes existing data and new information received since the 2020 
Technical Rule that have been evaluated by the EPA to arrive at the 
conclusion that there is no one-size-fits-all approach to predicting 
emissions from well sites and that the emissions vary greatly, in ways 
that bear little correlation to production levels alone. For example, 
site-level methane emissions data from comprehensive studies sampled 
across several different regions at numerous well sites, shows a wide 
range of methane emissions (i.e., ranging from as low as 0 to as high 
as 1,200 tpy for marginal or low production wells). Additionally, 
recently obtained ICR data indicate that actual component counts at 
well sites with equipment could be higher than those estimated by model 
plants for low and non-low production, e.g., EPA's non-low model plant 
could be underestimating number of wells, tanks and separators; and 
similar observations were made for low production based on this data. 
Contrary to previous general assumptions, information reviewed also 
shows that it is not necessarily the case that fugitive emissions from 
sites with lower production have lower emissions than sites with higher 
production. In fact, it is quite possible that the inverse can be true 
(i.e., lower producing sites could have higher emissions and inversely, 
higher producing sites could have lower emissions.) More information 
can be found in the NSPS OOOOb and EG TSD for this proposal.
    Therefore, the EPA has concluded that the previous model plant 
approach, which was based on two production levels (equal/above or 
below 15 boe per day) and the estimated equipment types and numbers 
associated with each of the two production levels, may not be 
reflective of the actual baseline fugitive emissions from well sites. 
Further, the potential for fugitive emissions at any given site is 
impacted more by the number and type of equipment at the site and 
maintenance practices, which can vary widely among well sites with low 
production.\224\ Given these

[[Page 63188]]

limitations in utilizing model plants to analyze fugitive emission 
reduction programs at well sites with widely varying configurations, 
operations, and production levels, we find it appropriate to shift away 
from using model plants and instead rely on the potential fugitive 
emissions at the individual site in our BSER analysis and resulting 
proposed standards. Therefore, this new analysis, which is described 
below, is conducted on this basis.
---------------------------------------------------------------------------

    \224\ See https://pubs.acs.org/doi/10.1021/acs.est.0c02927, 
https://data.permianmap.org/pages/flaring, and https://www.edf.org/sites/default/files/documents/PermianMapMethodology_1.pdf.
---------------------------------------------------------------------------

    This site-specific baseline emissions calculation approach is 
similar to the State of Colorado's LDAR program. The concept is that 
each site calculates its baseline methane emissions for all the 
equipment at the site, the number and type of equipment at the well 
site, the number of fugitive emissions components associated with each 
piece of equipment, and the site-specific gas composition. The fugitive 
monitoring frequency would be based on the baseline site-specific 
methane emissions level calculated based on this information. This 
calculation is described in detail in section XI.A.2. We believe that 
this approach will more accurately depict the emissions profile at each 
individual well site. As a result, the EPA is conducting the BSER 
analysis based on site-level baseline methane emissions, where the 
analysis is performed in increments of 1 tpy of site-level baseline 
methane emissions as discussed more below.
    During the rulemaking for the 2016 NSPS OOOOa, the EPA analyzed two 
options for reducing fugitive methane and VOC emissions at well sites: 
A fugitive emissions monitoring program based on individual component 
monitoring using EPA Method 21 for detection combined with repairs and 
a fugitive emissions monitoring program based on the use of OGI 
detection combined with repairs. Finding that both methods achieve 
comparable emission reduction but OGI was more cost effective, the EPA 
ultimately identified semiannual monitoring of well sites using OGI as 
the BSER. 81 FR 35856 (June 3, 2016). While there are several new 
fugitive emissions technologies under development, the EPA needs 
additional information to fully characterize the cost, availability, 
and capabilities of these technologies, and they are therefore not 
being evaluated as potential BSER at this time. However, we are 
proposing the use of these technologies as an alternative screening 
method as described in section XI.A.5. For this analysis for both the 
NSPS and the EG, we re-evaluated the use of OGI as BSER. In the 
discussion below, we evaluate OGI control options based on varying the 
frequency of conducting the survey and fugitive emissions repair 
threshold (i.e., the visible identification of methane or VOC when an 
OGI instrument is used). For this analysis, we considered biennial, 
annual, semiannual, quarterly, and monthly survey frequency for well 
sites.
    The regulatory concept for the proposed NSPS OOOOb is that the 
required frequency of fugitive monitoring would be based on total site 
baseline methane emissions. At well sites, the composition of gas is 
predominantly methane (approximately 70 percent on average). Therefore, 
as shown in our analysis, compared to VOC, methane better reflects the 
baseline emission level where it is cost effective to regulate both 
methane and VOC fugitive emissions at well sites. For this reason, we 
chose to use methane as the threshold for our determination.
    For the BSER analyses, we selected for evaluation total site-wide 
methane emissions increments of 1 tpy of site-level baseline methane 
emissions ranging from 1 tpy to 50 tpy. The EPA acknowledges that the 
site-level baseline methane emissions calculated may not account for 
the presence of large emission events when they occur. However, the EPA 
has found it inappropriate to apply a factor that assumes every site is 
experiencing a large emission event annually based on information 
suggesting that only a small percentage of sites experience these 
events at any given time.\225\
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    \225\ Brandt, A.R., Heath, G.A., Cooley, D. (2016). Methane 
Leaks from Natural Gas Systems Follow Extreme Distributions. 
Environ. Sci. Technol. 50, 12512, https://pubs.acs.org/doi/abs/10.1021/acs.est.6b04303; Zavala-Araiza, D., Alvarez, R., Lyon, D, et 
al. (2016). Super-emitters in natural gas infrastructure are caused 
by abnormal process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012; Zavala-Araiza, D., Lyon, D., 
Alvarez, R. et al. (2015). PNAS 112, 15597. https://www.pnas.org/content/112/51/15597.
---------------------------------------------------------------------------

    In 2015, we evaluated the potential emission reductions from the 
implementation of an OGI monitoring program where we assigned an 
emission reduction of 40, 60, and 80 percent to annual, semiannual, and 
quarterly monitoring survey frequencies, respectively. The EPA re-
evaluated the control efficiencies under different monitoring 
frequencies for the 2020 Technical Rule based on comments received on 
the 2018 proposal and concluded that the assigned control efficiencies 
described above can be expected from the corresponding monitoring 
frequencies using OGI.\226\ No other information reviewed since that 
time indicates that the assigned reduction frequencies are different 
than previously established and the reduction efficiencies are 
consistent with what current information indicates. In addition, we 
also evaluated biennial survey frequency for well sites assuming an 
achievable reduction frequency of 30 percent, and monthly monitoring 
where information evaluated indicated monthly OGI monitoring has the 
potential of reducing emissions up towards 90 percent.
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    \226\ See 85 FR 57412 and section 2.4.1.1 of the 2020 TSD.
---------------------------------------------------------------------------

    It is worth noting that these calculations are based on the 
expected reductions from ``typical'' component equipment leaks that 
occur with well-maintained sites. The EPA is aware of situations where 
equipment malfunctions related to equipment components can cause large 
emission events that are described in detail in section XII.A.5. In 
these cases, we expect the emission reductions associated with the 
different monitoring frequencies evaluated would be significantly 
higher than assumed above and is the reason we solicit comment on the 
proposed alternative screening program using advanced measurement 
technologies to identify and quantify large emission sources. Given the 
intermittent and stochastic nature of large emission events, it is 
difficult to apply emission factors that predict the probability of a 
site experiencing these events within any timeframe. As stated above, 
the EPA finds it inappropriate to apply a factor that assumes every 
site is experiencing a large emission event annually given the 
available data. However, we recognize that identifying and stopping 
these large emission events is a central purpose of the monitoring 
requirements proposed in this document, and that quantifying the 
pollution reduction benefits associated with addressing these large 
emission events is important to fully capture the benefits and cost-
effectiveness of our proposed fugitive emissions monitoring 
requirements. We also acknowledge there is substantial ongoing research 
on large emission events that may further inform the EPA's 
calculations, including the potential to develop factors that take into 
account a distribution of emissions across well sites and the 
associated emissions reductions achieved when large emission events are 
included in the calculation.
    We evaluated the costs of a monitoring and repair program under 
various monitoring frequencies. For

[[Page 63189]]

well sites, the capital costs associated with the fugitives monitoring 
program were estimated to be $1,030 per well site. These capital costs 
include the cost of developing the fugitive emissions monitoring plan 
and purchasing or developing a recordkeeping data management system 
specific to fugitive emissions monitoring and repair. Consistent with 
the analyses used for the 2016 NSPS OOOOa and 2020 Technical Rule, the 
EPA assumes that each company will develop a monitoring plan and 
recordkeeping system that covers a company-defined area, which is 
assumed to include 22 well sites. This assumption is used because there 
are several elements of the fugitive monitoring program that are not 
site-specific. The total company-defined area (22 well site) capital 
costs are divided evenly to arrive at the $1,030 capital cost per well 
site estimate.
    When evaluating the annual costs of the fugitive emissions 
monitoring and repair requirements (i.e., monitoring, repair, repair 
verification, data management licensing fees, recordkeeping, and 
reporting), the EPA considers costs at the individual site level. 
Estimates for these costs were updated extensively as part of the 2020 
Technical Rule, and the EPA has made further updates for this proposal 
based on more recent information. With these updates, the estimated 
annual costs of the fugitive emissions program at well sites are 
estimated to range from $2,490 for biennial monitoring to $8,140 for 
monthly monitoring.\227\ These total annual costs include annualization 
of the up-front cost at 7 percent interest rate over 8 years. We note 
these costs are representative of the average annual costs expected at 
well sites, where larger sites may have larger costs associated with 
longer surveys or potentially more repairs, while smaller sites may 
experience the opposite with shorter surveys or potentially less 
repairs. Therefore, we believe the costs developed for well sites are 
representative of OGI fugitives monitoring program costs and reflect 
the best information available at this time.
---------------------------------------------------------------------------

    \227\ As a comparison, the annualized costs for fugitive 
emissions monitoring and repair at well sites were estimated to 
range from $1,900 to $3,500 for annual to quarterly monitoring, 
respectively, in the 2020 Technical Rule. See 2020 TSD, attachment 5 
at Document ID No. EPA-HQ-OAR-2017-0483-2290.
---------------------------------------------------------------------------

    The EPA requests comment on its range of cost estimates for an OGI 
fugitives monitoring program. The EPA believes that there will be 
sufficient supply of OGI equipment and available OGI camera operators 
for industry to conduct all required monitoring, upon the effective 
date of the NSPS OOOOb and the subsequent implementation of the EG 
OOOOc. However, the EPA requests additional information on this 
capacity and whether there is a likelihood of shortages in the early 
years of the program that might raise costs. The EPA is also requesting 
comment on the proposed appendix K and whether the proposed training, 
certification, and audit provisions are appropriate and do not place 
undue burden on the ability of industry to satisfy the regulatory 
requirements.
    At well sites, there are savings associated with the gas not being 
released. The value of the natural gas saved is assumed to be $3.13 per 
Mcf of recovered gas. Annual costs were also calculated considering 
these savings.
    As discussed in section XI.C, natural gas-driven intermittent 
pneumatic controllers are designed to vent during actuation only, but 
these devices are known to malfunction and operate incorrectly, which 
causes them to release natural gas to the atmosphere when idle. The EPA 
is proposing a zero VOC and methane emissions standard for natural gas-
driven intermittent pneumatic controllers. However, for sites in Alaska 
located in the production segment (well sites, gathering and boosting 
stations, and centralized tank batteries) and in the transmission and 
storage segment that do not have electricity, the EPA is proposing a 
standard wherein intermittent natural gas-driven pneumatic controllers 
only vent during actuation and not when idle. See section XII.C on 
pneumatic controllers for a full explanation of this standard. While 
these intermittent controllers are their own separate affected 
facility, we are proposing that they be monitored in conjunction with 
the fugitive emissions components located at the same well site to 
verify proper actuation and that venting does not occur during idle 
times.
    We created a matrix that includes, for each site-wide methane 
emission level, the capital (up front) cost, annual costs (with and 
without the consideration of savings), emission reductions for methane 
and VOC, and cost effectiveness (dollar per tons of emission 
reduction). Cost effectiveness was calculated using two approaches; the 
single pollutant approach where all the costs are assigned to the 
reduction of one pollutant; and the multipollutant approach, where half 
the costs are assigned to the methane reduction and half to the VOC 
reduction, see discussion in preamble section IX. This was repeated for 
each site-wide methane emissions level for each monitoring frequency. 
There were several trends shown in this matrix. As noted above, the 
annual cost for each individual monitoring frequency is applied to all 
site-wide emission levels when evaluating that frequency. Therefore, as 
the emissions (and potential emission reductions) increased, the 
fugitive emissions monitoring became more cost-effective. For example, 
for semiannual monitoring, the cost effectiveness ranged from $5,300 
per ton of methane reduced (for a 1 tpy site-wide methane site) to $100 
per ton (for a 50 tpy site-wide methane site). Also, because the 
emission reduction increase was greater than the cost increase with 
increasing monitoring frequency, the fugitive emissions monitoring 
became more cost-effective with increasing monitoring frequency. For 
example, for a 10 tpy site-wide methane site, the methane cost 
effectiveness for annual monitoring was $750 per ton, $530 per ton for 
semiannual monitoring, and $525 per ton for quarterly monitoring. This 
trend did not extend to monthly monitoring, as the cost of monthly 
monitoring increases significantly (almost double) compared to 
quarterly monitoring, while the emission reduction only increased by 10 
percent. The complete matrix is available in the NSPS OOOOb and EG TSD 
for this rulemaking.
    The matrix shows that, on a multipollutant basis, both semiannual 
and quarterly monitoring at well sites with baseline emissions as low 
as 2 tpy is cost-effective, and that at 3 tpy, both semiannual and 
quarterly monitoring are cost-effective based on the methane emissions 
alone. Cost-effectiveness, however, is not the only relevant factor in 
setting the BSER, particularly for a source as numerous and diverse as 
well sites. We estimate that there will be approximately 21,000 new 
wells each year (and 410,000 existing wells) to which the proposed 
fugitive emissions requirements will apply.\228\ Various studies 
demonstrate that the vast majority of emissions come from a relatively 
small subset of wells.\229 230\

[[Page 63190]]

The EPA would like to ensure that resources and effort are focused on 
those wells that emit the most methane and VOC. Moreover, given the 
diversity of ownership, while our cost assumption that distributes the 
costs of recordkeeping evenly across 22 sites within a company-defined 
area is a reasonable estimate for the population as a whole, it may 
underestimate the costs and therefore overestimate the cost-
effectiveness for owners with fewer than 22 well sites (and conversely, 
underestimate cost-effectiveness for owners with more than 22 well 
sites). In order to best focus resources and effort on the well sites 
with the greatest emissions and more accurately capture costs, 
particularly for owners with fewer well sites, the EPA requests comment 
on the number of wells that likely emit at each baseline emissions 
level, and the baseline emissions level of wells generally owned by 
owners with few wells. The EPA anticipates that it may refine its BSER 
determination for well sites through its supplemental proposal based on 
the information gathered from commenters.
---------------------------------------------------------------------------

    \228\ Estimated well counts are based on non-wellhead only 
sites. Based on information provided by API, we assume that 27% of 
sites are wellhead only; see Memoranda for Meetings with the 
American Petroleum Institute (API), September 23, 2021, located at 
Docket ID No. EPA-HQ- OAR-2021-0317. Absent additional information, 
we also assume that 27% of wells are wellhead only. The estimated 
new well count reflects the arithmetic average of well counts over 
the analysis horizon in the RIA, 2023-2035. The estimated existing 
well count reflects the total in 2026, which is the first year that 
we estimate impacts for the emissions guidelines.
    \229\ Brandt, A., Heath, G., Cooley, D. (2016) Methane leaks 
from natural gas systems follow extreme distributions. Environ. Sci. 
Technol., DOI: 10.1021/acs.est.6b04303.
    \230\ Zavala-Araiza, D., Alvarez, R., Lyon, D, et al. (2016). 
Super-emitters in natural gas infrastructure are caused by abnormal 
process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012.
---------------------------------------------------------------------------

    Taking these factors into account, and as explained in more detail 
below, the EPA proposes to conclude that (1) BSER for well sites with a 
baseline site-wide emissions level of less than 3 tpy is no regular 
monitoring, but that to help ensure that these sites actually emit at 
less than 3 tpy, a one-time survey (following each calculation of site-
level baseline methane emissions) would be required to ensure that any 
abnormalities are addressed; (2) BSER for well sites with a baseline 
site-wide emissions level of 3 tpy or greater is quarterly monitoring. 
Because of the uncertainties discussed above, and as explained in more 
detail below, the EPA further co-proposes to conclude that BSER for 
well sites with a baseline site-wide emissions level of 3 tpy or 
greater and less than 8 tpy is semiannual monitoring. Our co-proposal 
is the same as our main proposal with regard to well sites whose 
baseline site-wide emissions are less than 3 tpy (no regular 
monitoring, but a one-time survey) and whose emissions are 8 tpy or 
greater (quarterly monitoring). The EPA estimates that a majority of 
fugitive emissions (approximately 86%) can be attributed to wells with 
site-wide baseline emissions of 3 tpy or greater, where 54% can be 
attributed to wells with site-wide baseline emissions of 8 tpy or 
greater.\231\
---------------------------------------------------------------------------

    \231\ Percentages were estimated for the baseline scenario in 
the RIA for the 2030 analysis year by combining the bin percentages 
presented in RIA Table 2-4 with the projected well site activity 
data documented in the RIA.
---------------------------------------------------------------------------

    Proposed BSER for Well Sites with Baseline Emissions Less Than 3 
tpy. As noted, in both our main proposal and our co-proposal, we 
propose to conclude that BSER for well sites with baseline emissions of 
less than 3 tpy is no regular monitoring, but a one-time survey to help 
ensure that these sites actually emit at less than 3 tpy.
    Based on the matrix described above, the EPA determined that where 
total site baseline methane emissions are 2 tpy, semiannual and 
quarterly monitoring costs approximately $2,700/ton methane reduced, 
while biennial and annual monitoring costs approximately $4,000/ton 
methane reduced. The costs for VOC reductions range from $10,000 to 
$15,000/ton VOC reduced for quarterly to biennial monitoring, 
respectively. These costs are outside the range of what we are 
proposing to consider cost effective on a single-pollutant basis for 
both methane and VOC. See Section IX.B. However, when considered on a 
multipollutant basis, the costs of semiannual and quarterly monitoring 
are approximately $1,350 per ton methane reduced, and approximately 
$5,000 per ton of VOC, which we do consider cost-effective. Thus, for 
sites with total baseline methane emissions of 2 tpy, we conclude that 
regular monitoring at semiannual or quarterly frequencies would be 
cost-effective.\232\
---------------------------------------------------------------------------

    \232\ The NSPS OOOOb and EG OOOOc TSD also provide costs for 
monitoring at 1 tpy, which is not considered cost-effective at any 
frequency evaluated.
---------------------------------------------------------------------------

    We do not propose to conclude that routine monitoring with OGI is 
the BSER for sites with baseline emissions of less than 3 tpy, however, 
for several reasons. While the estimates for semiannual and quarterly 
monitoring are within what we consider to be cost effective for well 
sites with baseline emissions of 2 tpy, in light of the large cohort of 
relatively lower-emitting sites, we are concerned that our cost 
effectiveness estimates may not accurately capture the costs, and 
therefore cost-effectiveness, of routine monitoring with OGI for 
businesses that own relatively few well sites. Throughout the 
development of the 2016 NSPS OOOOa, and in subsequent analyses and 
rulemaking actions, industry stakeholders have consistently stated that 
the fugitive monitoring requirements are particularly burdensome for 
smaller entities that own fewer well sites. The EPA believes that many 
of these smaller entities are likely to own well sites with baseline 
emissions of less than 3 tpy, a category that tends to include smaller 
and less complex facilities with few or no major pieces of production 
and processing equipment.\233\ And as noted, the EPA would like to 
ensure that resources and effort are focused on well sites with 
significant emissions. Given the possibility that our cost-
effectiveness analysis has overestimated the average number of sites, 
and therefore underestimated the cost-effectiveness, for this cohort of 
well sites, the EPA is proposing no regular monitoring at sites with 
baseline site-wide emissions of less than 3 tpy.
---------------------------------------------------------------------------

    \233\ Anna M. Robertson, Rachel Edie, Robert A. Field, David 
Lyon, Renee McVay, Mark Omara, Daniel Zavala-Araiza, and Shane M. 
Murphy. ``New Mexico Permian Basin Measured Well Pad Methane 
Emissions Are a Factor of 5-9 Times Higher Than U.S. EPA 
Estimates.''
    Environmental Science & Technology 2020 54 (21), 13926-13934. 
DOI: 10.1021/acs.est.0c02927.
---------------------------------------------------------------------------

    While the EPA is proposing to conclude that BSER for well sites 
with total site-level baseline methane emissions less than 3 tpy is no 
regular monitoring, we believe it is essential to ensure that well 
sites in this monitoring tier are operating in a well-controlled 
manner, and are not experiencing leaks or malfunctions that would cause 
their emissions to exceed 3 tpy. Therefore, the EPA is proposing a 
requirement for owners and operators to conduct a survey, and perform 
repairs as needed, to demonstrate that the well site is free of leaks 
or malfunctions and is therefore operating in a manner consistent with 
the baseline methane emissions calculation.\234\ This survey could 
employ any method available that would demonstrate the actual emissions 
are consistent with the baseline calculation, including, but not 
limited to, the use of OGI, EPA Method 21 (which includes provisions 
for a soap bubble test), or alternative methane detection technologies 
like those discussed in the proposed screening alternative in section 
XI.A.5.
---------------------------------------------------------------------------

    \234\ We anticipate that during the survey to confirm their 
baseline methane emissions and thus exemption status, sources would 
also repair the leaks found, consistent with our understanding of 
the standard industry practice.
---------------------------------------------------------------------------

    The EPA seeks comment on all aspects of this proposed BSER 
determination, including information, data, and analysis that would 
shed further light on the factors and concerns just expressed and that 
would support the establishment of ongoing monitoring requirements at 
the cohort of sites with baseline methane emissions below 3 tpy. Among 
other things, the EPA seeks

[[Page 63191]]

comment on the ownership profile of well sites with site-wide baseline 
emissions less than 3 tpy, the extent to which well sites in this 
cohort are owned by firms that own relatively few wells, and the 
relative economic costs associated with requiring regular OGI 
monitoring at these wells. The EPA also seeks information that would 
improve our understanding of the overall number of wells that would 
fall in this cohort of sites, and the contribution these wells make to 
overall fugitive emissions. And the EPA seeks comment on our estimates 
of the costs and emission reduction associated with OGI monitoring at 
this cohort of sites, or other data and analysis that would provide 
support for regular OGI monitoring at these sites. In addition, the EPA 
notes that the advanced measurement technologies that form the basis of 
our proposed alternative screening option in section XI.A.5 could be 
particularly well-suited for rapidly and cost-effectively detecting 
recurrences of large emitting events at sites with baseline emissions 
below 3 tpy. Accordingly, the EPA seeks comment that could inform 
whether to require the use of these technologies for ongoing monitoring 
at this cohort of sites, including information on the capabilities of 
these emerging technologies, methodologies for their use, and the costs 
and emission reductions associated with using these advanced 
measurement technologies as part of a mandatory monitoring regime. If 
appropriate, and based on input received during the comment period, the 
EPA may consider further addressing monitoring requirements for sites 
with baseline emissions below 3 tpy as part of a supplemental proposal.
    Additionally, the EPA is soliciting comment on different criteria, 
such as the number of well sites owned by a specific owner, that could 
better account for factors that may affect the costs of fugitive 
emissions monitoring. As noted, while the EPA has presented costs on an 
individual site-level, we have also distributed the costs of 
recordkeeping evenly across an assumed 22 sites within a company-
defined area. While this may be appropriate for companies with larger 
ownership, it is likely underestimating the cost (and overestimating 
the cost-effectiveness) on owners with fewer sites. Information 
provided on small businesses, including ownership thresholds, could be 
used to further determine differences in OGI monitoring requirements at 
well sites through a supplemental proposal.
    Further, the EPA is soliciting comment on whether the presence of 
specific major production and processing equipment types at a well site 
warrants a separate monitoring frequency consideration even where the 
calculated total site-level baseline methane emissions are below 3 tpy. 
As mentioned throughout this preamble, the EPA is concerned about the 
presence of large emission events, which various studies have shown are 
most often attributed to specific equipment. This equipment includes 
separators paired with onsite storage vessels, combustion devices, and 
intermittent pneumatic controllers.^{235 236 237} Therefore, 
the EPA is soliciting comment on whether well sites with these specific 
types of equipment present must conduct at least semiannual monitoring, 
regardless of the total site-level baseline methane emissions 
calculated, including those sites calculated below 3 tpy.
---------------------------------------------------------------------------

    \235\ Id.
    \236\ Tyner, David R., Johnson, Matthew R., ``Where the Methane 
Is--Insights from Novel Airborne LiDAR Measurements Combined with 
Ground Survey Data.'' Environmental Science & Technology 2021 55 
(14), 9773-9783. DOI: 10.1021/acs.est.1c01572.
    \237\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al. 
Closing the methane gap in US oil and natural gas production 
emissions inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4.
---------------------------------------------------------------------------

    Finally, the EPA believes there is a subset of well sites (i.e., 
wellhead only well sites) that will never have baseline methane 
fugitive emissions of 3 tpy or greater. Therefore, the proposed rule 
would not define these sites as affected facilities, thus removing the 
need for these sites to determine baseline emissions. As defined in the 
2020 Technical Rule, a ``wellhead only well site'' is ``a well site 
that contains one or more wellheads and no major production and 
processing equipment.'' The term ``major production and processing 
equipment'' is defined as including reciprocating or centrifugal 
compressors, glycol dehydrators, heater/treaters, separators, and 
storage vessels collecting crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water. As described earlier in this 
section, sites will calculate their baseline methane emissions using a 
combination of population-based emission factors and storage vessel 
emissions. The population-based emission factors include emissions from 
wellheads, reciprocating and centrifugal compressors, glycol 
dehydrators, heater/treaters, separators, natural gas-driven pneumatic 
pumps, and natural gas-driven pneumatic controllers (both continuous 
and intermittent). By definition, a wellhead only well site would not 
have emissions associated with the major production and processing 
equipment, which includes storage vessels. Further, this proposed rule 
would not allow the use of natural gas-driven pneumatic controllers at 
any location (except on the Alaska North Slope), including wellhead 
only well sites. Therefore, the only emissions would be calculated 
based on the fugitive emissions components associated with the 
wellhead, which we believe would never be above 3 tpy.
    Proposed BSER for Sites with Baseline Emissions of 3 tpy or 
Greater. The EPA next evaluated what frequency of OGI monitoring is 
BSER for well sites where the total site-level baseline methane 
emissions are 3 tpy or greater. Table 14 summarizes the cost-
effectiveness information for each monitoring frequency evaluated at 
this threshold.

                   Table 14--Summary of Emission Reductions and Cost-Effectiveness for Site-Level Baseline Methane Emissions of 3 TPY
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Single-pollutant                 Multipollutant
                                                              Methane      VOC emission  ---------------------------------------------------------------
          Monitoring frequency              Annual cost      emission     reduction (tpy/  Methane cost-     VOC cost-     Methane cost-     VOC cost-
                                            ($/yr/site)      reduction         site)       effectiveness   effectiveness   effectiveness   effectiveness
                                                            (tpy/site)                        ($/ton)         ($/ton)         ($/ton)         ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                       3 tpy site-level baseline methaneemissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
Biennial................................          $2,500            0.90            0.25          $2,800         $10,000          $1,400          $5,000
Annual..................................           3,000            1.20            0.33           2,500           9,000           1,250           4,500
Semiannual..............................           3,200            1.80            0.50           1,800           6,400             900           3,200
Quarterly...............................           4,200            2.40            0.67           1,800           6,300             900           3,200
Monthly.................................           8,100            2.70            0.75           3,000          11,000           1,500           5,400
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 63192]]

    Based on the information summarized in Table 14, the average costs 
per ton reduced appear to be reasonable for either semiannual or 
quarterly monitoring when site-level baseline methane emissions are 3 
tpy or greater under the single pollutant approach for methane 
(biennial, annual, or monthly are outside of what the EPA considers 
reasonable for VOCs in the single pollutant approach), or reasonable at 
any frequency under the multipollutant approach.
    In addition to considering the average costs per ton reduced for 
these sites, the EPA also evaluated the incremental cost associated 
with progressing to greater monitoring frequencies. To conduct this 
analysis, the EPA first considered semiannual monitoring for these 
sites as a baseline for comparison. Since 2016, owners and operators 
have been conducting semiannual monitoring pursuant to NSPS OOOOa, 
State requirements, or voluntarily, thus demonstrating the 
reasonableness of that frequency. Additionally, the cost is comparable 
to the costs found reasonable in the 2016 NSPS OOOOa \238\ for both the 
single pollutant approach for methane or multipollutant approach for 
both methane and VOC. To determine if quarterly monitoring is 
reasonable for sites with total baseline methane emissions of 3 tpy, we 
evaluated the incremental costs of going from semiannual to quarterly 
monitoring. The incremental costs of semiannual to quarterly monitoring 
for an emissions baseline of 3 tpy methane is $1,700/ton methane and 
$6,000/ton VOC using the single pollutant approach (and $800/ton 
methane and $3,000/ton VOC using the multipollutant cost effectiveness 
approach). These incremental costs are within the range we find 
reasonable in this proposal under the single pollutant approach for 
methane and under the multipollutant approach.
---------------------------------------------------------------------------

    \238\ The 2020 Technical Rule amended only the VOC standards in 
the 2016 NSPS OOOOa and, as discussed in section X.A, incorrectly 
identified $738/ton as the highest value that the EPA found cost 
effective for methane reduction in the 2016 NSPS OOOOa.
---------------------------------------------------------------------------

    We next evaluated monthly monitoring for this cohort. As shown in 
Table 14, monthly monitoring appears reasonable under the 
multipollutant approach. Therefore, we evaluated the incremental costs 
of going from quarterly monitoring to monthly monitoring to determine 
if monthly monitoring is appropriate. Table 15 summarizes these 
incremental costs. As shown in Table 15, the incremental cost of going 
from quarterly to monthly monitoring when baseline emissions are 3 tpy 
is $13,000/ton methane and $47,000/ton VOC under the single pollutant 
approach ($6,500/ton methane and $23,500/ton VOC under the 
multipollutant approach). In both approaches, these costs are outside 
the range of what we are proposing to consider cost effective. See 
Section IX.B.
    Based on the analysis described above, we propose to find that 
quarterly monitoring at well sites with total site-level baseline 
methane emissions of 3 tpy or greater is the BSER. We note that 
California requires quarterly inspections for all well sites under its 
LDAR requirements in Code of Regulations, Title 17, Division 3, Chapter 
1, Subchapter 10 Climate Change, Article 4, Article Subarticle 13: 
Greenhouse Gas Emission Standards for Crude Oil and Natural Gas 
Facilities, which supports a conclusion that quarterly monitoring at 
these sites is feasible and cost-effective.\239\
---------------------------------------------------------------------------

    \239\ https://ww2.arb.ca.gov/sites/default/files/classic/regact/2016/oilandgas2016/ogfro.pdf.
---------------------------------------------------------------------------

    Accordingly, the EPA's primary proposal is to conclude that BSER 
for well sites with total site-level baseline emissions of less than 3 
tpy is no regular monitoring (but a one-time survey) and that BSER for 
well sites with total site-level baseline emissions of 3 tpy or greater 
is quarterly monitoring and repair.
    While the EPA is proposing quarterly OGI monitoring for well sites 
with total site-level baseline methane emissions of 3 tpy or greater, 
we are concerned this cost-effectiveness analysis may not fully account 
for the numerosity and diversity of sites and their potential emission 
profiles. We further note that some States with established fugitive 
emissions monitoring programs have provided for more graduated 
frequencies that recognize this diversity among sites. For example, 
Colorado's Regulation 7 Control of Ozone via Ozone Precursors and 
Control of Hydrocarbons via Oil and Gas Emissions \240\ requires a 
tiered inspection frequency regime that provides for semiannual 
monitoring at site-wide baseline emissions thresholds that far exceed 
the EPA's proposed 3 tpy threshold. Under the Colorado regulations, a 
semiannual inspection frequency is required for well production 
facilities with uncontrolled actual VOC emissions between 2 and 12 tpy 
(corresponding to approximately 7 to 43 tpy methane). Quarterly 
inspections are required for well sites without storage tanks and with 
uncontrolled actual VOC emissions between 12 and 20 tpy (corresponding 
to approximately 43 to 72 tpy methane), and for well sites with storage 
tanks and with uncontrolled actual VOC emissions between 12 and 50 tpy 
(corresponding to approximately 43 to 180 tpy methane). Colorado 
Regulation 7 also requires monthly inspections for well production 
facilities without storage tanks with uncontrolled actual VOC emissions 
above 20 tpy (and above 50 tpy for facilities with storage tanks). The 
proposed thresholds for quarterly monitoring in this action are more 
stringent than the Colorado regulations when compared using the gas 
composition ratio of 0.28 VOC to methane that is used in our BSER 
analysis. Specifically, the VOC emissions associated with a site-level 
baseline methane emission rate of 3 tpy are 0.83 tpy VOC, less than 
half the VOC threshold that requires semiannual monitoring and 14.5 
times lower than the VOC threshold requiring quarterly monitoring in 
Colorado.
---------------------------------------------------------------------------

    \240\ https://cdphe.colorado.gov/aqcc-regulations.
---------------------------------------------------------------------------

    Although Colorado's regulations are most directly comparable to the 
EPA's proposed approach, other States also provide for more graduated 
monitoring frequencies. For example, Ohio's General Permits 12.1 and 
12.2 initially require quarterly monitoring for well sites, followed by 
a reduced monitoring frequency of semiannual or annual monitoring 
depending on the fraction of equipment found to be leaking.\241\
---------------------------------------------------------------------------

    \241\ https://epa.ohio.gov/dapc/genpermit/oil-and-gas-well-site-production.
---------------------------------------------------------------------------

    When considering these State programs, particularly the comparison 
of our proposal to Colorado's thresholds; the fact that our cost-
effectiveness calculation may not account for the diversity of 
emissions and sites; and the concerns we have raised regarding the 
cost-effectiveness for businesses with fewer well sites than are 
assumed in our cost-effectiveness analysis (many of whom we anticipate 
are small businesses), the EPA believes it is also appropriate to co-
propose semiannual monitoring for well sites in a middle cohort--those 
with total site-level baseline emissions of 3 tpy or greater and less 
than 8 tpy. We seek comment on the number and ownership profile of 
wells that would fall into this category to better understand whether 
semiannual monitoring is an appropriate monitoring frequency for sites 
in this range.
    To inform this analysis, we evaluated methane emissions in 1 tpy 
increments starting at 3 tpy. Tables 15a and 15b summarize the total 
costs and incremental costs of semiannual to quarterly for baseline 
methane

[[Page 63193]]

emissions of 3 tpy or greater and less than 8 tpy.

              Table 15a--Summary of Total Cost-Effectiveness for Fugitive Monitoring at Well Sites
----------------------------------------------------------------------------------------------------------------
                                                      Single pollutant cost-           Multipollutant cost-
                                                           effectiveness                   effectiveness
   Site-level baseline methane    Annual cost ($/---------------------------------------------------------------
         emissions (tpy)             yr/site)       Methane ($/                     Methane ($/
                                                       ton)         VOC ($/ton)        ton)         VOC ($/ton)
----------------------------------------------------------------------------------------------------------------
                                              Semiannual Monitoring
----------------------------------------------------------------------------------------------------------------
3...............................          $3,200          $1,800          $6,400            $890          $3,200
4...............................           3,200           1,300           4,800             670           2,400
5...............................           3,200           1,100           3,800             530           1,900
6...............................           3,200             890           3,200             440           1,600
7...............................           3,200             760           2,700             380           1,400
8...............................           3,200             670           2,400             330           1,200
----------------------------------------------------------------------------------------------------------------
                                              Quarterly Monitoring
----------------------------------------------------------------------------------------------------------------
3...............................           4,200           1,800           6,300             880           3,200
4...............................           4,200           1,300           4,700             660           2,400
5...............................           4,200           1,000           3,800             530           1,900
6...............................           4,200             880           3,200             440           1,600
7...............................           4,200             750           2,700             380           1,400
8...............................           4,200             660           2,400             330           1,200
----------------------------------------------------------------------------------------------------------------


           Table 15B--Summary of Incremental Cost-Effectiveness for Fugitive Monitoring at Well Sites
----------------------------------------------------------------------------------------------------------------
                                                    Incremental                   Incremental cost-effectiveness
                                    Incremental       methane       Incremental  -------------------------------
   Site-level baseline methane    annual cost ($/    emission      VOC emission
         emissions (tpy)             yr/site)     reduction (tpy/ reduction (tpy/   Methane ($/     VOC ($/ton)
                                                       site)           site)           ton)
----------------------------------------------------------------------------------------------------------------
                                     Incremental for semiannual to quarterly
----------------------------------------------------------------------------------------------------------------
3...............................          $1,000            0.60            0.17          $1,700          $6,000
4...............................           1,000            0.80            0.22           1,250           4,500
5...............................           1,000            1.00            0.27           1,000           3,600
6...............................           1,000            1.20            0.33             840           3,000
7...............................           1,000            1.40            0.39             720           2,600
8...............................           1,000            1.60            0.45             630           2,250
----------------------------------------------------------------------------------------------------------------

    While there is no obvious cutoff point, the EPA anticipates that 
well sites with calculated baseline emissions of 8 tpy or greater will 
generally consist of complex sites comprising multiple wellheads and/or 
one or more of the major pieces of production or processing equipment 
that are known to have a propensity for causing large emissions events. 
The EPA also believes it is possible that at 8 tpy and greater, well 
sites are both more likely to be owned by companies with a larger 
number of sites and that the owners of these wells are likely to be 
larger companies. Lastly, the EPA estimates that a large share of 
fugitive emissions (approximately 54%) can be attributed to wells with 
site-wide baseline emissions of 8 tpy or greater.\242\ For these 
reasons, the EPA believes that an 8 tpy threshold for quarterly 
monitoring would appropriately focus resources on the wells with the 
largest emissions profiles, and that concerns about on the costs for 
small owners or operators are most attenuated for this cohort of 
relatively large and high-emitting sites. As noted above, we seek 
comment on whether it is sensible to have a middle cohort with a 
semiannual monitoring requirement and, if so, what the bounds of that 
cohort should be. In making this determination, the EPA is particularly 
interested in comments regarding the number and ownership profiles of 
well sites that may fall into this middle cohort.
---------------------------------------------------------------------------

    \242\ Percentage estimated using the analysis underpinning the 
baseline scenario in the RIA for the 2030 analysis year.
---------------------------------------------------------------------------

    As required by section 111, the EPA's proposed BSER analysis for 
fugitive emissions from all well sites has considered nonair quality 
health and environmental impacts. No secondary gaseous pollutant 
emissions or wastewater are generated during the monitoring and repair 
of fugitive emissions components. There are some emissions that would 
be generated by contractors conducting the OGI camera monitoring 
associated with driving to and from the site for the fugitive emissions 
survey. Using AP-42 mobile emission factors and assuming a distance of 
70 miles to the well site, the emissions generated from semiannual 
monitoring at a well site (140 miles to and from the well site twice a 
year) is estimated to be 0.35 lb/yr of hydrocarbons, 6.0 lb/yr of CO 
and 0.40 lb/yr of NOx. No other secondary impacts are 
expected. We do not believe these secondary emissions are so 
significant as to affect the proposed determinations described above.
    In summary, based on the analysis described above, the EPA is 
proposing OGI monitoring based on tiered total site-wide baseline 
methane emission levels to represent thresholds that would determine 
the monitoring frequency. For well sites with total site-level methane 
emissions less than 3 tpy,

[[Page 63194]]

the EPA is proposing to require a one-time survey to demonstrate that 
the well site is free of leaks or other abnormal conditions that are 
not accounted for in the baseline calculation. For well sites with 
total site-level methane emissions of 3 tpy or greater, the EPA is 
proposing quarterly monitoring at all sites. Lastly, the EPA is co-
proposing semiannual monitoring for well sites with total site-level 
methane emissions of 3 tpy or greater and less than 8 tpy, and 
quarterly monitoring for all sites with baseline emissions of 8 tpy or 
greater. As noted earlier, site-level baseline emission levels would be 
calculated by owners and operators for each site based on prescribed 
population emission factors for components and equipment at the site, 
combined with an assessment of potential methane emission from storage 
vessels (after applying controls).
b. Fugitive Emissions From Compressor Stations
    The EPA continues to utilize the model plant approach in estimating 
baseline fugitive emissions from compressor stations. Unlike well 
sites, we believe that compressor station designs are less variable and 
that model plants are an effective construct to analyze fugitive 
emission control programs. The EPA has evaluated feedback received from 
several industry stakeholders related to development of compressor 
station model plants over multiple years since the original 2015 NSPS 
OOOOa proposal were model plants for compressor stations (including 
those at gathering and boosting stations, transmission stations, and 
storage facilities) were first introduced. Consistent with this early 
approach for estimating emissions from compressor stations, the EPA 
still believes the model plant approach is the best way to assess 
fugitive emissions from compressor stations, in the absence of 
information indicating otherwise. Baseline model plant emissions for 
compressor stations can reasonably be calculated using equipment 
counts, fugitive emissions component counts, and emissions factors from 
the 1995 Emissions Protocol. The EPA has evaluated each specific model 
plant for gathering and boosting, transmission, and storage, based on 
information that has become available, and model plants were updated 
where information indicated an update was appropriate. For example, 
information from actual compressor stations in operation provided by 
GPA Midstream for several of their member companies representing 
numerous sites across the country, was used to refine the gathering and 
boosting model plant in 2020. Refinements have also been made to the 
transmission and storage model plants based on information received 
from companies in these segments. The size and equipment located at 
compressor stations do not vary as widely as at well sites, and 
therefore emissions are expected to be less variable as well. 
Furthermore, stakeholders have not indicated that a model plant 
approach is not reasonable. For these reasons, the EPA retains a model 
plant approach for compressor stations which are representative in 
estimating fugitive emissions.
    There are three types of compressor stations in the Crude Oil and 
Natural Gas source category: (1) Gathering and boosting stations, (2) 
transmission stations, and (3) storage stations. The equipment 
associated with these compressor stations vary depending on the volume 
of natural gas that is transported and whether any treatment of the gas 
occurs, such as the removal of water or hydrocarbons. The model plants 
developed for these sites include all equipment (including piping and 
associated components, compressors, generators, separators, storage 
vessels, and other equipment) and associated components (e.g., valves 
and connectors) that may be sources of fugitive emissions associated 
with these operations. One model plant was developed for each of the 
three types of compressor stations described above, which are discussed 
in detail in the 2020 NSPS OOOOa TSD and in the NSPS OOOOb and EG TSD 
supporting this action. For gathering and boosting stations, the 
fugitive baseline emissions were estimated to be 16.6 tpy of methane 
and 4.6 tpy of VOC. For transmission stations, the fugitive baseline 
emissions were estimated to be 40.4 tpy of methane and 1.1 tpy of VOC. 
For storage stations, the fugitive baseline emissions were estimated to 
be 142.2 tpy of methane and 3.9 tpy of VOC.
    As with well sites, in the original BSER analysis for the 2016 NSPS 
OOOOa rulemaking, two options for reducing fugitive methane and VOC 
emissions at compressor stations were identified, which were (1) a 
fugitive emissions monitoring program based on individual component 
monitoring using EPA Method 21 for detection combined with repairs and 
(2) a fugitive emissions monitoring program based on the use of OGI 
detection combined with repairs. Finding that both methods achieve 
comparable emission reduction but OGI was more cost effective, the EPA 
ultimately identified quarterly monitoring of compressor stations using 
OGI as the BSER. 81 FR 35862. While there are several new fugitive 
emissions technologies under development, the EPA needs additional 
information and better understanding of these technologies, and they 
are therefore not being evaluated as potential BSER at this time. For 
this analysis for both the NSPS and the EG, we re-evaluated OGI as 
BSER. In the discussion below, we evaluate OGI control options based on 
varying the frequency of conducting the survey and fugitive emissions 
repair threshold (i.e., the visible identification of methane or VOC 
when an OGI instrument is used). For this analysis, we considered 
annual, semiannual, quarterly, and monthly survey frequency for 
compressor stations.
    In 2015, we evaluated the potential emission reductions from the 
implementation of an OGI monitoring program where an emission reduction 
of 40, 60 and 80 percent for annual, semiannual, and quarterly 
monitoring survey frequencies, respectively, were determined 
appropriate. No other information reviewed since 2015 indicates that 
the assigned reduction frequencies are different than previously 
established and the reduction efficiencies are consistent with what 
current information indicates. In addition, we also evaluated monthly 
monitoring for compressor stations where information evaluated 
indicated monthly OGI monitoring has the potential of reducing 
emissions up towards 90 percent.
    We evaluated the costs of monitoring and repair under various 
monitoring frequencies described above, including the cost of OGI 
monitoring via the camera survey, repair costs, resurvey costs, 
monitoring plan development and the cost of a recordkeeping system. For 
compressor stations, the capital cost associated with the fugitives 
monitoring program were estimated to be $3,090 for each gathering and 
boosting compressor station, which includes development of a fugitive 
emissions monitoring plan for a company-defined area (assumed to 
include 7 gathering and boosting compressor stations) and database 
management development or licensing for recordkeeping. These capital 
costs are divided evenly amongst the 7 gathering and boosting 
compressor stations in the company-defined area for purposes of the 
model plant analysis, consistent with the 2016 NSPS OOOOa and 2020 
Technical Rule analyses. The capital cost associated with the fugitives 
monitoring program for transmission and storage compressor stations was 
estimated at $23,880, which is for a single transmission and storage 
compressor station. The annual costs

[[Page 63195]]

include the capital recovery cost (calculated at a 7 percent interest 
rate for 10 years), survey and repair costs, database management fees, 
and recordkeeping and reporting costs. The annual costs estimated for 
compressor stations range from $6,350 for annual monitoring to $33,220 
for monthly monitoring at gathering and boosting compressor stations. 
For transmission compressor stations, the annual costs estimated range 
from $12,900 for annual monitoring to $39,770 for monthly monitoring. 
For storage compressor stations, the annual costs estimated range from 
$17,000 for annual monitoring to $43,860 for monthly monitoring.
    As discussed above, the EPA is proposing that natural gas-driven 
intermittent vent controllers at production and natural gas 
transmission sites in Alaska without electricity would be subject to a 
standard that prohibits emissions when the controller is idle. 
Intermittent pneumatic controllers are designed to vent during 
actuation only, but these devices are known to malfunction and operate 
incorrectly which causes them to release natural gas to the atmosphere 
when idle. For sites in Alaska that do not have electricity located in 
the production segment (well sites, gathering and boosting stations, 
and centralized tank batteries) and in the transmission and storage 
segment, the EPA is proposing to define intermittent natural gas-driven 
pneumatic controllers as an affected facility and proposing to apply a 
standard that these controllers only vent during actuation and not when 
idle. See section XII.C on pneumatic controllers for a full explanation 
of this standard. We have determined that it would be efficient and 
reasonable to verify proper actuation and that venting does not occur 
during idle times by proposing that these devices are monitored along 
with fugitive emissions components at a site to ensure these devices 
are meeting the standard. We believe the cost of monitoring of 
intermittent pneumatic controllers will be absorbed by the cost of the 
fugitive emissions program, and that little to no additional cost would 
be associated with monitoring these devices on the fugitive emissions 
components monitoring schedule. If compressor stations have 
electricity, they would be required to have non-emitting controllers, 
and no additional costs are expected to be incurred relayed to repair 
and/or replacement of malfunctioning intermittent vent controllers.
    At gathering and boosting compressor stations there are savings 
associated with the gas not being released. The value of the natural 
gas saved is assumed to be $3.13 per Mcf of recovered gas. Transmission 
and storage compressor stations do not own the natural gas; therefore, 
revenues from reducing the amount of natural gas emitted/lost was not 
applied for this segment.
    The EPA evaluated the cost-effectiveness of monitoring for each 
sub-type of compressor station, starting with evaluating whether 
quarterly monitoring remains the BSER. The 2016 NSPS OOOOa requires a 
fugitive emissions monitoring and repair program, where compressor 
stations have to be monitored quarterly. Compressor stations have 
successfully met this standard. Further, several State agencies have 
rules that require quarterly monitoring at compressor stations. For 
example, Colorado's Regulation 7 Control of Ozone via Ozone Precursors 
and Control of Hydrocarbons via Oil and Gas Emissions \243\ requires a 
semiannual inspection frequency for compressor stations with 
uncontrolled actual VOC emissions between 2 and 12 tpy, a quarterly 
inspection frequency for compressor stations with uncontrolled actual 
VOC emissions between 12 and 50 tpy, and monthly inspections for 
compressor stations with uncontrolled actual VOC emissions above 50 
tpy. California requires quarterly inspections under their LDAR 
requirements \244\ and similarly, Ohio's General Permit 18.1 also 
requires quarterly monitoring for compressor stations.\245\ These 
examples of State rules, where quarterly monitoring appears to be the 
lowest monitoring frequency required with one exception where the VOC 
baseline emissions were extraordinarily high, is a demonstration of the 
reasonableness of monitoring fugitive emissions components on a 
quarterly basis for compressor stations.
---------------------------------------------------------------------------

    \243\ https://cdphe.colorado.gov/aqcc-regulations.
    \244\ https://ww2.arb.ca.gov/sites/default/files/classic/regact/2016/oilandgas2016/ogfro.pdf.
    \245\ https://www.epa.state.oh.us/dapc/genpermit/ngcs/GP_181.
---------------------------------------------------------------------------

    Given the apparent reasonableness of quarterly monitoring as 
discussed above, the EPA evaluated whether it was reasonable to require 
monthly monitoring for compressor stations. Table 16 summarizes the 
cost, emission reductions, and cost-effectiveness of quarterly and 
monthly OGI monitoring at compressor stations for the single pollutant 
approach, while Table 17 summarizes the multi-pollutant approach.

                     Table 16--Summary of the Single Pollutant Cost of Control for Compressor Station Fugitive Emissions Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                Emission reductions        Methane cost     VOC cost of
                                           Capital cost   Annual cost ($/ Annual cost w/ -------------------------------- of control w/o    control w/o
               Model plant                      ($)             yr)       savings ($/yr)  Methane  (tons/                   savings ($/     savings ($/
                                                                                                yr)        VOC (tons/yr)       ton)            ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Quarterly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting....................          $3,100         $13,400         $11,000            13.3             3.7          $1,000          $3,600
Transmission............................          23,900          19,900          19,900            32.3             0.9             600          22,300
Storage.................................          23,900          24,000          24,000           114.0             3.2             200           7,600
                                         ---------------------------------------------------------------------------------------------------------------
    Compressor Program Weighted Average.  ..............  ..............  ..............  ..............  ..............             900           4,400
                                         ---------------------------------------------------------------------------------------------------------------
                                                                   Monthly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting....................           3,100          33,200          30,500            15.0             4.2           2,200           8,000
Transmission............................          23,900          39,800          39,800            36.4             1.0           1,100          39,500
Storage.................................          23,900          43,900          43,900           128.2             3.5             340          12,400
                                         ---------------------------------------------------------------------------------------------------------------
    Compressor Program Weighted Average.  ..............  ..............  ..............  ..............  ..............           1,800           9,300
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 63196]]


                      Table 17--Summary of the Multi-Pollutant Cost of Control for Compressor Station Fugitive Emissions Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                Emission reductions        Methane cost     VOC Cost of
                                           Capital cost   Annual cost ($/ Annual cost w/ -------------------------------- of control w/o    control w/o
               Model plant                      ($)             yr)       savings ($/yr)  Methane (tons/                    savings ($/     savings ($/
                                                                                                yr)        VOC (tons/yr)       ton)            ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Quarterly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting....................          $3,100         $13,400         $11,000            13.3             3.7            $500          $1,800
Transmission............................          23,900          19,900          19,900            32.3             0.9             300          11,100
Storage.................................          23,900          24,000          24,000           114.0             3.2             100           3,800
                                         ---------------------------------------------------------------------------------------------------------------
    Compressor Program Weighted Average.  ..............  ..............  ..............  ..............  ..............             430           2,200
                                         ---------------------------------------------------------------------------------------------------------------
                                                                   Monthly Monitoring
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering & Boosting....................           3,100          33,200          30,500            15.0             4.2           1,100           4,000
Transmission............................          23,900          39,800          39,800            36.4             1.0             550          19,800
Storage.................................          23,900          43,900          43,900           128.2             3.5             200           6,200
                                         ---------------------------------------------------------------------------------------------------------------
    Compressor Program Weighted Average.  ..............  ..............  ..............  ..............  ..............             900           4,600
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on the single pollutant approach, both quarterly and monthly 
frequencies are reasonable for methane emissions, while only quarterly 
is reasonable for VOC emissions. Like described for well sites, owners 
and operators of compressor stations have been monitoring quarterly 
since 2016 pursuant to NSPS OOOOa, State requirements, or voluntarily, 
which suggests these costs are reasonable. These costs for quarterly 
monitoring are also comparable to those found reasonable in both the 
2016 NSPS OOOOa and the 2020 Technical Rule. Further, both frequencies 
are reasonable under the multipollutant approach when considering the 
total cost-effectiveness compared to a baseline of no OGI monitoring.
    The EPA then looked at the incremental costs of going from 
quarterly to monthly monitoring. Quarterly monitoring achieves an 
emission reduction ranging from 13.3 tpy at gathering and boosting 
compressor stations to 114 tpy at storage compressor stations. Monthly 
monitoring achieves additional reductions ranging from 1.7 tpy at 
gathering and boosting compressor stations to 14.2 tpy at storage 
compressor stations. However, these additional reductions are achieved 
at $9,400/ton methane (and nearly $50,000/ton VOC). The EPA finds that 
achieving these additional emissions reductions is not reasonable for 
the cost, given the only small fraction of additional reductions 
realized at monthly monitoring. Based on the cost analysis summarized 
above, we find that the cost effectiveness of quarterly monitoring for 
compressor stations is reasonable.
    Finally, no secondary gaseous pollutant emissions or wastewater are 
generated during the monitoring and repair of fugitive emissions 
components. There are some emissions that would be generated by the OGI 
camera monitoring contractors with respect to driving to and from the 
site for the fugitive emissions survey. Using AP-42 mobile emission 
factors and assuming a distance of 70 miles to the compressor station, 
the emissions generated from quarterly monitoring at a compressor 
station (140 miles to and from the compressor station four times a 
year) is estimated to be 0.70 lb/yr of hydrocarbons, 12.0 lb/yr of CO 
and 0.80 lb/yr of NOX. No other secondary impacts are 
expected.
    In light of the above, we find that the BSER for reducing methane 
and VOC emissions from all compressor stations, including gathering and 
boosting stations, transmission stations, and storage stations is 
quarterly monitoring for this proposal. Therefore, for NSPS OOOOb, we 
are proposing to require quarterly monitoring for all compressor 
stations.
2. EG OOOOc
    The EPA also evaluated BSER for the control of fugitive emissions 
at existing well sites and compressor stations. The findings were that 
the controls evaluated for new sources for NSPS OOOOb are appropriate 
for consideration under the EG OOOOc. Further, the EPA finds that the 
OGI monitoring, methane emission reductions, costs, and cost 
effectiveness results discussed above for new sources are also 
applicable for existing sources.
    Therefore, for the EG OOOOc, the EPA is proposing presumptive 
standards to require quarterly monitoring for well sites with site-
level baseline methane emissions greater than and equal to 3 tpy. 
Further, we are co-proposing semiannual monitoring for well sites with 
site-level baseline methane emissions greater than and equal to 3 tpy 
and less than 8 tpy, and quarterly monitoring for well sites with site-
level baseline methane emissions greater than and equal to 8 tpy. We 
find the costs reasonable for existing well sites with total site-level 
baseline methane emissions greater than or equal to 3 tpy to conduct 
quarterly OGI monitoring at an incremental cost of $1,700/ton methane 
reduced. We are aware that there is a large percentage of existing well 
sites that are likely owned and operated by small businesses. We 
continue to be concerned about the burden of frequent OGI monitoring on 
these small businesses and are requesting comment consistent with our 
solicitation for new sources.
    The EPA also finds, and is proposing, that the BSER for reducing 
methane emissions from all existing compressor stations, including 
gathering and boosting stations, transmission stations, and storage 
stations is quarterly monitoring. For compressor stations, we find that 
both quarterly (at $430/ton methane reduced) and monthly monitoring (at 
$900/ton methane reduced) are reasonable when looking at total cost-
effectiveness against a baseline of no monitoring, however, at an 
incremental cost of $9,400/ton methane reduced, monthly monitoring is 
not reasonable. Therefore, for the EG OOOOc, we are proposing a 
presumptive standard of quarterly monitoring for all compressor 
stations.

[[Page 63197]]

3. Alternative Screening Using Advanced Measurement Technology
    As discussed throughout this preamble, the EPA recognizes the 
existence large emission events. In certain instances, these situations 
could be caused by severely and continuously leaking components that 
would be identified and corrected via the routine OGI-based periodic 
monitoring program, but only on a quarterly or semiannual basis. 
Moreover, some large emission events are intermittent and stochastic in 
nature and may not be identified via these OGI surveys. Since the 2016 
NSPS OOOOa, significant strides have occurred in developing and 
deploying methane detection technologies that can detect fugitive 
emissions (especially large emission events) in a potentially faster 
and more cost-effective manner than traditional techniques such as OGI 
and EPA Method 21. The EPA has continued following the development of 
these technologies and their applications through various public 
programs, such as the DOE ARPA-E programs, which have focused on the 
development of cost-effective tools to locate and measure methane 
emissions. Additionally, the EPA has continued discussions with 
stakeholders, including academic researchers and private industry, as 
they develop and evaluate novel tools for the detection and 
quantification of methane emissions in the oil and gas sector. As noted 
in section VII.B, the EPA also held a two-day workshop in August 2021 
to hear perspectives on these new technologies. Some of the promising 
technologies now emerging include, but are not limited to, fixed-base 
and open path sensor networks, unmanned aircraft systems (UAS) equipped 
with methane detection equipment, the use of high-end instruments for 
mobile measurements on the ground and in the air, and satellite 
observations with advanced optical techniques.
    As the EPA learned during the Methane Detection Technology 
Workshop, industry has utilized these advanced measurement technologies 
to supplement existing fugitive emissions programs and to quickly 
identify unexpected emissions events (e.g., emissions from controlled 
storage vessels) in order to make repairs as quickly as possible.\246\ 
While most of these advanced measurement technologies are not sensitive 
enough to pin-point the exact same emission sources as the current 
fugitive emission detection programs, many can more quickly detect the 
largest emissions sources (e.g., malfunctions and undersized or non-
performing major equipment), and they can also find emissions that may 
be missed by fugitive emission surveys (e.g., component-level leaks on 
valves, connectors, and meters). Moreover, the EPA understands the 
stochastic nature, distribution, and frequency of these large emission 
events across sites and over time is uncertain, and that these events 
occur sporadically at an individual site in ways that may take longer 
to detect or might not be detected through a periodic fugitive 
emissions survey using traditional technologies. Integrating advanced 
emission detection technologies into this rule--whether deployed by 
owner-operators themselves or by third parties--could be a valuable way 
to reduce fugitive emissions more cost-effectively and rapidly detect 
and remedy ``super-emitting'' events that make an outsize contribution 
to overall emissions from this source category.
---------------------------------------------------------------------------

    \246\ See summary report of the EPA's Methane Detection Workshop 
located at Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    There are many other advantages to these advanced measurement 
technologies over technologies currently used for fugitive emissions 
detection (i.e., OGI and EPA Method 21 technologies). For instance, 
these advanced measurement technologies may be less susceptible to 
operator error or judgment than traditional methods of leak detection, 
thus making surveys more consistent and reliable. Many of these 
technologies can survey broader areas than can be effectively surveyed 
with field personnel, drastically reducing the driving time from site 
to site, which could have potential cost and safety benefits and allow 
for more frequent monitoring, which could allow for the identification 
and mitigation of large volume methane emissions sooner than OGI or EPA 
Method 21 surveys.
    As described in section XI.A.5, the EPA is proposing an alternative 
work practice for detecting fugitive emissions that incorporates these 
advanced measurement technologies. There were a number of presentations 
during the Methane Detection Technology Workshop that discussed the 
detection capabilities of various methane measurement technologies 
which could be used for a screening approach. Given the diverse array 
of advanced technologies that are now in use, and the rapid pace at 
which these technologies are being refined and new technologies are 
being developed, the EPA believes that it is appropriate to articulate 
a foundational set of performance criteria and documentation 
requirements for this alternative work practice that can be applied to 
multiple existing and forthcoming technologies. Based on the 
information available to the Agency, including the information 
presented in the Methane Detection Technology Workshop, the EPA 
believes setting a minimum detection threshold of 10 kg/hr methane 
might be appropriate for use in determining what technologies and in 
what deployment platforms (e.g., fixed, ground and aerial) are 
appropriate for a potential screening alternative within the proposed 
NSPS OOOOb and EG OOOOc. Therefore, the specific alternative work 
practice that the EPA is proposing includes a provision that would 
allow the use of any technology with a minimum detection threshold of 
10 kg/hr.
    Although we have focused this discussion on advanced measurement 
technologies, the EPA is also soliciting comment on whether there are 
ways to utilize existing technologies to screen for large emission 
events. For example, could gauges or meters be utilized to identify 
potential large losses between the wellhead and the custody meter 
assembly.
    Further, the EPA is seeking comment on very simple AVO checks that 
could be performed in conjunction with the periodic OGI monitoring 
surveys to help identify potential large emission events. For example, 
two often-cited causes of super-emitter sources are unlit flares and 
separator dump valves that are stuck open allowing unintentional gas 
carry-through to emit from storage vessels. The additional time and 
cost required to perform visual inspections to see if the flare pilot 
light is working, or to see if a dump valve is stuck open, would be 
minimal. Yet the benefits of simple AVO inspections could be 
significant. The EPA is soliciting comment on this concept, as well as 
comments on the common items that could be included on a checklist for 
such low-burden AVO inspections in conjunction with fugitive 
monitoring.

B. Proposed Standards for Storage Vessels

1. NSPS OOOOb
a. Background
    In the 2012 NSPS OOOO, the EPA established VOC standards for 
storage vessels. Based on our review of these standards, we are 
proposing to retain the current standard of 95 percent reduction. 
However, the EPA is proposing to redefine the affected facility to 
include a tank battery. Specifically, the EPA is proposing to define a 
storage vessel affected facility as a single storage vessel or a group 
of storage vessels that are physically adjacent and that receive fluids 
from the

[[Page 63198]]

same source (e.g., well, process unit, or set of wells or process 
units) or manifolded together for the transfer of liquid or vapors. In 
this definition, we consider tanks to be physically adjacent when they 
are near or next to each other and may or may not be connected or piped 
together. In addition, the EPA is proposing methane standards for new, 
reconstructed, and modified storage vessels under the proposed NSPS 
OOOOb. Both the proposed revised VOC standards and the proposed methane 
standards would be the same (i.e., 95 percent reduction of emissions 
from storage vessel affected facilities as defined above in this 
proposal). These reductions can be achieved by utilizing a cover and 
closed vent system to capture and route the emissions to a control 
device that achieves an emission reduction of 95 percent, or by routing 
the captured emissions to a process.
    Both methane and VOC emissions from storage vessels are a result of 
working, breathing and flashing losses. Working losses occur when 
vapors are displaced due to the emptying and filling of storage 
vessels. Breathing losses are the release of gas associated with daily 
temperature fluctuations when the liquid level remains unchanged. 
Flashing losses occur when a liquid with dissolved gases is transferred 
from a vessel with higher pressure (e.g., separator) to a vessel with 
lower pressure (e.g., storage vessel), thus allowing dissolved gases 
and a portion of the liquid to vaporize or flash. In the Crude Oil and 
Natural Gas source category, flashing losses occur when crude oils or 
condensates flow into a storage vessel from a separator operated at a 
higher pressure. Typically, the higher the operating pressure of the 
upstream separator, the greater the flash emissions from the storage 
vessel. Temperature of the liquid may also influence the amount of 
flash emissions. Lighter crude oils and condensate generally flash more 
hydrocarbons than heavier crude oils.
b. Definition of Affected Facility
    The current standards apply to single storage vessels with 
potential VOC emissions of 6 tpy or greater, although the EPA has long 
observed that these storage vessels are typically located as part of a 
tank battery. 76 FR 52738, 52763 (Aug. 23, 2011). Further, the 6 tpy 
applicability threshold was established by directly correlating VOC 
emissions to throughput, was based on the use of a single combustion 
control device, regardless of the number of storage vessels routing 
emissions to that control device, and control of 6 tpy VOC was cost 
effective using that single control device. Id. at 52763-64. Over the 
years, there have been questions and issues raised regarding how to 
calculate the potential VOC emissions from individual storage vessels 
that are part of a tank battery. The EPA attempted to address this 
issue through various amendments to NSPS OOOO and NSPS OOOOa,\247\ most 
recently in the 2020 Technical Rule. In the 2020 Technical Rule, the 
EPA continued to recognize that tank batteries are more prevalent than 
individual storage vessels. While the 2020 Technical Rule included 
amendments to the calculation methodology for determining potential VOC 
emissions from storage vessels that are part of a tank battery, the EPA 
has now determined that it is more appropriate to evaluate the control 
of methane and VOC emissions from tank batteries \248\ as a whole 
instead of each individual storage vessel within a tank battery.\249\ 
In this review the EPA evaluated regulatory options based on the use of 
a single control device to reduce both methane and VOC emissions from a 
tank battery, which is consistent with the 2012 NSPS OOOO, 2016 NSPS 
OOOOa, and subsequent amendments to each of those rules. The EPA 
believes that this approach will simplify applicability criteria for 
owners and operators of storage vessels, and more accurately aligns 
with the EPA's original intent of how storage vessel affected facility 
status should be determined.
---------------------------------------------------------------------------

    \247\ See 79 FR 79018 and 80 FR 48262.
    \248\ For purposes of this analysis and the resulting proposed 
standards, the term ``tank battery'' refers to a single storage 
vessel or a group of storage vessels that are physically adjacent 
and that receive fluids from the same source (e.g., well, process 
unit, or set of wells or process units) or which are manifolded 
together for liquid or vapor transfer.
    \249\ This approach would no longer allow facilities to apply 
certain criteria and average the total potential VOC emissions of 
the tank battery across the number of storage vessels in the battery 
to determine a per-vessel potential for VOC emissions.
---------------------------------------------------------------------------

c. Modification
    Section 60.14(a) of the general provisions to part 60 defines 
modification as follows: ``Except as provided in paragraphs (e) and (f) 
of this section, any physical or operational change to an existing 
facility which results in an increase in the emission rate to the 
atmosphere of any pollutant to which a standard applies shall be 
considered a modification. . . .'' We also note that 40 CFR 60.14(f) 
states that ``Applicable provisions set forth under an applicable 
subpart of this part shall supersede any conflicting provisions of this 
section.'' The EPA understands the difficulty assessing emissions from 
storage vessels and seeks to provide clarity on actions that are 
considered modification of a tank battery by explicitly listing these 
in the proposed NSPS OOOOb. We evaluated circumstances that would lead 
to an increase in the VOC and methane emissions from a tank battery and 
therefore constitute a modification of an existing tank battery. A 
modification of an existing tank battery would then require the tank 
battery owner or operator to assess the potential emissions relative to 
the proposed NSPS instead of the EG.
    The EPA is proposing that a single storage vessel or tank battery 
is modified when any of the following physical or operational changes 
are made: (1) The addition of a storage vessel to an existing tank 
battery; (2) replacement of a storage vessel such that the cumulative 
storage capacity of the existing tank battery increases; and/or (3) an 
existing single storage vessel or tank battery that receives additional 
crude oil, condensate, intermediate hydrocarbons, or produced water 
throughput (from actions such as refracturing a well or adding a new 
well that sends these liquids to the tank battery). For both items 1 
and 2, even if the type and quantity of fluid processed remains the 
same, the increased storage capacity will lead to higher breathing 
losses and thereby increase the VOC emissions from the tank battery 
relative to the VOC emissions prior to the vessel addition or 
replacement. Therefore, we conclude that these actions are a 
modification of the tank battery. However, we are soliciting comment to 
help us better understand the effect of the proposed definition number 
1 and 2 on the number of new storage vessels or tank batteries that 
would be subject to the NSPS. Under the current definition of a storage 
vessel affected facility in NSPS OOOOa, which is each single storage 
vessel that meets the 6 tpy applicability threshold, a new storage 
vessel that is installed in an existing tank battery is an affected 
facility (assuming the 6 tpy applicability threshold is met for the 
single storage vessel) whether the new storage vessel is a replacement 
or an addition to the tank battery. However, under the proposed 
definition number 1 and 2 above, the NSPS OOOOb is triggered only if 
the new storage vessel is an addition to the tank battery or is of 
bigger capacity than the storage vessel it is replacing in a tank 
battery. We therefore solicit comment on how often a storage vessel in 
a tank battery is replaced with one that is of bigger capacity, or 
whether the need to increase a tank battery's capacity is

[[Page 63199]]

generally accomplished by adding storage vessels as opposed to 
replacing an existing one with a bigger one. We further solicit comment 
on whether, under our proposed definition of a tank battery (i.e., a 
single storage vessel or a group of storage vessels that are physically 
adjacent and that receive fluids from the same source (e.g., well, 
process unit, or set of wells or process units)), the replacement of a 
storage vessel in a tank battery should also require the assessment of 
the potential VOC and methane emissions from the tank battery.
    Item 3 will increase the volumetric throughput of the tank battery 
relative to the throughput prior to storage of the additional fluid. 
This will increase the working losses and potentially increase the 
flashing losses from the tank battery, depending on the properties of 
the new fluid stream. In any event, adding a new fluid stream to an 
existing tank battery increases the VOC emissions from that tank 
battery relative to just prior to the addition of a new fluid stream 
and is therefore considered a modification of the tank battery.
    The EPA is proposing to require that the owner or operator 
recalculate the potential VOC emissions when any of these actions occur 
on an existing single storage vessel or tank battery to determine if 
the modification may require control of VOC emissions. The existing 
single storage vessel or tank battery will only become subject to the 
proposed NSPS if it is modified pursuant to this proposed definition of 
modification and its potential VOC emissions exceed the proposed 6 tpy 
VOC emissions threshold for the tank battery.
d. Technology Review
    The available control techniques for reducing methane and VOC 
emissions from storage vessels include routing the emissions from the 
storage vessels to a combustion control device or a VRU, which would 
route the emission to a process (including a gas sales line). These are 
the same control systems that were evaluated under the 2012 NSPS OOOO. 
While floating roofs can also be used to reduce emissions from many 
storage vessel applications, including at natural gas processing plants 
and compressor stations, floating roofs are not effective at reducing 
emissions from storage vessels that have flashing losses (e.g., storage 
vessels at well sites or centralized production facilities). Besides 
the control options described above, we did not find other available 
control options through our review, including review of the RACT/BACT/
LAER Clearinghouse.
    In the development of the 2012 NSPS OOOO, we found that using 
either a VRU or a combustion control device could achieve a 95 percent 
or higher VOC emission reduction efficiency. Available information 
since then continues to support that such devices can achieve a 95 
percent control efficiency for both methane and VOC emissions. We are 
not proposing to require higher control efficiency because, in order to 
achieve a minimum of 95 percent control efficiencies on a continuous 
basis, operators will need to design and operate the control to achieve 
greater than 95 percent. Thus, while the control device may commonly 
operate at greater than 95 percent control efficiencies, there may be 
process fluctuations in heat loads, inlet backpressure, and other 
variables that may affect performance that may lower the control 
efficiencies achieved. For example, there are field conditions, such as 
high winds that may influence combustion efficiencies.\250\ We also 
note that, while the EPA established operating and monitoring 
requirements to ensure flares achieve a 98 percent control efficiency 
at petroleum refineries in 40 CFR part 63, subpart CC, these 
requirements include sophisticated monitoring and operational controls 
and tend to lead to additional fuel use and greater secondary impacts 
than combustion systems targeting to achieve a minimum of 95 percent 
control efficiency. Considering these factors, we conclude that, 
consistent with CAA section 111(a) definition of a ``standard of 
performance,'' 95 percent control efficiency as the minimum allowable 
control efficiency at any time continues to reflect ``the degree of 
emission limitation achievable'' through the application of the BSER 
for tank batteries (a combustor or a VRU). We solicit comment on the 
issues described above for requiring higher than 95 percent 
reduction.\251\
---------------------------------------------------------------------------

    \250\ EPA. April 2012. Parameters for Properly Designed and 
Operated Flares. Prepared for U.S. Environmental Protection Agency, 
Office of Air Quality Planning and Standards, Research Triangle 
Park, NC.
    \251\ Further, in section XIII.E (solicitation of comment on 
control device efficiency), the EPA solicits comment on the level of 
reduction that can be reliably achieved using a flare and what 
measures need to be in place to assure such reduction.
---------------------------------------------------------------------------

    During pre-proposal outreach, some small businesses raised a 
concern that the NSPS OOOOa requirement for a continuous pilot light 
for a storage vessel control device generated more emissions than it 
prevented for storage vessels with low emissions. Specifically, small 
business representatives raised concerns that there are situations 
where propane or other fossil fuel must be used to maintain continuous 
pilot lights for flares used as control devices on storage vessels that 
do not produce enough emissions. The EPA is interested in whether the 
benefits of reducing emissions with these control devices are negated 
by the need to burn additional fossil fuels and whether there are 
additional factors that lead to variability in emissions from storage 
vessels that could be used to more narrowly target these requirements 
to limit the unnecessary operation of flares. We are soliciting comment 
from all stakeholders on this issue.
e. Control Options and BSER Analysis
    For this proposal, the EPA evaluated regulatory options based on 
different potential emissions thresholds for VOC and methane. We 
assumed the potential tank battery emissions were reduced by 95 percent 
using either a VRU or a combustion control device. Since VRUs recover 
saleable products, we also estimated the value of the recovered product 
when VRUs were used. The EPA encourages the use of VRUs to capture and 
sell the emissions from the storage vessels by classifying VRUs as part 
of the process, therefore emission recovered would not be included in 
the potential emissions at a site.
    For new, modified, or reconstructed sources, we evaluated the cost 
of control using a single combustion device (or VRU) on a single 
storage vessel as well as a tank battery made up of multiple storage 
vessels. To do this, we evaluated the use of a single control device 
achieving 95 percent reduction of VOC and methane emissions at the 
following potential emission thresholds: 6 tpy VOC from a single 
storage vessel; 3 and 6 tpy VOC from a tank battery; and 1.3 tpy, 5.3 
tpy, 20 tpy, and 50 tpy methane from a tank battery. Based on our cost 
analysis we propose to retain the 6 tpy applicability threshold.
    The estimated all-in capital costs for a single combustion control 
device are approximately $80,000. The estimated annualized costs 
include the capital recovery cost (calculated at a 7 percent interest 
rate for 15 years) and labor costs for operations and maintenance and 
are estimated at approximately $31,500/yr. The estimated capital costs 
for a VRU sized for a source with potential VOC emissions of 6 tpy are 
approximately $32,000 and the estimated annualized costs are estimated 
at approximately $24,000/yr not considering any potential recovery 
credits from sales. More information on this cost analysis

[[Page 63200]]

is available in the NSPS OOOOb and EG TSD for this proposal.
    Based on our analysis, the cost effectiveness of controlling VOC 
and methane emissions from a tank battery with the potential for VOC 
emissions of 6 tpy, under the single pollutant approach where all the 
costs are assigned to the reduction of VOC, is $5,540 per ton of VOC 
eliminated assuming the use a single combustion control device. As 
explained above, storage vessels are commonly located adjacent to one 
another as part of tank battery, which allows the vapors from the 
storage vessels within the tank battery to be collected and routed to a 
single control device, when one is used. The single pollutant cost 
effectiveness for a VRU to control a tank battery with potential VOC 
emissions of 6 tpy is approximately $4,000 per ton of VOC eliminated. 
As shown in section IX, costs ranging from $4,000 to $5,540 per ton of 
VOC reduced are within the range that the EPA considers to be cost 
effective for reducing VOC emissions. Because it is cost effective to 
reduce the VOC emissions from a tank battery with potential VOC 
emissions of 6 tpy or greater, one of the two targeted pollutants in 
this action, it is cost effective to reduce both VOC and methane 
emissions from a single storage vessel or a tank battery at that level. 
Based on our estimate, a tank battery with potential 6 tpy VOC 
emissions has potential 1.3 tpy of methane emissions. Because storage 
vessels contain crude oil, condensate, intermediate hydrocarbons, or 
produced water, which are approximately 80 percent VOC, the methane 
emissions from storage vessels are generally less than the VOC 
emissions.
    We also evaluated the cost effectiveness at a lower VOC threshold 
of 3 tpy. As shown in the NSPS OOOOb and EG TSD, the single pollutant 
cost effectiveness for controlling a tank battery with potential 
emissions of 3 tpy ranges from $7,500 to $11,000. As shown in section 
IX, costs ranging from $7,500 to $11,000 per ton of VOC reduced is not 
within the range that the EPA considers to be cost effective for 
reducing VOC emissions. Using the multipollutant approach, the VOC cost 
effectiveness is between $3,800 and $5,500, which is considered 
reasonable, but the methane cost effectiveness is between $17,000 and 
$25,000 for any of the methane thresholds assessed in conjunction with 
3 tpy VOC limit, which is considered unreasonable. Therefore, the 3 tpy 
VOC control option was not considered reasonable at this time using 
either the single pollutant or multipollutant approach.
    Our analysis also shows that, under the single pollutant approach 
where all the costs are assigned to the reduction of methane and zero 
to VOC, it is cost effective to control a single storage vessel or a 
tank battery with potential methane emissions of 20 tpy (at costs 
ranging from $1,250 to $1,660 per ton methane). Based on our estimate, 
a tank battery with potential methane emissions of 20 tpy would have 
the potential VOC emissions of 91 tpy, 95 percent of which would be 
reduced at zero cost. Under the multipollutant cost-effectiveness 
approach, where half of the cost is allocated to methane reduction and 
the other half to VOC reduction, it is cost effective to control a tank 
battery with potential methane emissions of 10 tpy and corresponding 
potential VOC emissions of 46 tpy, at an average cost of $1,500 per ton 
methane reduced and $330 per ton VOC reduced. In light of the above, 6 
tpy of VOC is the lowest threshold that is cost effective to control 
both VOC and methane emissions. Therefore, the EPA is proposing to 
define the affected facility for purposes of regulating both VOC and 
methane emissions as a tank battery with potential VOC emissions of 6 
tpy or greater.
2. EG OOOOc
    The EPA is proposing presumptive standards for reducing methane 
emissions from existing storage vessels. For purposes of the EG, we are 
proposing to define a designated facility as a single storage vessel or 
tank battery with the potential for methane emissions of 20 tpy or 
greater. For purposes of the EG, we are proposing the same definition 
of a storage vessel affected facility, which is a single storage vessel 
or a group of storage vessels that are physically adjacent and that 
receive fluids from the same source (e.g., well, process unit, or set 
of wells or process units).
    The available controls for reducing methane emissions from existing 
tank batteries are the same as those for reducing methane and VOC 
emissions from new, modified and reconstructed tank batteries. In 
assessing the control costs for existing sources, we applied a 30 
percent retrofit factor to the capital and installation costs to 
account for added costs of manifolding existing storage vessels and 
installing the control system on an existing tank battery. When 
applying controls to new sources, there is limited additional costs in 
designing the fixed roof with fittings to manifold the vapors and 
installing the closed vent piping or ducts during the tank installation 
process. For existing sources, installing fittings on an existing tank 
may require special lifts to access the roof and cut new ports in the 
roof. This may also require the tank to be taken out of service to 
conduct these installations, which requires additional time and labor. 
Additionally, when installing controls as part of the design for a new 
source, the facility layout can be designed to accommodate the control 
systems near the tank battery and the control device can be installed 
with the same crew installing the storage vessels, minimizing 
additional installation costs. For existing sources, there may be other 
equipment near the tanks that may require the control equipment to be 
further from the tank battery, which increases materials and 
installation costs. Also, control equipment costs will include the full 
costs of crew mobilization. Therefore, it is more expensive to install 
controls at an existing tank battery than to install controls as part 
of a new tank battery. We considered the same regulatory options based 
on potential methane emissions thresholds of 1.3 tpy, 5.3 tpy, 20 tpy, 
and 50 tpy per tank battery.
    The estimated capital costs for a single combustion control device 
for emissions in this range are approximately $103,000. The estimated 
annual costs include the capital recovery cost (calculated at a 7 
percent interest rate for 15 years) and labor costs for operations and 
maintenance and are estimated at approximately $34,000. The costs for 
VRU are more variable than combustion control systems and dependent on 
the potential emissions for which the VRU is designed to recover. The 
estimated capital costs for a VRU sized for a source with potential 
methane emissions of 20 tpy device are approximately $106,000 and the 
estimated annualized costs are approximately $49,000/yr not considering 
any potential recovery credits. With a VRU, the recovered VOC and 
methane are recovered as salable products. Considering the value of 
recovered product, the annualized cost for VRU sized to recover 
potential methane emissions of 20 tpy is estimated to be $26,000/yr. 
More information on this cost analysis is available in the NSPS OOOOb 
and EG TSD for this proposal.
    The resulting cost effectiveness, for the application of a single 
combustion control device or VRU to achieve a 95 percent emission 
reduction ranges from $19,000 to $27,400 per ton of methane eliminated 
at a threshold of 1.3 tpy methane. This cost is not considered 
reasonable. Next, we evaluated the cost effectiveness at a methane 
threshold of 5.3 tpy, which ranged from $10,000 to $13,700 per ton of 
methane reduced,

[[Page 63201]]

which is also not considered reasonable. At a threshold of 20 tpy 
methane, the cost effectiveness ranges from $1,400 to $1,800 per ton 
methane reduced. At a threshold of 50 tpy methane, the cost 
effectiveness ranges from $340 to $720 per ton methane reduced. When we 
considered the application of these options at a national level, the 
overall cost effectiveness of the 20 tpy potential methane emissions 
threshold was $400 per ton methane reduced without considering product 
recovery credits and has a net cost savings considering product 
recovery credits. Additionally, the incremental cost effectiveness of 
the 20 tpy option relative to the 50 tpy potential methane emissions 
threshold was approximately $900 per ton additional methane reduced 
when considering product recovery credits.
    Based on the cost analysis summarized above, we find that the cost 
effectiveness for achieving 95 percent emission reduction of methane 
from a tank battery with potential methane emissions of 20 tpy is 
reasonable for methane. A cost-effective value of $1,800/ton of methane 
reduction is comparable to the estimated methane cost-effectiveness 
values for the controls identified as BSER for the 2016 NSPS OOOOa and 
which we consider to be representative of reasonable control cost for 
reducing methane emissions from the Crude Oil and Natural Gas source 
category, as explained in section IX.B. We further note that both 
California and Colorado require 95 percent reduction of methane 
(California) and hydrocarbon (Colorado) emissions from storage vessels. 
For California, existing separator and tank systems with an annual 
emission rate greater than 10 tpy methane must control emissions using 
a vapor collection system that reduces emissions by at least 95 
percent.\252\ For Colorado, storage vessels that emit greater than or 
equal to 2 tpy of actual uncontrolled VOC emissions must reduce VOC 
emissions by 95 percent.\253\ These requirements, which are comparable 
to the proposed presumptive standards, are further indication that the 
cost of implementing the proposal is reasonable and not excessive.
---------------------------------------------------------------------------

    \252\ See sections 95668 and 95671 of California Code of 
Regulations, Title 17, Division 3, Chapter 1, Subchapter 10 Climate 
Change, Article 4.
    \253\ See section I.D.3.a of Colorado Department of Public 
Health and Environment, ``Control of Ozone via Ozone Precursors and 
Control of Hydrocarbons via Oil and Gas Emissions (Emissions of 
Volatile Organic Compounds and Nitrogen Oxides), Regulation Number 
7'' (5 CCR 1001-9), July 2021.
---------------------------------------------------------------------------

3. Legally and Practicably Enforceable Limits
    In addition to the BSER analysis described above, the EPA is 
clarifying the term ``legally and practicably enforceable limits'' as 
it related to storage vessel affected facilities in the proposed NSPS 
OOOOb and EG OOOOc. In the 2016 NSPS OOOOa, the EPA stated that ``any 
owner or operator claiming technical infeasibility, nonapplicability, 
or exemption from the regulation has the burden to demonstrate the 
claim is reasonable based on the relevant information. In any 
subsequent review of a technical infeasibility or nonapplicability 
determination, or a claimed exemption, the EPA will independently 
assess the basis for the claim to ensure flaring is limited and 
emissions are minimized, in compliance with the rule.'' See 81 FR 
35824, 35844 (June 3, 2016).
    In the context of storage vessels under both the 2012 NSPS OOOO and 
2016 NSPS OOOOa, the EPA has learned that numerous owners and operators 
claim that their storage vessels are not affected facilities under 40 
CFR 60.5365(e) and 40 CFR 60.5365a(e). This claim is made based on a 
determination that the potential for VOC emissions is less than 6 tpy 
when taking into account requirements under a legally and practicably 
enforceable limit in an operating permit or other requirement 
established under a Federal, State, local or Tribal authority.\254\ 
However, when the EPA has reviewed the limits considered by these 
facilities as legally and practicably enforceable, we have become aware 
that the limits do not require a reduction in emissions; they are often 
self-imposed or of such a general nature as to be unenforceable or 
otherwise lack measures to assure the required emission reduction. For 
example, a permit contains an emission limit of 2 tpy for a single 
storage vessel, but does not contain any performance testing 
requirements, continuous or other monitoring requirements, 
recordkeeping and reporting, or other requirements that would ensure 
that emissions are maintained below the emissions limit in the permit. 
In National Mining Ass'n v. EPA, 59 F.3d 1351 (D.C. Cir. 1995), the 
court explained what constitutes ``effective'' control in assessing a 
source's potential to emit. According to the court, while ``effective'' 
controls need not be Federally enforceable, ``EPA is clearly not 
obliged to take into account controls that are only chimeras and do not 
really restrain an operator from emitting pollution.'' Id. at 1362. The 
court also emphasized that these non-Federally enforceable controls 
must stem from state or local government regulations, and not 
``operational restrictions that an owner might voluntarily adopt.'' Id. 
at 1362. Further, as a general ``default rule,'' the burden of proof 
falls ``upon the party seeking relief.'' Schaffer ex rel. Schaffer v. 
Weast, 546 U.S. 49, 57-58, 126 S.Ct. 528, 163 L.Ed.2d 387 (2005).
---------------------------------------------------------------------------

    \254\ 40 CFR 60.5365(e) and 40 CFR 60.5365a(e)(1) and (2) allow 
owners and operators to take into account these requirements when 
calculating the potential VOC emissions.
---------------------------------------------------------------------------

    In light of the above, the EPA is proposing to include a definition 
for a ``legally and practicably enforceable limit'' as it relates to 
limits used by owners and operators to determine the potential for VOC 
emissions from storage vessels that would otherwise be affected 
facilities under these rules. The intent of this proposed definition is 
to provide clarity to owners and operators claiming the storage vessel 
is not an affected facility in the Oil and Gas NSPS due to legally and 
practicably enforceable limits that limit their potential VOC emissions 
below 6 tpy. This definition is being proposed for NSPS OOOOb and the 
proposed presumptive standard included in EG OOOOc. This proposed 
definition of ``legally and practicably enforceable limit'' is 
consistent with the EPA's historic position on what is considered 
``legally and practicably enforceable,'' as tailored to storage vessels 
in the oil and gas sector that would otherwise be affected facilities 
under these rules. The proposed definition is as follows:
    ``For purposes of determining whether a single storage vessel or 
tank battery is an affected facility, a legally and practicably 
enforceable limit must include all of the following elements:
    i. A quantitative production limit and quantitative operational 
limit(s) for the equipment, or quantitative operational limits for the 
equipment;
    ii. an averaging time period for the production limit in (i) (if a 
production-based limit is used) that is equal to or less than 30 days;
    iii. established parametric limits for the production and/or 
operational limit(s) in (i), and where a control device is used to 
achieve an operational limit, an initial compliance demonstration 
(i.e., performance test) for the control device that establishes the 
parametric limits;
    iv. ongoing monitoring of the parametric limits in (iii) that 
demonstrates continuous compliance with the production and/or 
operational limit(s) in (i);
    v. recordkeeping by the owner or operator that demonstrates 
continuous

[[Page 63202]]

compliance with the limit(s) in (i-iv); and
    vi. periodic reporting that demonstrates continuous compliance.''
    In this proposed definition, the EPA is not addressing the various 
ways in which a State or other authority's permit may be issued since 
the format of permit issuances varies by jurisdiction. The proposed 
definition of ``legally and practicably enforceable'' does not specify 
limits, monitoring requirements, or recordkeeping. Instead, the owner 
or operator should work with the permitting authority to establish 
specific limits, monitoring requirements and recordkeeping that will 
ensure any permitted emission limit is achieved. Only those limits that 
include the elements described above will be considered ``legally and 
practicably enforceable'' for purposes of determining the potential for 
VOC emissions from a single storage vessel or tank battery, and thus 
applicability (or non-applicability) of each single storage vessel or 
tank battery as an affected facility under the rule.
    This proposed definition will provide clarity to owners and 
operators in what limits are necessary to ensure they have 
appropriately determined their single storage vessels or tank batteries 
are affected facilities under the proposed NSPS OOOOb or designated 
facilities under the proposed EG OOOOc. Further, as stated in the 2016 
NSPS OOOOa, well-designed rules ensure fairness among industry 
competitors and are essential to the success of future enforcement 
efforts. 81 FR 35844 (June 3, 2016). The EPA is soliciting comment on 
this proposed definition from all stakeholders.

C. Proposed Standards for Pneumatic Controllers

1. NSPS OOOOb
a. Background
    In the 2012 NSPS OOOO, the EPA established VOC standards for 
natural gas-driven pneumatic controllers. Specifically, subpart OOOO 
established a natural gas bleed rate limit of 6 scfh for individual, 
continuous bleed, natural gas-driven controllers located in the 
production segment. Continuous bleed, natural gas-driven controllers 
with a bleed rate of 6 scfh or less are commonly called ``low bleed'' 
controllers. However, that rule also allowed for the use of ``high 
bleed'' controllers (those with a bleed rate over 6 scfh) where 
required by functional needs such as response time, safety, and 
positive actuation. At natural gas processing plants, subpart OOOO 
implemented a VOC standard that required a bleed rate of zero (``zero 
bleed'' or ``no bleed''). The rule also included allowances for the use 
of continuous bleed natural gas-driven controllers at natural gas 
processing plants where required by functional needs.
    In the 2016 NSPS OOOOa, the EPA extended the 6 scfh natural gas 
bleed rate standard to the natural gas transmission and storage segment 
and established GHG standards for all segments. Effectively, the 2016 
NSPS OOOOa required low bleed controllers to reduce methane and VOC 
emissions from the production and transmission and storage segments and 
required a bleed rate of zero for pneumatic controllers at natural gas 
processing plants. Like the 2012 NSPS OOOO, the 2016 NSPS OOOOa 
included allowances for the use of continuous high bleed controllers in 
the production and transmission and storage segments and continuous 
natural gas-driven pneumatic controllers at natural gas processing 
plants where required by functional needs.
    Emissions from natural gas-driven intermittent vent pneumatic 
controllers were not addressed in either the 2012 NSPS OOOO or the 2016 
NSPS OOOOa. This was because, when operated and maintained properly, 
methane and VOC emissions from intermittent controllers are 
substantially lower (by an order of magnitude) than emissions from 
other types of natural gas-driven controllers. However, the EPA is now 
aware that these intermittent controllers often malfunction and vent 
during idle periods. Emissions factors considering this fact are around 
four times higher than the factors for low-bleed controllers. Further, 
as presented in subsection c of this section, methane emissions from 
intermittent controllers make up a significant portion of the overall 
methane emissions from all natural gas and petroleum system sources in 
the GHGI. As such, the EPA is now proposing to reduce emissions from 
intermittent controllers via NSPS OOOOb.
b. Affected Facility Definitions and Zero Emissions Standard
    As a result of the review of these requirements in the 2016 NSPS 
OOOOa, the previous BSER determinations, and the consideration of new 
information, including State regulations that have been enacted since 
2016, the EPA is proposing GHG (methane) and VOC standards for natural 
gas-driven pneumatic controllers in all segments of the industry 
included in the Crude Oil and Natural Gas source category (i.e., 
production, processing, transmission and storage).
    First, in terms of the definition of an affected facility, the EPA 
is proposing to revise the types of pneumatic controllers that are 
affected facilities to include both continuous bleed controllers and 
intermittent vent controllers. For continuous bleed controllers, an 
affected facility is each single continuous bleed natural gas-driven 
pneumatic controller that vents to the atmosphere. For intermittent 
vent controllers, an affected facility is each single natural gas-
driven pneumatic controller that is not designed to have a continuous 
bleed rate but is designed to only release natural gas to the 
atmosphere as part of the actuation cycle. These affected facility 
definitions apply for pneumatic controllers in both the production and 
transmission and storage segments, as well as for those at natural gas 
processing plants.
    Next, in terms of standards, we are proposing a requirement that 
all controllers (continuous bleed and intermittent vent) in the 
production and natural gas transmission and storage segments must have 
a methane and VOC emission rate of zero. Controllers that emit zero 
methane and VOC to the atmosphere can include, but are not limited to, 
air-driven pneumatic controllers (also referred to as instrument air-
driven or compressed air-driven controllers), mechanical controllers, 
electronic controllers, and self-contained natural gas-driven pneumatic 
controllers. While these ``zero-emissions controllers'' would not 
technically be affected facilities because they are not driven by 
natural gas (air-driven, mechanical, and electronic) or because they do 
not vent to the atmosphere, owners and operators should maintain 
documentation if they would like to be able to demonstrate to permit 
writers or enforcement officials that there are no methane or VOC 
emissions from the controllers and that these controllers are not 
affected facilities and are not subject to the rule. The proposed 
standard would apply to both continuous bleed and intermittent vent 
controllers at these sites.
    For all natural gas processing plants, we are proposing to 
essentially retain the 2016 NSPS OOOOa standard that requires that 
controllers must have a methane and VOC emission rate of zero (i.e., 
zero-emissions controllers must be used). However, we are proposing to 
slightly change the wording of the standard from subparts OOOO and 
OOOOa, which require a ``bleed rate of zero.'' Many natural gas 
processing plants use pneumatic controllers that are powered by 
compressed air, which

[[Page 63203]]

can technically have a compressed air bleed rate greater than zero. Put 
another way, some controllers that are powered with compressed air can 
allow some of that compressed air to leave the controller and thus be 
released into the atmosphere (they can ``bleed'' compressed air). 
However, since the compressed air does not contain any natural gas, 
methane, or VOC, we are clarifying the standard by proposing to require 
that pneumatic controllers at natural gas processing plants have a 
methane and VOC emission rate of zero.
    In both NSPS OOOO and OOOOa, there is an exemption from the 
standards in cases where the use of a pneumatic controller affected 
facility with a bleed rate greater than the applicable standard is 
required based on functional needs, including but not limited to 
response time, safety, and positive actuation. The EPA is not 
maintaining this exemption in the proposed NSPS OOOOb, except for in 
very limited circumstances explained below. As discussed below, the 
reasons to allow for an exemption based on functional need in NSPS OOOO 
and OOOOa were based on the inability of a low-bleed controller to meet 
the functional requirements of an owner/operator such that a high-bleed 
controller would be required in certain instances. Since we are now 
proposing that pneumatic controllers have a methane and VOC emission 
rate of zero, we do not believe that the reasons related to the use of 
low bleed controllers are still applicable.
    The proposed rule also does include an exemption from the zero-
emission requirement for pneumatic controllers in Alaska at locations 
where electricity power is not available. In these situations, the 
proposed standards would require the use of a low-bleed controller 
instead of high-bleed controller. The proposed rule also includes the 
exemption for pneumatic controllers in Alaska at sites without power 
that would allow the use of high-bleed controllers instead of low-bleed 
based on functional needs. In addition, inspections of intermittent 
vent controllers to ensure they are not venting during idle periods 
described above would also be required at sites in Alaska without 
power.
c. Description
    Pneumatic controllers are devices used to regulate a variety of 
physical parameters, or process variables, using air or gas pressure to 
control the operation of mechanical devices, such as valves. The 
valves, in turn, control process conditions such as levels, 
temperatures and pressures. When a pneumatic controller identifies the 
need to alter a process condition, it will open or close a control 
valve. In many situations across all segments of the Oil and Natural 
Gas Industry, pneumatic controllers make use of the available high-
pressure natural gas to operate or control the valve. In these 
``natural gas-driven'' pneumatic controllers, natural gas may be 
released with every valve movement (intermittent) and/or continuously 
from the valve control. Pneumatic controllers can be categorized based 
on the emissions pattern of the controller. Some controllers are 
designed to have the supply-gas provide the required pressure to power 
the end-device, and the excess amount of gas is emitted. The emissions 
of this excess gas are referred to as ``bleed,'' and this bleed occurs 
continuously. Controllers that operate in this manner are referred to 
as ``continuous bleed'' pneumatic controllers. These controllers can be 
further categorized based on the rate of bleed they are designed to 
have. Those that have a bleed rate of less than or equal to 6 scfh are 
referred to as ``low bleed,'' and those with a bleed rate of greater 
than 6 scfh are referred to as ``high bleed.'' Another type of 
controller is designed to release gas only when the process parameter 
needs to be adjusted by opening or closing the valve, and there is no 
vent or bleed of gas to the atmosphere when the valve is stationary. 
These types of controllers are referred to as ``intermittent vent'' 
pneumatic controllers. A third type of natural gas-driven controller 
releases gas to a downstream pipeline instead of the atmosphere. These 
``self-contained'' types of controllers can be used in applications 
with very low pressure.
    As discussed above, emissions from natural gas-powered pneumatic 
controllers occur as a function of their design. Self-contained 
controllers do not emit natural gas to the atmosphere. Continuous bleed 
controllers using natural gas as the power source emit a portion of 
that gas at a constant rate. Intermittent vent controllers using 
natural gas as the power source are designed to emit natural gas only 
when the controller sends a signal to open or close the valve, which is 
called actuation. From continuous bleed and intermittent vent 
controllers, another source of emissions is from improper operation or 
equipment malfunctions. In some instances, a low bleed controller may 
emit natural gas at a higher level than it is designed to do (i.e., 
over 6 scfh) or an intermittent vent controller could emit continuously 
or near continuously rather than only during actuation.
    Not all pneumatic controllers are driven by natural gas. At sites 
with power, electrically powered pneumatic devices or pneumatic 
controllers using compressed air can be used. As these devices are not 
driven by pressurized natural gas, they do not emit any natural gas to 
the atmosphere, and consequently, they do not emit VOC or methane to 
the atmosphere. In addition, some controllers operate mechanically 
without a power source or operate electronically rather than 
pneumatically. At sites without electricity provided through the grid 
or on-site electricity generation, mechanical controllers and 
electronic controllers using solar power can be used.
    The emissions from natural gas-powered pneumatic controllers 
represent a significant portion of the total emissions from the Oil and 
Natural Gas Industry. In the 2021 GHGI, the estimated methane emissions 
for 2019 from pneumatic controllers were 700,000 metric tons of methane 
for petroleum systems and 1.4 million metric tons for natural gas 
systems. These levels represent 45 percent of the total methane 
emissions estimated from all petroleum systems (i.e., exploration 
through refining) sources and 22 percent of all methane emissions from 
natural gas systems (i.e., exploration through distribution). The vast 
majority of these emissions are from natural gas-driven intermittent 
vent controllers, which the EPA is proposing to define as an affected 
facility for the first time in NSPS OOOOb. Of the combined methane 
emissions from pneumatic controllers in the petroleum systems and 
natural gas systems production segments, emissions from intermittent 
vent controllers make up 88 percent of the total. Continuous high bleed 
and low bleed controllers make up 8 and 4 percent, respectively.
d. Control Options
    In identifying control options for this NSPS OOOOb proposal, we re-
examined the options previously evaluated in the rulemakings to 
promulgate the 2012 NSPS OOOO and the 2016 NSPS OOOOa, and also 
examined State rules with requirements for pneumatic controllers that 
achieve emission reductions beyond those achieved by NSPS OOOOa. For 
NSPS subparts OOOO and OOOOa, we identified options for reducing 
emissions from continuous bleed natural gas-driven pneumatic 
controllers. These options included using low bleed controllers in 
place of

[[Page 63204]]

high bleed controllers, enhanced maintenance (i.e., periodic inspection 
and repair), and using zero-emissions controllers. For the production 
and transmission and storage segments, only the option to require low 
bleed controllers was fully analyzed in these previous analyses. Based 
on the EPA's determination at that time that electricity was ``likely 
unavailable'' at production and transmission and storage sites, the EPA 
did not fully consider instrument air or electronic controllers. The 
EPA also did not evaluate enhanced maintenance, as it was concluded 
that the highly variable nature of determining the proper methods of 
maintaining a controller could incur significant costs. The EPA did not 
evaluate options to reduce emissions from intermittent vent controllers 
in either the 2012 or 2016 NSPS.
    Three U.S. States (California, Colorado, and New Mexico) and two 
Canadian provinces (Alberta and British Columbia) have rules or 
proposed rules that achieve emission reductions beyond those achieved 
by NSPS OOOOa. Starting on January 1, 2019, and subject to certain 
exceptions, a California rule requires that all new and existing 
continuous bleed devices must not vent natural gas to the atmosphere. 
The rule allows low bleed devices installed prior to January 1, 2016, 
to continue to operate, provided that annual testing is performed to 
verify that the low bleed rate is maintained. A Colorado rule adopted 
in February 2021, requires that all new controllers are no-bleed 
controllers (which includes self-contained natural gas-driven 
controllers), and over a period of two years, a sizeable portion of 
existing controllers must be retrofit to have a natural gas bleed rate 
of zero. New Mexico has proposed a rule that would require an emission 
rate of zero from all controllers located at sites with access to 
electrical power. The Canadian provinces of Alberta (effective 2022) 
and British Columbia (effective 2021) also regulate emissions from 
pneumatic controllers. In British Columbia, pneumatic devices that emit 
natural gas must not be used at new sources and at existing gas 
processing plants and large compressor stations, and in Alberta, owners 
and operators must prevent or control (by 95 percent) vent gas from new 
pneumatic controllers. While the terminology differs across these 
regulations, the EPA believes that all these requirements (with the 
exception of the 95 percent reduction requirement in Alberta) are very 
similar to if not the same as the zero methane and VOC emission 
requirement being proposed by the EPA for NSPS OOOOb.
    From EPA's review of our past BSER analysis as well as reviewing 
these other rules, several options were identified for the BSER 
analysis for NSPS OOOOb to reduce methane and/or VOC emissions from 
natural gas-driven pneumatic controllers. These include the following: 
(1) Use of low bleed natural gas-driven pneumatic controllers in the 
place of high bleed natural gas-driven pneumatic controllers; (2) 
require zero emissions from intermittent vent controllers except during 
actuation, and (3) prohibit the emissions of methane and VOC from all 
pneumatic controllers (i.e., establish a zero methane and VOC emission 
standard for both continuous bleed and intermittent bleed controllers).
e. 2021 BSER Analysis
Production and Transmission and Storage Segments
    For production and transmission and storage sites, the EPA 
evaluated two options. The first was an option to require the use of 
low bleed natural gas-driven pneumatic controllers in the place of high 
bleed natural gas-driven pneumatic controllers, along with a 
requirement that natural gas-driven intermittent vent pneumatic 
controllers only discharge natural gas during actuation. We also 
evaluated an option of establishing a zero methane and VOC emissions 
standard, which we propose to determine represents the BSER for 
production and natural gas transmission and storage sites.
    The first option evaluated was the use of low bleed natural gas-
driven pneumatic controllers in the place of high bleed natural gas-
driven pneumatic controllers. In the analysis of this option, we 
examined the emissions reduction potential, the cost of implementation, 
and the cost effectiveness in terms of cost per ton of emissions 
eliminated.
    The emission reduction potential of using a low bleed controller in 
place of a high bleed controller depends on the actual bleed rate of 
each device, which varies from device to device. Using average emission 
factors for each device type, the difference in emissions can be 
estimated on a per-controller basis. We estimated this difference 
between a low bleed and a high bleed device to be an 84 percent 
reduction for controllers in the production segment and a 92 percent 
reduction in emissions in the transmission and storage segment, 
equating to a difference of 2.1 tpy methane and 0.6 tpy VOC per 
controller in the production segment and 2.9 tpy methane and 0.08 tpy 
VOC per controller in the transmission and storage segment. The cost of 
a new low bleed natural gas-driven pneumatic controller is 
approximately $255 higher than the cost of a new high bleed device. On 
an annualized basis, assuming a 15-year equipment lifetime and a 7 
percent interest rate, the cost is $28 per year per low bleed 
controller. Under the single pollutant approach where all the costs are 
assigned to the reduction of one pollutant, the estimated cost 
effectiveness is $13 per ton of methane avoided and $48 per ton of VOC 
avoided per controller in the production segment. Using the 
multipollutant approach where half the cost of control is assigned to 
the methane reduction and half to the VOC reduction, the estimated cost 
effectiveness is $7 per ton of methane avoided and $24 per ton of VOC 
avoided. When considering the cost of saving the natural gas that would 
otherwise be emitted for the production segment, the cost effectiveness 
shows an overall savings under both the single pollutant and 
multipollutant approaches. For the natural gas transmission and storage 
segment, the cost effectiveness is $10 per ton methane avoided and $355 
per ton VOC avoided per controller using the single pollutant method, 
and $5 per ton of methane and $178 per ton of VOC avoided per 
controller using the multipollutant method. Transmission and storage 
facilities do not own the natural gas; therefore, revenues from 
reducing the amount of natural gas emitted/lost was not applied for 
this segment. These values are well within the range of what the EPA 
considers to be reasonable for methane and VOC using both the single 
pollutant and multipollutant approaches.
    We also evaluated a requirement that natural gas-driven 
intermittent vent pneumatic controllers only discharge natural gas 
during actuations. This emissions reduction option would be required in 
conjunction with a requirement to use low bleed controllers in place of 
high bleed controllers. The average emission factor determined by an 
industry study for natural gas-driven intermittent vent controllers, 
including both properly and improperly operating controllers, is 9.2 
scfh natural gas.\255\ Comparing this to the emission factor for a 
properly operating intermittent vent controller of 0.3 scfh natural gas 
illustrates the significant potential for reductions from a program 
that

[[Page 63205]]

identifies intermittent vent controllers that are improperly operating 
and repairing, replacing, or altering their operating conditions so 
they may function properly. To ensure these devices are emitting 
natural gas only during actuations in accordance with their design, 
there would be no equipment expenditure or associated capital costs; 
however, emissions monitoring or inspections, combined with repair as 
needed, would be necessary to ensure this proper operation is achieved. 
We considered requiring independent inspections specifically for 
intermittent vent controllers but concluded that it would be more 
efficient to couple inspections of these controllers with the 
inspections of equipment for leaks under the fugitive monitoring 
program (see section XII.A of this preamble).
---------------------------------------------------------------------------

    \255\ API Field Measurement Study: ``Pneumatic Controllers EPA 
Stakeholder Workshop on Oil and Gas.'' November 7, 2019--Pittsburgh 
PA. Paul Tupper.
---------------------------------------------------------------------------

    The second option we evaluated was a zero methane and VOC emissions 
standard. While applicability of both the 2012 NSPS OOOO and the 2016 
NSPS OOOOa are based on an individual pneumatic controller (as is the 
proposed definition of affected facility under NSPS OOOOb), zero-
emissions controller options are more appropriately evaluated as 
``site-wide'' controls. While individual natural gas-driven pneumatic 
controllers can be switched to other types of natural-gas driven 
pneumatic controllers (e.g., high bleed to low bleed types or low bleed 
to self-contained), the implementation of some zero-emissions 
controllers options would require equipment that would presumably be 
used for all the controllers at the site. For example, in order to 
utilize instrument air driven controllers, a compressor and related 
equipment would need to be installed. For the vast majority of 
situations, the EPA does not believe that an owner and operator would 
install a compressor just for a single controller, but rather would 
instead install a site-wide system to provide compressed air to all the 
controllers at the site. Therefore, to adequately account for the costs 
of the system, including the controllers and the common equipment, we 
evaluated these zero-emissions controller options using ``model'' 
plants.
    These model plants include assumptions regarding the number of each 
type of pneumatic controller at a site. Emissions were estimated for 
each of the model plants using a calculation based on of the number of 
controllers at the plant and emission factors for each controller. 
Three sizes of model plants (i.e., small, medium, and large) were 
developed and used for both the production and transmission and storage 
segments. Each model plant contained one high bleed natural gas-driven 
controller and increasing numbers of low bleed and intermittent natural 
gas-driven controllers. For the production segment, the controller-
specific emission factors used are from a recent study conducted by the 
American Petroleum Institute,\256\ and are 2.6 scfh, 16.4 scfh, and 9.2 
scfh total natural gas emissions for low bleed, high bleed, and 
intermittent bleed controllers, respectively. This API study did not 
cover the transmission and storage segment; therefore, the emission 
factors from GHGRP subpart W were used, which are 1.37 scfh, 18.2 scfh, 
and 2.35 scfh for low bleed, high bleed, and intermittent bleed 
controllers, respectively. It was assumed that the portion of natural 
gas that is methane is 82.9 percent in the production segment and 92.8 
percent in the transmission and storage segment. Further, it was 
assumed that VOCs were present in natural gas at a certain level 
compared to methane. The specific ratios assumed were 0.278 pounds VOC 
per pound methane in the production segment and 0.0277 pounds VOC per 
pound methane in the transmission and storage segment. This information 
results in estimated emissions for a single natural gas-driven 
pneumatic controller in the production segment of 0.39, 2.48, and 1.39 
tpy methane and 0.1, 0.7, and 0.4 tpy VOC per low bleed, high bleed, 
and intermittent vent controller, respectively. The emissions for a 
single natural gas-driven pneumatic controller in the transmission and 
storage segment are 0.23, 3.08, and 0.40 tpy methane and 0.006, 0.08, 
and 0.01 tpy VOC per low bleed, high bleed, and intermittent vent 
controller, respectively.
---------------------------------------------------------------------------

    \256\ API Field Measurement Study: ``Pneumatic Controllers EPA 
Stakeholder Workshop on Oil and Gas.'' November 7, 2019--Pittsburgh 
PA. Paul Tupper.
---------------------------------------------------------------------------

    Based on the factors described above and the number of each type of 
controller in each model plant, baseline emissions for the model plants 
were calculated. For the production model plants, the baseline 
emissions were calculated to be 5.7 tpy methane and 1.6 tpy VOC for the 
small model plant (assumes fewer controllers on site than medium 
plant), 11.2 tpy methane and 3.1 tpy VOC for the medium model plant 
(assumes more controllers on site than small plant), and 24.9 tpy 
methane and 6.9 tpy VOC for the large model plant (assumes more 
controllers on site than the medium plant). For the transmission and 
storage model plants, the baseline emissions were calculated to be 4.1 
tpy methane and 0.1 tpy VOC for the small model plant, 5.7 tpy methane 
and 0.2 tpy VOC for the medium model plant, and 10.0 tpy methane and 
0.3 tpy VOC for the large model plant. For detailed information on the 
configuration of these model plants and the calculation of the baseline 
emissions, see the NSPS OOOOb and EG TSD for this rulemaking, which is 
available in the docket.
    Instrument air controllers and electronic controllers were the two 
zero emission options evaluated. Both these options require electricity 
to operate. Instrument air systems use compressed air as the signaling 
medium for pneumatic controllers and pneumatic actuators, whereas 
electronic controllers send an electric signal to an electric actuator 
(rather than sending a pneumatic signal to a pneumatic actuator). As 
instrument air systems are usually installed at facilities where there 
is a high concentration of pneumatic control valves, electrical power 
from the grid, and the presence of an operator that can ensure the 
system is properly functioning, we evaluated the use of instrument air 
for the large model plant with more controllers and the use of 
electronic controllers, which can be powered by solar panels, at the 
small and medium-sized model plant with less controllers. The emission 
reduction potential of using these zero-emissions controllers rather 
than natural-gas-driven pneumatic controllers is 100 percent since 
these systems eliminate all natural gas emissions (they do not emit any 
VOC or methane). Based on the information available to the EPA during 
development of this proposal, these two zero-emissions options were the 
only two analyzed. The EPA solicits comment on the other potential 
zero-emission options for these sites (mechanical-only controllers, 
self-contained natural gas-driven controllers, and natural gas-driven 
controllers where the emissions are captured and routed to a process).
    For the small and medium-sized model plants, the zero-emissions 
option evaluated was the use of electronic controllers. The respective 
emissions reduction for small and medium-sized plants would be 5.7 and 
11.2 tpy methane and 1.6 and 3.1 tpy VOC in the production segment and 
4.1 and 5.7 tpy methane and 0.11 and 0.16 tpy VOC in the transmission 
and storage segment. The cost of a new electronic controller system 
using electricity from the grid or other on-site power generation is 
estimated to be $26,000 and $46,000, for small and medium-sized plants 
respectively. The cost of a new solar-powered electronic controller 
system is

[[Page 63206]]

estimated to be $28,000 and $52,000, for small and medium-sized plants 
respectively. The estimated annualized capital costs, assuming a 15-
year equipment lifetime and a 7 percent interest rate, are $2,800 and 
$5,040, respectively for a system powered with electricity from the 
grid or other power source for small and medium-sized plants, and 
$3,090 and $5,630, respectively, for a solar-powered system for small 
and medium-sized plants.
    For the production segment, considering the slightly more expensive 
solar-powered system, under the single pollutant approach, the 
estimated cost effectiveness is $550 per ton of methane avoided and 
$1,970 per ton of VOC avoided for a small plant and $500 per ton of 
methane avoided and $1,810 per ton of VOC avoided for a medium-sized 
plant. Using the multipollutant approach where half the cost of control 
is assigned to the methane reduction and half to the VOC reduction, the 
estimated cost effectiveness is $275 per ton of methane avoided and 
$980 per ton of VOC avoided for a small plant and $250 per ton of 
methane avoided and $900 per ton of VOC avoided for a medium-sized 
plant in the production segment. When considering the cost of saving 
the natural gas that would otherwise be emitted for the production 
segment, the cost effectiveness is $370 per ton of methane avoided and 
$1,320 per ton of VOC avoided for a small plant and $320 per ton of 
methane avoided and $1,150 per ton of VOC avoided for a medium-sized 
plant. Using the multipollutant approach, the estimated cost 
effectiveness is $185 per ton of methane avoided and $660 per ton of 
VOC avoided for a small plant and $160 per ton of methane avoided and 
$580 per ton of VOC avoided for a medium-sized plant in the production 
segment. These values are well within the range of what the EPA 
considers to be reasonable for methane and VOC using both the single 
pollutant and multipollutant approaches.
    For the natural gas transmission and storage segment, considering 
the slightly more expensive solar-powered system, the estimated cost 
effectiveness is $750 per ton of methane avoided and $27,200 per ton of 
VOC avoided for a small plant and $990 per ton of methane avoided and 
$35,700 per ton of VOC avoided for a medium-sized plant. Using the 
multipollutant approach, the estimated cost effectiveness is $380 per 
ton of methane avoided and $13,600 per ton of VOC avoided for a small 
plant and $490 per ton of methane avoided and $17,800 per ton of VOC 
avoided for a medium-sized plant. Transmission and storage facilities 
do not own the natural gas; therefore, revenues from reducing the 
amount of natural gas emitted/lost was not applied for this segment. 
While the cost effectiveness values for VOC are higher than the range 
of what the EPA considers to be reasonable for VOC, the cost 
effectiveness for methane is within the range of what the EPA considers 
to be reasonable for methane using the single pollutant approach.
    For the large model plants, the zero-emissions option evaluated was 
the use of instrument air systems. For the production segment, the 
emissions avoided would be 24.9 tpy methane and 6.9 tpy VOC, and in the 
transmission and storage segment 10.0 tpy methane and 0.3 tpy VOC. The 
cost of a new instrument air system is estimated to be $96,000 and the 
estimated annualized capital costs, assuming a 15-year equipment 
lifetime and a 7 percent interest rate, are $10,500. For the production 
segment, under the single pollutant approach, the estimated cost 
effectiveness is $420 per ton of methane avoided and $1,520 per ton of 
VOC avoided. Using the multipollutant approach, the estimated cost 
effectiveness is $210 per ton of methane avoided and $760 per ton of 
VOC avoided. When considering the cost of saving the natural gas that 
would otherwise be emitted for the production segment, the cost 
effectiveness is $240 per ton of methane avoided and $860 per ton of 
VOC avoided. Using the multipollutant approach, the estimated cost 
effectiveness is $120 per ton of methane avoided and $430 per ton of 
VOC avoided in the production segment. These values are well within the 
range of what the EPA considers to be reasonable for methane and VOC 
using both the single pollutant and multipollutant approaches.
    For the natural gas transmission and storage segment, the estimated 
cost effectiveness is $1,050 per ton of methane avoided and $38,000 per 
ton of VOC avoided. Using the multipollutant approach, the estimated 
cost effectiveness is $530 per ton of methane avoided and $19,000 per 
ton of VOC avoided. Transmission and storage facilities do not own the 
natural gas; therefore, revenues from reducing the amount of natural 
gas emitted/lost was not applied for this segment. While the cost 
effectiveness values for VOC are higher than the range of what the EPA 
considers to be reasonable for VOC, the cost effectiveness for methane 
is within the range of what the EPA considers to be reasonable for 
methane using the single pollutant approach.
    Note that the annual costs for these zero-emissions controllers are 
based on the annualized capital costs only. While we assume the 
maintenance costs for electric controllers is less than the costs for 
natural gas-driven controllers, there are costs associated with the use 
of electricity that are not incurred for natural gas-driven 
controllers. We solicit comments on whether such operational costs 
should be included in these estimates, as well as information regarding 
these costs.
    The capital costs of solar-powered controllers include the cost of 
the batteries, which represents around 7 percent of the total cost of a 
solar-powered system. As noted above, the capital cost was annualized 
assuming a 15-year lifetime, however batteries for a solar system may 
have a shorter life. We are soliciting comment on the life of these 
batteries and, if this life is shorter than 15 years, how the costs of 
these batteries should be included as a maintenance cost for solar 
powered systems.
    The EPA finds that the cost effectiveness for both the low bleed 
and zero-emissions options are reasonable for sites in the production 
and natural gas transmission and storage segments. The incremental cost 
effectiveness in going from the low bleed option to the zero-emissions 
option is estimated to be $390 and $340 per ton of additional methane 
eliminated for small and medium-sized plants ($1,400 and $1,200 per ton 
of VOC), respectively, in the production segment and $640 and $870 per 
ton of additional methane eliminated for small and medium-sized plants 
($23,000 and $31,500 per ton of VOC), respectively, in the transmission 
and storage segment. The incremental cost effectiveness in going from 
the low bleed option to the non-emissions option is estimated to be 
$260 and $940 per ton of additional methane and VOC avoided, 
respectively, for large plants in the production segment and to be $940 
and $34,000 per ton of additional methane and VOC avoided, 
respectively, for large plants in the transmission and storage segment. 
These incremental costs of control do not consider savings for the 
production segment. The EPA believes the incremental costs of control 
are reasonable for methane and VOC in the production segment, and for 
methane in the transmission and storage segment.
    As discussed above, several States and Canadian provinces require 
the use of controllers that do not emit methane or VOC throughout the 
Oil and Natural Gas Industry, which further demonstrates the 
reasonableness of this option and that there are no technical barriers 
inhibiting the use of electronic controllers or instrument air systems 
at sites in the production and transmission

[[Page 63207]]

and storage segments. In 2015, the EPA concluded that, ``[a]t sites 
without available electrical service sufficient to power an instrument 
air compressor, only gas driven pneumatic devices are technically 
feasible in all situations.'' (80 FR 56623, September 18, 2015). 
However, since that time, at least two States and two Canadian 
provinces have adopted regulations that require zero emitting 
controllers at all new sites. The EPA evaluated these rules, and 
considers these rules, along with the basic understanding that sources 
in these areas are able to comply with the rules, evidence that the 
feasibility issues that led to the EPA's previous decision not to 
require zero emission controllers in 2015 have been overcome. Further, 
the EPA recognizes that industry commenters on the proposed Colorado 
rule raised some of the same technical feasibility issues that have 
been presented to the EPA in the past, including battery storage 
capacity issues, weather-related issues, and mechanical issues related 
to vibration.\257\ However, despite these issues being raised, Colorado 
finalized the requirement that new controllers have a natural gas bleed 
rate of zero at all sites, even though without power. The EPA has 
considered new information since 2016 and has now concluded that use of 
zero-emission controllers is technically feasible subject to a 
particular proposed exception discussed below. The EPA specifically 
requests comments on this conclusion. The EPA further solicits comment 
on market availability of zero-emission options.
---------------------------------------------------------------------------

    \257\ Pneumatic Controller Task Force Report to the Air Quality 
Control Commission. Pneumatic Controller Field Study and 
Recommendations. Colorado Department of Public Health and 
Environment. Air Pollution Control Division. June 1, 2020.
---------------------------------------------------------------------------

    Secondary impacts from the use of electronic controllers and 
instrument air systems are indirect, variable, and dependent on the 
electrical supply used to power the compressor or controllers. These 
impacts are expected to be minimal. For example, it is estimated that 
the electricity needed to operate a compressor is only around 0.4 kW/
hour/controller when the compressor is operating. No other secondary 
impacts are expected. The EPA solicits comment on whether owners and 
operators would use diesel generators to generate power to run zero-
emissions controllers. The EPA recognizes that diesel generators would 
generate formaldehyde emissions and there could be associated secondary 
impacts. The EPA does not intend for diesel generators to be used.
    In light of the above, we find that the BSER for reducing methane 
and VOC emissions from natural gas-driven pneumatic controllers at 
production and transmission and storage sites is the use of zero-
emissions controllers. Therefore, for NSPS OOOOb, we are proposing to 
require zero emissions of methane and VOC to the atmosphere for all 
pneumatic controllers at production and transmission and storage sites.
    Both NSPS OOOO and NSPS OOOOa allow the use of high-bleed pneumatic 
controllers at production sites and natural gas-driven continuous bleed 
controllers at natural gas processing plants if it is determined that 
the use of such a pneumatic controller affected facility with a bleed 
rate greater than the applicable standard is required ``based on 
functional needs, including but not limited to response time, safety 
and positive actuation.'' See 40 CFR 60.5390(a) and 60.5390a(a). This 
exemption was based on comments received on the 2011 proposed NSPS OOOO 
rule. There, ``[t]he commenters suggest exemptions that address 
situations such as those where the natural gas includes impurities that 
could increase the likelihood of fouling a low-bleed pneumatic 
controller, such as paraffin or salts; where weather conditions could 
degrade pneumatic controller performance; during emergency conditions; 
where flow is not sufficient for low-bleed pneumatic controllers; where 
electricity is not available; and where engineering judgment recommends 
their use to maintain safety, reliability or efficiency.'' (77 FR 
49520, August 16, 2012). These reasons to allow for an exemption based 
on functional need were based on the inability of a low-bleed 
controller to meet the functional requirements of an owner/operator 
such that a high-bleed controller would be required in certain 
instances. Since we are now proposing that nearly all pneumatic 
controllers have a methane and VOC emission rate of zero, subject to 
exemption explained below, we do not believe that the reasons cited 
above are still applicable. Therefore, the proposed rule does not 
include an exemption based on functional need. The EPA is requesting 
comment regarding the possibility of situations where functional 
requirements/needs dictate that a natural gas-driven controller that 
emits any amount of VOC and/or methane be used. For example, are there 
situations where a zero-emission controller cannot be used due to 
functional needs such that an owner/operator must use a low-bleed 
controller or an intermittent controller instead? Comments requesting 
such an exemption should include details of the specific functional 
need and why all zero-emission controller options are not suitable.
    For many sites, the EPA believes that the most feasible zero-
emission option will be solar-powered controllers. The EPA recognizes 
that solar-powered controllers are dependent on sunshine, and in areas 
at higher latitudes that undergo prolonged periods without sunshine, 
this option could be problematic to implement due to the technical 
limitations of solar panels coupled with the practical realities 
related to the hours of sunshine received. Therefore, the proposed rule 
includes an exemption from the zero-emission requirement for pneumatic 
controllers at sites in Alaska that do not have access to power (i.e., 
electricity from the grid or produced using natural gas on-site). Sites 
with power have clearly demonstrated that zero emissions from 
controllers is achievable, and therefore the EPA is not proposing to 
exempt pneumatic controllers at sites in Alaska that have power. The 
proposed exemption would only apply to pneumatic controllers at sites 
located in Alaska that do not have access to power. In those 
situations, affected facilities would not be required to comply with 
the zero-emission standard, but instead must use low-bleed pneumatic 
controllers (unless a high bleed device is needed for functional 
reasons) and must monitor any intermittent controllers in conjunction 
with the fugitives monitoring program to ensure they are not venting 
when idle. The EPA is soliciting comment on this proposed exemption. 
Specifically, the EPA is interested in comments regarding the technical 
feasibility of solar panels to power pneumatic controllers in Alaska. 
The EPA is also interested in comments regarding whether there are 
other locations outside of Alaska where such an exemption may be 
warranted. In submitting responses to this request, commenters should 
be mindful that two Canadian Provinces, which are north of any U.S. 
State other than Alaska, require zero-emitting controllers at all new 
sites.
Natural Gas Processing Plants
    Natural gas processing plants typically have higher numbers of 
pneumatic controllers than production and transmission and storage 
sites. Model plants were also used for this analysis, specifically the 
model plants used are the same as those used for the 2011 and 2015 BSER 
analyses, and include small, medium, and large sites.

[[Page 63208]]

The number of controllers is 15, 63, and 175 for small, medium, and 
large model plants, respectively. All controllers at these sites are 
assumed to be continuous, but the number of low bleed and high bleed 
devices is not specified for the model plants. It was assumed that each 
controller emitted 1 tpy methane, as derived from Volume 12 of a 1996 
GRI report.\258\ In addition, it was assumed that the portion of 
natural gas that is methane is 82.8 percent in the natural gas 
processing segment, and the specific VOC to methane ratio assumed was 
0.278 pounds VOC per pound methane. For detailed information on the 
configuration of these model plants, see the NSPS OOOOb and EG TSD, 
which is available in the docket.
---------------------------------------------------------------------------

    \258\ Radian International LLC. Methane Emissions from the 
Natural Gas Industry, Vol. 12: Pneumatic Devices. Prepared for the 
Gas Research Institute and Environmental Protection Agency. EPA-600/
R-96-080k. June 1996.
---------------------------------------------------------------------------

    For natural gas processing plants, the only option evaluated was 
the requirement to use zero-emission controllers. For our analysis, we 
examined the use of instrument air, which is the most commonly used 
controller technology at natural gas processing plants. For this 
analysis, we used cost data from the 2011 NSPS OOOO TSD updated to 2019 
dollars. The updated capital costs for an instrument air system at a 
natural gas processing plant ranges from $20,000 to $162,000, depending 
on the system size. The annualized costs were based on a 7 percent 
interest rate and a 10-year equipment life. This equated to an 
annualized cost of approximately $13,000 to $96,000 per system. The 
emissions reduction associated with the installation of an instrument 
air system over natural gas-driven pneumatic controllers ranged from 
approximately 15 to 175 tpy methane and 4.2 to 49 tpy VOC per system. 
The cost effectiveness is estimated to range from approximately $550 to 
$900 per ton methane eliminated $2,000 to $3,100 per ton VOC 
eliminated. When considering the costs of saving the natural gas that 
would otherwise be emitted, the cost effectiveness improves, with a 
cost effectiveness of $370 to $700 per ton of methane eliminated and 
$1,300 to $2,500 per ton of VOC eliminated. These cost effectiveness 
values are presented on a single pollutant basis, and the cost of 
control on a multipollutant basis is 50 percent of these values. These 
values are well within the range of what the EPA considers to be 
reasonable for methane and VOC using both the single pollutant and 
multipollutant approaches.
    The 2012 NSPS OOOO and 2016 NSPS OOOOa require a zero-bleed 
emission rate for pneumatic controllers at natural gas processing 
plants. Natural gas processing plants have successfully met this 
standard for many years now. Further, several State agencies have rules 
that include this zero-bleed requirement for controllers at natural gas 
processing plants. This is further demonstration of the reasonableness 
of a zero methane and VOC emission standard for pneumatic controllers 
at natural gas processing plants.
    We find the cost effectiveness of eliminating methane and VOC 
emissions using both the single pollutant and multipollutant approaches 
to be reasonable.
    Secondary impacts from the use of instrument air systems are 
indirect, variable, and dependent on the electrical supply used to 
power the compressor. These impacts are expected to be minimal, and no 
other secondary impacts are expected.
    In light of the above, we find that the BSER for reducing methane 
and VOC emissions from natural gas-driven pneumatic controllers at 
natural gas processing plants is the use of zero-emissions controllers. 
Therefore, for NSPS OOOOb, we are proposing to require a natural gas 
emission rate of zero for all pneumatic controllers at natural gas 
processing plants. However, we recognize that there may be technical 
limitations in some situations where zero-emissions controllers may not 
be feasible, and therefore, we are proposing an allowance for the use 
of natural gas-driven pneumatic controllers with an emission rate of 
methane and VOC greater than zero where needed due to functional 
requirements in this BSER determination. Justification of this 
functional need must be provided in an annual report and maintained in 
records.
f. Use of Combustion Devices and VRUs
    Another option that could potentially be used to reduce emissions 
from pneumatic controllers is to collect the emissions from natural gas 
driven continuous bleed controllers and intermittent vent controllers 
and route the emissions through a closed vent system to a control 
device or process. This option is allowed in some State rules. While 
the EPA did not evaluate the cost effectiveness of this option due to a 
lack of available information regarding control system costs and 
feasibility across sites, we think this option could be cost effective 
for owners and operations in certain situations, particularly if the 
site already has a control device to which the emissions from 
controllers could be routed. As this option could be used to achieve 
significant methane and VOC emission reductions (95 percent or 
greater), we are soliciting comment on whether this is a control 
technique used in the industry to reduce emissions from natural gas-
driven pneumatic controllers. We are also interested in information 
related to the performance testing, monitoring, and compliance 
requirements associated with these control devices. Finally, we are 
interested in ideas as to how this option could potentially fit with 
the proposed requirements for pneumatic controllers. For example, if an 
owner or operator determines that a natural gas-driven pneumatic 
controller is required for functional need reasons, the EPA could 
require that emissions be collected and routed to a control device that 
achieves 95, or 98, percent control.
2. EG OOOOc
    The EPA evaluated BSER for the control of methane from existing 
pneumatic controllers (designated facilities) in all segments in the 
Crude Oil and Natural Gas source category covered by the proposed NSPS 
OOOOb and translated the degree of emission limitation achievable 
through application of the BSER into a proposed presumptive standard 
for these facilities that essentially mirrors the proposed NSPS OOOOb.
    First, based on the same criteria and reasoning as explained above, 
the EPA is proposing to define the designated facilities in the context 
of existing pneumatic controllers as those that commenced construction 
on or before November 15, 2021. Based on information available to the 
EPA, we did not identify any factors specific to existing sources that 
would indicate that the EPA should change these definitions as applied 
to existing sources. As such, for purposes of the emission guidelines, 
the definition of a designated facility in terms of pneumatic 
controllers is each individual natural gas driven pneumatic controller 
(continuous bleed or intermittent vent) that vents to the atmosphere.
    Next, the EPA finds that the control options evaluated for new 
sources for NSPS OOOOb are appropriate for consideration in the context 
of existing sources under the EG OOOOc. The EPA finds no reason to 
evaluate different, or additional, control measures in the context of 
existing sources because the EPA is unaware of any control measures, or 
systems of emission

[[Page 63209]]

reduction, for pneumatic controllers that could be used for existing 
sources but not for new sources.
    Next, the methane emission reductions expected to be achieved via 
application of the control measures identified above for new sources 
are also expected to be achieved by application of the same control 
measures to existing sources. The EPA finds no reason to believe that 
these calculations would differ for existing sources as compared to new 
sources because the EPA believes that the baseline emissions of an 
uncontrolled source are the same, or very similar, and the efficiency 
of the control measures are the same, or very similar, compared to the 
analysis above. This is also true with respect to the costs, non-air 
environmental impacts, energy impacts, and technical limitations 
discussed above for the control options identified.
    For the most part, the information presented above regarding the 
costs related to new sources and the NSPS are also applicable for 
existing sources. The instance where the EPA estimated a difference in 
the costs between a new and existing source was for the retrofit of an 
existing production site to use instrument air at sites equipped with 
electrical power. While the equipment needed is the same as for new 
sites, it may be more difficult to design and install a retrofitted 
system. Therefore, the EPA estimates the costs for design and 
installation to be twice that of the costs for new systems (from 
approximately $32,000 for new systems to approximately $64,000 for 
existing systems), resulting in the capital cost of the system being 
approximately $127,000 with an annualized cost of approximately 
$14,000.
    As noted above, the EPA's analysis for this proposal only examined 
the cost of instrument air for the large model plant. The total 
elimination of methane emissions (25 tons per year methane for 
production sites and 10 tons per year methane for transmission and 
storage sites) would be the same for existing sources as presented 
above for new sources. Considering the cost difference, the cost 
effectiveness for production sites is $560 per ton of methane 
eliminated without considering savings, and $365 per ton when 
considering savings. For the transmission and storage segment, the cost 
effectiveness is $1,400 per ton of methane eliminated. These values are 
within the range of what the EPA considers to be reasonable for 
methane. Since none of the other factors are different for existing 
sources when compared to the information discussed above for new 
sources, the EPA concludes that BSER for existing sources and the 
proposed presumptive standard for EG OOOOc to be the requirement to use 
zero-emission controllers. This proposed EG includes the exemption from 
the zero-emission standard for pneumatic controllers in Alaska as 
explained above in the context of the proposed NSPS OOOOb.
b. Possible Phase-In Approach for Existing Sources
    The EPA recognizes there could be different compliance time 
approaches that could be implemented for existing pneumatic 
controllers. The EPA's proposal for compliance times State plans must 
include to meet the requirements of the EG can be found in Section 
XIV.E. As explained there, the EPA is proposing that State plans must 
generally include a 2-year timeline for compliance in the proposed EG, 
but is also soliciting comment on the possibility of the EG requiring 
different compliance timelines for different emission points. 
Specifically, in the context of pneumatic controllers, the EPA is 
further soliciting comment on including a phase-in approach in the EG. 
The EPA recognizes that a phase-in approach may only be appropriate for 
existing sources as new facilities could presumably plan for zero-
emission controllers during construction. A phase-in period could span 
a number of years (e.g., 2 years), to allow owners and operators to 
prioritize conversion of natural gas-driven controllers at existing 
sites based on specific factors (e.g., focus first on sites with onsite 
power, sites with highest production, sites with the highest number of 
controllers). A phase-in approach could also result in the conversion 
of a certain percentage of sites within a given area (e.g., State or 
basin). For example, the State of Colorado requires a minimum of 40 
percent of sites to be converted after 2 years, with 15 percent in year 
1 and 25 percent in year 2. The EPA also recognizes potential 
challenges with a phase-in approach, such as difficulties with 
enforcement and calculation of the percentage converted due to the 
frequency at which sites may change ownership. The EPA solicits comment 
on all aspects of the EG requiring State plans to include a phase-in 
approach, and whether the agency should consider this type of approach 
rather than a single compliance time. The EPA also solicits comment on 
cost and feasibility factors that would enter into adopting and 
designing a phase-in timeline.
c. Natural Gas Processing Plants
    The information presented above regarding the emissions, emission 
reduction options and their effectiveness, costs, and other factors 
related to new natural gas processing plants and the NSPS are also 
applicable for existing sources. Therefore, the EPA concludes that BSER 
for existing sources and the EG OOOOc for natural gas processing plants 
is the requirement to use zero-emission controllers.

D. Proposed Standards for Well Liquids Unloading Operations

1. NSPS OOOOb
a. Background
    In the 2015 NSPS OOOOa proposal (80 FR 56614-56615, September 18, 
2015), the EPA stated that based on available information and input 
received from stakeholders on the 2014 Oil and Natural Gas Sector 
Liquids Unloading Processes review document,\259\ sufficient 
information was not available to propose a standard for liquids 
unloading.
---------------------------------------------------------------------------

    \259\ U.S. Environmental Protection Agency. Oil and Natural Gas 
Sector Liquids Unloading Processes. Report for Oil and Natural Gas 
Sector. Liquids Unloading Processes Review Panel. April 2014.
---------------------------------------------------------------------------

    At that time, the EPA requested comment on technologies and 
techniques that could be applied to new gas wells to reduce emissions 
from liquids unloading events in the future. In the 2016 NSPS OOOOa 
final rule (81 FR 35846, June 3, 2016), the EPA stated that, although 
the EPA received valuable information from the public comment process, 
the information was not sufficient to finalize a national standard 
representing BSER for liquids unloading at that time.
    For this proposal, the EPA conducted a review of available 
information, including new information that became available after the 
2016 NSPS OOOOa rulemaking. As a result of this review, the EPA is 
proposing a zero VOC and methane emission standard under NSPS OOOOb for 
liquid unloading, which can be achieved using non-venting liquids 
unloading methods. In the event that it is technically infeasible or 
not safe to perform liquids unloading with zero emissions, the EPA is 
proposing to require that an owner or operator establish and follow 
BMPs to minimize methane and VOC emissions during liquids unloading 
events to the extent possible. These proposed requirements apply to 
each well liquids unloading event.
    An overall description of liquids unloading, the definition of a 
modification, the definition of affected facility, our BSER analysis, 
and the proposed format of the standard are presented below.

[[Page 63210]]

b. Description
    In new gas wells, there is generally sufficient reservoir pressure/
gas velocity to facilitate the flow of water and hydrocarbon liquids 
through the well head and to the separator to the surface along with 
produced gas. In mature gas wells, the accumulation of liquids in the 
wellbore can occur when the bottom well pressure/gas velocity 
approaches the average reservoir pressure (i.e., volumetric average 
fluid pressure within the reservoir across the areal extent of the 
reservoir boundaries).\260\ This accumulation of liquids can impede and 
sometimes halt gas production. When the accumulation of liquids results 
in the slowing or cessation of gas production (i.e., liquids loading), 
removal of fluids (i.e., liquids unloading) is required in order to 
maintain production. These gas wells therefore often need to remove or 
``unload'' the accumulated liquids so that gas production is not 
inhibited.
---------------------------------------------------------------------------

    \260\ Gordon Smith Review. Oil & Natural Gas Sector Liquids 
Unloading Processes. Submitted: June 16, 2014. Pg. 4.
---------------------------------------------------------------------------

    The 2019 U.S. GHGI estimates almost 175,800 metric tpy of methane 
emissions from liquids unloading events for natural gas systems. 
Specifically, this includes almost 175,800 metric tpy from natural gas 
production, 98,900 metric tpy of which is from liquids unloading events 
that use a plunger lift, and 76,900 metric tpy from liquids unloading 
events that do not use a plunger lift. The overall total represents 3 
percent of the total methane emissions estimated from natural gas 
systems.
    In addition to the GHGI information, we also examined the 
information submitted under GHGRP subpart W. Specifically, we examined 
the GHGRP subpart W liquids unloading emissions data reported for 
Reporting Years 2015 to 2019. The liquids unloading emissions reported 
under GHGRP subpart W include emissions from venting wells, including 
those wells that vent during events that use a plunger lift and wells 
that vent during events that do not use a plunger lift. The information 
reported shows that methane emissions from liquids unloading for a well 
range from 0 to over 1,000 metric tons (1,100 tons) per year. While the 
single well with liquids unloading emissions of 1,100 tpy appears to be 
an outlier, there were over 65 subbasins with reported average liquids 
unloading emissions of 50 tpy or greater per well when disaggregating 
data by year and calculation method. There were over 1,000 wells 
reporting in these subbasins. In addition, there were almost 300 sub-
basins with reported average liquids unloading methane emissions of 10 
tpy or greater per well. There were almost 8,000 wells reporting in 
these subbasins.
    Another source of information reviewed related to emissions 
information from liquids unloading was a study published in 2015 by 
Allen, et al. (University of Texas (UT) Study).\261\ \262\ The UT Study 
collected monitoring data across regions of the U.S. Among other 
findings in this report, for wells that vent more than 100 times per 
year, the average methane emissions per well per year were 27 metric 
tpy, with 95 percent confidence bounds of 10 to 50 Mg/yr (based on the 
confidence bounds in the emissions per event). The monitoring data 
shows that methane emissions from liquids unloading for a well range 
from 1 to 19,500 Mscf per year, or 0.02 to 406 tpy.\263\ As indicated 
by the UT study \264\ emissions information, a small fraction of wells 
account for a large fraction of liquids unloading emissions.
---------------------------------------------------------------------------

    \261\ D.T. Allen, D.W. Sullivan, D. Zavala-Araiza, A.P. Pacsi, 
M. Harrison, K. Keen, M.P. Fraser, A. Daniel Hill, B.K. Lamb, R.F. 
Sawyer, J.H. Seinfeld, Methane emissions from process equipment at 
natural gas production sites in the United States: Liquid 
unloadings. Environ. Sci. Technol. 49, 641-648 (2015). doi:10.1021/
es504016r Medline. (UT Study).
    \262\ D.T. Allen, D.W. Sullivan, D. Zavala-Araiza, A.P. Pacsi, 
M. Harrison, K. Keen, M.P. Fraser, A. Daniel Hill, B.K. Lamb, R.F. 
Sawyer, J.H. Seinfeld. Methane Emissions from Process Equipment at 
Natural Gas Production Sites in the United States: Liquid 
Unloadings--Supporting Information; (UT Study--SI). Table S5-1, pg. 
21.
    \263\ UT Study--SI. Tables S3-1 to S3-3, pgs. 11-14.
    \264\ UT Study. pg. 642.
---------------------------------------------------------------------------

c. Modification
    As noted in section XII.D.1.b, new wells typically do not require 
liquids unloading until the point that the accumulation of liquids 
impedes or even stops gas production. At that point, the well must be 
unloaded of liquids to improve the gas flow. One method to accomplish 
this involves the intentional manual venting of the well to the 
atmosphere to improve gas flow. This is done using various techniques. 
One common manual unloading technique diverts the well's flow, 
bypassing the production separator to a lower pressure source, such as 
an atmospheric pressure tank. Under this scenario, venting to the 
atmospheric tank occurs because the separator operates at a higher 
pressure than the atmospheric tank and the well will temporarily flow 
to the atmospheric tank (which has a lower pressure than the 
pressurized separator). Natural gas is released through the tank vent 
to the atmosphere until liquids are unloaded and the flow diverted back 
to the separator. As discussed later in this section, the EPA has 
received feedback that there are technical difficulties with flaring 
vented emissions as a result of the intermittent and surging flow 
characteristic of venting for liquids unloading, and the changing 
velocities during an unloading event.
    Since each unloading event constitutes a physical or operational 
change to the well that has the potential to increase emissions, the 
EPA is proposing to determine each event of liquids unloading 
constitutes a modification that makes a well an affected facility 
subject to the NSPS. See 40 CFR 60.14(a) (``any physical or operational 
change to an existing facility which results in an increase in the 
emission rate to the atmosphere of any pollutant to which a standard 
applies shall be considered a modification within the meaning of 
section 111 of the Act''). The EPA solicits comment on this 
determination.
d. Definition of Affected Facility
    Given that we have proposed to determine that every liquids 
unloading event is a modification, the next step is to define the 
affected facility. The EPA recognizes that methods are commonly 
employed that significantly reduce, or even eliminate, emissions from 
liquids unloading. Therefore, the EPA is co-proposing two options on 
how a modified well due to a liquids unloading event would be covered 
under the rule.
    Under the first option, the affected facility subject to the 
requirements of NSPS OOOOb would be defined as every well that 
undergoes liquids unloading after the effective date of the final rule. 
Under this scenario, a well that undergoes liquids unloading is an 
affected facility regardless of whether the liquids unloading approach 
used results in venting to the atmosphere. This option posits that 
techniques employed to unload liquids that do not increase emissions 
are not to be considered in whether the unloading event is an affected 
facility or not, since the liquids unloading event in their absence 
could result in an emissions increase. This is somewhat analogous to a 
physical change to an existing storage vessel that resulted in the 
ability to increase throughput, and thus emissions. This physical 
change could result in an increase in emissions even if emissions were 
captured and routed back to a process such that the level of pollutant 
actually emitted to the atmosphere did not change. Under this scenario, 
the EPA could request and obtain compliance and enforcement information 
on non-venting liquids

[[Page 63211]]

unloading event methods commonly employed (simple records and reporting 
requirements), as well as venting liquids unloading events.
    Under the second option, the affected facility would be defined as 
every well that undergoes liquids unloading using a method that is not 
designed to totally eliminate venting (i.e., that results in emissions 
to the atmosphere). Under this scenario, if an owner or operator 
employs a method to unload liquids that does not vent to the 
atmosphere, the liquids unloading event would not constitute an 
increase in emissions and therefore, the well would not be an affected 
facility. As such, the first liquids unloading event that vents to the 
atmosphere after the effective date of the final rule, would be an 
affected facility subject to the requirements of NSPS OOOOb. This 
option could create an enforcement information and compliance gap. 
Specifically, the EPA would not be able to obtain compliance assurance 
information on liquids unloading events and emissions/methods and there 
could be a decreased incentive for owners or operators to ensure that 
no unexpected emission episodes occur when a method designed to be non-
venting is used.
    The EPA solicits comments on the two affected facility definition 
options being co-proposed. Specifically, we request comment on whether 
there are implementation and/or compliance assurance concerns that 
arise with applying either of the co-proposed options. In addition, we 
request comment on if there are any appropriate exemptions for 
operations that may be unlikely to result in emissions, such as 
wellheads that are not operating under positive pressure.
e. 2021 BSER Analysis
    The choice of what liquids unloading technique to employ is based 
on an operator well-by-well and reservoir-by-reservoir engineering 
analysis. Because liquids unloading operations entail a number of 
complex science and engineering considerations that can vary across 
well sites, there is no single technological solution or technique that 
is optimal for liquids unloading at all wells. Rather, a large number 
of differing technologies, techniques and practices (i.e., ``methods'') 
have been developed to address the unique characteristics of individual 
wells so as to manage liquids and maintain production. These methods 
include, but are not limited to, manual unloading, velocity tubing or 
velocity strings, beam or rod pumps, electric submergence pumps, 
intermittent unloading, gas lift (e.g., use of a plunger lift), foam 
agents, wellhead compression, and routing the gas to a sales line or 
back to a process.
    Selecting a particular method to meet a particular well's unloading 
needs must be based on a production engineering decision that is 
designed to remove the barriers to production. The situation is further 
complicated as the best method for a particular well can change over 
time. At the onset of liquids loading, techniques that rely on the 
reservoir energy are typically used. Eventually a well's reservoir 
energy is not sufficient to remove the liquids from the well and it is 
necessary to add energy to the well to continue production.
    In the 2016 NSPS OOOOa final rule preamble, the EPA acknowledged 
that operators must select the technique to perform liquids unloading 
operations based on the conditions of the well each time production is 
impaired. During the development of the 2016 NSPS OOOOa rule, the EPA 
considered subcategorization based on the potential for well site 
liquids unloading emissions but determined that the differences in 
liquids unloading events (with respect to both frequency and emissions 
level) are due to specific conditions of a given well at the time the 
operator determines that well production is impaired such that 
unloading must be done. Since owners and operators must select the 
technique to perform an unloading operation based on those conditions, 
and because well conditions change over time, each iteration of 
unloading may require repeating a single technique or attempting a 
different technique that may not have been appropriate under prior 
conditions. As noted above, we recognized that the choice of method to 
unload liquids from a well needs to be a production engineering 
decision based on the characteristics of the well at the time of the 
unloading, and owners and operators need the flexibility to select a 
method that is effective and can be safely employed. No information has 
become available since 2016 that leads the EPA to reach a different 
conclusion regarding subcategorization of wells for the purpose of 
developing standards to address liquids unloading emissions. Further, 
the EPA acknowledges the need for owners and operators to have the 
flexibility to select the most appropriate method(s) and recognize that 
any standard must not impede this flexibility.
    Many methods used for liquids unloading do not result in any 
venting to the atmosphere, provided that the method is properly 
executed. High-level summaries of a few of these methods are provided 
below.\265\
---------------------------------------------------------------------------

    \265\ ``Oil and Natural Gas Sector Liquids Unloading 
Processes''. Report for Oil and Natural Gas Sector Liquids Unloading 
Processes Review Panel. Prepared by U.S. EPA OAQPS. April 2014.
    \265\ 80 FR 56593, September 18, 2015.
---------------------------------------------------------------------------

    A commonly used method employed in the field is the use of a 
plunger lift system. While plunger lift systems often are used in a way 
to minimize emissions, under certain conditions they can be operated to 
unload liquids in a manner that eliminates the need to vent to the 
atmosphere. Plunger lifts use the well's own energy (gas/pressure) to 
drive a piston or plunger that travels the length of the tubing in 
order to push accumulated liquids in the tubing to the surface. 
Specific criteria regarding well pressure and liquid to gas ratio can 
affect applicability. Candidate wells for plunger lift systems 
generally do not have adequate downhole pressure for the well to flow 
freely into a gas gathering system. Optimized plunger lift systems 
(e.g., with smart well automation) can decrease the amount of gas 
vented by up to and greater than 90 percent, and in some instances can 
reduce the need for venting due to overloading. Plunger lift costs 
range from $1,900 to $20,000.\266\ Adding smart automation can cost 
anywhere between an estimated $4,700 to $18,000 depending on the 
complexity of the well. Natural Gas STAR estimates that the annual cost 
savings from avoided emissions from the use of an automated system 
ranges anywhere between $2,400 and $10,241 per year.\267\
---------------------------------------------------------------------------

    \266\ U.S. Environmental Protection Agency. Installing Plunger 
Lift Systems in Gas Wells. Office of Air and Radiation: Natural Gas 
Star Program. Washington, DC. 2006.
    \267\ U.S. Environmental Protection Agency. (U.S. EPA) 2011. 
Options for Removing Accumulated Fluid and Improving Flow in Gas 
Wells. Office of Air and Radiation: Natural Gas Star Program. 
Washington, DC. 2011. pg. 1.
---------------------------------------------------------------------------

    Other artificial lifts (e.g., rod pumps, beam lift pumps, pumpjacks 
and downhole separator pumps) are typically used when there is 
inadequate pressure to use a plunger lift, and the only means of 
liquids unloading to keep gas flowing is downhole pump technology. 
Artificial lifts can be operated in a manner that produces no 
emissions. The use of an artificial lift requires access to a power 
source. The capital and installation costs (including location 
preparation, well clean out, artificial lift equipment and pumping 
unit) is estimated to be $41,000 to $62,000/well, with the average cost 
of a pumping unit being between $17,000 to $27,000. \268\
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    \268\ U.S. EPA, 2011. pg. 9.

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[[Page 63212]]

    Velocity tubing is smaller diameter production tubing that reduces 
the cross-sectional area of flow, increasing the flow velocity and 
achieving liquids removal without blowing emissions to the atmosphere. 
Generally, a gas flow velocity of 1,000 feet per minute (fpm) is 
necessary to remove wellbore liquids. Velocity tubing strings are 
appropriate for low volume natural gas wells upon initial completion or 
near the end of their productive lives with relatively small liquids 
production and higher reservoir pressure. Candidate wells include 
marginal gas wells producing less than 60 Mcfd. Similarly, coil tubing 
can also be used in wells with lower velocity gas production (i.e., 
seamed coiled tubing may provide better lift due to elimination of 
turbulence in the flow stream). The proper use of velocity tubing is 
considered to be a ``no emissions'' solution. It is also low 
maintenance and effective for low volumes lifted. Velocity lifting can 
be deployed in combination with foaming agents (discussed below). The 
capital and installation costs are estimated to range anywhere from 
$7,000 to $64,000 per well.\269\ Installation requires a well workover 
rig to remove existing production tubing and placement of the smaller 
diameter tubing string in the well.
---------------------------------------------------------------------------

    \269\ U.S. EPA, 2011. pg. 8.
---------------------------------------------------------------------------

    The use of foaming agents (soap, surfactants) as a method to unload 
liquids is implemented by the injection of foaming agents in the 
casing/tubing annulus by a chemical pump on a timer basis. The gas 
bubbling of the soap-water solution creates gas-water foam which is 
more easily lifted to the surface for water removal. This, like the use 
of artificial lifts, requires power to run the surface injection pump. 
Additionally, foaming agents work best if the fluid in the well is at 
least 50 percent water and are not effective for natural gas liquids or 
liquid hydrocarbons. This method requires that the soap supply be 
monitored. If the well is still unable to unload fluid, smaller tubing 
may be needed to help lift the fluids. Foaming agents and velocity 
tubing are reported as possibly being more effective when used in 
combination. No equipment is required in shallow wells. In deep wells, 
a surfactant injection system requires the installation of surface 
equipment and regular monitoring. Foaming agents are reported as being 
low cost ``no emissions'' solution. The capital and startup costs to 
install soap launchers and velocity tubing is estimated to range 
between $7,500 and $67,880, with the monthly cost of the foaming agent 
is approximately $500 per well or approximately $6,000 per year.\270\
---------------------------------------------------------------------------

    \270\ U.S. EPA. 2011. Pg. 8.
---------------------------------------------------------------------------

    These are just a few examples of demonstrated methods that are 
being used in the industry to unload accumulated liquids that impair 
production, that can be implemented without venting and, thus, without 
emissions. As stressed earlier, the selection of a specific method must 
be made based on well-specific characteristics and conditions.
    Since GHGRP subpart W only requires reporting of liquids unloading 
events that resulted in venting of methane, no information is submitted 
regarding those wells that utilize a non-venting method. The EPA is 
also not aware of information that specifies the total number of wells 
that need to undergo liquids unloading. A 2012 report sponsored by the 
API and American Natural Gas Alliance (ANGA) \271\ provided more 
definitive insight into the number of wells that use non-venting 
liquids unloading methods. This report indicated that an estimated 21.1 
percent of plunger equipped wells vent, and 9.3 percent of non-plunger 
equipped wells vent. The EPA interprets this to mean that almost 80 
percent of plunger-equipped wells, and over 90 percent of non-plunger-
equipped wells perform liquids unloading and utilize non-venting 
methods.
---------------------------------------------------------------------------

    \271\ Shires, T. URS Corporation and Lev-On, M. the LEVON Group. 
Characterizing Pivotal Sources of Methane Emissions from Natural Gas 
Production. Summary and Analysis of API and ANGA Survey Responses. 
Prepared for the American Petroleum Institute and the American 
Natural Gas Alliance. September 21, 2012.
---------------------------------------------------------------------------

    As noted above, there is a tremendous range in the emissions from 
liquids unloading reported for individual wells. Further, as discussed 
above, the costs for the non-venting methods range considerably. Also, 
as discussed above, we have determined that the myriad of possible 
reservoir conditions and unloading methods do not lend to any 
reasonable subcategorization of the industry for which representative 
wells could be designed. Therefore, it is not possible to develop a 
``model'' well, or even a series of model wells, that can be used to 
conduct the type of analysis frequently performed for BSER 
determinations that calculates a cost per ton of emissions reduced (or 
in this case eliminated).
    Based on the highest costs included in the cost examples provided 
above, the cost effectiveness of a non-venting method would be 
considered reasonable for wells with annual methane emissions from 
liquids unloading of 16 tpy or greater, or VOC emissions of 3 tpy or 
greater. This upper range is based on the cost of the combination of 
velocity tubing and soap launchers. The upper range of the capital cost 
cited above was $67,800. Annualizing this capital cost at a 7 percent 
interest rate over 10 years, and adding in the $6,000 per year foaming 
agent cost, results in a total annual cost of $15,600. Given the total 
elimination of emissions, the cost effectiveness for a well with 16 tpy 
methane emissions would be $980 per ton of methane reduced, which is a 
level that the EPA considers reasonable for methane. Similarly, for 
VOC, the cost effectiveness for a well with 3 tpy VOC emissions would 
be $5,200 per ton of VOC reduced. This is also a level that the EPA 
considers reasonable. Given the range of costs, it could be reasonable 
even for some wells with annual liquids unloading methane emissions as 
low as 2.5 tpy ($400 per ton of methane reduced (velocity tubing)), or 
VOC emissions as low as 0.2 tpy ($5,000 per ton of VOC reduced 
(velocity tubing)). Based on the GHGRP subpart W data for the years 
2015 through 2019, around 50 percent of the wells that performed 
liquids unloading and reported emissions reported emissions higher than 
these levels.
    While owners and operators must select a liquids unloading method 
that is applicable for the well-specific conditions, they have the 
choice of many methods that can be used to eliminate venting/emissions 
from liquids unloading events. While we do not have information to 
calculate the specific percentage of total wells undergoing liquids 
unloading that use non-venting methods, available information suggests 
that a majority of wells that undergo liquids unloading do not vent. 
The EPA solicits information on the number (or percent) of liquids 
unloading events that vent to the atmosphere versus do not vent to the 
atmosphere under normal conditions and whether there are technical 
obstacles (other than costs) that would not allow liquids unloading to 
be performed without venting.
    CAA section 111(a) requires that the standard reflect the BSER that 
the EPA determines ``has been adequately demonstrated.'' An 
``adequately demonstrated system'' is one that ``has been shown to be 
reasonably reliable, reasonably efficient, and which can reasonably be 
expected to serve the interests of pollution control without becoming 
exorbitantly costly in an economic or environmental way.'' Essex Chem., 
486 F.2d at 433. For the reasons explained above and further elaborated 
below, the EPA considers non-venting methods such as those described 
above

[[Page 63213]]

to have been adequately demonstrated as the BSER for liquids unloading 
events. The complete elimination of emissions from liquids unloading 
with these non-venting methods have been adequately demonstrated in 
practice. The EPA notes that as part of decisions regarding liquids 
unloading, one goal of owners and operators is to eliminate venting to 
prevent the loss of product (natural gas) that could be routed to the 
sales line. States currently encourage the use of methods to eliminate 
emissions unless venting of emissions is necessary for safety reasons 
or when it is technically infeasible to not vent to unload liquids from 
the wellbore. For example, Pennsylvania has a general plan approval 
and/or general operating permit application (BAQ-GPA/GP-5A) that 
specifies that an owner or operator that conducts wellbore liquids 
unloading operations shall use best management practices including, but 
not limited to, plunger lift systems, soaping, swabbing, unless venting 
is necessary for safety to mitigate emissions during liquids unloading 
activities (Best Available Technology (BAT) Compliance Requirements 
under Section L of the General Permit).
    As discussed previously, a majority of wells already conduct 
liquids unloading operations without venting to the atmosphere. Also, 
as discussed previously, there are multiple non-venting liquids 
unloading methods that an owner and operator can select based on a 
well's specific characteristics and conditions. Our evaluation of costs 
shows that there are non-venting liquids unloading methods that could 
be employed to unload liquids that are reasonable given a wide range of 
emission levels. Finally, there are no negative secondary environmental 
impacts that would result from the implementation of methods that would 
eliminate venting of methane and VOC emissions to the atmosphere. In 
light of the above, the EPA considers non-venting liquids unloading 
methods to have been adequately demonstrated to represent BSER for 
reducing methane and VOC emissions during liquids unloading events.
    An ``adequately demonstrated'' system needs not be one that can 
achieve the standard ``at all times and under all circumstances.'' 
Essex Chem., 486 F.2d at 433. That said, as discussed below, the EPA 
recognizes that there may be reasons that a non-venting method is 
infeasible for a particular well, and the proposed rule would allow for 
the use of BMPs to reduce the emissions to the maximum extent possible.
    The EPA recognizes that there may be safety and technical reasons 
why venting to the atmosphere is necessary to unload liquids. In 
addition, it is possible that a well production engineer has already 
explored non-venting options and determined that there was no feasible 
option due to its specific characteristics and conditions. For 
scenarios where a liquids unloading method employed requires venting to 
the atmosphere, the EPA evaluated requiring BMPs that would minimize 
venting to the maximum extent possible. There are several States that 
require the development and implementation of BMPs that minimize 
emissions from liquids unloading events that vent. For example, 
Colorado requires specified BMPs to eliminate or minimize vented 
emissions from liquids unloading. The rule requires that all attempts 
be made to unload liquids without venting unless venting is required 
for safety reasons. If venting is required, the rule requires that 
owners and operators be on site and that they ensure that any venting 
is limited to the maximum extent practicable. Specific BMPs evaluated 
are based on State rules that require BMPs to minimize emissions during 
liquids unloading events are to require operators to monitor manual 
liquids unloading events onsite and to follow procedures that minimize 
the need to vent emissions during an event. This includes following 
specific steps that create a differential pressure to minimize the need 
to vent a well to unload liquids and reducing wellbore pressure as much 
as possible prior to opening to atmosphere via storage tank, unloading 
through the separator where feasible, and requiring closure of all well 
head vents to the atmosphere and return of the well to production as 
soon as practicable. For example, where a plunger lift is used, the 
plunger lift can be operated so that the plunger returns to the top and 
the liquids and gas flow to the separator. Under this scenario, venting 
of the gas can be minimized and the gas that flows through the 
separator can be routed to sales. In situations where production 
engineers select an unloading technique that results or has the 
potential to vent emissions to the atmosphere, owners and operators 
already often implement BMPs in order to increase gas sales and reduce 
emissions and waste during these (often manual) liquids unloading 
activities. We performed a cost and impacts evaluation of the use of 
BMPs to reduce emissions from liquids unloading. This evaluation is 
provided in the NSPS OOOOb and EG TSD for this rulemaking.
    Another potential method for reducing emissions from liquids 
unloading is to capture the vented gas from an unloading event and 
route it to a control device. At the time the Crude Oil and Natural Gas 
Sector Liquids Unloading Processes draft review document was submitted 
to reviewers, the EPA noted that, although the EPA was not aware of any 
specific instances where combustion devices/flares were used to control 
emissions vented from unloading events, the EPA requested information 
on the technical feasibility of flaring as an emissions control option 
for liquids unloading events. Feedback received from reviewers 
indicated that there are technical reasons that flaring during liquids 
unloading is not a feasible option.\272\ Reviewers emphasized that, in 
order to flare gas during liquids unloading, the liquids would need to 
be separated from the well stream, and the intermittent and surging 
flow characteristics of venting for liquids unloading, changing 
velocities during an unloading, and flare ignition considerations for a 
sporadically used flare (i.e., would require either a continuous pilot 
or electronic igniter) would make use of a flare technically and 
financially infeasible.^{273 274} The reviewers indicated that 
separating the liquids from the well stream would require the well 
stream to flow through a separator with sufficient backpressure to 
separate the gas and liquids. One reviewer noted that after separating 
the liquids from the well stream the gas would then be piped to flare 
system, where the backpressure needed to operate the separator would 
affect the performance of a plunger lift system (if used). Based on 
feedback received on the technical and cost feasibility of using a 
flare to control vented emissions from liquids unloading events 
indicating that a flare cannot be used in all situations, we did not 
consider this option any further in this proposal. However, the EPA is 
soliciting comments about the use of control devices to reduce 
emissions from liquids unloading events. Specifically, we request 
information on the types of wells and unloading events for which 
routing to control is feasible

[[Page 63214]]

and effective, the level of emission reduction achieved, and the 
testing and monitoring requirements that apply.
---------------------------------------------------------------------------

    \272\ U.S. Environmental Protection Agency. Oil and Natural Gas 
Sector Liquids Unloading Processes. Report for Crude Oil and Natural 
Gas Sector. Liquids Unloading Processes Review Panel. April 2014.
    \273\ Gordon Smith Review. Oil and Natural Gas Sector Liquids 
Unloading Processes. Review Submitted: June 16, 2014. Pg. 31.
    \274\ Jim Bolander, P.E., Senior Vice President, Southwestern 
Energy (SWN). Review Submitted: April 2014. Pg. 8.
---------------------------------------------------------------------------

    A similar potential method is to capture the vented gas from an 
unloading event and route it to the sales line or back to a process. 
This could potentially represent another method that results in zero 
emissions. While this is not a mitigation option that has been 
specifically mentioned for emissions from liquids unloading, it is a 
common option for other emission sources in the oil and natural gas 
production segment. The EPA is soliciting comments about the option to 
collect and route emissions back to the sales line or to a process. 
Specifically, we request information on the types of wells and 
unloading events for which this option is feasible (if any). If this 
option is feasible, we also request information on the specifics of the 
equipment and processes needed to accomplish this, as well as the 
costs.
    In conclusion, the EPA evaluated several options and identified the 
use of non-venting methods as the BSER for reducing methane and VOC 
emissions during liquids unloading events. However, the EPA recognizes 
there could be situations where it is infeasible to utilize a non-
venting method. Therefore, the EPA proposes to allow for the 
development and implementation of BMPs to reduce emissions to the 
extent possible during liquids unloading where it is infeasible to 
utilize a non-venting method.
f. Format of the Standard
    As discussed under section XII.D.1.d of this preamble, the EPA is 
co-proposing two regulatory approaches to implement the BSER 
determination.
    For Option 1, the affected facility would be defined as every well 
that undergoes liquids unloading. This would mean that wells that 
utilize a non-venting method for liquids unloading would be affected 
facilities and subject to certain reporting and recordkeeping 
requirements. These requirements would include records of the number of 
unloadings that occur and the method used. A summary of this 
information would also be required to be reported in the annual report. 
The EPA also recognizes that under some circumstances venting could 
occur when a selected liquids unloading method that is designed to not 
vent to the atmosphere is not properly applied (e.g., a technology 
malfunction or operator error). Under the proposed rule Option 1 owners 
and operators in this situation would be required to record and report 
these instances, as well as document and report the length of venting 
and what actions were taken to minimize venting to the maximum extent 
possible.
    For wells that utilize methods that vent to the atmosphere, the 
proposed rule would require that they: (1) Document why it is 
infeasible to utilize a non-venting method due to technical, safety, or 
economic reasons; (2) develop BMPs that ensure that emissions during 
liquids unloading are minimized; (3) follow the BMPs during each 
liquids unloading event and maintain records demonstrating they were 
followed; (4) report the number of liquids unloading events in an 
annual report, as well as the unloading events when the BMP was not 
followed. While the proposed rule would not dictate the specific 
practices that must be included, it would specify minimum acceptance 
criteria required for the types and nature of the practices. Examples 
of the types and nature of the required practice elements for BMP are 
provided in section XII.D.1.e, such as those contained in Colorado's 
rule. The EPA is specifically requesting comment on the minimum 
elements that should be required in BMPs and the specificity that the 
proposed rule should include regarding these elements.
    An advantage of this regulatory option is that it would provide 
information to the EPA on the number of liquids unloading events that 
occur and the types of unloading methods used. Having this important 
information would enhance the EPA, the industry, and the public's 
knowledge of emissions from liquids unloading. Option 1 would also 
provide incentive for owners and operators to ensure that non-venting 
methods are applied as they are designed such that unexpected emissions 
do not occur as the result of technology malfunctions or operator 
error. However, it would result in some recordkeeping and reporting 
burden for wells that already use or plan to use non-venting methods 
that would not be incurred under Option 2.
    For Option 2, the affected facility would be defined as every well 
that undergoes liquids unloading using a method that is not designed to 
eliminate venting. The significant difference in this option is that 
wells that utilize non-venting methods would not be affected facilities 
that are subject to the NSPS OOOOb. Therefore, they would not have 
requirements other than to maintain records to demonstrate that they 
used non-venting liquids unloading methods. The requirements for wells 
that use methods that vent would be the same as described above under 
Option 1.
    The EPA believes that this option would provide additional 
incentive for owners and operators to seek ways to overcome potential 
infeasibility issues to ensure that their wells are not affected 
facilities and subject to reporting and recordkeeping requirements. 
This would ultimately result in lower emissions. However, this would 
not provide the EPA information to have a more comprehensive 
understanding of emissions and emission reduction methods from liquids 
unloading. It would also not provide incentive for owners and operators 
to ensure that no unexpected emission episodes occur when a method 
designed to be non-venting is used.
2. EG OOOOc
    As described above, the EPA is proposing that each unloading event 
represents a modification, which will make the well subject to new 
source standards under NSPS. Therefore, existing wells that undergo 
liquids unloading would become subject to NSPS OOOOb. This will mean 
that there will never be a well that undergoes liquids unloading that 
will be ``existing'' for purposes of CAA section 111(d). Therefore, 
there is no need for emissions guidelines or an associated presumptive 
standard under EG OOOOc for liquids unloading operations.

E. Proposed Standards for Reciprocating Compressors

1. NSPS OOOOb
a. Background
    The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each 
individual new or reconstructed reciprocating compressor, except for 
those compressors located at a well site, or those located at an 
adjacent well site and servicing more than one well site. The 2016 NSPS 
OOOOa required the reduction of methane and VOC emissions from new, 
reconstructed, or modified reciprocating compressors by replacing rod 
packing systems within 26,000 hours or 36 months of operation, 
regardless of the condition of the rod packing. As an alternative, the 
2016 NSPS OOOOa allowed owners or operators to collect the emissions 
from the rod packing using a rod packing emissions collection system 
that operates under negative pressure and route the rod packing 
emissions to a process through a closed vent system.
    In determining BSER for reciprocating compressors in 2016, the EPA 
determined that the previous determination for NSPS OOOO conducted in 
2011/2012 still represented BSER in 2016. In the 2012 determination the 
EPA first concluded that the piston rod packing wear

[[Page 63215]]

produces fugitive emissions that cannot be captured and conveyed to a 
control device, and that an operational standard pursuant to section 
111(h) of the CAA was appropriate. The EPA conducted analyses of the 
costs and emission reductions of the replacement of rod packing every 3 
years or 26,000 hours of operation and determined that the costs per 
ton of emissions reduced were reasonable for the industry, with the 
exception of compressors at well sites. Based on the 2011 BSER 
analysis, requiring replacement of rod packing every 3 years or 26,000 
hours of operation for well site reciprocating compressors was not 
considered cost effective (almost $57,000 per ton of VOC reduced).\275\ 
No other more stringent control options were evaluated at that time.
---------------------------------------------------------------------------

    \275\ 2011 NSPS OOOO TSD. pg. 6-17.
---------------------------------------------------------------------------

    For this review of the NSPS, the EPA focused on these control 
options which were previously assessed for the 2012 NSPS OOOO and the 
2016 NSPS OOOOa. In addition, we evaluated an option that would require 
annual monitoring to determine if the rod packing needed to be 
replaced. This option is in contrast to the option where replacement is 
required on a fixed (e.g., 3 year) schedule. For this review, BSER was 
evaluated for reciprocating compressors at gathering and boosting 
stations in the production segment (considered to be representative of 
emissions from reciprocating compressors at centralized production 
facilities), at natural gas processing plants, and at sites in the 
transmission and storage segment. In 2012 and in 2016, the EPA 
determined that the cost effectiveness of replacement of the rod 
packing based on the fixed 3-year (or 26,000 hours) schedule was 
unreasonable for reciprocating compressors located at the well site 
(discussed below). No new information has become available to change 
this determination. Therefore, we did not include reciprocating 
compressors located at well sites in our evaluation of regulatory 
options.
    However, as discussed in section XI.L (Centralized Production 
Facilities) of this preamble, the EPA believes the definition of ``well 
site'' in NSPS OOOOa may cause confusion regarding whether 
reciprocating compressors located at centralized production facilities 
are also exempt from the standards. The EPA is proposing a new 
definition for a ``centralized production facility''. The EPA is 
proposing to define centralized production facilities separately from 
well sites because the number and size of equipment, particularly 
reciprocating and centrifugal compressors, is larger than standalone 
well sites which would not be included in the proposed definition of 
``centralized production facilities''. This proposal is necessary in 
the context of reciprocating compressors to distinguish between these 
compressors at centralized production facilities where the EPA has 
determined that the standard should apply, and compressors at 
standalone well sites where the EPA has determined that the standard 
should not apply. In our current analysis, described below, we consider 
the reciprocating compressor gathering and boosting segment emission 
factor as being representative of reciprocating compressor emissions 
located at centralized production facilities. As such, the EPA is 
proposing that reciprocating compressors located at centralized 
production facilities would be subject to the standards in NSPS OOOOb 
and the EG in subpart OOOOc, but reciprocating compressors at well 
sites (standalone well sites) would not.
    As a result of the EPA's review of NSPS OOOOa, we are proposing 
that BSER is to replace the rod packing when, based on annual flow rate 
measurements, there are indications that the rod packing is beginning 
to wear to the point where there is an increased rate of natural gas 
escaping around the packing to unacceptable levels. We are proposing 
that if annual flow rate monitoring indicates a flow rate for any 
individual cylinder as exceeding 2 scfm, an owner or operator would be 
required to replace the rod packing.
b. Description
    In a reciprocating compressor, natural gas enters the suction 
manifold, and then flows into a compression cylinder where it is 
compressed by a piston driven in a reciprocating motion by the 
crankshaft powered by an internal combustion engine. Emissions occur 
when natural gas leaks around the piston rod when pressurized natural 
gas is in the cylinder. The compressor rod packing system consists of a 
series of flexible rings that create a seal around the piston rod to 
prevent gas from escaping between the rod and the inboard cylinder 
head. However, over time, during operation of the compressor, the rings 
become worn and the packaging system needs to be replaced to prevent 
excessive leaking from the compression cylinder.
    As discussed previously, emissions from a reciprocating compressor 
occur when, over time, during operation of the compressor, the rings 
that form a seal around the piston rod that prevents gas from escaping 
become worn. This results in increasing emissions from the compression 
cylinder. Based on the 2021 GHGI,\276\ the methane emissions from 
reciprocating compressors in 2019 represented 14 percent of the total 
methane emissions from natural gas systems in the Crude Oil and Natural 
Gas Industry sector. For segments where the GHGI included a breakdown 
of methane emissions for reciprocating compressors, the reported 
emissions were 309,500 metric tons for the gathering and boosting 
segment, 46,700 metric tons for the processing segment, 406,500 metric 
tons for the transmission segment, and 103,200 metric tons for the 
storage segment.
---------------------------------------------------------------------------

    \276\ U.S. Environmental Protection Agency. Inventory of U.S. 
Greenhouse Gas Emissions and Sinks (1990-2019). Published in 2021. 
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019.
---------------------------------------------------------------------------

c. Affected Facility
    For purposes of the NSPS, the reciprocating compressor affected 
facility is a single reciprocating compressor. A reciprocating 
compressor located at a well site, or an adjacent well site and 
servicing more than one well site, is not an affected facility under 
the proposed rule for the NSPS OOOOb. As discussed above, the EPA is 
proposing that the affected facility includes reciprocating compressors 
located at centralized production facilities and the affected facility 
exception for ``a well site, or an adjacent well site servicing more 
than one well site'' applies to standalone well sites and not 
centralized production facilities.
d. 2021 BSER Analysis
    The methodology used for estimating emissions from reciprocating 
compressor rod packing is consistent with the methodology developed for 
the 2012 NSPS OOOO BSER analysis and then also used to support the 2016 
NSPS OOOOa BSER. This approach uses volumetric methane emission factors 
referenced in the EPA/GRI study \277\ as the basis, multiplied by the 
density of methane. These factors were per cylinder, so they were 
multiplied by the average number of cylinders per reciprocating 
compressor at each oil and gas industry segment, the pressurized factor 
(percentage of hours per year the compressor was pressurized), and 
8,760 hours (number of hours in a year). Once the methane emissions 
were calculated, VOC emissions were calculated by multiplying the 
methane by ratios developed based on representative gas composition. 
The specific ratios that were used for this analysis were 0.278

[[Page 63216]]

pounds VOC per pound of methane for the production and processing 
segments, and 0.0277 pounds VOC per pound of methane for the 
transmission and storage segment. The resulting baseline emissions from 
reciprocating compressors were 12.3 tpy methane (3.4 tpy VOC) from 
gathering and boosting stations, 23.3 tpy methane (6.5 tpy VOC) from 
natural gas processing plants, 27.1 tpy methane (0.75 tpy VOC) from 
transmission stations, and 28.2 tpy methane (0.78 tpy VOC) from storage 
facilities.
---------------------------------------------------------------------------

    \277\ EPA/GRI. (1996). Methane Emissions from the Natural Gas 
Industry: Volume 8--Equipment Leaks.
---------------------------------------------------------------------------

    Reducing emissions that result from the leaking of natural gas past 
the piston rod packing can be accomplished through several approaches 
including: (1) Specifying a frequency for the replacement of the 
compressor rod packing, (2) monitoring the emissions from the 
compressor and replacing the rod packing when the results exceed a 
specified threshold, (3) specifying a frequency for the replacement of 
the piston rod, (4) requiring the use of specific rod packing 
materials, and/or (5) capturing the leaking gas and routing it either 
to a process or a control device.
    There was either insufficient information to establish BSER or it 
was determined that the option cannot be applied in all situations for 
approach options (3) through (5). These are discussed briefly below.
    Like the packing rings, piston rods on reciprocating compressors 
also deteriorate. Piston rods, however, wear more slowly than packing 
rings, having a life of about 10 years.\278\ Rods wear ``out-of-round'' 
or taper when poorly aligned, which affects the fit of packing rings 
against the shaft (and therefore the tightness of the seal) and the 
rate of ring wear. An out-of-round shaft not only seals poorly, 
allowing more leakage, but also causes uneven wear on the seals, 
thereby shortening the life of the piston rod and the packing seal. 
Replacing or upgrading the rod can reduce reciprocating compressor rod 
packing emissions. Also, upgrading piston rods by coating them with 
tungsten carbide or chrome reduces wear over the life of the rod. We 
assume that operators will choose, at their discretion, when to 
replace/realign or retrofit the rod as part of regular maintenance 
procedures and replace the rod when appropriate when the compressor is 
out of service for other maintenance such as rod packing replacement. 
Although replacing/realigning or retrofitting the rod has been 
identified as a potential methane and VOC emission reduction option for 
reciprocating compressors, there is insufficient information on its 
emission reduction potential and use throughout the industry. 
Therefore, we did not evaluate this option any further as BSER for this 
proposal.
---------------------------------------------------------------------------

    \278\ U.S. Environmental Protection Agency. Lessons Learned from 
Natural Gas STAR Partners. Reducing Methane Emissions from 
Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
---------------------------------------------------------------------------

    Although specific analyses have not been conducted, there may be 
potential for reducing methane and VOC emissions by updating rod 
packing components made from newer materials, which can help improve 
the life and performance of the rod packing system. One option is to 
replace the bronze metallic rod packing rings with longer lasting 
carbon-impregnated Teflon rings. Compressor rods can also be coated 
with chrome or tungsten carbide to reduce wear and extend the life of 
the piston rod. Although changing the rod packing material has been 
identified as a potential methane and VOC emission reduction option for 
reciprocating compressors, there is insufficient information on its 
emission reduction potential and use throughout the industry. 
Therefore, we did not evaluate this option any further as BSER for this 
proposal.
    The 2016 NSPS OOOOa includes the alternative to route the emissions 
from reciprocating compressors to a process. One estimate obtained by 
the EPA states that a gas recovery system can result in the elimination 
of over 99 percent of methane emissions that would otherwise occur from 
the venting of the emissions from the compressor rod packing. The 
emissions that would have been vented are combusted in the compressor 
engine to generate power. It was estimated that, if a facility is able 
to route rod packing vents to a VRU system, it is possible to recover 
approximately 95-100 percent of emissions. As a comparison, the EPA 
estimated that the 3-year/26,000-hour changeout results in between 55 
and 80 percent emission reduction. Therefore, an option to achieve 
additional emission reductions could be to require routing the 
reciprocating compressor emissions to a process/through a closed vent 
system under negative pressure. Although this was a control option 
considered in the 2016 NSPS OOOOa (and included as an alternative), the 
EPA did not require routing to a process for all compressors because at 
that time there was insufficient information to require this as a 
control for all reciprocating compressors. The EPA received feedback 
that this option cannot be applied in every installation, and has not 
received any new information that indicates this has changed. Thus, 
this option was not considered further as a requirement but for this 
proposal, as with the 2016 NSPS OOOOa, it is considered to be an 
acceptable alternative to mitigate methane and VOC emissions where it 
is technically feasible to apply.
    Similarly, another option evaluated as having the potential to 
achieve methane and VOC emission reductions was to require the 
collection of emissions in a closed vent system and routing them to a 
flare or other control device. If the gas is routed to a flare, 
approximately 95 percent of the methane and VOC would be reduced. The 
EPA has expressed historically and maintains that combustion is not 
believed to be a technically feasible control option for reciprocating 
compressors because, as detailed in the 2011 NSPS OOOO TSD, routing of 
emissions to a control device can cause positive back pressure on the 
packing, which can cause safety issues due to gas backing up in the 
distance piece area and engine crankcase in some designs. The EPA has 
not identified any new information to indicate that this has changed. 
Therefore, this option was not considered further as BSER for this 
proposal.
    The remaining two control option approaches that were evaluated 
further for this proposal include: (1) Specifying a frequency for the 
replacement of the compressor rod packing (equivalent to the frequency 
used in the 2016 NSPS OOOOa BSER control level), and (2) monitoring the 
emissions from the compressor and replacing the rod packing when the 
results exceed a specified threshold. Both of these approaches would 
reduce the escape of natural gas from the piston rod. No wastes would 
be created (other than the worn packing that is being replaced) and no 
wastewater would be generated.
    As noted previously, periodically replacing the packing rings 
ensures the correct fit is maintained between packing rings and the 
rod, thereby limiting emissions occurring around the flexible rings 
that fit around the shaft by recreating a seal against leakage that may 
have been lost due to wear. The potential emission reductions for 
reciprocating compressors at gathering and boosting stations, 
processing plants, and transmission and storage facilities were 
calculated by comparing the average rod packing emissions with the 
average emissions from newly installed and worn-in rod packing. As 
noted above, because the EPA concluded that the cost effectiveness of 
this option was extremely unreasonable for reciprocating compressors at 
well sites in previous BSER analyses (see the 2011 NSPS OOOO TSD, 
section 2.2; 80 FR 56620, September 18, 2015), and since no new 
information was identified that

[[Page 63217]]

would change this outcome as it relates to stand alone well sites, 
reductions and costs were not re-evaluated in this analysis for 
reciprocating compressors at production well sites.
    The emissions after the replacement of the rod packing were 
calculated using the methodology used under previous NSPS actions (see 
NSPS OOOOb and EG TSD, section 7.1). The resulting emission reductions 
used for the analysis represented the emission reductions expected in 
the year the rod packing is replaced. It is expected that there would 
be an increase in the emissions (and decrease in the emission 
reductions) from a compressor where the rod packing was replaced the 
second and third years before the next replacement. As noted above, 
this assumed reduction was between 55 and 80 percent depending on the 
location of the compressor.
    The costs of replacing rod packing were obtained from a Natural Gas 
STAR Lessons Learned document \279\ and the dollars were converted to 
2019 dollars. The estimated cost to replace the packing rings in 2019 
dollars was estimated to be $1,920 per cylinder. It was assumed that 
rod packing replacement would occur during planned shutdowns and 
maintenance, and therefore no additional travel costs would be incurred 
for implementing a rod packing replacement program. Since the assumed 
number of cylinders differs for reciprocating compressors at different 
segments, this means the capital costs also vary. These estimated 
capital costs are $6,350 at gathering and boosting and transmission 
stations, $4,800 at processing plants, and $8,650 at storage stations.
---------------------------------------------------------------------------

    \279\ EPA (2006). Lessons Learned: Reducing Methane Emissions 
from Compressor Rod Packing Systems. Natural Gas STAR. Environmental 
Protection Agency.
---------------------------------------------------------------------------

    The 26,000-hour replacement frequency used for the cost impacts in 
the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD was determined using a 
weighted average of the annual percentage of time that reciprocating 
compressors are pressurized. The weighted average percentage was 
calculated to be 98.9 percent. This percentage was multiplied by the 
total number of hours in 3 years to obtain a value of 26,000 hours. 
This calculates to an average of 3.8 years for gathering and boosting 
compressors, 3.3 years for processing compressors, 3.8 years for 
transmission compressors, and 4.4 years for storage compressors. The 
calculated years were assumed to be the equipment life of the 
compressor rod packing and were used to calculate the capital recovery 
factor for each of the segments. Assuming an interest rate of 7 
percent, the capital recovery factors were calculated to be 0.3093, 
0.3498, 0.3093, and 0.2695 for the gathering and boosting part of 
production, processing, transmission, and storage segments, 
respectively.
    The capital costs were calculated using the average rod packing 
cost noted above and the average number of cylinders per compressor 
(which differs depending on sector segment). The annual capital costs 
were calculated using the capital costs and the capital recovery 
factors. The estimated annual costs ranged from $1,700 at processing 
plants to just over $2,300 at storage facilities. Note that these 
estimated costs represent the costs, and associated emission 
reductions, that would occur in the year when the rod packing was 
changed. There would be no costs for the other two years in the three-
year cycle. The costs presented for gathering and boosting segment 
reciprocating compressors represent the estimated costs assumed for 
reciprocating compressors located at centralized production facilities.
    There are monetary savings associated with the amount of natural 
gas saved with reciprocating compressor rod packing replacement. 
Monetary savings associated with the amount of gas saved with 
reciprocating compressor rod packing replacement were estimated using a 
natural gas price of $3.13 per Mcf. Estimated savings were only applied 
for gathering and boosting stations and processing plants, as it is 
assumed the owners of the compressor station do not own the natural gas 
that is compressed at the station.
    Using the single pollutant approach, where all the costs are 
assigned to the reduction of one pollutant, the cost effectiveness of 
replacement of the reciprocating rod packing within 26,000 hours or 36 
months of operation, regardless of the condition of the rod packing, is 
approximately $290 per ton of methane reduced for gathering and 
boosting ($100 per ton if gas savings are considered), $90 per ton of 
methane reduced for the processing segment (net savings if gas savings 
are considered), $90 per ton of methane reduced for the transmission 
segment, and $110 per ton of methane reduced for the storage segment. 
Using the multipollutant approach, where half the cost of control is 
assigned to the methane reduction and half to the VOC reduction, the 
cost effectiveness of replacement of the reciprocating rod packing 
within 26,000 hours or 36 months of operation, regardless of the 
condition of the rod packing, is approximately $140 per ton of methane 
reduced for gathering and boosting ($50 per ton if gas savings are 
considered), $45 per ton of methane reduced for the processing segment 
(net savings if gas savings are considered), $45 per ton of methane 
reduced for the transmission segment, and $50 per ton of methane 
reduced for the storage segment.
    Using the single pollutant approach, where all the costs are 
assigned to the reduction of one pollutant, the VOC cost effectiveness 
of replacement of the reciprocating rod packing within 26,000 hours or 
36 months of operation, regardless of the condition of the rod packing, 
is approximately $1,030 per ton of VOC reduced for gathering and 
boosting ($380 per ton if gas savings are considered), $330 per ton of 
VOC reduced for the processing segment (net savings if gas savings are 
considered), $3,260 per ton of VOC reduced for the transmission 
segment, and $3,860 per ton of VOC reduced for the storage segment. 
Using the multipollutant approach, where half the cost of control is 
assigned to the methane reduction and half to the VOC reduction, the 
cost effectiveness of replacement of the reciprocating rod packing 
within 26,000 hours or 36 months of operation, regardless of the 
condition of the rod packing, is approximately $520 per ton of VOC 
reduced for gathering and boosting ($190 per ton if gas savings are 
considered), $160 per ton of VOC reduced for the processing segment 
(net savings if gas savings are considered), $1,630 per ton of VOC 
reduced for the transmission segment, and $1,930 per ton of VOC reduced 
for the storage segment.
    As an alternative to replacing the rod packing on a fixed schedule, 
another option is to replace the rod packing when, based on 
measurements, there are indications that the rod packing is beginning 
to wear to the point where there is an increased rate of natural gas 
escaping around the packing to unacceptable levels. This is an approach 
required by the California Greenhouse Gas Emission Regulation and in 
Canada. The California Greenhous Gas Emission Regulation requires that 
the rod packing/seal be tested during periodic inspections and, if the 
rod packing/seal leak concentration exceeds the specified threshold of 
2 scfm/cylinder, repairs must be made within 30 days.\280\ Similarly, 
certain Canadian jurisdictions require periodic monitoring measurements 
of rod packing vent

[[Page 63218]]

volumes (typically annually) for existing reciprocating compressors. 
Where specified vent volumes are exceeded, the rules require corrective 
action be taken to reduce the flow rate to below or equal to a 
specified limit, as demonstrated by a remeasurement. Vent volume 
thresholds specified that would result in the need for corrective 
action vary from 0.49 to 0.81 scfm/cylinder.\281\
---------------------------------------------------------------------------

    \280\ State of California Air Resources Board (CARB). 
``Regulation for Greenhouse Gas Emission Standards for Crude Oil and 
Natural Gas Facilities.'' Oil and Gas Final Regulation Order 
(ca.gov).
    \281\ Canadian Federal standards: https://gazette.gc.ca/rp-pr/p2/2018/2018-04-26-x1/pdf/g2-152x1.pdf; Discussion Draft Regulation 
26.11.41 (maryland.gov); MAP-Technical-Report-December-19-2019-
FINAL.pdf (nm.gov).
---------------------------------------------------------------------------

    This approach is similar to an approach identified in the Natural 
Gas STAR Program referred to as ``Economic Packing and Piston Rod 
Replacement.'' \282\ Under this approach, facilities use specific 
financial objectives and monitoring data to determine emission levels 
at which it is cost effective to replace rings and rods. Benefits of 
calculating and utilizing this ``economic replacement threshold'' 
include methane and VOC emission reductions and natural gas cost 
savings. Using this approach, one Natural Gas STAR partner reportedly 
achieved savings of over $233,000 annually at 2006 gas prices. An 
economic replacement threshold approach can also result in operational 
benefits, including a longer life for existing equipment, improvements 
in operating efficiencies, and long-term savings. The EPA is not 
proposing to establish a financial objective or economic replacement 
threshold in this proposal, but the costs and emission reductions of 
replacing rod packing based on monitoring from this program were 
considered in the analysis discussed below.
---------------------------------------------------------------------------

    \282\ U.S. Environmental Protection Agency. Lessons Learned from 
Natural Gas STAR Partners. Reducing Methane Emissions from 
Compressor Rod Packing Systems. Natural Gas STAR Program. 2006.
---------------------------------------------------------------------------

    The elements of such a program include establishing a frequency of 
monitoring, identifying a threshold where action is required to reduce 
emissions, and specifying the action for reducing emissions. The option 
defined by the EPA and evaluated below is for annual monitoring and 
requiring the replacement of the rod packing if the measured flow rate 
for any individual cylinder exceeds 2 scfm. This threshold is 
consistent with California's regulation. However, this option differs 
from the California regulation in that it would require a complete 
replacement of the rod packing if this threshold is exceeded, where 
California allows repair sufficient to reduce the flow rate back below 
2 scfm. The 2 scfm flow rate threshold was established based on 
manufacturer guidelines indicating that a flow rate of 2 scfm or 
greater was considered indicative of rod packing failure.\283\
---------------------------------------------------------------------------

    \283\ State of California. Air Resources Board Public Hearing to 
Consider the Proposed Regulation for Greenhouse Gas Emission 
Standards for Crude Oil and Natural Gas Facilities. Staff Report: 
Initial Statement of Reasons. pgs. 96-97.
---------------------------------------------------------------------------

    We estimated the emission reductions from requiring annual flow 
rate monitoring and repair/replacement of packing when the measured 
flow rate exceeds 2 scfm total gas during pressurized operation. Based 
on California's background regulatory documentation, information 
provided to the State indicated that the average leak rate for those 
compressors emitting more than 2 scfm was about 3 scfm during 
pressurized operation, and less than 2 scfm during pressurized idle and 
unpressurized states. Therefore, we assumed that the leak rate for 
compressors emitting more than 2 scfm was about 3 scfm during 
pressurized operation. As indicated above for the fixed schedule rod 
packing replacement option, based on the 2011 NSPS OOOO TSD and 2016 
NSPS OOOOa TSD, the average emissions from a newly installed rod 
packing are assumed to be 11.5 scfh per cylinder.\284\ Using a ratio of 
0.829 methane: Total natural gas ratio, 3 scfm total gas is 
approximately 2.49 scfm (149.2 scfh) methane. This compressor emission 
rate, which was used for all industry segments, was converted to an 
annual mass emission rate by applying segment-specific pressurized 
factors, then converted to a mass basis.
---------------------------------------------------------------------------

    \284\ 2011 TSD, pg. 6-13.
---------------------------------------------------------------------------

    The estimated percent reduction in methane emissions that would be 
achievable from reducing 149.2 scfh methane/cylinder to 11.5 scfh 
methane/cylinder (average emissions from a newly installed rod packing/
cylinder) is 92 percent. We applied this percent reduction in methane 
emissions and estimated reciprocating compressor methane and VOC 
emission reductions that would be achieved from repairing/replacing rod 
packing based on the annual flow rate monitoring option. The 
calculations assume that all cylinders are emitting at 3 scfm, and that 
the rod packings for all compressor cylinders are replaced. This 
represents the emission reductions expected for the year in which the 
rod packings are replaced. Emissions would be expected to increase (and 
emission reductions decrease) in subsequent years until the next time 
the annual measurements require that the rod packing be replaced.
    The capital and annual costs of replacing the rod packings are the 
same as presented above for the fixed interval rod packing replacement 
option. In addition, this option would include the costs associated 
with the annual flow measurements. The estimated costs of this 
monitoring are based on the costs for annual flow rate monitoring under 
GHGRP subpart W for similar flow rate annual measurement requirements 
($597). The capital costs associated with replacing compressor rod 
packing would only occur in the year when packing is required to be 
replaced. The monitoring costs would be incurred every year.
    Additionally, the cost estimates assume that the packing of all 
compressor cylinders would need to be replaced (which is unlikely to be 
the case in many instances) and are therefore conservative estimates. 
Support information for the California rule cites data indicating that 
approximately 14 percent of compressors measurements indicated a leak 
rate of over 2 scfm per cylinder. Based on an average of 3.45 
cylinders/compressor, California assumed that the packing for 2 
cylinders/compressor would need to be replaced to come into compliance 
with the 2 scfm standard (57.9 percent).\285\
---------------------------------------------------------------------------

    \285\ Based on Appendix B. Economic Analysis. State of 
California. Air Resources Board. Proposed Regulation for Greenhouse 
Gas Emission Standards for Crude Oil and Natural Gas Facilities. pg. 
B-28. Notice Package for Oil and Gas Reg (ca.gov); State of 
California. Air Resources Public Hearing to Consider the Proposed 
Regulation for Greenhouse Gas Emission Standards for Crude Oil and 
Natural Gas Facilities. Staff Report: Initial Statement of Reasons. 
Date of Release: May 31, 2016. pg. 99.
---------------------------------------------------------------------------

    Using the single pollutant approach, where all the costs are 
assigned to the reduction of one pollutant, the cost effectiveness of 
the annual monitoring option is approximately $230 per ton of methane 
reduced for gathering and boosting ($40 per ton if gas savings are 
considered), $110 per ton of methane reduced for the processing segment 
(net savings if gas savings are considered), $100 per ton of methane 
reduced for the transmission segment, and $110 per ton of methane 
reduced for the storage segment. Using the multipollutant approach, 
where half the cost of control is assigned to the methane reduction and 
half to the VOC reduction, the cost effectiveness of replacement of the 
reciprocating rod packing based on the annual monitoring approach is 
approximately $110 per ton of methane reduced for gathering and 
boosting ($20 per ton if gas savings are considered), $50 per ton of 
methane reduced for the processing segment (net savings if gas savings 
are considered), $50 per ton of methane reduced for the transmission

[[Page 63219]]

segment, and $60 per ton of methane reduced for the storage segment.
    Using the single pollutant approach, where all the costs are 
assigned to the reduction of one pollutant, the VOC cost effectiveness 
of the annual monitoring option is approximately $810 per ton of VOC 
reduced for gathering and boosting ($160 per ton if gas savings are 
considered), $380 per ton of VOC reduced for the processing segment 
(net savings if gas savings are considered), $3,700 per ton of VOC 
reduced for the transmission segment, and $4,100 per ton of VOC reduced 
for the storage segment. Using the multipollutant approach, where half 
the cost of control is assigned to the methane reduction and half to 
the VOC reduction, the cost effectiveness of replacement of the 
reciprocating rod packing based on the annual monitoring approach is 
approximately $410 per ton of VOC reduced for gathering and boosting 
($80 per ton if gas savings are considered), $190 per ton of VOC 
reduced for the processing segment (net savings if gas savings are 
considered), $1,850 per ton of VOC reduced for the transmission 
segment, and $2,040 per ton of VOC reduced for the storage segment.
    We also assessed the incremental cost effectiveness of the annual 
monitoring option compared to the fixed 3-year/26,000 replacement 
schedule. Using the single pollutant approach, where all the costs are 
assigned to the reduction of one pollutant, the incremental cost 
effectiveness (without natural gas savings) from the fixed replacement 
option to the annual monitoring option for methane is approximately 
$130 per ton for gathering and boosting stations, $210 per ton for 
processing plants, $180 per ton for transmission stations, and $140 per 
ton for storage facilities. For VOC, the incremental cost effectiveness 
is approximately $480 per ton for gathering and boosting stations, $750 
per ton for processing plants, $6,600 per ton for transmission 
stations, and $5,150 per ton for storage facilities.
    The cost effectiveness of both options (fixed schedule and annual 
monitoring) are reasonable for methane and VOC using either the single 
pollutant or multipollutant approach. The incremental cost 
effectiveness in going from the fixed schedule option to the annual 
monitoring option is reasonable for all scenarios, with the exception 
of VOC for transmission stations. Therefore, based on the consideration 
of the costs in relation to the emission reductions, the EPA finds that 
the annual monitoring option is the most reasonable option.
    Further, as discussed above, California requires reciprocating 
compressor annual rod packing flow rate monitoring and repair and or 
replacement of the packing where flow rate monitoring indicates a 
measurement that exceeds 2 scfm. This further supports the 
reasonableness of a monitoring program.
    Neither the fixed schedule rod packing replacement option nor the 
rod packing replacement based on annual monitoring option would result 
in secondary emissions impacts as both options would reduce the escape 
of natural gas from the piston rod. No wastes would be created (other 
than the worn packing that is being replaced) and no wastewater would 
be generated. An advantage related to the replacement of rod packing 
for reciprocating compressors based on annual rod packing monitoring is 
that it would only require replacement of the rod packing where 
monitoring of the rod packing indicates wear and increasing flow rate/
emissions to unacceptable levels. This optimizes the output of capital 
expenditures to focus on emissions control where an increased emissions 
potential is identified.
    In light of the above we determined that annual rod pack flow rate 
monitoring and replacement of the packing where flow rate monitoring 
indicates a measurement that exceeds 2 scfm represents BSER for NSPS 
OOOOb for this proposal for all segments including reciprocating 
compressors located at centralized productions facilities (with the 
exception of compressors at stand-alone well sites). As in the 2016 
NSPS OOOOa, the EPA is proposing to allow the collection and routing of 
emissions to a process as an alternative standard because that option 
would achieve emission reductions equivalent to, or greater than, the 
proposed standard for NSPS OOOOb.
    The affected facility based on EPA's review would continue to be 
each reciprocating compressor not located at a well site, or an 
adjacent well site and servicing more than one well site. As discussed 
above, the EPA is proposing a new definition for a ``centralized 
production facility''. The EPA is proposing to define centralized 
production facilities separately from well sites because the number and 
size of equipment, particularly reciprocating and centrifugal 
compressors, is larger than standalone well sites which would not be 
included in the proposed definition of ``centralized production 
facilities''. Thus, the EPA is proposing that reciprocating compressors 
located at centralized production facilities would be subject to the 
standards in NSPS in OOOOb, but reciprocating compressors at well sites 
(standalone well sites) would not.
2. EG OOOOc
    The EPA evaluated BSER for the control of methane from existing 
reciprocating compressors (designated facilities) in all segments in 
the Crude Oil and Natural Gas source category covered by the proposed 
NSPS OOOOb and translated the degree of emission limitation achievable 
through application of the BSER into a proposed presumptive standard 
for these facilities that essentially mirrors the proposed NSPS OOOOb.
    First, based on the same criteria and reasoning as explained above, 
the EPA is proposing to define the designated facility in the context 
of existing reciprocating compressors as those that commenced 
construction on or before November 15, 2021. Based on information 
available to the EPA, we did not identify any factors specific to 
existing sources that would indicate that the EPA should alter this 
definition as applied to existing sources. Next, the EPA finds that the 
control measures evaluated for new sources for NSPS OOOOb are 
appropriate for consideration for existing sources under the EG OOOOc. 
The EPA finds no reason to evaluate different, or additional, control 
measures in the context of existing sources because the EPA is unaware 
of any control measures, or systems of emission reduction, for 
reciprocating compressors that could be used for existing sources but 
not for new sources. Next, the methane emission reductions expected to 
be achieved via application of the control measures identified above to 
new sources are also expected to be achieved by application of the same 
control measures to existing sources. The EPA finds no reason to 
believe that these calculations would differ for existing sources as 
compared to new sources because the EPA believes that the baseline 
emissions of an uncontrolled source are the same, or very similar, and 
the efficiency of the control measures are the same, or very similar, 
compared to the analysis above. This is also true with respect to the 
costs, non-air environmental impacts, energy impacts, and technical 
limitations discussed above for the control options identified.
    The EPA has not identified any costs associated with applying these 
controls at existing sources, such as retrofit costs, that would apply 
any differently than, or in addition to, those costs assessed above 
regarding application of the identified controls to new sources. The 
cost effectiveness values for the

[[Page 63220]]

proposed presumptive standard of replacement of the rod packing based 
on an annual monitoring threshold is approximately $230 per ton of 
methane reduced ($40 per ton if gas savings are considered) for the 
gathering and boosting segment (including reciprocating compressors 
located at centralized tank facilities), $110 per ton of methane 
reduced for the processing segment (net savings if gas savings are 
considered), $100 per ton of methane reduced for the transmission 
segment, and $110 per ton of methane reduced for the storage segment.
    In summary, the EPA did not identify any factors specific to 
existing sources, as opposed to new sources, that would alter the 
analysis above for the proposed NSPS OOOOb as applied to the designated 
pollutant (methane) and the designated facilities (reciprocating 
compressors). As a result, the proposed presumptive standard for 
existing reciprocating compressors is as follows.
    For reciprocating compressors in the gathering and boosting segment 
(including reciprocating compressors located at centralized tank 
facilities), processing, and transmission and storage segments, the 
presumptive standard is replacement of the rod packing based on an 
annual monitoring threshold. Specifically, the presumptive standard 
would require an owner or operator of a reciprocating compressor 
designated facility to monitor the rod packing flow rate annually. When 
the measured leak rate exceeds 2 scfm (in pressurized mode), the 
standard would require replacement of the rod packing. As an 
alternative, the presumptive standard would be routing rod packing 
emissions to a process via a closed vent system under negative 
pressure.

F. Proposed Standards for Centrifugal Compressors

1. NSPS OOOOb
a. Background
    The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each wet seal 
compressor not located at a well site, or an adjacent well site and 
servicing more than one well site. The 2016 NSPS OOOOa required methane 
and VOC emissions be reduced from each centrifugal compressor wet seal 
fluid degassing system by 95.0 percent. Compliance with this 
requirement allowed routing of emission from the wet seal fluid 
degassing system to a control device or to a process. Dry seal 
compressors were not subject to requirements under the 2016 NSPS OOOOa.
    In determining BSER for wet seal compressors in 2016, the EPA 
determined that the previous determination for NSPS OOOO conducted in 
2011/2012 still represented BSER for the control of VOC in 2016. In 
addition, the EPA determined that analogous control of methane 
represented BSER. In the 2012 determinations, the EPA conducted 
analyses of the cost and emission reductions of (1) requiring the 
conversion of a wet seal system to a dry seal system, and (2) routing 
to a control device or process. The 2011 NSPS OOOO rule (76 FR 52738, 
52755, August 23, 2011) proposed an equipment standard that would have 
required the use of dry seals to limit the VOC emissions from new 
centrifugal compressors. At that time, the EPA solicited comments on 
the emission reduction potential, cost, and any technical limitations 
for the option of routing the gas back to a low-pressure fuel stream to 
be combusted as fuel gas. In addition, in 2011 (76 FR 52738), the EPA 
solicited comments on whether there are situations or applications 
where a wet seal is the only option, because a dry seal system is 
infeasible or otherwise inappropriate. The EPA received information 
indicating that the integration of a centrifugal compressor into an 
operation may require a certain compressor size or design that is not 
available in a dry seal model, and in the case of capture of emissions 
with routing to a process, there may not be down-stream equipment 
capable of handling a low-pressure fuel source. In the final 2012 NSPS 
OOOO rule, the EPA made the determination that the replacement of wet 
seals with dry seals and routing to a process was not technically 
feasible or practical for some centrifugal compressors, and also that 
the costs per ton of emissions reduced were reasonable for routing 
emissions to a control device or process. No other more stringent 
control options were evaluated at that time. During the development of 
the 2016 NSPS OOOOa rule, the EPA reviewed available information on 
control options for wet seal compressors and did not identify any new 
information to indicate that this has changed.
    For this review, the EPA also focused on these control options. 
BSER was evaluated for wet-seal centrifugal compressors at gathering 
and boosting stations (considered to be representative of emissions 
from centrifugal compressors at centralized production facilities) in 
the production segment, at natural gas processing plants, and at sites 
in the transmission and storage segment. During the development of the 
2012 NSPS OOOO and 2016 NSPS OOOOa rulemakings, our data indicated that 
there were no centrifugal compressors located at well sites. Since the 
2012 NSPS OOOO and 2016 NSPS OOOOa rulemakings, we have not received 
information that would change our understanding that there are no 
centrifugal compressors in use at well sites.
    However, as discussed in section XI.L (Centralized Production 
Facilities) of this preamble, the EPA believes the definition of ``well 
site'' in NSPS OOOOa may cause confusion regarding whether centrifugal 
compressors located at centralized production facilities are also 
exempt from the standards. The EPA is proposing a new definition for a 
``centralized production facility''. The EPA is proposing to define 
centralized production facilities separately from well sites because 
the number and size of equipment, particularly reciprocating and 
centrifugal compressors, is larger than standalone well sites which 
would not be included in the proposed definition of ``centralized 
production facilities''. This proposal is necessary in the context of 
centrifugal compressors to distinguish between these compressors at 
centralized production facilities where the EPA has determined that the 
standard should apply, and compressors at standalone well sites where 
the EPA has determined that the standard should not apply. In our 
current analysis, described below, we consider the centrifugal 
compressor gathering and boosting segment emission factor as being 
representative of centrifugal compressor emissions located at 
centralized production facilities. As such, the EPA is proposing that 
centrifugal compressors located at centralized production facilities 
would be subject to the standards in NSPS OOOOb and the EG in subpart 
OOOOc, but centrifugal compressors at well sites (standalone well 
sites) would not.
    In addition to the requirement to reduce methane and VOC emissions 
from each centrifugal compressor wet seal fluid degassing system by 
95.0 percent, the 2016 NSPS OOOOa requires compressor components to be 
monitored as fugitive emissions components and leaks found are to be 
repaired under the fugitive emissions monitoring requirements of 40 CFR 
60.5397a. The monitoring frequency depends on source (i.e., well sites, 
compressor stations) and sector segment. These fugitive emissions 
components were not considered part of the centrifugal compressor 
affected facility.
    Based on the EPA's review of NSPS OOOOa, we are proposing that BSER 
continues to be that methane and VOC

[[Page 63221]]

emissions be reduced from each centrifugal compressor wet seal fluid 
degassing system by 95.0 percent.
b. Description
    Centrifugal compressors use a rotating disk or impeller to increase 
the velocity of the natural gas where it is directed to a divergent 
duct section that converts the velocity energy to pressure energy. 
These compressors are primarily used for continuous, stationary 
transport of natural gas in the processing and transmission systems. 
Some centrifugal compressors use wet (meaning oil) seals around the 
rotating shaft to prevent natural gas from escaping where the 
compressor shaft exits the compressor casing. The wet seals use oil 
which is circulated at high pressure to form a barrier against 
compressed natural gas leakage. The circulated oil entrains and adsorbs 
some compressed natural gas that may be released to the atmosphere 
during the seal oil recirculation process. Off gassing of entrained 
natural gas from wet seal centrifugal compressors is not suitable for 
sale and is either released to the atmosphere, flared, or routed back 
to a process.
    Some centrifugal compressors utilize dry seal systems. Dry seal 
systems minimize leakage by using the opposing force created by 
hydrodynamic grooves and springs. The hydrodynamic grooves are etched 
into the surface of the rotating ring affixed to the compressor shaft. 
When the compressor is not rotating, the stationary ring in the seal 
housing is pressed against the rotating ring by springs. When the 
compressor shaft rotates at high speed, compressed natural gas has only 
one pathway to leak down the shaft, and that is between the rotating 
and stationary rings. This natural gas is pumped between the grooves in 
the rotating and stationary rings. The opposing force of high-pressure 
natural gas pumped between the rings and springs trying to push the 
rings together creates a very thin gap between the rings through which 
little natural gas can leak. While the compressor is operating, the 
rings are not in contact with each other and, therefore, do not wear or 
need lubrication. O-rings seal the stationary rings in the seal case. 
Historically, the EPA has considered dry seal centrifugal compressors 
to be inherently low-emitting and has never required control of 
emissions from dry seal compressors. The EPA has received 
feedback,\286\ however, that there are some wet seal compressor system 
designs that are also low emitting when compared to dry seal 
compressors and is soliciting comment on lower emitting wet seal 
compressor system designs and dry seal compressor emissions in this 
proposed action.
---------------------------------------------------------------------------

    \286\ Conference Call. Prepared by Tora Consulting. December 19, 
2018.
---------------------------------------------------------------------------

    The 2021 U.S. GHGI estimates over 166,700 metric tpy of methane 
emissions in 2019 from compressors from natural gas systems. For the 
natural gas processing and transmission segments, wet seal compressor 
methane emissions are estimated to be about 78,700 metric tons and dry 
seal compressor methane estimated emissions are estimated to be about 
88,000 metric tons.\287\ The wet seal and dry seal compressor methane 
emission estimates reflect the increasing prevalence of the use of dry 
seals over wet seals and emissions control requirements that require 
the control of emissions from wet seal compressors. The methane 
emissions from centrifugal compressors represent 3 percent of the total 
methane emissions from natural gas systems in the Oil and Natural Gas 
Industry sector.
---------------------------------------------------------------------------

    \287\ U.S. Environmental Protection Agency. Inventory of U.S. 
Greenhouse Gas Emissions and Sinks (1990-2019). Published in 2021. 
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019.
---------------------------------------------------------------------------

c. Affected Facility
    For purposes of the NSPS, the centrifugal compressor affected 
facility is a single centrifugal compressor using wet seals. A 
centrifugal compressor located at a well site, or an adjacent well site 
and servicing more than one well site, is not an affected facility 
under the proposed rule for NSPS OOOOb. As discussed above, the EPA is 
proposing that the affected facility includes centrifugal compressors 
located at centralized production facilities and the affected facility 
exception for ``a well site, or an adjacent well site servicing more 
than one well site'' applies to standalone well sites and not 
centralized production facilities.
d. 2021 BSER Analysis
    The methodology we used for estimating emissions from compressors 
is consistent with the methodology developed for the 2012 NSPS OOOO 
BSER analysis, which was also used to support the 2016 NSPS OOOOa 
BSER.\288\ The wet-seal centrifugal compressor methane uncontrolled 
emission factors are based on the volumetric emission factors used for 
the GHGI, which were converted to a mass emission rate using a density 
of 41.63 pounds of methane per thousand cubic feet. The VOC emissions 
were calculated using the ratio of 0.278 pounds VOC per pound of 
methane for the production and processing segments, and 0.0277 pounds 
VOC per pound of methane for the transmission and storage segment. The 
resulting baseline uncontrolled emissions per centrifugal compressor 
are 157 tpy methane (43.5 tpy VOC) from wet-seal compressors at 
gathering and boosting sites, 211 tpy methane (58.7 tpy VOC) from wet-
seal compressors at natural gas processing plants, 157 tpy methane (4.3 
tpy VOC) from wet-seal compressors at transmission compressor stations, 
and 117 (3.24 tpy VOC) from wet-seal compressors at storage facilities. 
Since the emission factors for dry seal compressors are approximately 
lower than wet seal compressors,\289\ the EPA considered requiring dry 
seals as a replacement to wet seals as a control option in 2011. The 
EPA proposed dry seals as a replacement to wet seals to control VOC 
emissions at that time. Based on comments received on the proposal that 
dry seal compressors were not feasible in all instances based on costs 
and technical reasons, the EPA did not finalize the proposal that dry 
seal compressors represented BSER. Instead, the EPA separately 
evaluated the control options for wet seal compressors (77 FR 49499-
49500, 49523, August 16, 2012). In the 2015 NSPS OOOOa proposed rule, 
the EPA maintained that available information since the 2012 NSPS OOOO 
rule continued to show that dry seal compressors cannot be use in all 
circumstances. The EPA has not identified any new information since 
that time that indicates that dry seal compressors as a replacement for 
wet seal compressors is technically feasible in all circumstances. 
Thus, we did not evaluate the replacement of a wet seal system with a 
dry seal system as BSER for controlling emissions from wet seal systems 
for the NSPS OOOOb proposal.
---------------------------------------------------------------------------

    \288\ 2011 NSPS OOOO TSD, section 6.2.2; 2016 NSPS OOOOa TSD, 
section 7.2.2.
    \289\ 2011 NSPS OOOO TSD, Table 6-2, pg. 6-4; 2016 NSPS OOOOa 
TSD, Table 7-2, pg. 104.
---------------------------------------------------------------------------

    In addition to soliciting comment and information on lower-emitting 
wet seal compressor designs (that emit less than dry seal compressors), 
the EPA is soliciting information on dry seal compressor emissions. 
Feedback received (noted above) on lower emitting wet seal compressor 
designs included concern that lower emitting wet seal systems were 
being replaced by higher emitting (but still low emitting) dry seal 
systems because they were not subject to the NSPS. Given that the trend 
has been that wet seal compressor systems are increasingly being 
replaced by dry seal compressor systems, the EPA solicits comments on 
dry seal compressor emissions and whether/and

[[Page 63222]]

to what degree operational or malfunctioning conditions (e.g., low seal 
gas pressure, contamination of the seal gas, lack of supply of 
separation gas, mechanical failure) have the potential to impact 
methane and VOC emissions. The EPA also solicits comment on whether 
owners and operators implement standard operating procedures to 
identify and correct operational or malfunction conditions that have 
the potential to increase emissions from dry seal systems. Finally, the 
EPA solicits comments on whether we should consider evaluating BSER and 
developing NSPS standards for dry seal compressors.
    The control options to reduce emissions from centrifugal 
compressors evaluated include control techniques that reduce emissions 
from leaking of natural gas from wet seal compressors by capturing 
leaking gas and route it either to (1) a control device (combustion 
device), or (2) to the process. We evaluated the costs and impacts of 
both of these options.
    Combustion devices are commonly used in the Crude Oil and Natural 
Gas Industry to combust methane and VOC emission streams. Combustors 
are used to control VOC and methane emissions in many industrial 
settings, since the combustor can normally handle fluctuations in 
concentration, flow rate, heating value and inert species content.\290\ 
A combustion device generally achieves 95 percent reduction of methane 
and VOC when operated according to the manufacturer instructions. For 
this analysis, we assumed that the entrained natural gas from the seal 
oil that is removed in the degassing process would be directed to a 
combustion device that achieves a 95 percent reduction of methane and 
VOC emissions. This option was determined to be BSER under the 2011 
NSPS OOOO (77 FR 49490, August 16, 2012) and 2016 NSPS OOOOa rules. The 
combustion of the recovered gas creates secondary emissions of 
hydrocarbons (NOX, CO2, and CO emissions). 
Routing the captured gas from the centrifugal compressor wet seal 
degassing system to a combustion device has associated capital and 
operating costs.
---------------------------------------------------------------------------

    \290\ U.S. Environmental Protection Agency. AP 42, Fifth 
Edition, Volume I, Chapter 13.5 Industrial Flares. Office of Air 
Quality Planning & Standards. 1991.
---------------------------------------------------------------------------

    The capital and annual costs for the installation of a combustion 
device (an enclosed flare for the analysis) were calculated using the 
methodology in the EPA Control Cost Manual.\291\ The capital costs of a 
flare and the equipment (closed vent system) necessary to route 
emissions to the flare are based on costs from the 2011 NSPS OOOO TSD 
and 2016 NSPS OOOOa TSD. These costs were updated to 2019 dollars. The 
updated capital costs of $80,930 were annualized at 7 percent based on 
an equipment life of 10 years. The total annualized capital costs were 
estimated to be $11,520. The annual operating costs are also based on 
the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD. These costs were 
updated to 2019 dollars. The 2019 annual operating costs were estimated 
to be $117,160. The combined annualized capital and operating costs per 
compressor per year is an estimated $128,680. There is no cost savings 
estimated for this option because the recovered natural gas is 
combusted. The costs presented for gathering and boosting segment 
centrifugal compressors represent the estimated costs assumed for 
centrifugal compressors located at centralized production facilities.
---------------------------------------------------------------------------

    \291\ U.S. Environmental Protection Agency. OAQPS Control Cost 
Manual: Sixth Edition (EPA 452/B-02-001). Research Triangle Park, 
NC.
---------------------------------------------------------------------------

    Using the single pollutant approach, where all the costs are 
assigned to the reduction of one pollutant, the cost effectiveness of 
routing emissions from a wet seal system to a new flare for methane 
emissions is $870 per ton of methane reduced for the transmission 
segment and gathering and boosting, $640 per ton of methane reduced for 
the processing segment, and $1,160 per ton of methane reduced for the 
storage segment. Using the multipollutant approach, where half the cost 
of control is assigned to the methane reduction and half to the VOC 
reduction, the cost effectiveness of routing emissions from a wet seal 
system to a new flare for methane emissions is $430 per ton of methane 
reduced for the transmission segment and gathering and boosting, $320 
per ton of methane reduced for the processing segment, and $580 per ton 
of methane reduced for the storage segment.
    Using the single-pollutant approach, where all the costs are 
assigned to the reduction of one pollutant, the cost effectiveness of 
routing emissions from a wet seal system to a new flare for VOC 
emissions is $3,100 per ton of VOC reduced for gathering and boosting, 
$2,300 per ton of VOC reduced for the processing segment, $31,200 per 
ton of VOC reduced for the transmission segment, and $41,800 per ton of 
VOC reduced for the storage segment. Using the multipollutant approach, 
where half the cost of control is assigned to the methane reduction and 
half to the VOC reduction, the cost effectiveness of routing emissions 
from a wet seal system to a new flare for VOC emissions is $1,600 per 
ton of VOC reduced for gathering and boosting, $1,200 per ton of VOC 
reduced for the processing segment, $15,600 per ton of VOC reduced for 
the transmission segment, and $20,900 per ton of VOC reduced for the 
storage segment.
    In addition to an owner or operator having the option to capture 
emissions and routing to a new combustion control device, a less costly 
option that may be available could be for owners and operators to 
capture and route emissions to a combustion control device installed 
for another source (e.g., a control device that is already on site to 
control emissions from another emissions source). The costs, which are 
provided in the NSPS OOOOb and EG TSD for this rulemaking, would be for 
the ductwork to capture the emissions and route them to the control 
device. The analysis assumes that the combustion control device on site 
achieves a 95 percent reduction in emissions of methane and VOC.
    Another option for reducing methane and VOC emissions from the 
compressor wet seal fluid degassing system is to route the captured 
emissions back to the compressor suction or fuel system, or other 
beneficial use (referred to collectively as routing to a process). 
Routing to a process would entail routing emissions via a closed vent 
system to any enclosed portion of a process unit (e.g., compressor or 
fuel gas system) where the emissions are predominantly recycled, 
consumed in the same manner as a material that fulfills the same 
function in the process, transformed by chemical reaction into 
materials that are not regulated materials, incorporated into a 
product, or recovered. Emissions that are routed to a process are 
assumed to result in the same or greater emission reductions as would 
have been achieved had the emissions been routed through a closed vent 
system to a combustion device.\292\ For purposes of this analysis, we 
assumed that routing methane and VOC emissions from a wet seal fluid 
degassing system to a process reduces VOC emissions greater than or 
equal to a combustion device (i.e., greater than or equal to 95 
percent). There are no secondary impacts with the option to control 
emissions from centrifugal wet seals by capturing gas and routing to 
the process.
---------------------------------------------------------------------------

    \292\ U.S. Environmental Protection Agency. Control Techniques 
Guidelines for the Oil and Natural Gas Industry. Office of Air 
Quality Planning and Standards, Sector Policies and Programs 
Division. October 2016. EPA-453/B-16-001. (2016 CTG). pgs. 5-19 to 
5-20.

---------------------------------------------------------------------------

[[Page 63223]]

    The capital cost of a system to route the seal oil degassing system 
to a process is estimated to be $26,210 ($2,019),\293\ The estimated 
costs include an intermediate pressure degassing drum, new piping, gas 
demister/filter, and a pressure regulator for the fuel line. The annual 
costs were estimated to be $2,880 (without savings) assuming a 15-year 
equipment life at 7 percent interest. Because the natural gas is not 
lost or combusted, the value of the natural gas represents a savings to 
owners and operators in the production (gathering and boosting) and 
processing segments. Savings were estimated using a natural gas price 
of $3.13 per Mcf, which resulted in annual savings of $27,000 per year 
at gathering and boosting stations and $36,400 per year at processing 
plants. The annual cost savings are much greater than the annual costs, 
which results in an overall savings when they are considered.
---------------------------------------------------------------------------

    \293\ 2011 NSPS OOOO TSD, pg. 114; 2016 CTG, pg. 5-20.
---------------------------------------------------------------------------

    Using the single pollutant approach, where all the costs are 
assigned to the reduction of one pollutant, the cost effectiveness 
(without natural gas savings) of routing emissions from a wet seal 
system to a process for methane emissions is approximately $19 per ton 
of methane reduced for the transmission segment and gathering and 
boosting, $14 per ton of methane reduced for the processing segment, 
and $26 per ton of methane reduced for the storage segment. Using the 
multipollutant approach, where half the cost of control is assigned to 
the methane reduction and half to the VOC reduction, the cost 
effectiveness (without natural gas savings) of routing emissions from a 
wet seal system to a process for methane emissions is approximately $10 
per ton of methane reduced for the transmission segment and gathering 
and boosting, $7 per ton of methane reduced for the processing segment, 
and $13 per ton of methane reduced for the storage segment. As noted 
above, there is an overall net savings if the value of the natural gas 
recovered is considered.
    Using the single pollutant approach, where all the costs are 
assigned to the reduction of one pollutant, the cost effectiveness 
(without natural gas savings) of routing emissions from a wet seal 
system to a process for VOC emissions is approximately $70 per ton of 
VOC reduced for gathering and boosting, $50 per ton of VOC reduced for 
the processing segment, $700 per ton of VOC reduced for the 
transmission segment, and $940 per ton of VOC reduced for the storage 
segment. Using the multipollutant approach, where half the cost of 
control is assigned to the methane reduction and half to the VOC 
reduction, the cost effectiveness (without natural gas savings) of 
routing emissions from a wet seal system to a process for VOC emissions 
is approximately $35 per ton of VOC reduced for gathering and boosting, 
$26 per ton of VOC reduced for the processing segment, $350 per ton of 
VOC reduced for the transmission segment, and $470 per ton of VOC 
reduced for the storage segment. As noted above, there is an overall 
net savings if the value of the natural gas recovered is considered.
    The cost effectiveness of both options (routing emissions to a 
combustion device or to a process) are reasonable for methane for all 
of the evaluated segments, using both the single pollutant and 
multipollutant approaches. The cost effectiveness of routing emissions 
to a process are also reasonable for VOC for all of the evaluated 
segments, using both the single pollutant and multipollutant 
approaches. For routing emissions to a combustion device, the cost 
effectiveness is reasonable for the gathering and boosting and 
processing segments using the single pollutant and multipollutant 
approaches. Based on the consideration of the costs in relation to the 
emission reductions of both methane and VOC, the EPA finds that 
requiring emissions to be reduced from each centrifugal compressor 
using a wet seal by at least 95 percent (which can be achieved by 
either option) continues to be reasonable in the gathering and boosting 
(considered to be representative of emissions/costs from centrifugal 
compressors at centralized production facilities). processing, 
transmission and storage segments.
    The 2012 NSPS OOOO and the 2016 NSPS OOOOa require emissions be 
reduced from each centrifugal compressor wet seal fluid degassing 
system by at least 95.0 percent by routing emissions to a control 
device or to a process. States have generally adopted/incorporated this 
NSPS level of control (or a level of control that is substantially 
similar) in their State regulations for the control of emissions from 
centrifugal compressor sources using wet seals. Owners and operators 
have successfully met this standard for almost a decade. These facts 
further demonstrate the reasonableness of this level of control. In the 
discussion above, we reviewed two options to reduce emissions from wet 
seal compressors that are both current regulatory options under the 
2016 NSPS OOOOa: (1) Capturing leaking gas and route to a combustion 
device (flare), or (2) capturing leaking gas and route to the process. 
Under the 2016 NSPS OOOOa, the level of control determined based on 
BSER was that methane and VOC emissions be reduced from each 
centrifugal compressor wet seal fluid degassing system by 95 percent or 
greater. The EPA has not identified any other control options or any 
other Federal, State, or local requirements that would achieve a 
greater reduction in methane and VOC emissions from centrifugal 
compressor wet seal systems. Although capturing leaking gas and routing 
to the process has the advantage of both reducing emissions by at least 
95 percent or greater and capturing the natural gas (resulting in a 
natural gas savings), the EPA has received feedback in the development 
of the 2012 NSPS OOOO rule that this option may not be a viable option 
in situations where there may not be down-stream equipment capable of 
handling a low-pressure fuel source. During the development of the 2016 
NSPS OOOOa rule, the EPA reaffirmed that information since the 
development of the 2012 NSPS OOOO rule continues to show that capturing 
leaking gas and routing to the process cannot be used in all 
circumstances. No new information has been identified since the 
development of the 2016 NSPS OOOOa rule to indicate that capturing 
leaking gas and routing to the process can be achieved in all 
circumstances (80 FR 56619, September 18, 2015). Thus, by establishing 
a 95 percent methane and VOC emissions control level as BSER, an owner 
or operator has the option of routing emissions to a process where it 
is a viable option, or to a combustion device where routing to a 
process is not a viable option. If an owner or operator chooses to 
route to a process to meet the 95 percent level of control, there are 
no secondary impacts. If an owner or operator chooses to route to a 
combustion device to meet the 95 percent level of control, the 
combustion of the recovered gas creates secondary emissions of 
hydrocarbons (NOX, CO2, and CO emissions).
    The costs, emission reductions, and cost effectiveness values were 
presented above for collecting the wet seal compressor emissions and 
routing them to both a combustion device and to a process to achieve at 
least a 95 percent control. The EPA considers the cost effectiveness of 
both of these control options reasonable across all segments evaluated 
(i.e., the gathering and boosting portion of production, processing, 
transmission, storage) for the reduction of methane emissions under the 
single pollutant approach and multipollutant approach. As discussed

[[Page 63224]]

above, in our current analysis, we consider the centrifugal compressor 
gathering and boosting segment emission factor as being representative 
of centrifugal compressor emissions located at centralized production 
facilities. Thus, the cost analysis performed for the gathering and 
boosting segment represents the estimated costs of evaluated options 
for centrifugal compressors with wet seals located at centralized 
storage facilities.
    In light of the above, we determined that reducing methane and VOC 
emissions from each centrifugal compressor wet seal fluid degassing 
system by 95 percent or greater continues to represent BSER for NSPS 
OOOOb for this proposal. The affected facility based on EPA's review 
would continue be each wet seal compressor not located at a well site, 
or an adjacent well site and servicing more than one well site. As 
discussed above, the EPA is proposing a new definition for a 
``centralized production facility''. The EPA is proposing to define 
centralized production facilities separately from well sites because 
the number and size of equipment, particularly reciprocating and 
centrifugal compressors, is larger than standalone well sites which 
would not be included in the proposed definition of ``centralized 
production facilities''. Thus, the EPA is proposing that centrifugal 
compressors located at centralized production facilities would be 
subject to the standards in the NSPS in OOOOb, but centrifugal 
compressors at well sites (standalone well sites) would not.
2. EG OOOOc
    The EPA evaluated BSER for the control of methane from existing 
centrifugal compressors using wet seals (not located at a well site, or 
an adjacent well site and servicing more than one well site) 
(designated facilities) in all segments in the Crude Oil and Natural 
Gas source category covered by the proposed NSPS OOOOb and translated 
the degree of emission limitation achievable through application of the 
BSER into a proposed presumptive standard for these facilities that 
essentially mirrors the proposed NSPS OOOOb.
    First, based on the same criteria and reasoning as explained above, 
the EPA is proposing to define the designated facility in the context 
of existing centrifugal compressors using wet seals (not located at a 
well site, or an adjacent well site and servicing more than one well 
site) as those that commenced construction on or before November 15, 
2021. Based on information available to the EPA, we did not identify 
any factors specific to existing sources that would indicate that the 
EPA should alter this definition as applied to existing sources. Next, 
the EPA finds that the control measures evaluated for new sources for 
NSPS OOOOb are appropriate for consideration for existing sources under 
the EG OOOOc. The EPA finds no reason to evaluate different, or 
additional, control measures in the context of existing sources because 
the EPA is unaware of any control measures, or systems of emission 
reduction, for centrifugal compressors that could be used for existing 
sources but not for new sources. Next, the methane emission reductions 
expected to be achieved via application of the control measures 
identified above to new sources are also expected to be achieved by 
application of the same control measures to existing sources. The EPA 
finds no reason to believe that these calculations would differ for 
existing sources as compared to new sources because the EPA believes 
that the baseline emissions of an uncontrolled source are the same, or 
very similar, and the efficiency of the control measures are the same, 
or very similar, compared to the analysis above. This is also true with 
respect to the costs, non-air environmental impacts, energy impacts, 
and technical limitations discussed above for the control options 
identified.
    The EPA has not identified any costs associated with applying these 
controls at existing sources, such as retrofit costs, that would apply 
any differently than, or in addition to, those costs assessed above 
regarding application of the identified controls to new sources. The 
cost effectiveness values for the proposed presumptive standard of 
reducing methane emissions from each centrifugal compressor wet seal 
fluid degassing system by 95 percent or greater are based on the cost 
effectiveness of routing emissions from a wet seal system to a flare or 
to a process. The cost effectiveness of routing emissions from a wet 
seal system to a new flare for methane emissions is $870 per ton of 
methane reduced for the transmission segment and gathering and 
boosting, $640 per ton of methane reduced for the processing segment, 
and $1,160 per ton of methane reduced for the storage segment. The cost 
effectiveness (without natural gas savings) of routing emissions from a 
wet seal system to a process for methane emissions is approximately $19 
per ton of methane reduced for the transmission segment and gathering 
and boosting, $14 per ton of methane reduced for the processing 
segment, and $26 per ton of methane reduced for the storage segment.
    In summary, the EPA did not identify any factors specific to 
existing sources, as opposed to new sources, that would alter the 
analysis above for the proposed NSPS OOOOb as applied to the designated 
pollutant (methane) and the designated facilities (centrifugal 
compressors using wet seals). As a result, the proposed presumptive 
standard for existing centrifugal compressors using wet seals is as 
follows.
    For centrifugal compressors using wet seals in the gathering and 
boosting segment (including centrifugal compressors using wet seals 
located at centralized tank facilities), processing, and transmission 
and storage segments, the presumptive standard is to reduce methane 
emissions by at least 95 percent. An owner or operator can meet this 
presumptive standard by routing methane emissions to a control device 
or process that reduces emissions by at least 95 percent. As discussed 
previously, the EPA is proposing a new definition for a ``centralized 
production facility''. The EPA is proposing to define centralized 
production facilities separately from well sites because the number and 
size of equipment, particularly reciprocating and centrifugal 
compressors, is larger than standalone well sites which would not be 
included in the proposed definition of ``centralized production 
facilities''. Thus, the EPA is proposing that centrifugal compressors 
located at centralized production facilities would be subject to the 
standards in the EG in OOOOc, but centrifugal compressors at well sites 
(standalone well sites) would not.

G. Proposed Standards for Pneumatic Pumps

1. NSPS OOOOb
a. Background
    In the 2016 NSPS OOOOa, the EPA established GHG (in the form of 
limitations on methane emissions) and VOC standards for natural gas-
driven diaphragm pneumatic pumps located at well sites. This standard 
required that natural gas emissions be reduced by 95.0 percent by 
routing to an existing control device if: (1) A control device was 
onsite, (2) the control device could achieve a 95.0 percent reduction, 
and (3) it was technically feasible to route the emissions to the 
control device. The standard did not require the installation of a 
control device solely for the purpose of complying with the 95.0 
percent reduction for the emissions from pneumatic pumps. It also 
allowed

[[Page 63225]]

the option of routing emissions to a process. At natural gas processing 
plants, the EPA established a standard that required a natural gas 
emission rate of zero (i.e., that prohibited methane and VOC emissions 
from pneumatic pumps).
    As a result of the review of these requirements and the previous 
BSER determination, the EPA is proposing methane and VOC standards in 
NSPS OOOOb for natural gas-driven pneumatic pumps located in all 
segments of the source category. Specifically, the EPA is proposing 
that each natural gas driven pneumatic pump is an affected facility. 
The EPA is proposing that methane and VOC emissions from natural gas-
driven diaphragm and piston pumps at well sites and all other sites in 
the production segment be reduced by 95.0 percent or routed to a 
process, provided that there is an existing control device onsite or it 
is technically feasible to route the emissions to a process. For 
natural gas driven pneumatic pumps at natural gas transmission stations 
and natural gas storage facilities, the same requirement applies, but 
only to diaphragm pumps. The EPA is proposing to retain the technical 
infeasibility provisions of NSPS OOOOa for purposes of NSPS OOOOb. If 
there is a control device onsite,\294\ the owner or operator is not 
required to route emissions to that control device if it is not 
technically feasible to do so, even for new construction sites which 
the EPA had previously referred to as ``greenfield'' sites. The EPA is 
also proposing to retain in NSPS OOOOb the exception to the 95.0 
percent reduction requirement if there is a control device onsite that 
it is technically feasible to route to that cannot achieve that level 
of reduction but can achieve a lower level of reductions. In those 
situations, the emissions from the pump are still to be routed to the 
control device and controlled at the level that the device can achieve. 
The EPA is also proposing a prohibition on methane and VOC emissions 
from pneumatic pumps (diaphragm and piston pumps) at natural gas 
processing plants. While zero emissions pneumatic pumps would not 
technically be affected facilities because they are not driven by 
natural gas, owners and operators should maintain documentation if they 
would like to be able to demonstrate to permit writers or enforcement 
officials that there are no methane or VOC emissions from the pumps and 
that these pumps are not affected facilities subject to the rule.
---------------------------------------------------------------------------

    \294\ For the same reasons discussed in section X.B.2, the EPA 
is proposing that boilers and process heaters are not control 
devises for purposes of controlling emissions from pneumatic pumps.
---------------------------------------------------------------------------

    This BSER for reducing methane and VOC from pneumatic pumps are the 
same as those for the 2016 NSPS OOOOa, except that (1) the EPA 
determined that the NSPS OOOOa levels of control also represent BSER 
for diaphragm pumps at all sites in the production segment (including 
gathering and boosting stations), and for all transmission and storage 
sites, and (2) the EPA determined that the NSPS OOOOa levels of control 
also represent BSER for piston pumps (in addition to diaphragm pumps) 
in the production segment and at natural gas processing plants.
    As discussed below, a primary reason that the EPA is unable to 
conclude that requiring a natural gas emission rate of zero for 
production and transmission and storage facilities is BSER at this time 
is because proven technologies that eliminate natural gas emissions 
rely on electricity to function. In contrast to pneumatic controllers, 
our review of information that has become available since the 
promulgation of the 2016 NSPS OOOOa standards, including State-level 
regulations for pneumatic pumps, does not demonstrate that zero 
emission technology for pneumatic pumps would be feasible at sites that 
lack access to onsite power. The EPA is specifically soliciting 
comments on the possibility of subcategorizing production and natural 
gas transmission and storage sites into those sites that have access to 
onsite power and those that do not, and then determining BSER 
separately for each subcategory. Further, the EPA is soliciting comment 
on how, if at all, the proposed NSPS OOOOb standards for pneumatic 
controllers might factor into how the EPA ought to evaluate the 
possibility of requiring a natural gas emission rate of zero for 
pneumatic pumps in the production and transmission and storage 
segments. For example, if a site installs a solar-powered system to 
operate their controllers, then could that same system provide power to 
the pumps such that all pumps at the site could have zero emissions of 
natural gas?
b. Description
    A pneumatic pump is a positive displacement reciprocating unit 
generally used by the Oil and Natural Gas Industry for one of four 
purposes: (1) Hot oil circulation for heat tracing/freeze protection, 
(2) chemical injection, (3) moving bulk liquids, and (4) glycol 
circulation in dehydrators. There are two basic types of pneumatic 
pumps used in the Oil and Natural Gas Industry, diaphragm pumps and 
piston pumps. Pumps used for heat tracing/freeze protection circulate 
hot glycol or other heat-transfer fluids in tubing covered with 
insulation to prevent freezing in pipelines, vessels and tanks. These 
heat tracing/freeze protection pumps are usually diaphragm pumps. 
Chemical injection pumps are designed to inject precise amounts of 
chemical into a process stream to regulate operations of a plant and 
protect the equipment. Typical chemicals injected in an oil or gas 
field are biocides, demulsifiers, clarifiers, corrosion inhibitors, 
scale inhibitors, hydrate inhibitors, paraffin dewaxers, surfactants, 
oxygen scavengers, and H2S scavengers. These chemicals are 
normally injected at the wellhead and into gathering lines or at 
production separation facilities. Since the injection rates are 
typically small, the pumps are also small. They are often attached to 
barrels containing the chemical being injected. These chemical 
injection pumps are primarily piston pumps, although they can be small 
diaphragm pumps. Examples of the use of pneumatic pumps to transfer 
bulk liquids at oil and natural gas production sites include pumping 
motor oil or pumping out sumps. Pumps used for these purposes ae 
typically diaphragm pumps.
    Glycol dehydrator pumps recover energy from the high-pressure rich 
glycol/gas mixture leaving the absorber and use that energy to pump the 
low-pressure lean glycol back into the absorber. Glycol dehydrator 
pumps are controlled under the oil and gas NESHAPs (40 CFR part 63, 
subparts HH and HHH), are not included as affected facilities for the 
2016 NSPS OOOOa and were not included in the review for proposed NSPS 
OOOOb.
    Both diaphragm and piston pumps are positive displacement 
reciprocating pumps, meaning they use contracting and expanding 
cavities to move fluids. These pumps work by allowing a fluid (e.g., 
the heat transfer fluid, demulsifier, corrosion inhibitor, etc) to flow 
into an enclosed cavity from a low-pressure source, trapping the fluid, 
and then forcing it out into a high-pressure receiver by decreasing the 
volume of the cavity. The piston and diaphragm pumps have two major 
components, a driver side and a motive side, which operate in the same 
manner but with different reciprocating mechanisms. Pressurized gas 
provides energy to the driver side of the pump, which operates a piston 
or flexible diaphragm to draw fluid into the pump. The motive side of 
the pump delivers the energy to the fluid being moved in order to 
discharge

[[Page 63226]]

the fluid from the pump. The natural gas leaving the exhaust port of 
the pump is either directly discharged into the atmosphere or is 
recovered and used as a fuel gas or stripping gas.
    Diaphragm pumps work by flexing the diaphragm out of the 
displacement chamber, and piston pumps typically include plunger pumps 
with a large piston on the gas end and a smaller piston on the liquid 
end to enable a high discharge pressure with a varied but much lower 
pneumatic supply gas pressure.
    As noted above, energy is supplied to the driver side of the pump 
to operate the piston or diaphragm. Commonly, this energy is provided 
by pressurized gas. This gas can be compressed air, or ``instrument 
air,'' provided by an electrically powered air compressor. In many 
situations across all segments of this industry, electricity is not 
available, and this energy is provided by pressurized natural gas 
(i.e., ``natural gas-driven pneumatic pumps''). This energy can also be 
directly provided by electricity.
    Natural gas-driven pneumatic pumps emit methane and VOC as part of 
their normal operation. These emissions occur when the gas used in the 
pump stroke is exhausted to enable liquid filling of the liquid cavity 
of the pump. Emissions are a function of the amount of fluid pumped, 
the pressure of the pneumatic supply gas, the number of pressure ratios 
between the pneumatic supply gas pressure and the fluid discharge 
pressure, and the mechanical inefficiency of the pump.
    The 2021 U.S. GHGI estimates almost 215,000 metric tpy of methane 
emissions from pneumatic pumps in the oil and natural gas production 
segment in 2019. Specifically, this includes almost 113,000 metric tpy 
from natural gas production, 75,000 from petroleum production, and 
26,000 from gathering and boosting compressor stations. These emissions 
make up 5 percent of all methane emissions in the GHGI for the combined 
gas and oil production segment, and 2 percent of all methane emissions 
for gathering and boosting. The overall total, which represents 3 
percent of the total methane emissions from this industry, does not 
include emissions from the processing, transmission, and storage 
segments which the EPA is now proposing to regulate under NSPS OOOOb.
c. 2021 BSER Analysis
    BSER was evaluated for all segments of the industry. The 2015 NSPS 
OOOOa proposal included methane and VOC standards for pneumatic pumps 
in the production and transmission and storage segments. However, the 
EPA did not finalize regulations for pneumatic pumps at gathering and 
boosting stations in the final 2016 NSPS OOOOa due to lack of data on 
the prevalence of the use of pneumatic pumps at gathering and boosting 
stations. Since that time, GHGRP subpart W has required that emissions 
from natural gas-driven pneumatic pumps be reported from gathering and 
boosting stations. As reported above, the 2021 GHGI estimates over 
26,000 metric tpy of methane emissions from these pumps in the 
gathering and boosting segment in 2019. Similarly, the EPA did not 
include pneumatic pumps in the transmission and storage segment in the 
final 2016 NSPS OOOOa because we did not have a reliable source of 
information indicating the prevalence of pneumatic pumps or their 
emission rates in the transmission and storage segment. While the GHGI 
does not include emissions from pneumatic pumps in the transmission and 
storage segment, and the GHGRP does not require the reporting of 
emissions from these pumps in this segment, State rules (notably the 
California rule and the proposed New Mexico rule) do include 
requirements for natural gas driven pneumatic pumps at transmission and 
storage facilities. The EPA is soliciting comment on whether natural 
gas driven pneumatic pumps are used in the natural gas transmission and 
storage segment and to what extent.
    In 2015, the EPA identified several options for reducing methane 
and VOC emissions from natural gas-driven pumps in the production and 
natural gas transmission and storage segments: Replace natural gas-
driven pumps with instrument air pumps, replace natural gas-driven 
pumps with solar-powered direct current pumps (solar pumps), replace 
natural gas-driven pumps with electric pumps, route natural gas-driven 
pump emissions to a control device, and route natural gas-driven pump 
emissions to a process. The only option identified in 2015 and analyzed 
at natural gas processing plants was the use of instrument air. The EPA 
re-evaluated that information as well as new information including 
updated GHGI and GHGRP information, as well as information from more 
recent State regulations. No additional options were identified at this 
time. Therefore, for this analysis for the NSPS, the EPA re-evaluated 
these options as BSER. In the discussion below, the options to require 
technology that would eliminate methane and VOC emissions by requiring 
the use of a non-natural gas driven pumps are discussed, followed by a 
discussion of routing natural gas driven pumps to a control device.
    With the exception of the evaluation of instrument air systems, the 
BSER analysis for pneumatic pumps was conducted on an individual pump 
basis. Due to the differences in the level of emissions, we conducted 
the BSER analysis separately for natural gas-driven diaphragm pneumatic 
pumps and natural gas-driven piston pneumatic pumps for the production 
and transmission and storage segments. The emission factor for 
diaphragm pneumatic pumps is 3.46 tpy of methane, while it is only 0.38 
tpy of methane for piston pumps. The corresponding VOC emission factors 
are 0.96 tpy for the production segment and 0.096 tpy for the 
transmission and storage segment for diaphragm pumps, and 0.11 and 0.01 
tpy for piston pumps, for production and transmission and storage 
segment, respectively.
    For instrument air systems, the BSER analysis was conducted using 
model plants that included combinations of diaphragm and piston pumps. 
For example, the smallest model plant included two diaphragm pumps and 
two piston pumps. Therefore, the cost effectiveness calculated for 
these instrument air systems represents the cost to eliminate emissions 
from both types of pumps. Since instrument air was the only option 
evaluated for natural gas processing plants, the BSER determination was 
made for all pumps at the plants (as opposed to separate determinations 
for diaphragm and piston pumps).
Zero Emissions Options
    For this analysis, we first evaluated the options that would 
eliminate methane and VOC emissions from pneumatic pumps, specifically 
instrument/compressed air systems, electric pumps, and solar-powered 
pumps.
    Instrument air systems require a compressor, power source, 
dehydrator, and volume tank. No alterations are needed to the pump 
itself to convert from using natural gas to instrument air. However, 
they can only be utilized in locations with sufficient electrical 
power. Instrument air systems are more economical and, therefore, more 
common at facilities with a high concentration of pneumatic devices and 
where an operator can ensure the system is properly functioning. 
Electric pumps provide the same functionality as gas-driven pumps and 
are only restricted by the availability of a source of electricity.
    Solar-powered pumps are a type of electric pump, except that the 
power is

[[Page 63227]]

provided by solar-charged direct current (DC). Solar-powered pumps can 
be used at remote sites where a source of electricity is not available, 
and they have been shown to be able to handle a range of throughputs up 
to 100 gallons per day with maximum injection pressure around 3,000 
pounds per square inch gauge (psig).
    Production and Transmission and Storage Segments. For the 
production and transmission and storage segments, we evaluated the 
costs and impacts of these ``zero-emissions'' options (See Chapter 9 of 
the NSPS OOOOb and EG TSD for this rulemaking). We found that the cost-
effectiveness of these options, for both diaphragm and piston pumps, 
were generally within the ranges that the EPA considers reasonable. 
However, for instrument air systems and electric pumps, our analysis 
assumes that electricity is available onsite. As noted above, in 2015, 
the EPA determined that a zero-emission standard for pumps in the 
production and transmission and storage segments was infeasible because 
(1) electricity is not available at all sites and (2) solar pumps are 
not technically feasible in all situations for which piston pumps and 
diaphragm pumps are needed. 80 FR 56625-56626. While we specifically 
requested comment on this determination in 2015, nothing was submitted 
at that time that caused a reversal in this decision. At this time, we 
are unclear as to whether these limitations have been overcome and 
whether zero-emission pneumatic pumps are technically feasible for all 
pneumatic pumps throughout the production and transmission and storage 
segments. Therefore, at this time, we are unable to conclude that this 
zero-emission option represents BSER in this proposal, but we are 
soliciting comment on this issue to better understand whether a zero-
emission option is now technically feasible.
    As explained in Section XII.C.1.e, the EPA believes that similar 
previously identified technical limitations have been overcome in the 
context of pneumatic controllers. Further, a few States do prohibit 
emissions from pneumatic pumps throughout the Crude Oil and Natural Gas 
Industry. California prohibits the venting of natural gas to the 
atmosphere from pneumatic pumps through the use of compressed air or 
electricity, or by collecting all potentially vented natural gas with 
the use of a vapor collection system that undergoes periodic leak 
detection and repair. While California requires this, the fact that 
other States (e.g., Colorado, Wyoming) do not require zero emissions 
from pneumatic pumps at all locations leads us to be uncertain as to 
whether it is technically feasible at this time. Canadian Provinces 
also regulate emissions from natural gas-driven pneumatic pumps. In 
British Columbia, pneumatic pumps installed after January 1, 2021, must 
not emit natural gas, and in Alberta, vent gas from pneumatic pumps 
installed after January 2, 2022, must be prevented. In addition, New 
Mexico has proposed a regulation that requires zero-emitting pumps, but 
only at production and transmission and storage sites that have access 
to electricity.
    The EPA is soliciting comment on the basis for our proposed 
determination: That because electricity is not available at all sites 
and that there are applications at these sites where solar-powered 
pumps may not be feasible the Agency is uncertain as to whether the 
zero-emission options represent BSER. Also, as noted above, we are 
soliciting comment on an approach where the EPA would propose to 
subcategorize pneumatic pumps located in the production and 
transmission and storage sites based on availability of electricity and 
develop separate standards for each subcategory.
    Natural gas processing plants. Natural gas processing plants are 
known to have a source of electrical power. Therefore, instrument air 
and electric pumps are technically feasible options at these 
facilities.
    As the next step in the BSER determination, we evaluated capital 
and annual costs of compressed air systems for the natural gas 
processing plants. While electric pumps are an option at natural gas 
processing plants, we assumed that natural gas processing plants will 
elect to always use instrument air and an impacts analysis for electric 
pumps was not conducted.
    The capital costs for an instrument air system were estimated to 
range from $4,500 to $39,500. The annual costs include the capital 
recovery cost (calculated at a 7 percent interest rate for 10 years), 
labor costs for operations and maintenance, and electricity costs. 
These are estimated to range from $11,300 to $81,350. Because gas 
emissions are avoided as compared to the use of natural gas-driven 
pumps, the use of an instrument air system will have natural gas 
savings realized from the gas not released. The EPA estimates that each 
diaphragm pump replaced will save 201 Mcf per year of natural gas from 
being emitted and each piston pump will save of 22 Mcf per year in the 
processing segment. The estimated value of the natural gas saved, based 
on $3.13 per Mcf, would range from $1,400 to $35,000 per year per 
plant. The annual costs, including these savings, ranges from $9,900 to 
$46,500. More information on this cost analysis is available in the 
NSPS OOOOb and EG TSD for this proposal.
    The resulting cost effectiveness, under the single pollutant 
approach where all the costs are assigned to the reduction of one 
pollutant, for the application of instrument air to achieve a 100 
percent emission reduction at natural gas processing plants ranges from 
$420 to $1,470 per ton of methane eliminated. For VOC, these cost 
effectiveness values ranged from $1,520 to $5,290 per ton of VOC 
eliminated. Considering savings, these cost effectiveness values range 
from $240 to $1,300 per ton of methane eliminated and $870 to $4,600 
per ton of VOC eliminated. Under the multipollutant approach where half 
the cost of control is assigned to the methane reduction and half to 
the VOC reduction, the cost effectiveness ranges from $210 to $730 per 
ton of methane eliminated and $760 to $2,640 per ton of VOC eliminated. 
Considering savings, the cost effectiveness values range from $120 to 
$650 per ton of methane eliminated and from $440 to $2,320 per ton of 
VOC eliminated. These values are well within the range of what the EPA 
considers to be reasonable for methane and VOC using both the single 
pollutant and multipollutant approaches. As discussed above, the 
evaluation for instrument air systems is based on a combination of 
diaphragm and piston pumps. Therefore, this determination of 
reasonableness applies to both types of pumps at natural gas processing 
plants.
    The 2016 NSPS OOOOa requires a natural gas emission rate of zero 
for pneumatic pumps at natural gas processing plants. Natural gas 
processing plants have successfully met this standard. Further, as 
discussed above several State agencies have rules that include this 
zero-emission requirement. This is a demonstration of the 
reasonableness of a natural gas emission rate of zero for pneumatic 
pumps at natural gas processing plants.
    Secondary impacts from the use of instrument air systems are 
indirect, variable, and dependent on the electrical supply used to 
power the compressor. These impacts are expected to be minimal, and no 
other secondary impacts are expected.
    In light of the above, we find that the BSER for reducing methane 
and VOC emissions from natural gas-driven piston and diaphragm pumps at 
gas processing plants is a natural gas emission rate of zero. This 
option results in a 100 percent reduction of emissions for both methane 
and VOC. Therefore, for NSPS OOOOb, we are

[[Page 63228]]

proposing to require a natural gas emission rate of zero for all 
pneumatic pumps at natural gas processing plants.
Routing to a Control Device or VRU Options
    Above we stated our determination that the EPA is unable to 
conclude that this zero-emission option represents BSER in this 
proposal for pumps in the production and transmission and storage 
segments. Therefore, we evaluated the use of control devices to reduce 
methane and VOC emissions. This BSER analysis was conducted on an 
individual pump basis and diaphragm and piston pumps were evaluated 
separately.
    Combustors (e.g., enclosed combustion devices, thermal oxidizers 
and flares that use a high-temperature oxidation process) can be used 
to control emissions from natural gas-driven pumps. Combustors are used 
to control VOCs in many industrial settings, since the combustor can 
normally handle fluctuations in concentration, flow rate, heating 
value, and inert species content. The types of combustors installed in 
the Crude Oil and Natural Gas Industry can achieve at least a 95 
percent control efficiency on a continuous basis. It is noted that 
combustion devices can be designed to meet 98 percent control 
efficiencies, and can control, on average, emissions by 98 percent or 
more in practice when properly operated. However, combustion devices 
that are designed to meet a 98 percent control efficiency may not 
continuously meet this efficiency in practice in the oil and gas 
industry due to factors such as variability of field conditions.
    A related option for controlling emissions from pneumatic pumps is 
to route vapors from the pump to a process, such as back to the inlet 
line of a separator, to a sales gas line, or to some other line 
carrying hydrocarbon fluids for beneficial use, such as use as a fuel. 
Use of a VRU has the potential to reduce the VOC and methane emissions 
from natural gas-driven pneumatic pumps by 100 percent if all vapor is 
recovered. However, the effectiveness of the gas capture system and 
downtime for maintenance would reduce capture efficiency and therefore, 
we estimate that routing emissions from a natural gas-driven pump to a 
VRU and to a process can reduce the gas emitted by approximately 95 
percent, while at the same time, capturing the gas for beneficial use.
    Based on a 95 percent reduction, the reduction in emissions in the 
production segment would be 3.29 tpy of methane and 0.91 tpy of VOC per 
diaphragm pump, and 0.36 tpy methane and 0.10 tpy VOC per piston pump. 
In the transmission and storage segment, the reduction in emissions 
would be 3.29 tpy of methane and 0.09 tpy of VOC per diaphragm pump, 
and 0.36 tpy of methane and 0.01 ton per year of VOC per piston pump.
    Installation of a new combustion device or VRU. Costs for the 
installation of a new combustion device and a new VRU were evaluated. 
Installing a new combustion device has associated capital costs and 
operating costs. Based on the analysis conducted for the 2012 NSPS for 
a combustion device to control emissions from storage vessels, the 
capital cost for installing a new combustion device was $32,300 in 2008 
dollars. We updated this to $38,500 to reflect 2019 dollars. Based on 
the life expectancy for a combustion device at 10 years, we estimate 
the annualized capital cost of installing a new combustion device to be 
$5,500 in 2019 dollars, using a 7 percent discount rate. The 2016 NSPS 
OOOOa TSD indicates the annual operating costs associated with a new 
combustion device were $17,000 in 2012 dollars, which we updated to 
$19,100 in 2019 dollars. Therefore, the total annual costs for a new 
combustion device are $24,600. Because the gas captured is combusted 
there are no gas savings associated with the use of a combustion 
device.
    Installing a new VRU would also have both capital costs and 
maintenance costs. We based the costs of a VRU on the analysis 
conducted for the 2012 NSPS for control of emissions from storage 
vessels, which is representative of the costs that would be incurred 
for a VRU used to reduce emissions from natural gas-driven pneumatic 
pumps. The capital cost and installation costs for a new VRU are 
estimated to be $116,900 (in 2019 dollars) and the annual operation and 
maintenance costs estimated to be $11,200 (in 2019 dollars). The total 
annualized cost of a new VRU is estimated to be $27,800, including the 
operation and maintenance cost and the annualized capital costs based 
on a 7 percent discount rate and 10-year equipment life.
    Because there is potential for beneficial use of gas recovered 
through the VRU, the savings that would be realized for 95 percent of 
the gas that would have emitted and lost were estimated. The gas saved 
would equate to 191 Mcf per year from a diaphragm pump and 21 Mcf per 
year from a piston pump. This results in estimated annual savings of 
$600 per diaphragm pump and $65 per piston pump in the production 
segment. The resulting annual costs, considering these savings, are 
$27,200 per diaphragm pump and $27,700 per piston pump in the 
production segment. Transmission and storage facilities do not own the 
natural gas; therefore, savings from reducing the amount of natural gas 
emitted/lost was not applied for this segment. More information on 
these cost analyses is available in the NSPS OOOOb and EG TSD for this 
proposal.
    The resulting cost effectiveness estimates for application of a new 
control device to reduce emissions from natural gas-driven pumps in the 
production segment by 95 percent, or the use of a VRU to route 
emissions back to a process, are discussed below under both the single 
pollutant approach, where all the costs are assigned to the reduction 
of one pollutant, and the multipollutant approach, where half the cost 
of control is assigned to the methane reduction and half to the VOC 
reduction. The results are presented separately for diaphragm and 
piston pumps. These values assume that the control device or VRU is 
installed solely for the purpose of controlling the emissions from a 
single natural gas-driven pneumatic pump, and only the emission 
reductions from a single pump are considered.
    For diaphragm pumps in the production segment using the single 
pollutant approach, the cost effectiveness is estimated to be $7,500 
per ton of methane reduced using a new combustion device, and $8,500 
using a new VRU ($8,300 with savings). For VOC, these cost 
effectiveness values are $26,900 per ton of VOC reduced using a new 
combustion device, and $30,400 using a new VRU ($29,800 with savings). 
These values are outside of the range considered reasonable by the EPA 
for both methane and VOC.
    For diaphragm pumps in the production segment using the 
multipollutant approach, the cost effectiveness is estimated to be 
$3,750 per ton of methane reduced using a new combustion device, and 
$4,250 using a new VRU ($4,150 with savings). For VOC, these cost 
effectiveness values are $13,450 per ton of VOC reduced using a new 
combustion device, and $15,200 using a new VRU ($14,900 with savings). 
These values are outside of the range considered reasonable by the EPA 
for both methane and VOC.
    For piston pumps in the production segment using the single 
pollutant approach, the cost effectiveness is estimated to be $68,100 
per ton of methane reduced using a combustion device, and $77,000 using 
a VRU ($76,800 with savings). For VOC, these cost effectiveness values 
are $244,800

[[Page 63229]]

per ton of VOC reduced using a combustion device, and $277,000 using a 
VRU ($276,400 with savings). These values are outside of the range 
considered reasonable by the EPA for both methane and VOC.
    For piston pumps in the production segment using the multipollutant 
approach, the cost effectiveness is estimated to be $34,000 per ton of 
methane reduced using a combustion device, and $38,500 using a VRU 
($38,400 with savings). For VOC, these cost effectiveness values are 
$122,400 per ton of VOC reduced using a combustion device, and $138,500 
using a VRU ($138,200 with savings). These values are outside of the 
range considered reasonable by the EPA for both methane and VOC.
    For diaphragm pumps in the transmission and storage segment using 
the single pollutant approach, the cost effectiveness is estimated to 
be $7,400 per ton of methane reduced using a new combustion device, and 
$8,500 using a new VRU. For VOC, these cost effectiveness values are 
$270,000 per ton of VOC reduced using a new combustion device, and 
$305,000 using a new VRU. These values are outside of the range 
considered reasonable by the EPA for both methane and VOC.
    For diaphragm pumps in the transmission and storage segment using 
the multipollutant approach, the cost effectiveness is estimated to be 
$3,700 per ton of methane reduced using a new combustion device, and 
$4,200 using a new VRU. For VOC, these cost effectiveness values are 
$135,000 per ton of VOC reduced using a new combustion device, and 
$152,600 using a new VRU. These values are outside of the range 
considered reasonable by the EPA for both methane and VOC.
    For piston pumps in the transmission and storage segment using the 
single pollutant approach, the cost effectiveness is estimated to be 
$68,000 per ton of methane reduced using a combustion device, and 
$77,000 using a VRU. For VOC, these cost effectiveness values are $2.5 
million per ton of VOC reduced using a combustion device, and $2.8 
million using a VRU. These values are outside of the range considered 
reasonable by the EPA for both methane and VOC.
    For piston pumps in the transmission and storage segment using the 
multipollutant approach, the cost effectiveness is estimated to be 
$34,000 per ton of methane reduced using a combustion device, and 
$38,500 using a VRU. For VOC, these cost effectiveness values are $1.2 
million per ton of VOC reduced using a combustion device, and $1.4 
million using a VRU. These values are outside of the range considered 
reasonable by the EPA for both methane and VOC.
    For diaphragm pumps, we do not consider the costs to be reasonable 
to install a new control device, or a new VRU to route the emissions to 
a process, for the production and transmission and storage segments for 
methane or VOC emission reduction using either the single pollutant or 
multipollutant approach. Similarly, for piston pumps, we do not 
consider the costs to be reasonable under any scenario. Therefore, we 
are unable to conclude that requiring the installation of a new control 
device, or the installation of a new VRU to route emissions to a 
process, to achieve 95 percent reduction of methane and VOC emissions 
from natural gas-driven pumps for the production or transmission 
segments represents BSER in this proposal.
    Routing to an existing combustion device or VRU. In addition to 
evaluating the installation of a new control device or new VRU 
installed solely for the purpose of reducing the emissions from a 
single natural gas-driven pneumatic pump, we evaluated the option of 
routing the emissions from natural gas-driven pneumatic pumps to an 
existing control device to achieve a 95 percent reduction in methane 
and VOC emissions or routing the emissions to an existing VRU and to a 
process. The emission reduction for this option would be the same as 
discussed above for a new control device achieving 95 percent control, 
that is 3.29 tpy of methane and 0.91 tpy of VOC per diaphragm pump, and 
0.36 tpy methane and 0.10 tpy VOC per piston pump in the production 
segment and 3.29 tpy of methane and 0.09 tpy of VOC per diaphragm pump, 
and 0.36 tpy of methane and 0.01 ton per year of VOC per piston pump in 
the transmission and storage segment. The resulting cost effectiveness 
estimates for use of an existing control device to reduce emissions 
from natural gas-driven pumps in the production segment by 95 percent, 
or the use of an existing VRU to route emissions to a process, are 
discussed below under both the single pollutant approach, where all the 
costs are assigned to the reduction of one pollutant, and the 
multipollutant approach, where half the cost of control is assigned to 
the methane reduction and half to the VOC reduction. The results are 
presented separately for diaphragm and piston pumps.
    We estimated the costs for routing emissions to an existing control 
device or VRU based on the average of the cost presented in the 2015 
proposed NSPS OOOOa and the costs presented by two commenters to the 
proposal,\295\ as documented in the 2016 NSPS OOOOa TSD. This yielded a 
capital cost estimate of $6,100 in 2019 dollars, for an annualized cost 
of $900 in 2019 dollars, using the 7 percent discount rate and 10-year 
equipment life. In the 2016 NSPS OOOOa TSD the EPA assumed there were 
no incremental operating costs for routing to an existing control 
device or VRU, so the total annual costs consist only of the $900 
capital recovery cost. This assumption is maintained for this analysis. 
The same savings discussed above for the gas that is recovered by a VRU 
would be realized when routing to an existing VRU and to a process. 
These savings are $600 per year per diaphragm pump and $65 per year per 
piston pump in the production segment. The resulting annual costs for 
routing to an existing VRU and to process, considering these savings, 
are $270 per diaphragm pump and $800 per piston pump in the production 
segment. As noted above, transmission and storage facilities do not own 
the natural gas; therefore, savings from reducing the amount of natural 
gas emitted/lost was not applied for this segment.
---------------------------------------------------------------------------

    \295\ EPA-HQ-OAR-2010-0505-6884-A1 and EPA-HQ-OAR-2010-0505-
6881.
---------------------------------------------------------------------------

    For diaphragm pumps in the production segment using the single 
pollutant approach, the cost effectiveness is estimated to be $260 per 
ton of methane reduced using an existing combustion device, and $260 
per ton of methane using an existing VRU ($80 with savings). For VOC, 
these cost effectiveness values are $950 per ton of VOC reduced using 
an existing combustion device, and $950 using an existing VRU ($300 
with savings). For diaphragm pumps in the production segment using the 
multipollutant approach, the cost effectiveness is estimated to be $130 
per ton of methane reduced using an existing combustion device, and 
$130 using an existing VRU ($40 with savings). For VOC, these cost 
effectiveness values are $475 per ton of VOC reduced using an existing 
combustion device, and $475 using an existing VRU ($150 with savings). 
These values are well within the range of what the EPA considers to be 
reasonable for methane and VOC using both the single pollutant and 
multipollutant approaches.
    For diaphragm pumps in the transmission and storage segment using 
the single pollutant approach, the cost effectiveness is estimated to 
be $260 per ton of methane reduced using an existing combustion device, 
and $260 using an existing VRU. For VOC, these

[[Page 63230]]

cost effectiveness values are $9,500 per ton of VOC reduced using an 
existing combustion device, and $9,500 using an existing VRU. For 
diaphragm pumps in the transmission and storage segment using the 
multipollutant approach, the cost effectiveness is estimated to be $130 
per ton of methane reduced using an existing combustion device, and 
$130 using an existing VRU. For VOC, these cost effectiveness values 
are $4,800 per ton of VOC reduced using an existing combustion device, 
and $4,800 using an existing VRU. These values are within the range of 
what the EPA considers to be reasonable.
    The 2016 NSPS OOOOa requires that emissions from natural gas driven 
pneumatic pumps at well sites achieve a 95 percent reduction in methane 
and VOC emissions by routing them to a control device if an existing 
control device is on site. Owners and operators at well sites have 
successfully met this standard. Further, several State agencies (e.g., 
California, proposed in New Mexico) have rules that include this 
requirement, and have extended the requirement to sites throughout the 
production segment as well as the transmission and storage segment. 
These factors considered together demonstrate the reasonableness of a 
requirement that emissions from natural gas driven pneumatic pumps at 
sites without access to electricity achieve a 95 percent reduction in 
methane and VOC emissions by routing them to a control device, provided 
that an existing control device is on site.
    There are secondary impacts from the use of a combustion device to 
control emissions routed from natural gas-driven diaphragm pumps. The 
combustion of the recovered natural gas creates secondary emissions of 
hydrocarbons, NOX, CO2, and CO. The EPA considers 
the magnitude of these emissions to be reasonable given the significant 
reduction in methane and VOC emissions that the control would achieve. 
Details of these impacts are provided in the NSPS OOOOb and EG TSD for 
this rulemaking. There are no other wastes created or wastewater 
generated. The secondary impacts from use of a VRU are indirect, 
variable, and dependent on the electrical supply used to power the VRU. 
No other secondary impacts are expected.
    In light of the above, we find that the BSER for reducing methane 
and VOC emissions from natural gas-driven diaphragm pumps in the 
production and transmission and storage segments is to route the 
emissions to an existing control device that achieves 95 percent 
control of methane and VOC, or to route the emissions to an existing 
VRU and to a process. We are, therefore, proposing to include this 
requirement in NSPS OOOOb.
    For piston pumps in the production segment using the single 
pollutant approach, the cost effectiveness is estimated to be $2,400 
per ton of methane reduced using a combustion device, and $2,400 using 
a VRU ($2,200 with savings). For VOC, these cost effectiveness values 
are $8,700 per ton of VOC reduced using a combustion device, and $8,700 
using a VRU ($8,000 with savings).
    For piston pumps in the production segment using the multipollutant 
approach, the cost effectiveness is estimated to be $1,200 per ton of 
methane reduced using a combustion device, and $1,200 using a VRU 
($1,100 with savings). For VOC, these cost effectiveness values are 
$4,350 per ton of VOC reduced using a combustion device, and $4,350 
using a VRU ($4,000 with savings).
    For piston pumps in the production segment, we do not consider the 
costs to route emissions from a natural gas-driven pneumatic pump to an 
existing control device to achieve 95 percent reduction, or to route to 
an existing VRU and to a process, to be reasonable for methane or VOC 
using the single pollutant approach. However, the methane and VOC cost 
effectiveness using the multipollutant method is within the range that 
the EPA considers reasonable.
    There are secondary impacts from the use of a combustion device to 
control emissions routed from natural gas-driven piston pumps. These 
impacts are the same as discussed above for diaphragm pumps.
    In light of the above, we find that the BSER for reducing methane 
and VOC emissions from natural gas-driven piston pumps in the 
production and transmission and storage segments is to route the 
emissions to an existing control device that achieves 95 percent 
control of methane and VOC, or to route the emissions to an existing 
VRU and to a process. We are, therefore, proposing to include this 
requirement for piston pumps in NSPS OOOOb.
    The EPA notes that State rules for concerning natural gas-driven 
piston pumps emissions control requirements differ. For example, 
California specifically includes both diaphragm and piston pumps in the 
definition of pneumatic pumps, while Colorado specifically excludes 
piston pumps from control requirements. At this time, the EPA is unable 
to fully understand the basis for the piston pump State control 
requirement differences based on the background information for these 
State rules.
    We are specifically seeking comment on the emissions factors used 
to estimate the baseline emissions from pneumatic pumps, which are from 
a 1996 EPA/GRI study.\296\ The EPA is interested in more recent 
information regarding emissions from pneumatic pumps.
---------------------------------------------------------------------------

    \296\ Gas Research Institute (GRI)/U.S. Environmental Protection 
Agency. 1996d. Research and Development, Methane Emissions from the 
Natural Gas Industry, Volume 13: Chemical Injection Pumps. June 1996 
(EPA-600/R-96-080m).
---------------------------------------------------------------------------

    For piston pumps in the transmission and storage segment using the 
single pollutant approach, the cost effectiveness is estimated to be 
$2,400 per ton of methane reduced using a combustion device, and $2,400 
using a VRU. For VOC, these cost effectiveness values are $87,000 per 
ton of VOC reduced using a combustion device, and $87,000 using a VRU.
    For piston pumps in the transmission and storage segment using the 
multipollutant approach, the cost effectiveness is estimated to be 
$1,200 per ton of methane reduced using a combustion device, and $1,200 
using a VRU. For VOC, these cost effectiveness values are $43,500 per 
ton of VOC reduced using a combustion device, and $43,500 using a VRU.
    For piston pumps in the transmission and storage segment, we do not 
consider the costs to be reasonable to route emissions from a natural 
gas-driven pneumatic pump to an existing control device, or to route to 
an existing VRU and to a process, for either methane or VOC under the 
single pollutant approach. Further, we do not find that the cost 
effectiveness for both methane and VOC to be reasonable under the 
multipollutant approach. Therefore, we are unable to conclude that 
requiring the routing of emissions from natural gas-driven piston pumps 
in the transmission and storage segment to an existing control device 
to achieve 95 percent reduction of methane and VOC emissions, or the 
routing of emissions to a VRU and to a process, represents BSER for 
NSPS OOOOb in this proposal.
2. EG OOOOc
    The EPA evaluated BSER for the control of methane from existing 
pneumatic pumps (designated facilities) in all segments in the Crude 
Oil and Natural Gas source category covered by the proposed NSPS OOOOb 
and translated the degree of emission limitation achievable through 
application of the BSER into a proposed presumptive standard for these 
facilities

[[Page 63231]]

that mirrors the proposed NSPS OOOOb, with the exception of the BSER 
conclusion regarding piston pumps in the production segment.
    First, based on the same criteria and reasoning explained above the 
EPA is proposing to define the designated facility in the context of 
existing pneumatic pumps as those that commenced construction on or 
before November 15, 2021. Based on information available to the EPA, we 
did not identify any factors specific to existing sources that would 
indicate that the EPA should alter this definition as applied to 
existing sources.
    The EPA finds that the controls evaluated for new sources for NSPS 
OOOOb are appropriate for consideration for existing sources under the 
EG OOOOc. The EPA finds no reason to evaluate different, or additional, 
control measures in the context of existing sources because the EPA is 
unaware of any control measures, or systems of emission reduction, for 
pneumatic pumps that could be used for existing sources but not for new 
sources. Next, the methane emission reductions expected to be achieved 
via application of the control measures identified above to new sources 
are also expected to be achieved by application of the same control 
measures to existing sources. The EPA finds no reason to believe that 
these calculations would differ for existing sources as compared to new 
sources because the EPA believes that the baseline emissions of an 
uncontrolled source are the same, or very similar, and the efficiency 
of the control measures are the same, or very similar, compared to the 
analysis above. This is also true with respect to the costs, non-air 
environmental impacts, energy impacts, and technical limitations 
discussed above for the control options identified.
    The EPA has not identified any costs associated with applying these 
controls at existing sources, such as retrofit costs, that would apply 
any differently than, or in addition to, those costs assessed above 
regarding application of the identified controls to new sources. The 
cost effectiveness values for the option of zero emissions from 
pneumatic pumps in the natural gas processing sector range from $420 to 
$1,470 per ton of methane eliminated ($240 to $1,300 per ton 
considering savings). These cost effectiveness values are in the range 
considered reasonable by the EPA. However, as explained above in the 
context of new sources, at this time we are unclear as to whether the 
technical limitations associated with this option have been overcome 
and whether zero-emission pneumatic pumps are technically feasible. 
Therefore, at this time, we are unable to conclude that this zero-
emission option represents BSER in this proposal for the EG, but we are 
soliciting comment on this issue to better understand whether a zero-
emission option is technically feasible.
    For diaphragm pumps in the production segment the cost 
effectiveness is estimated to be $260 per ton of methane reduced using 
an existing (on site) combustion device or VRU, and $260 per ton of 
methane using an existing (on site) VRU ($80 with savings). For 
diaphragm pumps in the transmission and storage segment the cost 
effectiveness of is estimated to be $260 per ton of methane reduced 
using an existing (on site) combustion device, and $260 using an 
existing (on site) VRU. This cost effectiveness is considered 
reasonable by the EPA.
    For piston pumps in the production segment the cost effectiveness 
is estimated to be $2,400 per ton of methane reduced using an existing 
(on site) combustion device or VRU, and $2,400 per ton of methane using 
an existing (on site) VRU ($2,200 with savings). For piston pumps in 
the transmission and storage segment the cost effectiveness is 
estimated to be $2,400 per ton of methane reduced using an existing (on 
site) combustion device, and $2,400 using an existing (on site) VRU. 
This cost effectiveness is outside of the range considered reasonable 
by the EPA. In summary, the EPA did not identify any factors specific 
to existing sources, as opposed to new sources, that would alter the 
analysis above for the proposed NSPS OOOOb as applied to the designated 
pollutant (methane) and the designated facilities (pneumatic pumps). 
However, the BSER conclusion regarding piston pumps in the production 
and transmission and storage segments for the EG differs from the 
conclusion for new sources under the NSPS. As a result, the proposed 
presumptive standards for existing pneumatic pumps are as follows.
    For diaphragm pneumatic pumps in the production and transmission 
and storage segments, the presumptive standard is routing emissions to 
an existing (already on site) control device or existing (already on 
site) VRU and to a process to achieve 95 percent reduction in methane. 
For pneumatic pumps (diaphragm and piston) in the natural gas 
processing sector, the presumptive standard is a natural gas emission 
rate of zero.
    As for new sources, the EPA is specifically soliciting comment on 
whether the production and transmission storage segments should be 
subcategorized based on the availability of electricity and BSER 
determined separately for each subcategory in the EG.

H. Proposed Standards for Equipment Leaks at Natural Gas Processing 
Plants

1. NSPS OOOOb
a. Background
    In the 2012 NSPS OOOO, the EPA established VOC standards for 
equipment leaks at onshore natural gas processing plants. These 
standards were based on the Standards of Performance for Equipment 
Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry 
(NSPS VVa), which is an EPA Method 21 LDAR program generally requiring 
monthly monitoring of pumps with a leak definition of 2,000 ppm, 
quarterly monitoring of valves with a leak definition of 500 ppm, and 
annual monitoring of connectors with a leak definition of 500 ppm.\297\ 
In the 2016 NSPS OOOOa, the EPA added GHG (methane) to the title of the 
standards for equipment leaks at onshore natural gas plants but 
continued to rely on the requirements in NSPS VVa, which limited 
monitoring and repair (if found leaking) to those equipment components 
``in VOC service.'' Based on our review of the current standards, we 
are proposing to revise the equipment leak standards for onshore 
natural gas plants to more readily apply to equipment components that 
have the potential to emit methane even though they are not ``in VOC 
service.''
---------------------------------------------------------------------------

    \297\ 40 CFR part 60, subpart VVa, includes ``skip period'' 
provisions that may alter the cited monitoring frequencies.
---------------------------------------------------------------------------

b. Technology and LDAR Program Review
    The EPA acknowledges that advancements are being made in leak 
detection, including remote sensing, sensor networks, and OGI. The EPA 
already provides use of OGI as an alternative work practice at 40 CFR 
60.18(g); however, the alternative work practice requires annual EPA 
Method 21 monitoring as part of the OGI monitoring protocol. Parallel 
with this proposal, the EPA is proposing appendix K to part 60 to 
provide a standard method for OGI leak monitoring. This allows us to 
consider a wider range of LDAR programs when evaluating the BSER for 
equipment leaks at onshore natural gas processing plants. To evaluate 
different LDAR programs, we used a Monte Carlo simulation that 
simulated initiation of leaks for pumps, valves, and connectors at 
monthly intervals based on

[[Page 63232]]

component specific leak frequencies and EPA Method 21 leak size 
distributions based on historical EPA Method 21 leak data. We randomly 
assigned a mass emission rate based on the EPA Method 21 leak size 
assuming a lognormal distribution for the mass emission rate around the 
EPA Method 21 screening value correlation equation estimates. The 
simulation runs for five years for each LDAR program to build up leaks 
that might not be repaired under a given program, and compares the 
emissions estimated in the fifth year of the simulation for different 
LDAR programs. The model also records the number of repairs made in the 
fifth year of the simulation to assess the annual repair costs 
associated with the LDAR program. More information on the LDAR program 
Monte Carlo simulation and associated cost analyses is available in the 
NSPS OOOOb and EG TSD for this proposal.
    Based on our model simulation of NSPS OOOOa requirements (Method 21 
based LDAR program following the requirements in NSPS VVa), the EPA 
projects that the program achieves a 91.5 percent emission reduction 
for the components monitored. This is comparable to the projected 
control efficiencies of this LDAR program applied to similar industrial 
processes.\298\ However, when considering the components not monitored 
at the onshore natural gas processing plant because they are not ``in 
VOC service'', the overall hydrocarbon control efficiency of the 
current NSPS OOOOa requirements drops to 73.2 percent. Thus, 
significant emission reductions can be achieved by extending the 
current provisions to include all components that have the potential to 
emit methane.
---------------------------------------------------------------------------

    \298\ EPA, October 2007. ``Leak Detection and Repair--A Best 
Practices Guide.'' Office of Enforcement and Compliance Assurance. 
EPA-305-D-07-001. See ``Table 4.1--Control effectiveness for an LDAR 
program at a chemical process unit and a refinery.''
---------------------------------------------------------------------------

    Based on our model simulation of an OGI-based LDAR program, we 
found that bimonthly OGI monitoring of all equipment components (with 
potential VOC or methane emissions) using devices capable of 
identifying mass leaks at 30 g/hr and at 15 g/hr would achieve emission 
reductions of 88.5 percent and 92.2 percent, respectively. Based on the 
requirements in appendix K that the instrument be able to detect a 
methane leak of 17 g/hr, these results suggest that bimonthly OGI 
monitoring following appendix K will achieve comparable emission 
reductions as the current NSPS OOOOa requirements for the equipment 
components subject to the monitoring requirements.
c. Control Options and 2021 BSER Analysis
    The EPA then evaluated various LDAR programs for their control 
efficiency, cost and cost effectiveness for a small and a large model 
natural gas processing plant. These ``small'' and ``large'' model 
plants were based on the number of components at each facility in 
various monitoring summaries for onshore natural gas processing 
plants.\299\ We considered the (option 1) current NSPS OOOOa standards 
expanded to components that also have the potential to emit methane 
regardless of the VOC content of the stream, (option 2) bimonthly OGI 
following appendix K for all components (VOC or methane), and (options 
3 and 4) a hybrid approach following the current alternative work 
practice (regular OGI with annual EPA Method 21). For option 3 we 
evaluated requiring quarterly OGI with an annual EPA Method 21 survey 
at 10,000 ppm. For option 4 we evaluated requiring bimonthly OGI with 
an annual EPA Method 21 survey at 10,000 ppm. These control options and 
their associated costs are summarized in Tables 18 and 19 for the small 
and large model plants, respectively.
---------------------------------------------------------------------------

    \299\ See Section 10.4 of Chapter 10 ``Equipment Leaks from 
Natural Gas Processing Plants'' in the TSD located at Docket ID No. 
EPA-HQ-OAR-2021-0317.

                                                              Table 18--Summary of Control Options and Costs for Small Model Plants
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Emissions reduction (tpy)
                         Control option                          --------------------------------  Capital cost   Annual cost ($/  CE \a\ ($/ton   CE \a\ ($/ton  Incremental ($/ Incremental ($/
                                                                        VOC           Methane           ($)             yr)            VOC)          methane)        ton VOC)      ton  methane)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Methane and VOC Service
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1...............................................................           12.34           56.95         $17,700        $114,100          $9,200          $2,000  ..............  ..............
2...............................................................           12.61           58.19           1,500          62,800           5,000           1,100        -189,100         -41,300
3...............................................................           12.64           58.33          19,200          84,500           6,700           1,400         696,200         151,100
4...............................................................           12.76           58.92          19,200          95,500           7,500           1,600          87,000          18,800
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Cost effectiveness (CE) compared to no monitoring.


                                                              Table 19--Summary of Control Options and Costs for Large Model Plants
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Emissions reduction (tpy)
                         Control option                          --------------------------------  Capital cost   Annual cost ($/  CE \a\ ($/ton   CE \a\ ($/ton  Incremental ($/ Incremental ($/
                                                                        VOC           Methane           ($)             yr)            VOC)          methane)        ton VOC)      ton  methane)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                     Methane and VOC Service
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1...............................................................           25.59          118.27         $36,200        $229,000          $9,000          $1,900  ..............  ..............
2...............................................................           26.11          120.81           3,000         123,500           4,700           1,000        -200,000         -43,100
3...............................................................           26.17          121.10          39,200         170,500           6,500           1,400         760,000         165,200
4...............................................................           26.44          122.31          39,200         191,300           7,200           1,600          79,500          17,100
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Cost effectiveness (CE) compared to no monitoring.

    We further assumed that all facilities outsource their equipment 
leak surveys. The first year ``capital'' costs of implementing an EPA 
Method 21 program (identifying components required to be monitored and 
developing a data system to track the proper frequency to monitor each 
component) are summarized in Tables 18 and 19. Additionally, these 
tables summarize the annualized costs of conducting a complete EPA 
Method 21

[[Page 63233]]

monitoring survey of all equipment (those in VOC service or contacting 
methane), which includes the annual costs of conducting required 
surveys and making the necessary repairs as well as annualized first 
year ``capital'' costs. The first-year startup costs for OGI surveys 
are small, estimated to be $750 for small plants and $1,500 for large 
plants. Because OGI surveys can be conducted much more quickly, the 
annualized cost of conducting bimonthly OGI surveys is approximately 
half the annualized cost of EPA Method 21 surveys through NSPS VVa. 
Both EPA Method 21 and OGI LDAR programs reduce loss of product. 
Therefore, the costs of the LDAR programs are offset to some degree to 
the emissions reduced. When evaluating LDAR programs that consider all 
components (both VOC and methane), the annual value of the product not 
lost due to reduced emissions is approximately $14,000/yr.
    Based on our analysis, the resulting cost effectiveness is 
reasonable for all of the options when assigning all costs to the 
reduction of methane. When assigning all costs to VOC reduction, 
however, only the bimonthly OGI option is considered reasonable at 
$5,000/ton VOC reduced for small plants and $4,700/ton VOC reduced at 
large plants. The EPA next considered the incremental cost-
effectiveness between the four options to determine which option 
represents the BSER for equipment leaks at onshore natural gas 
processing plants. All four options achieve similar emission 
reductions, as discussed in the previous section. Bimonthly OGI (option 
2) reduces an additional 2 tpy of methane at a cost savings. Adding 
annual EPA Method 21 to bimonthly OGI monitoring (option 4) reduces an 
additional 1.5 tpy methane for large model gas plant but at significant 
cost well above any costs the EPA would consider appropriate, at 
approximately $45,000/ton methane reduced (comparing option 4 with 
option 2). Therefore, the EPA does not consider it reasonable to 
require the additional of annual EPA Method 21.
    Based on the discussion above, we consider a bimonthly OGI LDAR 
program following appendix K that includes all equipment components 
that have the potential to emit VOC or methane to be BSER for new 
sources. Therefore, we are proposing this LDAR requirement for new 
sources under NSPS OOOOb. Because an EPA Method 21 monitoring program 
based on the requirements of NSPS VVa when applied to all equipment 
components that have the potential to emit VOC or methane is projected 
to achieve similar emission reductions, we are proposing that this EPA 
Method 21-based LDAR program may be used as an alternative to bimonthly 
OGI surveys.
    In the development of the 2012 NSPS OOOO, we found that NSPS VVa 
provisions for PRDs, open-ended valves or lines, and closed vent 
systems and equipment designated with no detectable emissions were 
BSER. Available information since then continues to support this 
conclusion. Therefore, we are proposing to retain the current 
requirements in the 2016 NSPS OOOOa (which adopts by reference specific 
provisions NSPS VVa) for PRDs, open-ended valves or lines, and closed 
vent systems and equipment designated with no detectable emissions, 
except expanding the applicability to sources that have the potential 
to emit methane. The EPA is soliciting information that would support 
the use of the proposed bimonthly OGI monitoring requirement for these 
equipment components in place of the NSPS VVa annual EPA Method 21 
monitoring.
    The EPA requests comments on ways to streamline approval of 
alternative LDAR programs using remote sensing techniques, sensor 
networks, or other alternatives for equipment leaks at onshore natural 
gas processing plants. Based on our Monte Carlo equipment leak model 
that assumes well-implemented LDAR programs with no delayed repair, 
both an EPA Method 21 based program following NSPS VVa and a bimonthly 
OGI monitoring program following appendix K are projected to achieve a 
91-percent emission reduction effectiveness. We request comment on 
whether providing such an emission reduction target and equipment leak 
modeling tool to simulate LDAR under similar ``ideal'' program 
implementation conditions may facilitate future equivalency 
determinations.
2. EG OOOOc
    The application of an LDAR program at an existing source is the 
same as at a new source because there is no need to retrofit equipment 
at the site to achieve compliance with the work practice standard. The 
cost effectiveness for implementing a bimonthly OGI LDAR program for 
all equipment components that have the potential to emit methane is 
approximately $850/ton methane reduced. As explained above, the cost 
effectiveness of this OGI monitoring option is within the range of 
costs we believe to be reasonable for methane reductions. Therefore, we 
consider a bimonthly OGI LDAR program following appendix K that 
includes all equipment components that have the potential to emit 
methane to be BSER for existing sources.

I. Proposed Standards for Well Completions

1. NSPS OOOOb
a. Background
    Pursuant to CAA section 111(b)(1)(B), the EPA reviewed the current 
standards in NSPS OOOOa for well completions and proposes to determine 
that they continue to reflect the BSER for reducing methane and VOC 
emissions during oil and natural gas well completions following 
hydraulic fracturing and refracturing. Accordingly, we are not 
proposing revisions to these standards. Provided below are a 
description of the affected facilities, the current standards, and a 
summary of our review.
    Natural gas and oil wells all must be ``completed'' after initial 
drilling in preparation for production. Well completion activities not 
only will vary across formations but can vary between wells in the same 
formation. Over time, completion and recompletion activities may change 
due to the evolution of well characteristics and technology 
advancement. Well completion activities include multiple steps after 
the well bore hole has reached the target depth. Developmental wells 
are drilled within known boundaries of a proven oil or gas field and 
are located near existing well sites where well parameters are already 
recorded and necessary surface equipment is in place. When drilling 
occurs in areas of new or unknown potential, well parameters such as 
gas composition, flow rate, and temperature from the formation need to 
be ascertained before surface facilities required for production can be 
adequately sized and brought on site. In this instance, exploratory 
(also referred to as ``wildcat'') wells and field boundary delineation 
wells typically either vent or combust the flowback gas.
    One completion step for improving oil and gas production is to 
fracture the reservoir rock with very high-pressure fluid, typically a 
water emulsion with a proppant (generally sand) that ``props open'' the 
fractures after fluid pressure is reduced. Natural gas emissions are a 
result of the backflow of the fracture fluids and reservoir gas at high 
pressure and velocity necessary to clean and lift excess proppant to 
the surface. Natural gas from the completion backflow escapes to the 
atmosphere during the reclamation of water, sand, and hydrocarbon 
liquids during the collection of the multi-phase mixture directed to a 
surface impoundment. As the fracture fluids are depleted, the

[[Page 63234]]

backflow eventually contains a higher volume of natural gas from the 
formation. Due to the specific additional equipment and resources 
involved and the nature of the backflow of the fracture fluids, 
completions involving hydraulic fracturing have higher costs and vent 
substantially more natural gas than completions not involving hydraulic 
fracturing.
    During its lifetime, wells may need supplementary maintenance, 
referred to as recompletions (these are also referred to as workovers). 
Recompletions are remedial operations required to maintain production 
or minimize the decline in production. Examples of the variety of 
recompletion activities include completion of a new producing zone, re-
fracture of a previously fractured zone, removal of paraffin buildup, 
replacing rod breaks or tubing tears in the wellbore, and addressing a 
malfunctioning downhole pump. During a recompletion, portable equipment 
is conveyed back to the well site temporarily and some recompletions 
require the use of a service rig. As with well completions, 
recompletions are highly specialized activities, requiring special 
equipment, and are usually performed by well service contractors 
specializing in well maintenance. Any flowback event during a 
recompletion, such as after a hydraulic fracture, will result in 
emissions to the atmosphere unless the flowback gas is captured.
    When hydraulic re-fracturing (recompletions) is performed, the 
emissions are essentially the same as new well completions involving 
hydraulic fracture, except that surface gas collection equipment will 
already be present at the wellhead after the initial fracture. The 
flowback velocity during re-fracturing will typically be too high for 
the normal wellhead equipment (separator, dehydrator, lease meter), 
while the production separator is not typically designed for separating 
sand.
    Flowback emissions are a result of free gas being produced by the 
well during well cleanup event, when the well also happens to be 
producing liquids (mostly water) and sand. The high rate flowback, with 
intermittent slugs of water and sand along with free gas, is directed 
to an impoundment or vessels until the well is fully cleaned up, where 
the free gas vents to the atmosphere while the water and sand remain in 
the impoundment or vessels. Therefore, nearly all of the flowback 
emissions originate from the recompletion process but are vented as the 
flowback enters the impoundment or vessels. Minimal amounts of 
emissions are caused by the fluid (mostly water) held in the 
impoundment or vessels since very little gas is dissolved in the fluid 
when it enters the impoundment or vessels.
    The 2021 GHGI estimates approximately 34,000 metric tpy of methane 
emissions from hydraulically fractured completion/workover natural gas 
well events and approximately 12,000 metric tpy of methane emissions 
from hydraulically fractured completion/workover oil well events in 
2019.
b. Affected Facility
    Each affected facility is a single well that conducts a well 
completion operation following hydraulic fracturing or refracturing.
c. Current NSPS Requirements
    The current NSPS for natural gas and oil well completions and 
recompletions are the same. For well completions of hydraulically 
fractured (or refractured) wells, the EPA identified two subcategories 
of hydraulically fractured wells for which well completions are 
conducted: (1) Non-wildcat and non-delineation wells (subcategory 1 
wells); and (2) wildcat and delineation wells and low-pressure wells 
(subcategory 2 wells). A wildcat well, also referred to as an 
exploratory well, is a well drilled outside known fields or is the 
first well drilled in an oil or gas field where no other oil and gas 
production exists. A delineation well is a well drilled to determine 
the boundary of a field or producing reservoir.
    In the 2016 NSPS OOOOa rule, the EPA finalized operational 
standards for non-wildcat and non-delineation wells (subcategory 1 
wells) that required a combination of REC and combustion. Because RECs 
are not feasible for every well at all times during completion or 
recompletion activities due to variability of produced gas pressure 
and/or inert gas concentrations, the rule allows for wellhead owners 
and operators to continue to reduce emissions when RECs are not 
feasible due to well characteristics (e.g., wellhead pressure or inert 
gas concentrations) by using a completion combustion device. For 
wildcat and delineation wells and low-pressure wells (subcategory 2 
wells), the EPA finalized an operational standard that required either 
(1) routing all flowback directly to a completion combustion device 
with a continuous pilot flame (which can include a pit flare) or, at 
the option of the operator, (2) routing the flowback to a well 
completion vessel and sending the flowback to a separator as soon as a 
separator will function and then directing the separated gas to a 
completion combustion device with a continuous pilot flame. For option 
2, any gas in the flowback prior to the point when the separator will 
function was not subject to control. For both options (1) and (2), 
combustion is not required in conditions that may result in a fire 
hazard or explosion, or where high heat emissions from a completion 
combustion device may negatively impact tundra, permafrost, or 
waterways. Under the 2016 NSPS OOOOa rule, oil wells with a gas-to-oil 
ratio less than 300 scf of gas per stock tank barrel of oil produced 
are affected facilities but have no requirements other than to maintain 
records of the low GOR certification and a claim signed by the 
certifying official. As discussed in section X.B.1 of this preamble, in 
the 2020 Technical Rule, the EPA made certain amendments (e.g., related 
to the use of a separator, amended definition of flowback, amended 
recordkeeping and reporting requirements) to the VOC standards for well 
completions in the 2016 NSPS OOOOa, and is proposing to apply the same 
amendments to the methane standards for well completions in the 2016 
NSPS OOOOa.
d. 2021 BSER Analysis
    The two techniques considered under the previous BSER analyses that 
have been proven to reduce emissions from production segment well 
completions and recompletions include REC and completion combustion. 
REC is an approach that not only reduces emissions but delivers natural 
gas product to the sales meter that would typically be vented. The 
second technique, completion combustion, destroys the organic 
compounds. No other emissions control techniques were identified as 
being required under other rules (Federal, State, or local rules) that 
would exceed the level of control required under the 2016 NSPS OOOOa 
rule. Therefore, no other technology control requirements were 
evaluated in this review.
    Reduced emission completions, also referred to as ``green'' or 
``flareless'' completions, use specially designed equipment at the well 
site to capture and treat gas so it can be directed to the sales line. 
This process prevents some natural gas from venting and results in 
additional economic benefit from the sale of captured gas and, if 
present, gas condensate. However, as the EPA has previously 
acknowledged, there are some limitations that may exist for performing 
RECs based on technical barriers. These limitations continue to exist. 
Three main limitations for performing a REC include the proximity of 
pipelines to the well, the pressure of the produced gas, and the inert 
gas

[[Page 63235]]

concentration. These limitations are discussed below.
    For exploratory wells (in particular), no nearby sales line may 
exist. The lack of a nearby sales line incurs higher capital outlay 
risk for exploration and production companies and/or pipeline companies 
constructing lines in exploratory fields. The EPA is soliciting comment 
on how ``access to a sales line'' and a ``sales line'' should be 
defined.
    During the completion/recompletion process, the pressure of 
flowback fluids may not be sufficient to overcome the gathering line 
backpressure. In this case, combustion of flowback gas is one option, 
either for the duration of the flowback or until a point during 
flowback when the pressure increases to flow to the sales line. Another 
potential compressor application is to boost pressure of the flowback 
gas after it exits the separator. This technique is experimental 
because of the difficulty operating a compressor where there is a 
widely fluctuating flowback rate.
    Lastly, if the concentration of inert gas, such as nitrogen or 
CO2, in the flowback gas exceeds sales line concentration 
limits, venting to the atmosphere or to a combustion device of the 
flowback may be necessary for the duration of flowback or until the gas 
energy content increases to allow flow to the sales line. Further, 
since the energy content of the flowback gas may not be high enough to 
sustain a flame due to the presence of the inert gases, combustion of 
the flowback stream would require a continuous ignition source with its 
own separate fuel supply.
    Where a REC can be conducted, the achievable emission reductions 
vary according to reservoir characteristics and other parameters 
including length of completion, number of fractured zones, pressure, 
gas composition, and fracturing technology/technique. Based on several 
experiences presented at Natural Gas STAR technology transfer 
workshops, this analysis assumes 90 percent of flowback gas can be 
recovered during a REC.\300\ Gas that cannot be recovered during a REC 
can be directed to a completion combustion device in order to achieve 
an estimated 95 percent reduction in overall emissions.
---------------------------------------------------------------------------

    \300\ Memorandum to Bruce Moore, U.S. EPA from ICF Consulting. 
Percent of Emissions Recovered by Reduced Emission Completions. May 
2011.
---------------------------------------------------------------------------

    Completion combustion devices commonly found on drilling sites are 
generally crude and portable, often installed horizontally due to the 
liquids that accompany the flowback gas. These flares can be as simple 
as a pipe with a basic ignition mechanism and discharge over a pit near 
the wellhead. However, the flow directed to a completion combustion 
device may or may not be combustible depending on the inert gas 
composition of flowback gas, which would require a continuous ignition 
source. Sometimes referred to as pit flares, these types of combustion 
devices do not employ an actual control device and are not capable of 
being tested or monitored for efficiency. They do provide a means of 
minimizing vented gas and is preferable to venting.
    The efficiency of completion combustion devices, or exploration and 
production flares, can be expected to achieve 90 percent, on average, 
over the duration of the completion or recompletion.\301\ If the energy 
content of natural gas is low, then the combustion mechanism can be 
extinguished by the flowback gas. Therefore, it is more reliable to 
install an igniter fueled by a consistent and continuous ignition 
source. Because of the exposed flame, open pit flaring can present a 
fire hazard or other undesirable impacts in some situations (e.g., dry, 
windy conditions and proximity to residences). As a result, owners and 
operators may not be able to combust unrecoverable gas safely in every 
case.
---------------------------------------------------------------------------

    \301\ 77 FR 48889-48890, March 22, 2013 (Approval and 
Promulgation of Federal Implementation Plan for Oil and Natural Gas 
Well Production Facilities; Fort Berthold Indian Reservation 
(Mandan, Hidatsa, and Arikara Nation), North Dakota; Rule).
---------------------------------------------------------------------------

    Noise and heat are the two adverse impacts of completion combustion 
device operations. In addition, combustion and partial combustion of 
many pollutants also create secondary pollutants including 
NOX, CO, sulfur oxides (SOX), CO2, and 
smoke/particulates. The degree of combustion depends on the rate and 
extent of fuel mixing with air and the temperature maintained by the 
flame. Most hydrocarbons with carbon-to-hydrogen ratios greater than 
0.33 are likely to smoke. The high methane content of the gas stream 
routed to the completion combustion device, it suggests that there 
should not be smoke except in specific circumstances (e.g., energized 
fractures). The stream to be combusted may also contain liquids and 
solids that will also affect the potential for smoke.
    The previous BSER analyses cost effectiveness per ton of methane 
and VOC emissions reduced per completion event evaluated for REC, 
completion combustion, and REC and completion combustion were updated 
to 2019 dollars. The results of this updated analysis are provided 
below, and details are provided in the NSPS OOOOb and EG TSD for this 
rulemaking.
    The updated capital cost for performing a REC for a well completion 
or recompletion lasting 3 days is estimated to be $15,174 (2019 
dollars). Monetary savings associated with additional gas captured to 
the sales line is estimated based on a natural gas price of $3.13 per 
Mcf. It was assumed that all gas captured would be included as sales 
gas. The updated capital and cost for wells including completion 
combustion devices resulted in an estimated average completion 
combustion device cost of approximately of $4,198 per well completion 
(2019 dollars). For both REC and completion combustion devices, the 
capital costs are one-time events, and annual costs were conservatively 
assumed to be equal to the capital costs. The EPA also evaluated the 
costs that would be associated with using a combination of a REC and 
completion combustion device. The annual costs would be a combined 
estimated capital and annual cost of $19,371 (2019 dollars). As a 
result of updating capital/annual costs to reflect 2019 dollars and 
decreasing the control efficiency assumed for completion combustion 
from 95 percent to 90 percent, the cost effectiveness estimates are 
slightly higher, but substantially similar to previous cost 
effectiveness BSER analysis control option estimates for natural gas 
well and oil well completions and recompletions.
    For gas wells, under the single pollutant approach where all the 
costs are assigned to the reduction of methane emissions and zero to 
reduction of VOC, the cost effectiveness estimates were approximately 
$1,180 per ton of methane reduced for REC ($990 with natural gas 
savings), $330 for completion combustion, and $1,420 for a combination 
of REC and completion combustion ($1,250 with natural gas savings). If 
all costs were assigned to VOC reduction and zero to methane reduction, 
the cost effectiveness estimates were approximately $4,230 per ton of 
VOC removed for REC ($3,570 with natural gas savings), $1,170 for 
completion combustion, and $5,110 for a combination of REC and 
completion combustion ($4,490 with natural gas savings). Under the 
multipollutant approach where half the cost of control is assigned to 
the methane reduction and half to the VOC reduction, these estimates 
are approximately $590 per ton of methane reduced for REC ($500 with 
natural gas savings), $160 for completion combustion, and $710 for a 
combination of REC and completion combustion ($630 with natural gas 
savings). For VOC, the cost effectiveness

[[Page 63236]]

estimates were approximately $2,100 per ton of VOC removed for REC 
($1,790 with natural gas savings), $590 for completion combustion, and 
$2,600 for a combination of REC and completion combustion ($2,250 with 
natural gas savings).
    For oil wells, under the single pollutant approach where all the 
costs are assigned to the reduction of methane emissions and zero to 
reduction of VOC emissions, the cost effectiveness values were 
approximately $1,620 per ton of methane reduced for REC ($1,440 with 
natural gas savings), $450 for completion combustion, and $1,960 for a 
combination of REC and completion combustion ($1,790 with natural gas 
savings). Where all costs were assigned to reducing VOC emissions and 
zero to reducing methane emissions, the cost effectiveness estimates 
were approximately $5,840 per ton of VOC removed for REC ($5,190 with 
natural gas savings), $1,620 for completion combustion, and $7,070 for 
a combination of REC and completion combustion ($6,450 with natural gas 
savings). Under the multipollutant approach where half the cost of 
control is assigned to the methane reduction and half to the VOC 
reduction, these estimates are approximately $810 per ton of methane 
reduced for REC ($720 with natural gas savings), $230 for completion 
combustion, and approximately $980 for a combination of REC and 
completion combustion ($900 with natural gas savings). For VOC, the 
cost effectiveness estimates were approximately $2,920 per ton of VOC 
removed for REC ($2,600 with natural gas savings), $810 for completion 
combustion, and $3,530 for a combination of REC and completion 
combustion ($3,220 with natural gas savings).
    As noted above, the current NSPS OOOOa requirements consist of a 
combination of REC and completion combustion for hydraulically 
fractured natural gas and oil well completions. These techniques have 
been employed by the oil and gas industry since 2012 for natural gas 
well completions and 2016 for oil well completions. The EPA concludes 
that the cost effectiveness of REC, completion combustion, or a 
combination, for natural gas and oil wells are within the range that 
the EPA considers to be reasonable when considering both methane and 
VOC cost effectiveness. Since there are multiple scenarios where the 
cost effectiveness of the control measures is reasonable for natural 
gas and oil wells (including the cost effectiveness of VOC for REC and 
combined REC and completion combustion), we conclude that the overall 
cost effectiveness is reasonable.
    There are secondary impacts from the use of a completion combustion 
device, as the combustion of the gas creates secondary emissions of 
hydrocarbons, NOX, CO2, and CO. The EPA considers 
the magnitude of these emissions to be reasonable given the significant 
reduction in methane and VOC emissions that the control would achieve. 
Details of these impacts are provided in the NSPS OOOOb and EG TSD for 
this rulemaking. There are no other wastes created or wastewater 
generated from either REC or completion combustion.
    In light of the above, we determined that the current standards, 
which consist of a combination of REC and combustion, continue to 
represent the BSER for reducing methane and VOC emissions from well 
completions of hydraulically fractured or refractured oil and natural 
gas wells. We therefore propose to retain these standards in the 
proposed NSPS OOOOb.
    As discussed in section XII.I.1.c, in the 2020 Technical Rule, the 
EPA made certain amendments to the VOC standards for well completions 
in the 2016 NSPS OOOOa. For the same reasons provided in the 2020 
Technical Rule and discussed in section X.B.1 of this preamble for 
including these amendments for methane in NSPS OOOOa, the EPA is 
proposing to include these methane and VOC amendments for well 
completions in the NSPS OOOOb rule.
2. EG OOOOc
    A well completion operation following hydraulic fracturing or 
refracturing is a ``modification,'' as defined in CAA section 111(a), 
as each such well completion operation involves a physical change to a 
well that results in an increase in emissions; accordingly, each such 
operation would trigger the applicability of the NSPS. Therefore, there 
are no ``existing'' well completion operations of hydraulically 
fractured or refractured oil or natural gas wells. In light of the 
above, there are no proposed presumptive standards for such operations 
in this action.

J. Proposed Standards for Oil Wells With Associated Gas

1. NSPS OOOOb
a. Background
    Wells in some formations and shale basins are drilled primarily for 
oil production. Although the wells are drilled for oil, the wells may 
produce an associated, pressurized natural gas stream. The natural gas 
is either naturally occurring in a discrete gaseous phase within the 
liquid hydrocarbon or is released from the liquid hydrocarbons by 
separation. In many areas, a natural gas gathering infrastructure may 
be at capacity or unavailable. In such cases, if there is not another 
beneficial use of the gas at the site (e.g., as fuel) the collected 
natural gas is either flared or vented directly to the atmosphere.
    Emissions from associated gas venting and flaring are not regulated 
by either the 2012 NSPS OOOO or the NSPS OOOOa. The EPA did not 
evaluate BSER for associated gas production in either rulemaking. For 
this rulemaking, the EPA is proposing that methane and VOC emissions 
resulting from associated gas production be reduced by at least 95 
percent.
b. Definition of Affected Facility
    The EPA is proposing the definition of an oil well associated gas 
affected facility as an oil well that produces associated gas.
c. Description
    In 2019, according to the EIA, the number of onshore gas producing 
oil wells in the U.S.\302\ was 334,342 and the volume of vented and 
flared natural gas in 2019 was 523,066 million cubic feet.\303\ 
According to the 2021 GHGI, in 2019 venting of associated gas emitted 
42,051 metric tons of CH4 and 1,291 metric tons of 
CO2 and flaring of associated gas emitted 81,797 metric tons 
of CH4 and 25,355,892 metric tons of CO2.
---------------------------------------------------------------------------

    \302\ https://www.eia.gov/dnav/ng/ng_prod_oilwells_s1_a.htm. The 
number of onshore gas producing oil wells was derived from the 
``U.S. Natural Gas Number of Oil Wells'' subtracting ``Federal 
Offshore--Gulf of Mexico'' wells [336,732--2,390 = 334,342 wells].
    \303\ https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_VGV_mmcf_a.htm. The volume of vented and flared 
natural gas was derived from ``U.S. Natural Gas Vented and Flared'' 
subtracting ``Alaska--State Offshore'' and ``California--State 
Offshore'' and ``Federal Offshore--Gulf of Mexico'' and 
``Louisiana--State Offshore'' and ``Texas--State Offshore'' 
[538,479-825-0-14,461-45-82 = 523,066].
---------------------------------------------------------------------------

    For the 2019 reporting year in GHGRP subpart W, there were a total 
of 2,500 wells that reported emissions from the venting of associated 
gas emissions. The total emissions from these wells were just over 
33,900 metric tons of methane (848,000 metric tons CO2e). 
Over 90 percent of these methane emissions were reported in three 
basins--Gulf Coast, Williston, and Permian. Examining this information 
by State shows that almost half of the venting wells and over 64 
percent of the methane emissions from the venting of associated gas 
occurs in Texas. Texas and North Dakota account for almost 90

[[Page 63237]]

percent of the reported methane emissions from vented associated gas 
oil wells. The average methane emissions from the venting of associated 
gas in 2019 was 13.6 metric tpy per venting well. The average per State 
ranges from 0.03 tpy per venting well in California to over 340 tpy per 
venting well in North Dakota.
    The 2019 GHGRP subpart W data also show that there were over 38,000 
wells reporting that they flared associated gas, with over 21 million 
metric tons of CO2 emissions and over 68,000 metric tons of 
methane emissions. As with the venting emissions, the majority of the 
wells flaring associated gas (over 93 percent) were in the Gulf Coast, 
Williston, and Permian basins. Approximately 96 percent of the 
CO2 and methane emissions were reported in these three 
basins. The majority of the wells flaring associated gas (over 72 
percent) and emissions (over 87 percent) were from wells in Texas and 
North Dakota.
d. Control Options
    For new and existing sources (oil wells), options to mitigate 
emissions from associated gas in order of environmental and resource 
conservation benefit include:
     Capturing the associated gas from the separator and 
routing into a gas gathering flow line or collection system;
     Beneficially using the associated gas (e.g., onsite use, 
natural gas liquid processing, electrical power generation, gas to 
liquid);
     Reinjecting for enhanced oil recovery; and
     Flaring with legally and practicably enforceable limits.
    Typically, State oil and gas regulatory agencies (or, on certain 
public and Tribal lands, the BLM) regulate venting and flaring of 
associated gas from oil wells to ensure oil and natural gas resources 
are conserved and utilized in a manner consistent with their respective 
statutes. State oil and gas regulatory agencies typically encourage, 
and in some cases require, capture (conservation) over flaring, then 
flaring over venting. In addition, these State regulators have adopted 
a variety of approaches for regulating venting and flaring of 
associated gas from oil wells. Some require technical and economic 
feasibility analyses for continuing flaring beyond a certain time 
(e.g., one year). Some require gas capture plans to track and 
incrementally increase the percentage of gas captured (rather than 
flared) over prescribed timelines and some of these include provisions 
to curtail production in the event of not meeting gas capture goals. 
Many State oil and gas regulations recognize that there are times when 
gas capture may not be feasible, such as when there is no gas gathering 
pipeline to tie into, the gas gathering pipeline may be at capacity, or 
a compressor station or gas processing plant downstream may be off-
line, thus closing in the gas gathering pipeline. Venting is allowed by 
some State and regulatory agencies in certain circumstances such as 
emergency or upset conditions, during production evaluation, and well 
purging or productivity tests. In cases where venting is allowed, these 
rules typically require reporting of the volume of gas flared and 
vented (and sometimes a gas analysis), while some States combine 
flaring and venting information together in publicly accessible well 
data.
    Where flares are allowed, these State oil and gas regulations 
typically do not include monitoring, recordkeeping and reporting on the 
performance of the flare and would not be recognized as providing 
legally and practicably enforceable limits for CAA purposes. Some State 
environmental regulators address associated gas with a regulation 
stipulating flaring over venting that includes monitoring, 
recordkeeping and reporting provisions, while others regulate flaring 
over venting without monitoring requirements.
    The EPA is interested in information on, and the feasibility, of 
options to utilize associated gas in some useful manner in situations 
where a sales line is not available. In addition to use as fuel, such 
options could include conversion technologies where methane is 
converted into hydrogen or other added value chemicals. The EPA is 
interested in information on these, as well as other, technologies.
e. 2021 BSER Analysis
    In performing the BSER analysis for emissions from associated gas 
oil wells, we recognize there are similarities between the control 
options available for associated gas and those available for emissions 
from oil well completions. We are soliciting comment on these 
similarities. For both flowback emissions during oil well completions 
and associated gas production, if the infrastructure exists to allow 
the routing of the gas to a sales line (e.g., ``into a gas flow line or 
collection system''), owners and operators will almost always choose 
that option given the economic benefits of being able to sell the gas. 
For example, in the 2019 GHGRP subpart W data, applicable facilities 
reported over 1.2 trillion scf of associated gas was routed to sales 
lines. This represents only a subset of the total volume of associated 
gas sent to a sales line, as GHGRP subpart W does not require reporting 
of this volume in subbasins where the company is not also reporting 
venting or flaring associated gas.
    The environmental benefit of routing all associated gas to a sales 
line is significant, as there are no methane and VOC emissions. The EPA 
assumes that in situations where gas sales line infrastructure is 
available, there is minimal cost to owners and operators to route the 
associated gas to the sales line. While situations at well sites can 
differ, which would impact this cost, the EPA believes that in every 
situation the value of the natural gas captured and sold would outweigh 
these minimal costs of routing the gas to the sales line, thus 
resulting in overall savings. Given the prevalence of this practice, 
the environmental benefit, and the economic benefits to owners and 
operators, the EPA concludes that BSER is routing associated gas from 
oil wells to a sales line. The EPA seeks comment on this proposed BSER 
determination, including comment on how to define whether an oil well 
producing associated gas has access to a sales line for purposes of 
this BSER and what factors (such as proximity to an existing sales 
line) should bear on that determination.
    NSPS OOOOa also includes other compliance options that achieve a 
100 percent reduction in emissions from recovered flowback gas. These 
are ``re-inject the recovered gas into the well or another well, use 
the recovered gas as an onsite fuel source, or use the recovered gas 
for another useful purpose that a purchased fuel or raw material would 
serve.'' 40 CFR 60 60.5375a(a)(1)(ii). The EPA believes that, for 
associated gas from oil wells, the options of using the gas as an 
onsite fuel source or for another useful purpose are also viable 
alternatives to routing to a sales line. However, a significant 
difference exists between the short-term and relatively small volume of 
gas recovered during the limited duration of completion flowback versus 
the consistent flow of recovered gas from ongoing production from the 
well. Because of this difference, the EPA does not have information 
that supports re-injecting the associated gas into the well or another 
well as a viable emissions control alternative. Therefore, the EPA is 
specifically requesting comment on whether NSPS OOOOb should include 
re-injecting associated gas as an alternative to routing the gas to a 
sales line.
    The format of the well completion provisions in NSPS OOOOa 
recognize that routing the recovered gas to a gas flow line or 
collection system, re-

[[Page 63238]]

injecting the recovered gas, or using the recovered gas fuel or for 
another purpose may not be technically feasible. In these situations, 
owners and operators are required to route the flowback emissions to a 
completion combustion device.
    Similarly, the EPA recognizes that there are associated gas oil 
wells where there is no access to a gas sales line. Therefore, as an 
aspect of BSER in these situations, the EPA evaluated the flaring of 
the associated gas as an option to control emissions for situations 
where access to a sales line is not available.
    As discussed previously, the average annual methane emissions from 
the venting of associated gas reported in GHGRP subpart W for 2019 is 
13.6 metric tpy (14.9 tpy) per venting well. Using a representative gas 
composition for the production segment, the estimated VOC emissions 
would be 4.15 tpy per well. We conducted the BSER analysis using this 
emissions level as a representative well.
    The installation and proper operation of a flare can achieve 95 
percent and greater reduction in methane and VOC emissions. To be 
conservative, a 95 percent emission reduction was used for the BSER 
analysis. Therefore, the resulting emission reductions are 14.2 tpy 
methane and 3.9 tpy VOC.
    The capital cost of a flare is estimated to be $5,719. This was 
based on a 2011 Natural Gas Star Pro Fact Sheet and updated to 2019 
dollars. The resulting capital recovery, assuming a 7 percent interest 
rate and 15-year equipment life, was $628. The Natural Gas Star Pro 
report estimated the cost of the natural gas needed for the pilot was 
$1,800 per year. For this cost analysis, we assumed that this cost was 
not warranted since the associated gas could be used to fuel the pilot. 
We are soliciting comments on this cost estimate.
    The EPA stresses that 95 percent or greater emission reduction is 
achievable if the flare is properly operated and maintained. In order 
to ensure that this occurs, the EPA proposes to apply the requirements 
in Sec.  60.18 of the part 60 General Provisions to oil wells flaring 
associated gas. In order to account for the cost of the compliance with 
these requirements, we assumed that the associated cost would be 25 
percent of the total annual costs, or an additional $160. This results 
in a total estimated annual cost of $785. We are soliciting comment on 
the estimated costs associated with compliance with the Sec.  60.18 
monitoring, reporting, and recordkeeping costs for flares used to 
control emissions of vented associated gas emissions, and whether those 
requirements would ensure the flare is achieving the proposed emission 
reduction of 95 percent or greater.
    Based on these annual costs and the emission reductions cited 
above, the cost effectiveness, using the single pollutant method, is 
$55 per ton of methane reduction and $200 per ton of VOC reduction. 
Using the multipollutant approach, the cost effectiveness is $30 per 
ton of methane and $100 per ton of VOC. These cost effectiveness values 
are well within the range considered reasonable by the EPA.
    As discussed above, while flares significantly reduce the methane 
and VOC emissions, there are CO, CO2, and NOX 
emissions resulting from the combustion of the associated gas. We 
estimate that for the representative well, the annual emissions 
resulting from the flaring of the associated gas would be 50 tpy 
CO2, 0.1 tpy CO, and 0.03 tpy NOX. While these 
secondary impacts are not negligible, the EPA notes that emissions from 
flaring represents over an 80 percent reduction in CO2e 
emissions as compared to venting.
    Based on our analysis, we find that the BSER for reducing methane 
and VOC emissions from associated gas venting at well sites is routing 
of the associated gas from oil wells to a sales line. In the event that 
access to a sales line is not available, we are proposing that the gas 
can be used as an onsite fuel source, used for another useful purpose 
that a purchased fuel or raw material would serve, or routed to a flare 
or other control device that achieves at least a 95 percent reduction 
in emissions of methane and VOC.
    We are requesting comment on the affected facility definition and 
the overall format of the proposed requirements. The EPA is proposing 
that an associated gas oil well affected facility be each oil well that 
produces associated gas. The EPA is soliciting comments on how to 
define ``associated gas'' or an ``oil well that produces associated 
gas.'' The proposed NSPS OOOOb would require that all associated gas be 
routed to a sales line. In the event that access to a sales line is not 
available, the proposed NSPS OOOOb would require that the gas can be 
used as an onsite fuel source, used for another useful purpose that a 
purchased fuel or raw material would serve, or routed to a flare or 
other control device that achieves at least a 95 percent reduction in 
emissions of methane and VOC.
    Under this proposal, every oil well that produces associated gas 
would be an affected facility and therefore, subject to the rule. For 
those wells where the associated gas is routed to a sales line, the 
only requirement would be to certify that this is occurring. Wells that 
use the associated gas as a fuel or for another purpose would be 
required to document how it is used. If the associated gas is routed to 
a flare, all of the proposed monitoring, recordkeeping, and reporting 
requirements would apply.
    As an alternative, the EPA is soliciting comments on defining the 
affected facility as each oil well that produces associated gas and 
does not route the gas to a sales line. This would significantly reduce 
the number of affected facilities, although the burden for owners and 
operators that route the gas to a sales line would be similar. While 
they would not be required under NSPS OOOOb to maintain documentation 
that the gas is routed to a sales line, they would still need to 
maintain documentation to prove that the well was not an affected 
facility. Under this alternative, the proposed rule would require that 
the gas be used as an onsite fuel source, used for another useful 
purpose that a purchased fuel or raw material would serve, or routed to 
a flare or other control device that achieves at least a 95 percent 
reduction in emissions of methane and VOC. The EPA's concern with this 
alternative is that while we believe that most owners and operators 
would route the gas to a sales line if there is access, it would not 
specifically require routing the gas to a sales line. We expect that 
the cost of a flare, along with the associated monitoring, reporting, 
and recordkeeping costs, will provide additional incentive for owners 
and operators to connect to an available sales line. We are requesting 
comment on how, under this alternative approach, to incentivize owners 
and operators even more to capture or beneficially use associated gas. 
The EPA is specifically requesting comment on whether the proposed 
requirements will incentivize the sale or productive use of captured 
gas, and if not, other methods that the EPA could use to incentivize or 
require the sale or productive use instead of flaring.
2. EG OOOOc
    The EPA evaluated BSER for the control of methane from existing 
associated gas oil wells that do not route the gas to a sales line or 
to a process for another beneficial use (designated facilities) and 
translated the degree of emission limitation achievable through 
application of the BSER into a proposed presumptive standard for these 
facilities that essentially mirrors the proposed NSPS OOOOb.
    First, based on the same criteria and reasoning as explained above, 
the EPA is proposing to define the designated

[[Page 63239]]

facilities in the context of those that commenced construction on or 
before November 15, 2021. Based on information available to the EPA, we 
did not identify any factors specific to existing sources that would 
indicate that the EPA should change these definitions as applied to 
existing sources. As such, for purposes of the emission guidelines, the 
definition of a designated facility in terms of associated gas oil 
wells as existing oil wells with associated gas that do not route the 
gas to a sales line or to a process for another beneficial use.
    Next, the EPA finds that the control options evaluated for new 
sources for NSPS OOOOb are appropriate for consideration in the context 
of existing sources under the EG OOOOc. The EPA finds no reason to 
evaluate different, or additional, control measures in the context of 
existing sources because the EPA is unaware of any control measures, or 
systems of emission reduction, for the venting of associated gas that 
could be used for existing sources but not for new sources.
    Next, the methane emission reductions expected to be achieved via 
application of the control measures identified above for new sources 
are also expected to be achieved by application of the same control 
measures to existing sources. The EPA finds no reason to believe that 
these calculations would differ for existing sources as compared to new 
sources because the EPA believes that the baseline emissions of an 
uncontrolled source are the same, or very similar, and the efficiency 
of the control measures are the same, or very similar, compared to the 
analysis above. This is also true with respect to the costs, non-air 
environmental impacts, energy impacts, and technical limitations 
discussed above for the control options identified.
    The information presented above regarding the costs related to new 
sources and the NSPS are also applicable for existing sources. The EPA 
considers these cost effectiveness values to be reasonable. Since none 
of the other factors are different for existing sources when compared 
to the information from discussed above for new sources, the EPA 
concludes that BSER for existing sources and the proposed presumptive 
standard for EG OOOOc to be the requirement to route associated gas to 
a flare or other control device that achieves at least 95 percent 
control.
    Related to control option of flaring with legally and practicably 
enforceable limits at existing oil wells specifically, enhancing 
monitoring and performance requirements for flares at existing oil 
wells may be an important emissions reduction measure. For those 
operators who have already installed monitoring capability on their 
existing flares, the additional investment may be minimal to cover 
reporting of performance. For those existing oil wells where operators 
do not have flare monitoring installed, the EPA solicits comment both 
on the flare performance monitoring technology available and the cost 
of procuring, installing, operating and maintaining such technology. 
This could include, but is not limited to, digital pilot light 
monitors, combustion temperature, gas flow meters, gas chromatography 
(GC) units, and passive remote monitoring of combustion efficiencies at 
the flare tip. Similar technologies have been used for flares 
controlling landfill gas, including automated notifications of flare 
failure. Additional discussion of control devices, including flares, is 
included in section XIII.D of this preamble.

K. Proposed Standards for Sweetening Units

    Sulfur dioxide (SO2) standards for onshore sweetening 
units were first promulgated in 1985 and codified in 40 CFR part 60, 
subpart LLL (NSPS LLL). In 2012, the EPA reviewed the NSPS for the oil 
and natural gas sector, and the resulting 2012 NSPS OOOO rule 
incorporated provisions of NSPS LLL with minor revisions to adapt the 
NSPS LLL language to NSPS OOOO (77 FR 49489). The incorporated 
provisions required sweetening unit affected facilities to reduce 
SO2 emissions via sulfur recovery. The EPA also increased 
the SO2 emission reduction standard from the subpart LLL 
requirement for units with a sulfur production rate of at least 5 long 
tons per day (LT/D) from 99.8 percent to 99.9 percent. This change was 
based on the reanalysis of the original data used in the NSPS LLL BSER 
analysis.
    In 2016, the EPA finalized the NSPS OOOOa rule--which established 
standards for both methane and VOCs for certain equipment, process and 
activities across the oil and natural gas sector. The final 2016 NSPS 
OOOOa rule reaffirmed and included the SO2 emission 
reduction requirements as specified in the 2012 NSPS OOOO rule (81 FR 
35824).
    The EPA then amended the 2016 NSPS OOOOa rule in 2020 to correct an 
affected facility definition applicability error in the rule as it 
pertains to sweetening units. The 2016 NSPS OOOOa rule erroneously 
limited the applicability of the SO2 standards to sweetening 
units located at onshore natural gas processing plants. This limitation 
was not included in NSPS LLL, and no reason was identified as to ``why 
the extraction of natural gas liquids relates in any way to the 
SO2 standards such that the standards should only apply to 
sweetening units located at onshore natural gas processing plants 
engaged in extraction or fractionation activities'' (85 FR 57398). 
Therefore, the 2020 NSPS OOOOa final rule amendments corrected the 
affected facility description applicability error to correctly define 
affected facilities as any onshore sweetening unit that processes 
natural gas produced from either onshore or offshore wells at 40 CFR 
60.5365a(g).
    A sweetening unit refers to a process device that removes 
H2S and/or CO2 from the sour natural gas stream 
(40 CFR 60.5430a)--i.e., sweetening units convert H2S in 
acid gases (i.e., H2S and CO2) that are separated 
from natural gas by a sweetening process, like amine gas treatment, 
into elemental sulfur in the Claus process. These units can operate 
anywhere within the production and processing segments of the oil and 
natural gas source category, including as stand-alone processing 
facilities that do not extract or fractionate natural gas liquids from 
field gas (85 FR 57408, September 15, 2020).
    An estimated 6,900 tons of SO2 emissions were reported 
under the National Emissions Inventory (NEI) for Year 2017 \304\ for 
Source Classification Code 31000201 (Industrial Processes Oil and Gas 
Production, Natural Gas Production, Gas Sweetening: Amine Process) and 
SCC 31000208 (Industrial Processes, Oil and Gas Production, Natural Gas 
Production, Sulfur Recovery Units).
---------------------------------------------------------------------------

    \304\ 2017 National Emissions Inventory (NEI) Data [verbar] US 
EPA.
---------------------------------------------------------------------------

    Pursuant to CAA section 111(b)(1)(B), the EPA reviewed the current 
standards in NSPS OOOOa (including the 2020 revisions) for sweetening 
units and proposes to determine that they continue to reflect the BSER 
for reducing SO2 emissions. The EPA has not identified any 
greater emissions control level than what is currently required under 
NSPS OOOOa for sweetening unit affected facilities. Therefore, the EPA 
is proposing to retain/include the current NSPS OOOOa requirements for 
sweetening units for the control of SO2 emissions from 
sweetening unit affected facilities in NSPS OOOOb. The proposed NSPS 
OOOOb maintains the requirement that each sweetening unit that 
processes natural gas produced from either onshore or offshore wells is 
an affected facility; as well as each sweetening unit

[[Page 63240]]

that processes natural gas followed by a sulfur recovery unit. Units 
with a sulfur production rate of at least 5 long tons per day must 
reduce SO2 emissions by 99.9 percent. Compliance with the 
standard is determined based on initial performance tests and daily 
reduction efficiency measurements. For affected facilities that have a 
design capacity less than 2 LT/D of H2S in the acid gas 
(expressed as sulfur), recordkeeping and reporting requirements are 
required; however, emissions control requirements are not required. 
Facilities that produce acid gas that is entirely re-injected into oil/
gas-bearing strata or that is otherwise not released to the atmosphere 
are also not subject to emissions control requirements.

XIII. Solicitations for Comment on Additional Emission Sources and 
Definitions

    The EPA is considering including additional sources as affected 
facilities under the proposed NSPS OOOOb and the proposed EG OOOOc. 
Specifically, the EPA is evaluating the potential for establishing 
standards applicable to abandoned and unplugged wells, pipeline pigging 
and related blowdown activities, and tank truck loading operations. 
While the EPA has assessed these sources based on currently available 
information, we have determined that we need additional information to 
evaluate BSER and propose NSPS and EG for these emissions sources. As 
described below, the EPA is soliciting information to assist in this 
effort.
    The EPA is also assessing whether proposed standards that would 
require 95 percent reduction based on a combustion control device as 
the BSER (e.g., standards for storage vessels, centrifugal compressors, 
pneumatic pumps, and associated gas that cannot be routed to a sales 
line or consumed for a useful purpose) could be further strengthened, 
including the potential for additional monitoring and associated 
recordkeeping and reporting requirements, to ensure proper design and 
operation of combustion control devices.
    While we are not proposing NSPS nor EG for these emissions sources 
(i.e., abandoned wells, pigging operations, or tank truck loading) or 
updates to ensure proper design and operation of combustion control 
devices in this action, the EPA is soliciting comment and information 
that would better inform the EPA as we continue to evaluate options for 
these sources. Should the EPA receive information through the public 
comment process that would help the Agency evaluate BSER for these 
emission sources, the EPA could consider NSPS and EG for these sources 
through a supplemental proposal. In this section we summarize the 
available information that we have evaluated regarding emissions, 
control options, and where specific States may have existing 
requirements, and we solicit specific comments. In the case of 
combustion control devices, we solicit comment on the current standard 
of 95 percent reduction and what additional monitoring, recordkeeping, 
and reporting may be appropriate to ensure compliance. We also 
generally solicit comment and information on the following topics 
associated with these emission sources.
    The EPA solicits comment on the control options discussed below and 
how these controls may be broadly applied across different basins or 
geographic areas. The EPA solicits comment on what equipment is onsite 
during these emission events. The EPA solicits comment on the technical 
feasibility of control options and any instances where it is not 
technically feasible to minimize emissions from these sources 
including, but not limited to, any retrofit concerns for existing 
sources. The EPA solicits comment on any practices owners and operators 
already implement as part of voluntary efforts or State requirements to 
minimize emissions from these sources. The EPA solicits comment on 
methods/approaches for estimating baseline emissions from these 
sources, estimating cost of control, and efficiency of control options. 
Finally, the EPA solicits comment on the cost of maintaining records 
and submitting reports for these emissions sources, including the types 
of records that are appropriate to maintain and report.

A. Abandoned Wells

    The EPA is soliciting comment for potential NSPS and EG to address 
issues with emissions from abandoned, or non-producing oil and natural 
gas wells that are not plugged or are plugged ineffectively. Should the 
EPA receive information through the public comment process that would 
help the Agency evaluate BSER, the EPA may propose NSPS and EG through 
a supplemental proposal.
    The EPA broadly characterizes abandoned wells as oil or natural gas 
wells that have been taken out of production, which may include a wide 
range of non-producing wells. This includes wells that State 
governments classify as idle, inactive, dormant, or shut-in, but not 
plugged. The classification varies from State to State, and State 
governments may allow these wells to be dormant, without plugging, for 
varying time periods that may last several years. It also includes 
wells with no production for many years--sometimes more than a decade--
and no responsible operator. These wells are commonly referred to as 
orphaned, deserted, or long-term idle. Finally, this includes wells 
that have been abandoned for long periods, known as legacy wells. State 
governments have varied definitions of temporarily idled, orphaned, or 
non-producing wells.
    It is the EPA's understanding that since non-producing oil and 
natural gas wells generally are not staffed and are seldom monitored, 
many have fallen into disrepair. The EPA recognizes that some States 
and NGOs also have elevated concerns about the potential number of low-
production wells that could be abandoned in the near future as they 
reach the end of their productive lives. The 2021 GHGI estimates that 
in 2019 the U.S. population of abandoned wells (including orphaned 
wells and other non-producing wells) is around 3.4 million (about 2.7 
million abandoned oil wells and 0.6 million abandoned natural gas 
wells).\305\ These non-producing wells often have methane, 
CO2, and VOC emissions. The most recent studies of emissions 
from abandoned wells focus on methane emissions, which are larger than 
the CO2 or VOC emissions from such wells.\306\ The GHGI 
estimates that abandoned oil wells emitted 209 kt of methane and 4 kt 
of CO2 in 2019. While emissions of both pollutants from 
abandoned oil wells decreased by 10 percent from 1990, the total 
population of these wells increased 28 percent. The GHGI estimates that 
abandoned gas wells emitted 55 kt of methane and 2 kt of CO2 
in 2019. While emissions of both pollutants increased from abandoned 
gas wells by 38 percent from 1990, the total population of such wells 
increased 84 percent.
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    \305\ The GHGI separates non-producing oil and gas wells into 
those that are unplugged and plugged. The abandoned wells identified 
in the GHGI include those that have been taken out of production 
temporarily, but can return to production, as well as orphan wells.
    \306\ See TSD at Docket ID No. EPA-HQ-OAR-2021-0317.
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    The large populations of abandoned unplugged wells are likely due 
to various circumstances. For instance, some operators declare 
bankruptcy before wells are plugged, and for many, bonding requirements 
represent only a fraction of the actual costs to plug the well and 
restore the well site. Wells are also abandoned or idled when changing 
oil or natural gas prices make them unprofitable to continue 
production.

[[Page 63241]]

    The EPA recognizes that many oil and natural gas producing States 
require the plugging of non-producing oil and natural gas wells, and 
subsequent restoration of the well site. However, the large number of 
abandoned, unplugged wells nationwide suggests that Federal standards 
may be warranted. Many oil and gas producing States specify the time in 
which wells may remain in idle status without State approval. At the 
end of that time, States generally require tests of well integrity 
before giving approval for additional time in this idle status.
    In its 2018 survey of idled and abandoned wells, the IOGCC 
documented State definitions and requirements for idled wells, as well 
as the management plans for those wells.\307\ There is variation in how 
States define these idle wells, ranging from no definitions to specific 
definitions for documented and undocumented orphaned and abandoned 
wells. Further, there is great variability in the allowance for the 
length of time a well may remain in idle status with or without 
approval, with some States limiting that time to a few months while 
other States allow idled status indefinitely. While some States require 
strict management plans of idled wells, others do not. Finally, some 
States provide funds for plugging, remediating, and reclaiming orphan 
wells, and others do not. These funds are supported by civil penalties, 
settlements, forfeited bonds, and State appropriations. The IOGCC's 
survey found that 28 States and Canadian provinces have wells approved 
to remain in idle status, with most having between 100 and 10,000 
approved idle wells. Most States and provinces maintain inventories of 
documented orphan wells and prioritize orphan wells for plugging 
according to risk. States and provinces reported from zero to 13,266 
documented orphan wells, with about half reporting fewer than 100 
orphan wells.
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    \307\ See IOGCC Report located at Docket ID No. EPA-HQ-OAR-2021-
0317.
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    The IOGCC's 2018 survey also collected estimates from some States 
on the number of undocumented orphan wells, including those for which 
no permits or other records exist. Most of these wells were drilled 
before there was any regulatory oversight. Ten States reported no 
undocumented orphan wells. Nine other States did not provide an 
estimate. Eleven States provided an estimate ranging from fewer than 10 
to 100,000 or more undocumented orphan wells. Most of the States 
surveyed by the IOGCC had established funds dedicated to plugging 
orphan wells. Money for these funds comes primarily from taxes, fees, 
or other assessments on the oil and gas industry.
    The EPA has identified the following potential strategies to reduce 
air emissions from these sources. The first strategy is to employ 
practices and procedures to ensure proper well closure. Under this 
strategy, the EPA could focus on well closure requirements aimed at 
preventing future abandonment of unplugged wells and halt the growth of 
this unplugged population. Given that all wells eventually reach their 
end of life, this strategy could be applied to both new and existing 
wells. Under the NSPS, for example, the EPA could require owners or 
operators to submit a closure plan describing when and how the well 
would be closed and to demonstrate whether the owner or operator has 
the financial capacity to continue to demonstrate compliance with the 
rules until the well is closed and to carry out any required closure 
procedures per the rule. This demonstration could require some 
financial assurance or bonding if the Agency determines the financial 
capacity of the owner or operator to continue to assure compliance with 
the rule is in doubt. The EPA also could require reporting any transfer 
of well ownership, along with a copy of the well closure requirements, 
to the EPA and/or the applicable State when transferring ownership. The 
Agency might also consider a requirement to temporarily close the well 
to the atmosphere with a swedge and valve or packer or other approved 
method once a well is temporarily abandoned or shut in. As one example, 
this is a requirement under Colorado law for all wells that are 
designated as shut in or temporarily abandoned.\308\
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    \308\ Code of Colorado Regulations, Oil and Gas Conservation 
Commission, 2 CCR 404-1, paragraph b, ``Temporary Abandonment,'' p. 
80.
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    The primary purpose of detailing financial capacity as part of a 
compliance plan, and to potentially require some financial assurance 
bonding, is to ensure that State governments have adequate resources to 
plug oil and gas wells when the owner or operator is unwilling or 
unable to do so. The IOGCC notes that States typically have 
requirements for both single-well or blanket financial assurance. In 
the IOGCC's 2018 survey, 35 States reported information on the types of 
financial assurance accepted in their jurisdictions, with most 
accepting more than one type. The IOGCC noted that the amounts and 
criteria for bonding vary considerably among the States. Single-well 
bond amounts range from $1,500 to $500,000 per well; blanket bonds 
(covering multiple wells) vary from $7,500 to $30,000,000, the IOGCC 
said. In some States, bond amounts are based on well depth; in others, 
bond amounts are based on case-by-case evaluations; and in several, 
bond amounts may be increased if determined necessary.
    That study identified the following types of financial assurance, 
including cash deposit of a payment given as a guarantee that an 
obligation will be met, certificate of deposit of a financial 
instrument certifying that the face amount is on deposit with the 
issuing bank to be redeemed for cash by the State if required, 
financial statements of a report of basic accounting data that depicts 
a firm's financial history and activities, letter of credit, 
irrevocable letter of credit where payment is guaranteed if stipulated 
conditions are met, security interest giving the right to take property 
or a portion of property offered as security, and surety or performance 
bonds as a contract by which one party agrees to make payment on the 
default or debt of another party. Other forms of financial assurance 
include certificates of insurance, consolidated financial funds, escrow 
accounts, and liens. The amounts and criteria for financial assurance 
vary considerably among the States and provinces.
    Another strategy under consideration is to require fugitive 
emissions monitoring at a specified frequency for the duration of time 
the well is idled and unplugged. The EPA's understanding, however, is 
that most idled and non-producing well sites would be classified as 
wellhead only sites, which the EPA is proposing to exclude from 
fugitive emissions monitoring for both new and existing well sites (see 
section XI.A).
    The EPA is aware that other Federal agencies have information on, 
and experience with, abandoned wells, such as the U.S. Forest Service, 
National Park Service, U.S. Fish and Wildlife Service, and the BLM. On 
Federal and Tribal mineral estate, the BLM coordinates with the surface 
management agency when remediating abandoned wells to mitigate the 
potential risks those wells may pose. The EPA may be informed by the 
methods employed by the BLM to monitor and remediate abandoned wells on 
Federal lands, as well as by draft legislative initiatives that may 
expand the scope of the BLM's efforts. The EPA understands that one 
such initiative, the ``Revive Economic Growth and Reclaim Orphaned 
Wells (REGROW) Act,'' could amend the Energy Policy Act of 2005 to

[[Page 63242]]

require the BLM to establish a new program to plug, remediate, and 
reclaim orphaned oil and gas wells and surrounding land, and to provide 
funds to State and Tribal governments for this purpose.\309\
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    \309\ S. 1076, ``To amend the Energy Policy Act of 2005 to 
require the Secretary of the Interior to establish a program to 
plug, remediate, and reclaim orphaned oil and gas wells and 
surrounding land, to provide funds to State and Tribal governments 
to plug, remediate, and reclaim orphaned oil and gas wells and 
surrounding land, and for other purposes,'' 117th Congress, 1st 
Session, as introduced on April 12, 2021, available at https://www.congress.gov/117/bills/s1076/BILLS-117s1076is.xml.
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    The EPA is soliciting additional information that would support a 
determination of the BSER to address emissions from abandoned, idled, 
and non-producing wells. The specific information of interest includes 
updates to the number of abandoned, orphaned, or temporarily idled 
wells in the U.S., which could be State-specific or basin-specific; 
fugitive emission estimates for the wells; and costs of mitigation 
measures, including effective closure requirements and proper plugging 
practices, financial assurance mechanisms, and requiring fugitive 
emissions monitoring while in idled and unplugged status. The EPA is 
also soliciting information on mechanisms to disincentivize operator 
delay in permanently abandoning wells and/or transfer of late-life 
assets to companies that may not be well-positioned to fund proper 
closure. The EPA also solicits information at the State level, on the 
length of time that wells remain temporarily idled before they must be 
inspected by State governments. Further, we are seeking information 
about what would be included in well closure requirements, including 
what closure requirements are appropriate and any recordkeeping and 
reporting associated with those requirements, as well as whether it is 
appropriate to close the well to the atmosphere once it is designated 
as shut in or temporarily abandoned. The EPA also solicits information 
on whether compliance assurance for well closure requirements will 
necessitate certain forms of financial assurance on the part of well 
owners and operators. The EPA solicits comment on effective plugging, 
such as criteria or guidelines are necessary for sufficient plugging 
and post-plugging follow up monitoring necessary over a certain time 
period. Finally, the EPA solicits comments on the cost of monitoring 
idled or abandoned wells or monitoring techniques that might lower the 
costs of such monitoring.

B. Pigging Operations and Related Blowdown Activities

    The EPA is soliciting comment for potential NSPS and EG under 
consideration that include addressing emissions from pipeline pigging 
and related blowdown activities. Should the EPA receive information 
through the public comment process that would help the Agency evaluate 
BSER, the EPA may propose NSPS and EG through a supplemental proposal.
    Raw natural gas is transported from production wells to natural gas 
processing plants through networks of gathering pipelines. After 
natural gas processing, pipeline networks in the transmission and 
storage segment transport the gas to downstream customers. Raw natural 
gas is frequently saturated with hydrocarbons and may contain other 
components such as water, carbon dioxide, and hydrogen sulfide, 
especially upstream of the natural gas processing plant. Liquid 
condensates can accumulate in low elevation segments of the gathering 
pipelines, impeding the flow of natural gas. To maintain gas flow and 
operational integrity of the gathering pipelines, operators 
mechanically push these condensates out of the low elevations and down 
the pipeline by an operation called ``pigging,'' which involves first 
inserting a device called a pig \310\ into a pig launcher upstream of 
the pipeline segment where condensates have accumulated. The natural 
gas flowing through the pipeline then pushes the pig through the 
pipeline, allowing the pig to sweep along the accumulated condensates. 
The pig is removed from the pipeline segment when it is caught in a pig 
receiver. Pigging operations are also conducted using ``smart'' pigs 
that are equipped with sensors to collect data about the pipeline's 
structural characteristics and integrity for safety and maintenance 
purposes.
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    \310\ Pigs are typically spherical, barrel- or bullet-shaped 
objects slightly smaller than the diameter of the pipeline.
---------------------------------------------------------------------------

    Before a pig can be inserted or removed through the hatch of a pig 
launcher or a pig receiver, the pipeline gas in the launcher or 
receiver barrel must be removed. It is common practice to vent the gas 
directly to the atmosphere where gas capture or control are not used. 
This gas is under the same pressure as the pipeline and contains 
methane, ethane, and VOCs including HAP such as benzene, toluene, 
ethylbenzene, and xylene. Emissions can also result from the 
volatilization of collected condensate liquid when the pig barrel is 
depressurized.
    Pig launchers and receivers can be installed within larger 
facilities, such as at a compressor station or natural gas processing 
plant, or can be ``stand-alone'' sites, where the only equipment at a 
particular location is related to pigging operations. Additionally, 
sections of pipeline or equipment that are separate from the pig 
launcher or receiver may need to be evacuated of gas for reasons other 
than pigging, such as routine maintenance or inspection activities. 
Emissions from blowdowns can be calculated by accounting for the volume 
of the section of pipeline or equipment being evacuated, composition of 
that gas being vented, pressure of the gas vented, frequency of the 
blowdown activity, and inclusion of emissions from any volatile liquids 
present in the pipeline section or equipment being vented.
    The EPA is aware of some State and local governments have 
regulations in place that address blowdown activities, including 
pigging. These include limits on the amount of emissions from pigging 
operations, required use of add-on controls, and implementation of best 
management practices.\311\ Estimating emissions from pigging operations 
is fairly straightforward if all variables (e.g., volume, pressure, and 
composition of gas) are known. However, the wide range of variables, 
which are applied in different combinations and are dependent on the 
frequency of blowdown events, can make it challenging to estimate total 
nationwide emissions from pigging and related blowdown activities. For 
example, in 2019, six of the eight operators reporting to GHGRP subpart 
W in the Uinta Basin reported a collective 7,299 blowdown events due to 
pigging that met the threshold for reporting under GHGRP subpart W, but 
the attribution of emissions from each individual pigging event is 
undetermined at this time.\312\ Data reported in 2019 under GHGRP 
subpart W include 472,995 total individual blowdown events from 1,212 
facilities for a combined 307,630 metric tons of methane emitted, 
including 79,746 events at pig launchers or receivers for a combined 
total of 19,066 metric tons of methane, however, these data only 
include emissions from blowdown equipment with a unique physical volume 
greater than 50 cubic feet and occurring at a facility with total 
emissions greater than 25,000 metric

[[Page 63243]]

tons CO2 Eq.\313\ The EPA is also aware of a single operator 
in the Marcellus Shale region that operates around 400 pig launchers 
and receivers which collectively emit approximately 1,335 metric tons 
of methane annually, but the total annual emissions from each launcher 
or receiver varies widely, due to variations in the inputs used to 
calculate emissions from an individual pigging event.\314\ The EPA is 
seeking comment on the availability of nationwide data sets or 
methodologies to better identify the total inventory of pig launchers 
and receivers, and, if no such data set or proxy exists, comment on the 
most defensible method of calculating total emissions from pigging and 
related blowdown activities.
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    \311\ See TSD located at Docket ID No. EPA-HQ-OAR-2021-0317.
    \312\ EPA (2020) Greenhouse Gas Reporting Program. U.S. 
Environmental Protection Agency. Data reported as of September 26, 
2020.
    \313\ Id.
    \314\ See Appendix A to the TSD located at Docket ID No. EPA-HQ-
OAR-2021-0317.
---------------------------------------------------------------------------

    The EPA has identified the following potential control options that 
can reduce emissions from pipeline pig launchers and receivers: (1) 
Reducing the frequency that the pig launcher or receiver must be 
evacuated of gas; (2) eliminating or reducing the volume of gas vented 
during blowdowns; (3) using add-on controls that are applied to 
blowdown emissions; or (4) a combination of these strategies. The EPA 
has identified the following systems as potential control strategies to 
evaluate further.
    First, pig ball valves are a design alternative to conventional pig 
launcher and receiver systems that have a smaller sized barrel (or 
chamber) that launches and receives the pig, thus resulting in reduced 
emissions from pigging operations. A conventional pig launcher or 
receiver system can be retrofitted by replacing the conventional 
launcher and receiver barrels with special ball valves used to insert 
and remove the pig directly from the main pipeline. By replacing the 
large volume barrel with the much smaller volume ball valve, the volume 
of gas vented during each pigging operation can be reduced by as much 
as 80 to 95 percent, with a corresponding reduction in emissions and 
other risks associated with pipeline pigging operations. The net cost 
of a pig ball valve compared to a traditional launcher/receiver should 
consider not only the cost of the valve and its installation, but also 
the savings realized from the prevention of large quantities of vented 
gas and personnel time spent blowing down a larger launcher/receiver. 
These costs and savings will vary according to site-specific 
dimensions, gas composition, and pigging frequency. The EPA understands 
that not every dimension of pipeline and pig launcher or receiver can 
use a pig ball valve and seeks further comment on specific 
circumstances where such equipment is appropriate, potential challenges 
to using a pig ball valve or retrofitting a launcher or receiver to 
accommodate a pig ball valve, and specific costs of installing or 
retrofitting a launcher or receiver compared to a conventional full-
barrel launcher or receiver.
    Second, multi-pig launcher systems are a design alternative to 
conventional launcher/receiver systems and reduce pigging emissions by 
reducing the frequency that launchers and receivers must be opened to 
the atmosphere and vented prior to pig insertion and removal. The 
launcher barrel is designed to hold multiple spherical pigs, which are 
each held in place by gates or pins prior to release. Emission 
reductions are approximately proportional to the reduction in frequency 
of opening the launcher and receiver hatch. For example, if a pig 
launcher holds six pigs, which are loaded all at once, the frequency of 
venting of the pig barrel is reduced to one-sixth of what it would have 
been if each pig were loaded individually. The EPA understands that 
multi-pig launchers and receivers are most appropriate for large 
diameter pipelines where the footprint of the launcher or receiver site 
is large enough to accommodate such a system. The EPA seeks comment on 
specific circumstances where such equipment is appropriate, and 
requests information on emission reductions and specific costs and 
savings of installing or retrofitting and operating a multi-pig 
launcher or receiver compared to a conventional single-pig launcher or 
receiver.
    Next, there are several liquids management technologies that focus 
on reducing emissions from the liquid condensate that is collected 
during pigging operations. The first technology relates to the design 
of condensate drains on receiver barrels. Drains can be installed in 
the bottom of receiver barrels and pig ball valves to ensure that all 
condensate is drained from the system prior to depressurization. These 
drains generally route the condensate back into the main pipelines, to 
onsite storage tanks, or to onsite processes via enclosed piping and 
can be retrofitted to existing systems. Recovering condensate prevents 
emissions that would occur when the liquids volatilize during 
depressurization of the pig receiver. The EPA seeks comment on 
different configurations of condensate drains, how the recovered 
condensate is routed and managed, limitations on using this technology, 
and data showing the amount of condensate recovered and associated 
emissions prevented.
    The second liquids management technology is a pig ramp on a 
receiver barrel. A pig ramp \315\ is a simple device that can be 
installed inside a receiver barrel to allow liquids trapped in front of 
the pig to be captured and to allow liquids clinging to the pig itself 
to drain before the pig is pulled from the chamber. Pig ramps are 
typically used in conjunction with condensate drains. The pig ramp 
promotes the flow of liquid through the barrel and into the drain line 
by elevating the pig on a rack-like apparatus within the receiver 
barrel, thereby preventing the pig from creating blockages in the 
receiver. By promoting the flow of liquid to a location within the 
receiver or pipeline where the liquids can be captured and drained 
prior to depressurization, pig ramps reduce the amount of condensed 
VOCs that would otherwise volatilize during depressurization and 
removal of the pig from the receiver, thereby reducing emissions. The 
EPA seeks comment on the successful installation and use of pig ramps 
as well as information on cost, emission reductions, and concerns or 
challenges that may make the use of pig ramps inappropriate.
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    \315\ https://www.mplx.com/content/documents/mplx/markwest/Launcher%20Receiver%20Design%20Detail.pdf.
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    The third liquids management technology involves enhanced liquids 
containment. If recovered condensate cannot be routed back to the 
pipeline or to controlled storage vessels, covering containers that 
collect liquids remaining in a receiver barrel after depressurization 
with a fitted impermeable material will reduce emissions from 
evaporation. However, whether or not this strategy will ultimately 
reduce emissions depends on how the recovered condensate is actually 
managed. The EPA seeks comment on how recovered condensate can be 
managed to ensure that emissions from the volatilization of the liquids 
is minimized, thereby achieving emissions reductions.
    Lastly, the EPA has identified several additional control options 
that can be employed to reduce emissions. First, an owner or operator 
could install ``jumper lines'' that allow routing high pressure systems 
to lower pressure systems. The depressurization emissions from high 
pressure launchers and receivers can be reduced by routing the high-
pressure gases to a lower pressure system before venting the remaining 
gases to the atmosphere or to control equipment.

[[Page 63244]]

Routing to a lower pressure system is achieved with a depressurization 
line (or jumper line) exiting the top of the barrel, or exiting the top 
of the pig ball valve, and connecting to nearby low-pressure lines on 
site. Compressor stations and gas plants have low pressure lines on the 
site that typically can receive these depressurized gases and recycle 
them through the process. Similarly, launchers and receivers along high 
pressure pipelines are occasionally located near low pressure pipelines 
that can receive depressurized gases exiting the barrel or pig ball 
valve. The EPA seeks comment on the universe of sites where jumper 
lines are feasible to install, as well as information on cost, emission 
reductions, and comment on implementation successes and challenges.
    Second, owners and operators can route low-pressure systems into a 
fuel gas system or VRU. Gases that remain in high pressure barrels 
after venting to low pressure systems, and gases in low pressure 
barrels, can be recovered during depressurization by discharging the 
gases to very low-pressure systems at the site (e.g., 10-15 psig). Two 
examples of very low-pressure systems at compressor stations are a fuel 
gas system and a condensate tank VRU. Applying such an approach can 
reduce the gas pressure in the barrels to the pressure of the very low-
pressure system, with a corresponding reduction in depressurization 
emissions. The feasibility of this option is contingent upon the 
presence of such equipment already onsite. The EPA seeks comment on the 
universe of sites where routing gas to low-pressure systems is 
feasible, as well as information on cost, emission reductions, and 
comment on implementation successes and challenges.
    Third, owners and operators can utilize barrel pump-down systems. 
In barrel pump-down systems, small fixed or portable compressors are 
used to pump vapors in the receiver or a launcher barrel back into the 
main pipeline prior to venting and opening the barrel hatch. In barrel 
pump-down systems, the inlet of a gas compressor is connected to the 
receiver or launcher depressurization line, and the compressor 
discharge is connected into the main pipeline. Vapors exiting the 
depressurization line are pulled into the compression system and 
recovered back into the pipeline at system pressure. These control 
systems can recover greater than 99 percent of the depressurization 
vapors from pig launchers and receivers. The EPA seeks comment on the 
universe of sites where barrel pump-down systems are feasible, as well 
as information on cost, emission reductions, and comment on 
implementation successes and challenges.
    Finally, owners and operators could route depressurization gases to 
combustion devices to control emissions from pigging operations. 
Depressurization gases from barrels and pig ball valves can be routed 
through the depressurization line to onsite combustion devices. Well-
designed and operated combustion devices can achieve vapor destruction 
efficiencies as high as 95 to 98 percent. Combustion devices can be 
used in conjunction with engineering solutions discussed above that 
first reduce accumulation of or recover as much natural gas and 
condensate as possible, before destroying the remaining vapors in the 
combustion device. An example would be to route high pressure systems 
to low pressure lines and drain barrel condensate, then route the 
remaining vapors to a combustion device. The EPA understands that 
large, high-capacity combustion devices are typically available at 
compressor stations and processing plants and can be used to control 
pigging gases while meeting the other flaring needs of the facility. 
There are also numerous low-capacity combustion devices available for 
serving remote launcher/receiver sites. The EPA seeks comment on the 
universe of sites where routing depressurization gases from pigging 
operations to a combustion device is feasible, as well as information 
on cost, emission reductions, and comment on implementation successes 
and challenges.
    In addition to those methods already identified above for reducing 
emissions from pigging and related blowdown activities, the EPA is 
seeking comment on other existing technologies and work practices to 
reduce the need for blowdown events or reduce emissions from blowdown 
events when they occur. The EPA is specifically interested in the costs 
of such technologies or work practices and any variables impacting 
cost, the control efficiency of the technology or work practice and 
variables affecting efficiency, and any technological or logistical 
limitations to implementing the technology or work practice.
    While blowdown emissions due to pigging are the primary area where 
the EPA seeks comment, the EPA is aware that planned blowdowns occur 
for many reasons, typically related to maintenance or inspection 
activities. Planned blowdowns may occur at facilities such as a gas 
processing plant, compressor station, well pad, or stand-alone pig 
launcher and receiver station, but may also occur at locations other 
than these facilities, including along pipelines. Under GHGRP subpart 
W, blowdown vent stack equipment or event types are grouped into the 
following seven categories: Facility piping (i.e., piping within the 
facility boundary), pipeline venting (i.e., physical volumes associated 
with pipelines vented within the facility boundary), compressors, 
scrubbers/strainers, pig launchers and receivers, emergency shutdowns 
(this category includes emergency shutdown blowdown emissions 
regardless of equipment type), and all other equipment with a physical 
volume greater than or equal to 50 cubic feet.\316\ The EPA seeks 
comment on any substantive differences between pigging blowdowns and 
other types of planned blowdowns. Further, the EPA is soliciting 
comment on how to define an affected facility that includes these 
blowdown activities, and specific limitations (e.g., technical or 
logistical) to including non-pigging-related types of blowdowns as part 
of affected facilities. In particular, the EPA is considering whether 
the pipeline itself could be defined as an affected facility for 
purposes of regulating blowdowns. In this scenario, the owner or 
operator of the pipeline would be responsible for complying with any 
requirements in place for blowdown activities that occur anywhere along 
the pipeline. The EPA is soliciting comment on any potential concerns 
this type of approach would raise for owners and operators, 
particularly where pipelines cross State boundaries or at the location 
where pipeline ownership may change from the upstream owner to a 
different downstream owner.
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    \316\ 40 CFR 98.233(i)(2).
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C. Tank Truck Loading

    The EPA is considering including emission standards and EG for tank 
truck loading operations; however, additional information is needed to 
evaluate BSER and propose NSPS or EG for this emissions source. The EPA 
is therefore soliciting comment on adding tank truck loading operations 
as an affected facility in both the NSPS and EG. Depending on the 
information received through the public comment process, the EPA may 
propose NSPS and EG for this source through a supplemental proposal. In 
this section we summarize the available information we have reviewed 
for this emissions source and potential control options.
    Tank truck loading operations result in emissions when organic 
vapors in empty tank trucks are displaced to the

[[Page 63245]]

atmosphere as crude oil, condensate, intermediate hydrocarbon liquids, 
or produced water from storage vessels is loaded into the tank 
trucks.\317\ Tank truck loading emissions are the primary source of 
evaporative emissions from tank trucks. It is the EPA's understanding 
that these vapors are a composite of vapors formed in the empty tank 
truck by evaporation of residual materials from previous loads, vapors 
transferred to the tank truck in vapor balance systems as materials are 
being unloaded, and vapors generated in the tank truck as new material 
is being loaded. Further, the quantity of evaporative losses from 
loading operations is, therefore, a function of the parameters such as 
the physical and chemical characteristics of the crude oil, condensate, 
intermediate hydrocarbon liquids, or produced water; the method of 
unloading the crude oil, condensate, intermediate hydrocarbon liquids, 
or produced water from the storage vessel into the tank truck; and the 
operations to transport the empty tank truck off-site. The composition 
of evaporative losses includes VOC, methane, and some HAP.
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    \317\ Section 5.2.2.1.1 of the AP-42 Section 5.2: Transportation 
and Marketing of Petroleum Liquids https://www.epa.gov/sites/default/files/2020-09/documents/5.2_transportation_and_marketing_of_petroleum_liquids.pdf.
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    According to the 2017 NEI, VOC emissions from tank truck loading 
operations were approximately 72,448 tpy, of which over 70,990 tpy were 
emitted in the crude oil and natural gas production segment, with the 
balance of approximately 1,457 tpy emitted from the natural gas 
processing segment. According to the Oklahoma loading losses guidance, 
\318\ a loading loss vapor VOC content of 85 percent by weight (i.e., 
15 percent by weight methane and ethane) may be assumed at wellhead 
facilities. Condensate and crude oil being loaded at a facility other 
than a wellhead facility may assume a vapor VOC content of 100 percent. 
Applying these compositions to the emissions in the 2017 NEI results in 
approximately 12,528 tpy methane at well sites and 1,457 tpy methane 
from other segments.
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    \318\ See https://www.deq.ok.gov/wp-content/uploads/deqmainresources/LoadingLossesGuidance_08-2019.pdf.
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    According to EIA, the contiguous continental states area comprising 
of 48 States have a six year daily average condensate production (API 
gravity greater than or equal to 50) \319\ of 911,000 bbls/day.\320\ 
Emissions per barrel of liquids loaded into tank trucks may be 
estimated at 0.43lb VOC/bbl. It is the EPA's understanding that most 
sites use tank trucks with a capacity of approximately 130 bbl. The EPA 
solicits comment on whether API gravity greater than or equal to 50 is 
the appropriate gravity of condensate to use.
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    \319\ See https://glossary.oilfield.slb.com/en/terms/c/condensate.
    \320\ See https://www.eia.gov/dnav/pet/pet_crd_api_adc_mbblpd_m.htm and TSD located at Docket ID No. EPA-
OAR-HQ-2021-0317.
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    The EPA understands that there are three options generally in use 
for controlling emissions during the tank truck loading process. The 
first control option is vapor balancing which is used to route the 
vapors displaced during material loading from the tank truck back to 
the storage vessel. Vapor balancing requires a vapor capture line to 
connect the tank truck to the storage vessel or manifold system of a 
tank battery. Because vapor balancing is a closed system, the only 
anticipated emissions from this control option would be fugitive in 
nature. However, emissions may occur from the tank truck if it is not 
properly maintained to DOT specifications, or when the tank truck is 
cleaned or reloaded without control off-site. Vapor balancing does not 
have any secondary air impacts or energy requirements. We estimate the 
capital cost associated with a vapor balancing loading arm (equipment 
associated with a capture line to connect the tank truck to the storage 
vessel) at about $5000 per arm based on limited available information.
    The second control option is use of a closed vent system operating 
with a reduction efficiency of 95 to 99 percent. A vapor capture system 
is used and routed to a vapor recovery device (VRD) or VRU which uses 
refrigeration, absorption, adsorption, and/or compression. The 
recovered liquid product is piped back to storage. Alternatively, the 
vapors may be collected via a vapor capture system and routed to an on-
site thermal oxidizer or flare. It is possible to route emissions from 
this closed vent system to an existing control device located on-site 
for another purpose. The EPA recognizes that this option may have 
secondary impacts dependent on the type of control chosen (e.g., VRU, 
VRD, or combustion device).
    Finally, the third option is to directly pipe liquids downstream. 
By directly piping liquids downstream, no emissions from tank truck 
loading are released to the atmosphere. We are not aware of any 
secondary impacts or energy costs associated with this option. However, 
the EPA is also unsure if this option is technically feasible for every 
site. It is our understanding that this option requires access to 
pipelines that can transport the crude oil and/or condensate to 
downstream locations, and availability of pipelines or capacity to move 
these liquids in existing pipelines may present an issue with requiring 
this option for all sites.
    In addition to these three control options, the EPA has also 
identified work practices related to the method of loading which are 
important and play a role in minimizing air emissions. Practices such 
as submerged fill and bottom loading help reduce emissions when the 
fill pipe opening is below the liquid surface level which reduces 
liquid turbulence and results in much lower vapor generation than 
encountered during splash (top) loading. We estimate the capital costs 
of submerged fill loading arms are approximately $1,500 per arm based 
on limited available data at this time.
    The EPA is soliciting comment on the three control options and work 
practices presented in this section to control or reduce emissions 
resulting from the tank truck loading process. We solicit comment on 
other control options or other work practice standards similar to those 
used in other sectors such as petroleum refineries and how appropriate 
those options may be for the Crude Oil and Natural Gas source category. 
We solicit comment on how widely used the control measure and work 
practices are, any feasibility challenges, and estimates of baseline 
emissions and cost information associated with these control options 
and work practices. The EPA is aware of several State regulations that 
have established standards for this emissions source.\321\ Finally, the 
EPA solicits comment on any practices owners and operators already 
implement as part of voluntary efforts or State requirements to 
minimize emissions from these sources.
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    \321\ See TSD located at Docket ID No. EPA-OAR-HQ-2021-0317.
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D. Control Device Efficiency and Operation

    As discussed above in sections XI.B, F, and G and XII.B, F, and G, 
the EPA is proposing to retain the 95 percent reduction performance 
standard for storage vessels, wet seal centrifugal compressors, and 
pneumatic pumps based on our analysis showing that a combustion control 
device remains the BSER for these affected facilities and can reliably 
achieve this performance standard. This 95 percent reduction is 
generally achieved by capturing the emissions in a closed vent system 
that routes those emission to either a control device or back to the 
process. Under the 2016 NSPS OOOOa, as amended by the 2020 Technical 
Rule with further

[[Page 63246]]

amendments proposed in this action, closed vent systems must be 
designed and operated with no detectable emissions, which is defined as 
either no emissions detected greater than 500 ppm above background with 
EPA Method 21, no emissions detected with OGI, or no audible, visual, 
or olfactory emissions detected. Thus, for a closed vent system, the 
assumed control efficiency is 100 percent. Therefore, any control 
device used must be designed and operated to achieve at least 95 
percent reduction of emissions to comply with the standard. Examples of 
control devices include flares, thermal oxidizers, catalytic oxidizers, 
enclosed combustion devices, carbon adsorption systems, condensers, and 
VRUs. However, there are various data sources available that suggest 
combustion control devices, which we have again identified as the BSER 
for these affected facilities, can achieve a continuous destruction 
efficiency of 98 percent.\322\
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    \322\ Oil and Natural Gas Sector: Standards of Performance for 
Crude Oil and Natural Gas Production, Transmission, and 
Distribution. Background Supplemental Technical Support Document for 
the Final New Source Performance Standards; EPA-HQ-OAR-2010-0505-
7631, pp. 19-20.
---------------------------------------------------------------------------

    Therefore, the EPA is soliciting comment on potentially proposing a 
change in the standards for wet seal centrifugal compressors, storage 
vessels, and pneumatic pumps that would require 98 percent reduction of 
methane and VOC emissions from these affected facilities. It is the 
EPA's understanding that combustion control devices, such as flares and 
enclosed combustion devices, may achieve at least 98 percent control of 
all organic compounds. Further, as noted in AP-42 Chapter 13.5, 
properly operated flares achieve at least 98 percent destruction 
efficiency in the flare plume in normal operating conditions.\323\ 
However, the EPA has received some data \324\ relevant to the use of 
these controls at oil and gas facilities that indicates air-assisted 
and steam-assisted flares have been found operating outside of the 
conditions necessary to achieve at least 98 percent control efficiency 
on a continuous basis. Therefore, the EPA is soliciting comment and 
information that would help us better understand the cost, feasibility, 
and emission reduction benefits associated with establishing a 98 
percent control efficiency requirement for flares in the Crude Oil and 
Natural Gas source category, including information on the level of 
performance being achieved in practice by flares in the field, what 
conditions or factors contribute to malfunctions or poor performance at 
these flares, and what measures the EPA could or should require in 
order to ensure that flares perform at a 98 percent level of control.
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    \323\ https://www.epa.gov/sites/default/files/2020-10/documents/13.5_industrial_flares.pdf.
    \324\ ``Intermittency of Large Methane Emitters in the Permian 
Basin'' Daniel H. Cusworth, et al. Environmental Science & 
Technology Letters 2021 8 (7), 567-573 DOI: 10.1021/
acs.estlett.1c00173; and Irakulis-Loitxate, I., Guanter, L., Liu, 
Y.N., Varon, D.J., Maasakkers, J.D., Zhang, Y., Lyon, D., . . . & 
Jacob, D. J. (2021). Satellite-based characterization of methane 
point sources in the Permian Basin (No. EGU21-15877). Copernicus 
Meetings.
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    The EPA also requests comment on whether additional measures to 
ensure proper performance of flares would be appropriate to ensure that 
flares meet the current 95 percent control requirement. For example, 
the EPA is soliciting comment on the specific requirements that could 
be used to demonstrate continuous compliance when using a combustion 
control device. In its July 8, 2021, report, the Office of Inspector 
General (OIG) \325\ observed that State permitting authorities had 
difficulty verifying continuous compliance with combustion efficiency 
requirements for flares and enclosed combustors. The OIG recommended 
that the EPA explore additional means to verify continuous compliance 
in NSPS OOOO and NSPS OOOOa that would provide additional tools for 
State agencies to properly permit and enforce combustion efficiency. In 
considering this recommendation, the EPA has determined that additional 
information is necessary to support the development of cost-effective 
continuous compliance requirements.
---------------------------------------------------------------------------

    \325\ EPA Office of Inspector General Report ``EPA Should 
Conduct More Oversight of Synthetic-Minor-Source Permitting to 
Assure Permits Adhere to EPA Guidance,'' Report No. 21-P-0175 July 
8, 2021.
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    The current standards in NSPS OOOO and NSPS OOOOa require owners 
and operators to perform an initial demonstration of compliance for all 
control devices used to meet the standards in the rule. Further, NSPS 
OOOO and NSPS OOOOa require monthly EPA Method 22 observations to 
demonstrate continuous compliance with visible emission requirements, 
in addition to monitoring for the presence of a pilot light. When an 
enclosed combustion device is used, owners and operators may 
demonstrate initial compliance through field testing or through 
manufacturer testing. The EPA maintains a list of devices for which 
manufacturers have demonstrated compliance with the testing 
requirements, including achieving a destruction efficiency of at least 
95 percent. The devices that have demonstrated compliance through 
manufacturer testing have achieved greater than 98 percent destruction 
efficiency; however, this is demonstrated in a testing environment 
only, and while the testing is designed to challenge the units, the 
units may not necessarily demonstrate the same destruction efficiency 
in field applications. The EPA is seeking comment on alternative means 
to demonstrate continuous compliance with the required control 
efficiency (whether maintained at 95 percent or increased to 98 
percent).
    The Petroleum Refinery Sector Standards, 40 CFR part 63, subpart 
CC, were amended in 2015 (80 FR 75178) to include a series of 
additional monitoring requirements that ensure flares achieve the 
required 98 percent control of organic compounds. Previously these 
flares had been subject to the flare requirements at 40 CFR 60.18 in 
the part 60 General Provisions. More recently, the updated flare 
requirements in NESHAP subpart CC have been applied to other source 
categories in the petrochemical industry, such as ethylene production 
facilities (40 CFR part 63, subpart YY), to ensure that flares in that 
source category also achieve the required 98 percent control of organic 
compounds. These monitoring requirements include continuous monitoring 
of waste gas flow, composition and/or net heating value of the vent 
gases being combusted in the flare, assist gas flow, and supplemental 
gas flow. The data from these monitored parameters are used to ensure 
the net heat value in the combustion zone is sufficient to achieve good 
combustion. The monitoring also includes prescriptive requirements for 
monitoring pilot flames, visible emissions, and maximum permitted 
velocity. Lastly, where fairly uniform, consistent waste gas 
compositions are sent to a flare, owners or operators can simplify the 
monitoring by taking grab samples in lieu of continuously monitoring 
waste gas composition, and in some instances, engineering calculations 
can be used to determine flow measurements.
    While effective, the EPA seeks comment on how appropriate any such 
monitoring requirements and systems would be for the oil and gas 
production, gathering and boosting, gas processing, or transmission and 
storage segments subject to the proposed NSPS OOOOb and EG OOOOc. The 
EPA seeks comment on how to distinguish among flare units where such 
monitoring is practical, and alternatives where such systems are not 
practical because they

[[Page 63247]]

lack continuous, on-site personnel or do not have the supporting 
infrastructure.
    Additionally, the EPA seeks comment on several facets of ongoing 
compliance, including: (1) Owner or operator experience in determining 
the proper location of a thermocouple for monitoring the presence of a 
pilot flame, and how to avoid pilot flame failure; (2) how OGI may be 
used to identify poor combustion efficiency (e.g., to effectively 
utilize OGI to qualitatively screen enclosed combustion devices) for 
additional quantitative testing. As noted in Section XI.A.1 of this 
preamble, we are proposing that emissions resulting from control 
devices operating in a manner that is not in full compliance with any 
Federal rule, State rule, or permit, are also considered fugitive 
emissions. However, there may be other ways to use OGI beyond seeing 
these fugitive emissions to determine whether control devices are 
operating properly. For instance, the EPA is interested in how OGI has 
been used to evaluate heat signature of gases exiting the top of the 
stack and/or the presence of any unburned hydrocarbon trailing or 
advective plumes.
    With respect to enclosed combustors, the EPA is seeking information 
on the development of comprehensive specifications for creating an 
operating envelope under which a make/model can achieve 98 percent 
reduction (i.e., parameters that should be identified on enclosed 
combustion device specification sheets), such as maximum heat load, 
minimum heat load, minimum inlet pressure of waste gas stream, 
temperature of combustion zone (and proper location for temperature 
monitor), air intake rate, operation and maintenance necessary for 
optimal combustion. The EPA also seeks information on real-time 
monitoring of enclosed combustion device inlet waste gas stream 
pressure aimed at achieving higher combustion efficiency.
    The EPA is also soliciting comment on the current use of non-
combustion control devices, the practicality of requiring 98 percent 
reduction through the use of non-combustion control devices, and the 
monitoring requirements necessary to demonstrate initial and continuous 
compliance with such control efficiency. NSPS OOOO and NSPS OOOOa 
require parametric monitoring for condensers, carbon adsorption 
systems, and similar control devices, to demonstrate continuous 
compliance. However, the EPA is seeking comment on whether those 
monitoring requirements are sufficient to assure continuous compliance 
should the EPA propose a requirement of 98 percent reduction. In 
addition to monitoring requirements, the EPA is seeking information on 
what additional records should be maintained and/or reported for 
demonstrating continuous compliance when non-combustion control devices 
are used. The EPA is particularly concerned that increasing the level 
of control from 95 to 98 percent would disincentivize use or 
potentially force replacement of non-combustion control devices 
entirely, including those that capture product for reuse in vapor 
recovery systems. For example, Texas requires additional monitoring and 
other significant engineering upgrades for a VRU operator to meet a 
higher control efficiency than 95 percent.\326\ Adding to this concern 
is the potential increase in overall costs of the rule and potential 
increase in emissions where facilities replace non-combustion control 
devices with combustion control devices.
---------------------------------------------------------------------------

    \326\ See Vapor Recovery Unit Capture/Control Guidance located 
at https://www.tceq.texas.gov/assets/public/permitting/air/NewSourceReview/oilgas/vapor-rec-unit.pdf.
---------------------------------------------------------------------------

    Finally, the EPA is seeking comment on new technologies that would 
address control efficiency from flares specifically and provide real-
time or near real-time measurement of control efficiency. One example 
would be OGI continuous flame imaging systems that capture flame size 
and temperature to ensure these parameters are within acceptable 
ranges. New optical technology is in the early phases of development 
and deployment. The EPA acknowledges that it may be challenging to 
analyze costs and reductions without comprehensive data specific to a 
particular technology, but in the interest of a forward-looking 
standard, we seek information on potential methods to assure continuous 
compliance for these control devices.

E. Definition of Hydraulic Fracturing

    During pre-proposal outreach, a number of small businesses stated 
that the NSPS has unintentionally been applied to conventional and 
vertical wells that engage in hydraulic fracturing. The small business 
stakeholders contended that these wells have a very different profile 
from unconventional or horizontal wells in terms of footprint, water 
usage, chemical usage, equipment used, and flowback period. They 
recommended that the EPA explicitly exempt these wells from the 
proposal. We maintain that the original intent of the NSPS was to 
regulate hydraulically fractured wells, in both conventional and 
unconventional reservoirs,\327\ and both vertical and horizontal 
wells.\328\
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    \327\ See Docket ID Item Nos. EPA-HQ-OAR-2010-0505-0445, Chapter 
4, p. 4-2 and EPA-HQ-OAR-2010-0505-4546, p. 30.
    \328\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-4546, p. 61.
---------------------------------------------------------------------------

    NSPS OOOOa defines hydraulic fracturing as ``the process of 
directing pressurized fluids containing any combination of water, 
proppant, and any added chemicals to penetrate tight formations, such 
as shale or coal formations, that subsequently require high rate, 
extended flowback to expel fracture fluids and solids during 
completions.'' The NSPS does not offer numeric thresholds that define 
``tight formations'' or ``high rate, extended flowback''. When 
developing the original NSPS OOOO, EPA's analysis assumed hydraulic 
fracturing is performed in tight sand, shale, and coalbed methane 
formations which have an in situ permeability (flow rate capability) to 
gas of less than 0.1 millidarcy.\329\ The EPA also assumed the flowback 
lasted between 3 and 10 days for the average gas well,\330\ and 3 days 
for the average oil well.\331\ However, in response to a public comment 
on the 2015 NSPS OOOOa proposal claiming the definition of hydraulic 
fracturing was too broad, the EPA clarified it intended to ``include 
operations that would increase the flow of hydrocarbons to the 
wellhead''.\332\ Similarly, in response to a public comment seeking an 
exemption for wells that have a flowback period of less than 24 hours, 
the EPA acknowledged that there is a range of flowback periods, finding 
that the requested exemption was not warranted.\333\
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    \329\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-0445, Chapter 
4, p. 4-2.
    \330\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-0445, Chapter 
4, p. 4-1.
    \331\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-5021, p.20.
    \332\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-7632, Chapter 
3, p. 3-113.
    \333\ See Docket ID Item No. EPA-HQ-OAR-2010-0505-7632, Chapter 
3, p. 3-64.
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    We are soliciting comment on if numeric thresholds for ``tight 
formations'' or ``high rate, extended flowback'' are appropriate to 
include in the definition of hydraulic fracturing, and if so, what 
those numeric thresholds should be. Alternatively, we solicit comment 
on if it is appropriate to align the NSPS definition with the U.S. 
Geologic Survey (USGS) definition of hydraulic fracturing (``the 
process of injecting water, sand, and/or chemicals into a well to break 
up underground bedrock to free up oil or gas

[[Page 63248]]

reserves''),\334\ which may more accurately capture the EPA's original 
intent.
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    \334\ USGS. Hydraulic Fracturing. https://www.usgs.gov/mission-areas/water-resources/science/hydraulic-fracturing?qt-science_center_objects=0#qt-science_center_objects. Accessed 
September 1, 2021.
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XIV. State, Tribal, and Federal Plan Development for Existing Sources

    Over the last forty years, under CAA section 111(d), the agency has 
regulated four pollutants from five source categories (i.e., sulfuric 
acid plants (acid mist), phosphate fertilizer plants (fluorides), 
primary aluminum plants (fluorides), kraft pulp plants (total reduced 
sulfur), and municipal solid waste landfills (landfill gases)).\335\ In 
addition, the agency has regulated additional pollutants under CAA 
section 111(d) in conjunction with CAA section 129.\336\ The Agency has 
not previously addressed emissions of GHGs (in the form of limitations 
of methane) from the Crude Oil and Natural Gas source category under 
CAA section 111(d). However, the EPA has ample experience with this 
source category from implementing the NSPS for so long, and has 
examined existing sources in a variety of context including the 2013 
Federal Implementation Plan (FIP) for oil and natural gas well 
production facilities on the Fort Berthold Indian Reservation (78 FR 
17836 (Mar. 22, 2013)), the 2016 Oil and Natural Gas Control Techniques 
Guidelines (81 FR 74798 (Oct. 27, 2016)), and the 2020 proposed FIP for 
managing emissions from oil and natural gas sources on Indian country 
lands within the Uintah and Ouray Indian Reservation (85 FR 3492 (Jan. 
21, 2020)). The draft EG contained in this proposal draw from, among 
other sources of information and analysis, all of these experiences 
combined with information on State laws that regulate existing sources. 
In this action, the EPA is proposing EG for Sates to follow in 
developing their plans to reduce emissions of GHGs (in the form of 
limitations on methane) from designated facilities within the Crude Oil 
and Natural Gas source category.
---------------------------------------------------------------------------

    \335\ See ``Phosphate Fertilizer Plants; Final Guideline 
Document Availability,'' 42 FR 12022 (March 1, 1977); ``Standards of 
Performance for New Stationary Sources; Emission Guideline for 
Sulfuric Acid Mist,'' 42 FR 55796 (October 18, 1977); ``Kraft Pulp 
Mills, Notice of Availability of Final Guideline Document,'' 44 FR 
29828 (May 22, 1979); ``Primary Aluminum Plants; Availability of 
Final Guideline Document,'' 45 FR 26294 (April 17, 1980); ``EG and 
Compliance Times for Municipal Solid Waste Landfills,'' 81 FR 59276 
(August 29, 2016). In addition, EPA regulated mercury from coal-
fired electric power plants in a 2005 rule that was vacated by the 
D.C. Circuit, ``Standards of Performance for New and Existing 
Stationary Sources: Electric Utility Steam Generating Units; Final 
Rule,'' 70 FR 28606 (May 18, 2005) (Clean Air Mercury Rule), vacated 
by New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). EPA also 
regulated GHG from fossil fuel-fired electric power plants in a 2015 
rule that EPA subsequently repealed and replaced with a 2019 rule 
that, in turn, was vacated by the D.C. Circuit. ``Carbon Pollution 
EG for Existing Stationary Sources: Electric Utility Generating 
Units; Final Rule,'' 80 FR 64662 (Oct. 23, 2015) (Clean Power Plan), 
repealed and replaced by ``Repeal of the Clean Power Plan; EG for 
Greenhouse Gas Emissions From Existing Electric Utility Generating 
Units; Revisions to EG Implementing Regulations,'' 84 FR 32520 (July 
8, 2019) (Affordable Clean Energy Rule), vacated by Am. Lung Assoc.
    \336\ See, e.g., ``Standards of Performance for New Stationary 
Sources and EG for Existing Sources: Sewage Sludge Incineration 
Units, Final Rule,'' 76 FR 15372 (March 21, 2011).
---------------------------------------------------------------------------

A. Overview

    While section IV of this preamble provides a general overview of 
the State planning process triggered by the EPA's finalization of EG 
under CAA section 111(d), this section explains the EG process and 
proposed State plan requirements in more detail, and also solicits 
comment on various issues related to this EG. The EG process is 
governed by CAA section 111(d) as well as the final EG and the EPA's 
implementing regulations at 40 CFR part 60, subpart Ba.\337\ After the 
EPA establishes the BSER in the final EG, as described in preamble 
sections XI and XII, each State that includes a designated facility 
must develop, adopt, and submit to the EPA its State plan under CAA 
section 111(d). The EPA then must determine whether to approve or 
disapprove the plan. If a State does not submit a plan, or if the EPA 
does not approve a State's plan, then the EPA must establish a Federal 
plan for the State.
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    \337\ As previously noted, the D.C. Circuit has vacated certain 
timing provisions within subpart Ba. Am. Lung Assoc. v. EPA. 
However, the court did not vacate the applicability provision, and 
therefore Subpart Ba applies to any EG that EPA finalizes from this 
proposal.
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    Each of these steps, and more, is discussed in detail in this 
section which is organized into six parts. First, we discuss the 
components of the EG. Second, we discuss establishing standards of 
performance in State plans in response to a finalized EG. Third, we 
discuss the components of an approvable State plan submission. Fourth, 
we discuss the timing for State plan submissions and compliance times. 
Fifth, we discuss the EPA's action on State plans and promulgation of a 
Federal plan, if needed. Sixth, we discuss the CAA section 111(d) 
process as it relates to Tribes. While this section describes the 
requirements of the implementing regulations under 40 CFR part 60, 
subpart Ba, proposes requirements for States in the context of this EG, 
and solicits comments in the context of this EG, nothing in this 
proposal is intended to reopen the implementing regulations themselves 
for comment.

B. Components of EG

    As previously described, CAA sections 111(d)(1) and 111(a)(1) 
collectively establish and define certain roles and responsibilities 
for the EPA and the States. The EPA addresses its responsibilities by 
drafting and publishing EG in accordance with 40 CFR 60.22a, which 
``[contain] information pertinent to control of the designated 
pollutant from designated facilities.'' Mirroring language included in 
CAA section 111(d)(1), the EPA's implementing regulations define a 
designated pollutant as ``any air pollutant, the emissions of which are 
subject to a standard of performance for new stationary sources, but 
for which air quality criteria have not been issued and that is not 
included on a list published under section 108(a) or section 
112(b)(1)(A) of the Act.'' 40 CFR 60.21a(a). The EPA's implementing 
regulations also define a designated facility as ``any existing 
facility (see Sec.  60.2) which emits a designated pollutant and which 
would be subject to a standard of performance for that pollutant if the 
existing facility were an affected facility (see Sec.  60.2).'' Id. at 
Sec.  60.21a(b). The designated pollutant for purposes of the draft EG 
included in this proposal is GHGs, but the presumptive standards in the 
EG are expressed in terms of limitations on methane. A description of 
each of the designated facilities included in the draft EG can be found 
above in preamble sections XI and XII.
    More specifically, 40 CFR 60.22a(b) lists six components to be 
included in EG to provide information for development of the State 
plans triggered by the promulgation of the EG. First, EG must include 
information regarding the ``endangerment of public health or welfare 
caused, or contributed to, by the designated pollutant.'' 40 CFR 
60.22a(b)(1). Information on the harmful public health and welfare 
impacts of methane emissions from the oil and natural gas industry are 
included above in section III of this document. Second, the EG must 
include a ``description of systems of emission reduction which, in the 
judgment of the Administrator, have been adequately demonstrated.'' 40 
CFR 60.22a(b)(2). The EPA has included such a description above in 
sections XI and XII of this preamble, and the NSPS OOOOb and EG TSD 
located at Docket ID No. EPA-HQ-OAR-2021-0317.

[[Page 63249]]

Third, the EG must include information regarding ``the degree of 
emission limitation'' achievable through application of each system, 
along with information ``on the costs, non-air quality health 
environmental effects, and energy requirements of applying each system 
to designated facilities.'' 40 CFR 60.22a(b)(3). The EPA has included 
such a description in sections XI and XII of this preamble, and the 
NSPS OOOOb and EG TSD located at Docket ID No. EPA-HQ-OAR-2021-0317. 
Fourth, the EG must include information regarding the amount of time 
that the EPA believes would be normally necessary for designated 
facilities to design, install, and startup the control systems 
identified in component number three. See 40 CFR 60.22a(b)(4). The EPA 
explains how it proposes to address this component below in section 
XIV.E. Fifth, and likely most helpful to States when developing their 
plans in response to the final EG, the EG must include information 
regarding the ``degree of emission limitation achievable through the 
application of the best system of emission reduction'' that has been 
adequately demonstrated, taking into account the same factors as 
described in component three (cost, non-air quality health and 
environmental impact and energy requirements), ``and the time within 
which compliance with standards of performance can be achieved.'' 40 
CFR 60.22a(b)(5). The EPA has included such information in sections XI 
and XII of this preamble and the NSPS OOOOb and EG TSD located at 
Docket ID No. EPA-HQ-OAR-2021-0317 as well as in section XIV.E of this 
preamble. In identifying the degree of achievable emission limitation, 
the EPA may subcategorize, that is to ``specify different degrees of 
emission limitation or compliance times or both for different sizes, 
types, and classes of designated facilities when costs of control, 
physical limitations, geographical location, or similar factors make 
subcategorization appropriate.'' Id. The EPA can choose to exercise 
that discretion to subcategorize within the draft EG for certain 
emission points. Sixth, and last, the EG is to include any other 
information not contemplated by the five other components that the EPA 
``determines may contribute to the formulation of State plans.'' This 
section includes such information and guidance specifically designed to 
assist States in developing their plans under CAA 111(d) for these 
draft EG.

C. Establishing Standards of Performance in State Plans

    While the EPA has the authority and responsibility to determine the 
BSER and the degree of limitation achievable through application of the 
BSER, CAA section 111(d)(1) provides that States shall submit to the 
EPA plans that establish standards of performance for designated 
facilities (i.e., existing sources) and provide for implementation and 
enforcement of such standards. In light of the statutory text, and as 
reflected in the technical completeness criteria in the EPA's 
implementing regulations (explained below), State plans implementing 
the EG should include requirements and detailed information related to 
two key aspects of implementation: establishing standards of 
performance for designated facilities and providing measures that 
implement and enforce such standards.
    Establish Standards of Performance for Designated Facilities. As an 
initial matter, a State must identify existing facilities within its 
borders that meet the applicability requirements in the final EG and 
are thereby considered a ``designated facility'' under the EG.\338\ 
Then, States are required to establish standards of performance for the 
identified designated facilities. There is a fundamental requirement 
under CAA section 111(d) that a State's standards of performance 
reflect the degree of emission limitation achievable through the 
application of the BSER, which derives from the definition of 
``standard of performance'' in CAA section 111(a)(1). The statute 
further requires the EPA to permit States, in applying a standard of 
performance, to consider a source's remaining useful life and other 
factors. Accordingly, based on both the mandatory and discretionary 
aspects of CAA section 111(d), a certain level of process is required 
of State plans: namely, the standards of performance must reflect the 
degree of emission limitation achievable through application of the 
BSER, and if the State chooses, the consideration of remaining useful 
life and other factors in applying a standard of performance to a 
designated facility.
---------------------------------------------------------------------------

    \338\ In accordance with 40 CFR 60.23a(b), states without any 
designated facilities are directed to submit to the Administrator a 
letter of negative declaration certifying that there are no 
designated facilities, as defined by EPA's emissions guidelines, 
located within the state. No plan is required for states that do not 
have any designated facilities.
---------------------------------------------------------------------------

    For this EG the EPA is proposing to translate the degree of 
emission limitation achievable through application of the BSER (i.e., 
level of stringency) into presumptive standards of performance that 
States may use in the development of State plans for specific emission 
points. The EPA believes that the presumptive standards of performance 
included in the EG will provide States with the level of stringency 
that the EPA would require to approve a State plan. Put another way, 
the EPA is choosing to format this EG such that if a State chooses to 
adopt the presumptive standards as the standards of performance in 
their State plan, then the EPA believes that such plan could be 
approved as meeting the requirements of CAA section 111(d) and the 
finalized EG, assuming the plan meets all other applicable 
requirements. In this way, the presumptive standards included in the EG 
serve a similar purpose as a model rule because they are intended to 
assist States in developing their plan submissions by providing the 
States with a starting point for their standards that are based on 
general industry parameters and assumptions. The EPA believes that 
providing these presumptive standards of performance will create a 
streamlined approach for States in developing plans and for the EPA in 
evaluating State plans. Of course, the EPA cannot pre-determine the 
outcome of a future rulemaking process, and inclusion of these 
presumptive standards in this EG does not impact the rulemaking process 
associated with the EPA's review of, and action on, a State plan 
submission. In its review of State plans, the EPA will consider the 
information in the final EG (including what EPA publishes in the final 
EG as the presumptive standards), as well as information submitted by 
the State and the public. The EPA will evaluate the approvability of 
all plans through individual notice-and-comment rulemaking processes.
    As described in sections XI and XII, the EPA is proposing to 
translate the degree of emission limitation achievable through 
application of the BSER into presumptive standards for the following 
designated facilities as shown in Table 20.

[[Page 63250]]



  Table 20--Summary of Proposed EG Subpart OOOOc Presumptive Numerical
                                Standards
------------------------------------------------------------------------
                                       Proposed presumptive mass-based
        Designated facility           standards in the draft emissions
                                             guidelines for GHGs
------------------------------------------------------------------------
Storage Vessels: Tank Battery with  95 percent control.
 PTE of 20 tpy or More of Methane.
Pneumatic Controllers: Natural Gas  VOC and methane emission rate of
 Driven that Vent to the             zero.
 Atmosphere.
Wet Seal Centrifugal Compressors..  95 percent control.
Pneumatic Pumps: Natural Gas        Zero natural gas emissions from
 Processing Plants.                  diaphragm and piston pneumatic
                                     pumps.
Pneumatic Pumps: Locations Other    95 percent control of diaphragm
 Than Natural Gas Processing         pneumatic pumps if there is an
 Plants.                             existing control or process on
                                     site. 95 percent control not
                                     required if (1) routed to an
                                     existing control that achieves less
                                     than 95 percent or (2) it is
                                     technically infeasible to route to
                                     the existing control device or
                                     process.
Associated Gas from Oil Wells.....  Route associated gas to a sales
                                     line. In the event that access to a
                                     sales line is not available, the
                                     gas can be used as an onsite fuel
                                     source, used for another useful
                                     purpose that a purchased fuel or
                                     raw material would serve, or routed
                                     to a flare or other control device
                                     that achieves at least 95 percent
                                     control.
------------------------------------------------------------------------

    For these designated facilities, State plans would generally be 
expected to establish standards of performance that reflect these 
numerical presumptive standards, if included in the final EG. Further, 
for these designated facilities, the EPA is proposing to require that 
the standards of performance be expressed in the same form as the 
numerical presumptive standards set forth in Table 20. For example, for 
storage vessels that are part of a tank battery with a PTE of 20 tpy or 
more of methane, the EPA is proposing a numerical presumptive standard 
of 95-percent control. Accordingly, if finalized as proposed, States 
would be required to submit a plan that includes numerical standards of 
performance for these designated facilities expressed in the same form 
as the presumptive standard of 95 percent control. As described in this 
proposal and the associated supporting materials in the docket, the EPA 
has extensively and rigorously performed technical analyses in order to 
determine the appropriate proposed BSER for each set of designated 
facilities. The form of the numerical expression of the degrees of 
emission limitation achievable through application of the BSERs, and 
the associated presumptive standards, are a result of these technical 
analyses. The EPA believes that requiring States to maintain the same 
form of numerical standard in their plans will preserve the integrity 
of the BSERs and avoid analytic issues that are likely to arise if EPA 
is required to determine whether a different form of numerical standard 
submitted by a State has the same level of stringency as the final EG. 
Accordingly, having a uniform form of standard of performance will help 
streamline the States' development of their plans, as well as the EPA's 
review of those plans, since there will be fewer variables to evaluate 
in the development and review of each standard of performance. The EPA 
solicits comment on its proposal to require State plans to include 
numerical standards of performance for these designated facilities that 
are in the same form as the numerical presumptive standards, and 
whether EPA should additionally allow States to include a different 
form of numerical standards for these facilities so long as States 
demonstrate the equivalency of such standards to the level of 
stringency required under the final EG.
    For the following designated facilities, the EPA is proposing to 
translate the degree of emission limitation achievable through 
application of the BSER into the presumptive standards shown in Table 
21.

Table 21--Summary of Proposed EG Subpart OOOOc Presumptive Non-Numerical
                                Standards
------------------------------------------------------------------------
                                     Proposed presumptive non-numerical
        Designated facility           standards in the draft emissions
                                             guidelines for GHGs
------------------------------------------------------------------------
Fugitive Emissions: Well Sites-->0  Perform fugitive emissions survey
 to <3 tpy methane.                  and repair to demonstrate actual
                                     site emissions are reflected in
                                     calculation.
Fugitive Emissions: Well Sites--    Quarterly OGI monitoring following
 >=3 tpy methane.                    appendix K. (Optional quarterly EPA
                                     Method 21 monitoring with 500 ppm
                                     defined as a leak).
                                    First attempt at repair within 30
                                     days of finding fugitive emissions.
                                     Final repair within 30 days of
                                     first attempt.
(Co-proposal) Fugitive Emissions:   Semiannual OGI monitoring following
 Well Sites-->=3 to <8 tpy methane.  appendix K. (Optional semiannual
                                     EPA Method 21 monitoring with 500
                                     ppm defined as a leak).
                                    First attempt at repair within 30
                                     days of finding fugitive emissions.
                                     Final repair within 30 days of
                                     first attempt.
(Co-proposal) Fugitive Emissions:   Quarterly OGI monitoring following
 Well Sites-->=8 tpy methane.        appendix K. (Optional quarterly EPA
                                     Method 21 monitoring with 500 ppm
                                     defined as a leak).
                                    First attempt at repair within 30
                                     days of finding fugitive emissions.
                                     Final repair within 30 days of
                                     first attempt.
Fugitive Emissions: Compressor      Quarterly OGI monitoring following
 Stations.                           appendix K. (Optional quarterly EPA
                                     Method 21 monitoring with 500 ppm
                                     defined as a leak).
                                    First attempt at repair within 30
                                     days of finding fugitive emissions.
                                     Final repair within 30 days of
                                     first attempt.
Fugitive Emissions: Well Sites and  Annual OGI monitoring following
 Compressor Stations on Alaska       appendix K. (Optional annual EPA
 North Slope.                        Method 21 monitoring with 500 ppm
                                     defined as a leak).
                                    First attempt at repair within 30
                                     days of finding fugitive emissions.
                                     Final repair within 30 days of
                                     first attempt.
Fugitive Emissions: Well Sites and  (Optional) Alternative bimonthly
 Compressor Stations..               screening with advanced measurement
                                     technology and annual OGI
                                     monitoring following appendix K.
Pneumatic Controllers: Alaska (at   Natural gas bleed rate no greater
 sites where onsite power is not     than 6 scfh.
 available--continuous bleed
 natural gas driven).
Pneumatic Controllers: Alaska (at   Monitor and repair through fugitives
 sites where onsite power is not     program.
 available--intermittent natural
 gas driven).
Reciprocating Compressors.........  Replace the reciprocating compressor
                                     rod packing based on annual
                                     monitoring (when measured leak rate
                                     exceeds 2 scfm) or route emissions
                                     to a process.
Equipment Leaks at Gas Plants.....  Bimonthly OGI LDAR program (NSPS VVa
                                     as optional alternative).
------------------------------------------------------------------------


[[Page 63251]]

    The EPA's implementing regulations at 40 CFR 60.24a(b) require that 
standards of performance shall either be based on allowable rate or 
limit of emissions, except when the EPA identifies cases in an EG where 
it would not be feasible to prescribe or enforce a rate or limit. Put 
another way, 40 CFR 60.24a(b) permits the EPA to identify cases where 
it is not feasible for States to prescribe or enforce a numerical 
standard, and in those cases the EPA can include non-numerical 
emissions limitations such as design, equipment, work practice, or 
operational standards, or a combination thereof, in the EG. See also 
definition of ``standard of performance'' in 40 CFR 60.21a(f). This 
authority in the context of the EG is akin to the EPA's authority under 
CAA section 111(h) to prescribe non-numerical standards where the 
Administrator determines it is not feasible to prescribe or enforce a 
numerical standard of performance. Where the EPA finalizes EG that 
authorize design, equipment, work practice, or operational standard, or 
a combination thereof, the State ``plan shall, to the degree possible, 
set forth the emission reductions achievable by implementation of such 
standards, and may permit compliance by the use of equipment determined 
by the State to be equivalent to that prescribed'' by the State plan. 
See 40 CFR 60.24a(b).
    For the designated facilities listed in Table 21 the EPA has 
determined that it is not feasible to prescribe or enforce a numerical 
standard. As such, for these designated facilities, the EPA is 
proposing presumptive standards that are comprised of design, 
equipment, work practice, and/or operational standards. For these 
designated facilities, States are generally expected to establish the 
same non-numerical presumptive standards in Table 21. If States do not 
incorporate the presumptive standards included in the final EG into 
their State plan, but instead wish to utilize a different design, 
equipment, work practice, and/or operational standard for any of the 
designated facilities listed in Table 21, then the EPA is proposing to 
require that the State include in its plan a demonstration of how that 
standard will achieve a reduction in methane emissions at least 
equivalent to the reduction in methane emissions achieved by 
application of the presumptive standards included in the final EG. Such 
a demonstration should take into account, among other factors, the 
timelines for compliance. The EPA believes that this requirement is 
consistent with the AMEL provision in CAA section 111(h)(3), which 
requires a demonstration that any alternative ``will achieve a 
reduction in emissions . . . at least equivalent to the reduction in 
emissions'' achieved by EPA's standard, and the technical completeness 
criteria found at 40 CFR 60.27a(g)(3)(iv), which requires that State 
plans must include a ``demonstration that the State plan submittal is 
projected to achieve emissions performance under the applicable EG.''
    To the extent that a State determines the presumptive standards in 
the final EG are not reasonable for a particular designated facility 
due to remaining useful life and other factors, the statute requires 
that the EPA's regulations under CAA section 111(d) permit States to 
consider such factors in applying a standard of performance. As such, 
the EPA's implementing regulations at 40 CFR 60.24a(e) allow States to 
consider remaining useful life and other factors to apply a less 
stringent standard of performance to a designated facility or class of 
facilities if one or more demonstrations are made. These demonstrations 
include unreasonable cost of control resulting from plant age, 
location, or basic process design; physical impossibility of installing 
necessary control equipment; or other factors specific to the facility 
(or class of facilities) that make application of a less stringent 
standard or final compliance time significantly more reasonable. The 
implementing regulations also clarify that, absent such a 
demonstration, the State's standards of performance must be ``no less 
stringent than the corresponding'' EG. See 40 CFR 60.24a(c).
    The EPA intends to provide further clarification on the general 
process and requirements for accounting for remaining useful life and 
other factors, including on the reasonableness aspect of the required 
demonstration, via a rulemaking to amend the implementing regulations 
in the near future. However, the EPA also recognizes that the oil and 
natural gas industry is unique such that the general approach to 
considering remaining useful life and other factors in the implementing 
regulations may not be an ideal fit. For example, the sheer number and 
variety of designated facilities in the oil and natural gas industry 
could make a source-specific (or even a class-specific) evaluation of 
remaining useful life and other factors extremely difficult and 
burdensome for States that want to undertake a demonstration. In 
addition, the presumptive standards for these designated facilities 
generally entail fewer major capital expenses compared with other 
industries for which EPA has previously issued EG under CAA section 
111(d), and many of the proposed presumptive standards generally take 
the form of design, equipment, work practice, or operational standards 
rather than numerical emission limitations. Further, in proposing the 
presumptive standards for existing sources, the EPA has deliberately 
included certain flexibilities (e.g., in cases of technical 
infeasibility) such that the EPA believes the presumptive standards 
should be achievable and cost-effective for a wide variety of 
facilities across the source category. Given these facts, the EPA 
believes that it would likely be difficult for States to demonstrate 
that the presumptive standards are not reasonable for the vast majority 
of designated facilities. The EPA is soliciting comment on these 
observations, and any other facts and circumstances that are unique to 
the oil and natural gas industry that could impact the remaining-
useful-life-and-other-factors demonstration. The EPA is also soliciting 
comment as to whether the Agency should include specific provisions 
regarding the consideration of remaining useful life and other factors 
in this EG that would supplement or supersede the general provisions in 
the implementing regulations.
    To the extent a State chooses to submit a plan that includes 
standards of performance that are more stringent than the requirements 
of the final EG, States have the authority to do so under CAA section 
116, and the EPA has the authority to approve such plans and render 
them Federally enforceable if all applicable requirements are met. 
Union Electric Co. v. EPA, 427 U.S. 246, (1976). See also 40 CFR 
60.24a(f). The EPA acknowledges that in the Affordable Clean Energy 
(ACE) rule, it previously took the position that Union Electric does 
not control the question of whether CAA section 111(d) State plans may 
be more stringent than Federal requirements. The ACE rule took this 
position on the basis that Union Electric on its face applies only to 
CAA section 110, and that it is potentially salient that CAA section 
111(d) is predicated on specific technologies whereas CAA section 110 
gives States broad latitude in the measures used for attaining the 
National Ambient Air Quality Standards (NAAQS). 84 FR 32559-61 (July 8, 
2019). The EPA no longer takes this position. Upon further evaluation, 
the EPA believes that because of the structural similarities between 
CAA sections 110 and 111(d), CAA section 116 as interpreted by Union 
Electric

[[Page 63252]]

requires the EPA to approve CAA section 111(d) State plans that are 
more stringent than required by the EG if the plan is otherwise is 
compliance with all applicable requirements. See FCC v. Fox Television 
Stations, Inc., 556 U.S. 502 (2009). The D.C. Circuit in Union Electric 
rejected a construction of CAA sections 110 and 116 that measures more 
stringent than those required to attain the NAAQS cannot be approved 
into a federally enforceable State Implementation Plan (SIP) but must 
be adopted and enforced only as a matter of State law. Id. at 263-64. 
While the BSER and the NAAQS are distinct from one another in that the 
former is technology-based and the latter is based on ambient air 
quality, both CAA sections 111(d) and 110 are structurally similar in 
that States must adopt and submit to the EPA plans which include 
requirements to meet the objectives of each respective section. 
Requiring States to enact and enforce two sets of standards, one that 
is a federally approved CAA section 111(d) plan and one that is a 
stricter State plan, runs directly afoul of the court's holding that 
there is no basis for interpreting CAA section 116 in such manner. 
Therefore, the EPA interprets CAA sections 111(d) and 116 as allowing 
States to include, and the EPA to approve, more stringent standards of 
performance in State plans. The EPA notes that its authority is 
constrained to approving measures which comport with applicable 
statutory and regulatory requirements. For example, CAA section 111(d) 
only contemplates that State plans include requirements for designated 
facilities, therefore the EPA believes it does not have the authority 
to approve and render federally enforceable measures on other entities.
    The EPA is also aware that in the context of regulating the oil and 
natural gas industry many States have existing programs they may want 
to leverage for purposes of satisfying their CAA section 111(d) State 
plan obligations. The EPA anticipates providing information on ways in 
which State plans can accommodate existing State programs to the extent 
such programs are at least as stringent as the requirement of the final 
EG. Consistent with the proposed presumptive standards, the EPA 
proposes that a State plan which relies on an existing State program 
must still establish standards of performance that are in the same form 
as the presumptive standards. The EPA solicits comment on whether 
States relying on existing programs should be authorized to include a 
different form of standard in their plans so long as they demonstrate 
the equivalency of such standards to the level of stringency required 
under the final EG, and how such equivalency demonstrations can be made 
in a rigorous and consistent way. The EPA proposes to require that, in 
situations where a State wishes to rely on State programs (statutes 
and/or regulations) that pre-date finalization of the EG proposed in 
this document to satisfy the requirements of CAA section 111(d), the 
State plan should identify which aspects of the existing State programs 
are being submitted for approval as federally enforceable requirements 
under the plan, and include a detailed explanation and analysis of how 
the relied upon existing State programs are at least as stringent as 
the requirements of the final EG. The EPA notes that the completeness 
criteria in 40 CFR 60.27a(g) requires a copy of the actual State law/
regulation or document submitted for approval and incorporation into 
the State plan. Put another way, where a State is relying on an 
existing State program for its plan, a copy of the pre-existing State 
statute or regulation underpinning the program would be required by 
this criterion, and would be a critical component of the EPA's 
evaluation of the approvability of the plan. The EPA also solicits 
comment on various ways in which existing State programs can be adopted 
into State plans. Particularly, the EPA is interested in how existing 
State programs that regulate both designated facilities and sources not 
considered as designated facilities under this EG could be tailored for 
a State plan to meet the requirements of CAA section 111(d).
    Providing Measures that Implement and Enforce Such Standards. As 
part of establishing standards of performance, State plans must also 
include compliance schedules for those standards. See 40 CFR 60.24a(a). 
Section XIV.E, explains how the EPA is proposing to approach compliance 
schedules. The EPA's implementing regulations require that, except 
where the State chooses to account for remaining useful life and other 
factors, State plans shall require final compliance as expeditiously as 
practicable, but no later than the compliance times specified in the 
EG. See 40 CFR 60.24a(c). Where a State applies a less stringent 
standard of performance because of remaining useful life and other 
factors, the compliance schedule must appropriately comport with that 
standard.\339\
---------------------------------------------------------------------------

    \339\ 40 CFR 60.24a(d) additionally required state plans to 
include increments of progress for any compliance schedule that 
extended more than 24 months after the state plan submittal date. 
While the substantive requirement for increments of progress was not 
challenged and remains effective, the timing aspect of this 
provision was vacated by the D.C. Circuit. Am. Lung Assoc., 985 F.3d 
at 991. The EPA intends to address the timing aspect of this 
provision in the near future.
---------------------------------------------------------------------------

    In addition to establishing standards of performance and compliance 
schedules, State plans must also include, adequately document, and 
demonstrate the methods employed to implement and enforce the standards 
of performance such that the EPA can review and identify measures that 
assure transparent and verifiable implementation. As part of ensuring 
that regulatory obligations appropriately meet statutory requirements 
such as enforceability, the EPA has historically and consistently 
required that obligations placed on sources be quantifiable, non-
duplicative, permanent, verifiable, and enforceable. See 40 CFR 
60.27a(g)(3)(vi). In accordance with the EPA's implementing 
regulations, standards of performance required for designated 
facilities as part of a State plan to implement the EG proposed here 
must be non-duplicative, permanent, verifiable, and enforceable. The 
EPA acknowledges that it may not be feasible to quantify certain non-
numerical standards of performance included in the EG. As such, the EPA 
is proposing that standards of performance for this EG be quantifiable 
to the extent feasible. A State plan implementing the EG should include 
information adequate to support a determination by the EPA that the 
plan meets these requirements. Additionally, States must include 
appropriate monitoring, reporting, and recordkeeping requirements to 
ensure that State plans adequately provide for the implementation and 
enforcement of standards of performance. For designated facilities 
where the EPA's presumptive standards include associated monitoring, 
reporting, and/or recordkeeping requirements, the EPA has determined 
that such requirements are necessary to ensure compliance. Thus, for 
those designated facilities, the EPA is proposing to require that the 
standards of performance established by States maintain the same 
monitoring, reporting, and recordkeeping requirements, or equivalent 
requirements. For example, the EG's presumptive standards for fugitives 
monitoring at well sites includes requirements for owners and operators 
to maintain records and submit reports that demonstrate compliance with 
the monitoring and repair provisions. As such, the EPA is proposing 
that the portion of the State plan which

[[Page 63253]]

establishes standards of performance for that designated facility also 
includes requirements for owners and operators to maintain records and 
submit reports that demonstrate compliance with the monitoring and 
repair provisions. Where a State plan adopts standards of performance 
that differ from the presumptive standards, the plan may accordingly 
include different monitoring, reporting, and recordkeeping requirements 
than those in the presumptive standards, but such requirements must be 
appropriate for the implementation and enforcement of the standards. 
For components of a State plan that differ from any presumptively 
approvable aspects of the final EG, the EPA will review the 
approvability of such components through notice and comment rulemaking.
    Emissions Inventories. The implementing regulations at 40 CFR 
60.25a contain generally applicable requirements for emission 
inventories, source surveillance, and reports. State plans must include 
provisions to meet these requirements as well. Section 60.25a further 
specifies that such data shall be summarized in the plan, and emission 
rates of designated pollutants from designated facilities shall be 
correlated with applicable standards of performance. Typically, the EPA 
would expect that State plans would present this information on a 
source-specific or unit-specific level. However, the EPA recognizes 
that due to the very large number of existing oil and natural gas 
sources,\340\ and the frequent change of configuration and/or 
ownership, that it may not be practical to require States to compile 
this information in the same way that is typically expected for other 
industries under other EG. Therefore, the EPA is soliciting comment on 
whether to supersede the requirements of 40 CFR 60.25a(a) for purposes 
of this EG. The EPA may supersede any requirement in its implementing 
regulations for CAA section 111(d) if done so explicitly in the EG. See 
40 CFR 60.20a(a)(1). Specially, for the reasons explained previously, 
the EPA believes that in this context it could be difficult for the 
State plans to include ``an inventory of all designated facilities, 
including emission data for the designated pollutants and information 
related to emissions as specified in appendix D to this part'' as 
required by the first sentence in 40 CFR 60.25a(a). The EPA understands 
that States may not have such an inventory of all designated facilities 
already available and that creating such an inventory could be resource 
intensive. Likewise, the EPA understands that States may not have site-
specific emissions data for each designated facility, and that creating 
such an inventory could also be very resource intensive. The EPA does 
not believe that such detailed information is necessary for States to 
develop standards of performance, and that standards of performance 
could be developed with a different type of emissions inventory data. 
Therefore, in order to avoid the potential burden that could be imposed 
by applying 40 CFR 60.25a(a) as written to this EG, the EPA is 
soliciting comment on whether the Agency should supersede the 
requirements of 40 CFR 60.25a(a) for purposes of this EG, and replace 
that requirement with a different emissions inventory requirement that 
seeks to represent the same general type of information but allows 
States to utilize existing inventories and emissions data. An example 
of an inventory that could be leveraged, and on which the EPA 
specifically solicits comment, is the GHGRP. The EPA envisions a 
superseding requirement that would not impose such a resource intensive 
burden on States by allowing use of an inventory of GHG emissions data 
and operational data for designated facilities during the most recent 
calendar year for which data is available at the time of State plan 
development and/or submission. The emissions inventory data submitted 
for this purpose could be derived from the GHGRP, and/or other 
available existing inventory information available to the State. The 
EPA recognizes that in this situation the facility definitions used for 
purposes of compiling the emissions inventory data might not be fully 
aligned with the designated facilities in the EG, and that it is 
possible that there could be designated facilities under this EG that 
are not required to report under the emissions inventory program being 
relied upon. Further, the EPA recognizes that the GHGRP may include a 
reporting threshold and/or utilize emission factors in a different 
manner than the EG. The EPA solicits comment on whether it is 
appropriate to utilize or supersede 40 CFR 60.25a(a) for purposes of 
this EG. Specifically, the EPA solicits comment on the practicality of 
States compiling an inventory for all designated facilities and on what 
reasonable alternatives may be more practical.
---------------------------------------------------------------------------

    \340\ In the U.S. the EPA has identified over 15,000 oil and gas 
owners and operators, around 1 million producing onshore oil and gas 
wells, about 5,000 gathering and boosting facilities, over 650 
natural gas processing facilities, and about 1,400 transmission 
compression facilities.
---------------------------------------------------------------------------

    Meaningful Engagement. The fundamental purpose of CAA section 111 
is to reduce emissions from certain stationary sources that cause, or 
significantly contribute to, air pollution which may reasonably be 
anticipated to endanger public health or welfare. Therefore, a key 
consideration in the State's development of a State plan pursuant to an 
EG promulgated under CAA section 111(d) is the potential impact of the 
proposed plan requirements on public health and welfare. A robust and 
meaningful public participation process during State plan development 
is critical to ensuring that these impacts are fully considered. The 
EPA is proposing and soliciting comment on requiring States to perform 
outreach and meaningful engagement with overburdened and underserved 
communities during the development process of their State plan pursuant 
EG OOOOc.
    States often rely primarily on public hearings as the foundation of 
their public engagement in their State plan development process because 
a public hearing is explicitly required pursuant to the applicable 
regulations. The existing provisions in subpart Ba (40 CFR 60.23a(c)-
(f)) detail the public participation requirements associated with the 
development of a CAA section 111(d) State plan. Per these implementing 
regulations, States must provide certain notice of and conduct one or 
more public hearings on their State plan before such plan is adopted 
and submitted to the EPA for review and action. However, robust and 
meaningful public involvement in the development of a State plan should 
go beyond the minimum requirement to hold a public hearing. Meaningful 
engagement should include ensuring that States share information with 
and solicit input from stakeholders at critical junctures during plan 
development, which helps ensure that a plan is adequately addressing 
the potential impacts to public health and welfare that are the core 
concern of CAA section 111.
    This early engagement is especially important for those 
stakeholders and communities directly impacted by the GHG emissions 
from designated facilities within the Crude Oil and Natural Gas source 
category being addressed in a State plan developed pursuant the EG 
OOOOc. As reflected in section VI and VII of the preamble, engagement 
with stakeholders and in particular adjacent communities was key during 
the development of the proposed NSPS and EG and will be key in the 
development of corresponding State plans that achieve the intended 
emission reductions and provide benefits to these communities. In

[[Page 63254]]

recognizing that minority and low-income populations often bear an 
unequal burden of environmental harms and risks, the EPA continues to 
consider ways to protect them from adverse public health and 
environmental effects of air pollution emitted from sources within the 
Oil and Natural Gas Industry that are addressed in this proposed 
rulemaking. For these reasons, the EPA is proposing to include an 
additional requirement associated with the adoption and submittal of 
State plans pursuant to EG OOOOc (in addition to the current 
requirements of Subpart Ba) by requiring States to meaningfully engage 
with members of the public, including overburdened and underserved 
communities, during the plan development process and prior to adoption 
and submission of the plan to the EPA.
    The EPA's authority for proposing to include an additional 
requirement for meaningful engagement is provided by the authority of 
both CAA sections 111(d) and 301(a)(1). Under CAA section 111(d), one 
of the EPA's obligations is to promulgate a process ``similar'' to that 
of CAA section 110 under which States submit plans that implement 
emission reductions consistent with the BSER. CAA section 110(a)(1) 
requires States to adopt and submit State implementation plans (SIPs) 
after ``reasonable notice and public hearings.'' The Act does not 
define what constitutes ``reasonable notice'' under CAA section 110, 
and therefore the EPA may reasonably interpret this requirement in 
promulgating a process under which States submit section 111(d) plans. 
The EPA proposes to give the ``reasonable notice'' requirement 
additional and separate meaning from the ``public hearing'' 
requirement. Therefore, in addition to the generally applicable public 
participation requirements in 40 CFR 60.23a(c)-(f) (which presently 
only require public notification of a public hearing), the EPA proposes 
to promulgate these additional meaningful engagement requirements 
within the EG OOOOc to ensure that the public has reasonable notice of 
relevant information and the opportunity to participate in the State 
plan development throughout the process. Given the public health and 
welfare objectives of CAA section 111(d) in regulating specific 
existing sources, the EPA believes it is reasonable to require 
meaningful engagement as part of the public participation process in 
order to further these objectives. Additionally, CAA section 301(a)(1) 
provides that the EPA is authorized to prescribe such regulations ``as 
are necessary to carry out [its] functions under [the CAA].'' The 
proposed meaningful engagement requirements would effectuate the EPA's 
function under CAA section 111(d) in prescribing a process under which 
States submit plans to implement the statutory directives of this 
section.
    The proposed meaningful engagement requirements for State plan 
development would ensure that the process is inclusive, effective, and 
accessible to all. For this reason, the process must not be 
disproportionate or favor certain stakeholders. During the development 
of the State plan pursuant to EG OOOOc, the EPA expects States to 
identify any underserved or overburdened communities potentially 
impacted by the State plan. If any communities are identified, States 
should engage with these communities and develop public participation 
strategies to overcome linguistic, cultural, institutional, geographic, 
and other barriers to meaningful participation and ensure meaningful 
community representation in the process, recognizing diverse 
constituencies within any particular community. Community participation 
should occur as early as possible if it is to be meaningful. Meaningful 
engagement includes targeted outreach to underserved and overburdened 
communities, sharing information, and soliciting input on State plan 
development and on any accompanying assessments. The EPA uses the term 
``underserved'' to mean populations sharing a particular 
characteristic, as well as geographic communities, that have been 
systemically denied a full opportunity to participate in aspects of 
economic, social, and civic life, and the term ``overburdened'' in 
referring to minority, low-income, Tribal, and indigenous populations 
or communities in the U.S. that potentially experience disproportionate 
environmental harms and risks as a result of greater vulnerability to 
environmental hazards . This increased vulnerability may be 
attributable to an accumulation of both negative and lack of positive 
environmental, health, economic, or social conditions within these 
populations or communities. This engagement will help ensure that State 
plans achieve meaningful emission reductions, that overburdened 
communities partake in the benefits and gains of the State plan, and 
that these communities are protected from being adversely impacted by 
the State plan. The EPA recognizes that emissions from designated 
sources could cross State borders, and therefore may affect underserved 
and overburdened communities in neighboring States. The EPA is 
soliciting comment on how meaningful engagement should apply to 
communities outside of the State that is developing a State plan, for 
example if a State should coordinate with the neighboring State for 
outreach or directly contact the affected community.
    In sections VI and VII of this preamble the EPA addresses 
environmental justice considerations, implications, and stakeholder 
outreach the agency is taking to help ensure vulnerable communities are 
not disproportionately impacted by this rule. The considerations, 
analyses, and outreach presented in these preamble sections could help 
States in designing, planning, and developing their own outreach and 
engagement plans associated with the development and implementation of 
their State plans to reduce emissions of GHGs from designated 
facilities within the Crude Oil and Natural Gas source category.
    To ensure that robust and meaningful public engagement process 
occurs as the States develop their CAA 111(d) plans, the EPA is also 
proposing to include a requirement within EG OOOOc for States to 
demonstrate in their plan submittal how they provided meaningful and 
timely engagement with all pertinent stakeholders, including, as 
necessary, industries and small businesses, as well as low-income 
communities, communities of color, and indigenous populations living 
near the designated facilities and who may be otherwise potentially 
affected by the State's plan. The State would be required to describe, 
in their plan submittal, the engagement they had with their 
stakeholders, including their overburdened and underserved communities. 
Additionally, the EPA would evaluate the States' demonstrations 
regarding meaningful public engagement as part of its completeness 
evaluation of a State plan submittal. If a State plan submission does 
not meet the required elements for public participation, including 
requirements for meaningful engagement, this may be ground for the EPA 
to find the submission incomplete or to disapprove the plan.
    The EPA further notes that the implementing regulations allow a 
State to request the approval of different State procedures for public 
participation pursuant 40 CFR 60.23a(h). The EPA proposes to require 
that such alternate State procedures do not supersede the meaningful 
engagement requirements being proposed within EG OOOOc, so that a State 
would still be required to comply with the meaningful

[[Page 63255]]

participation requirements even if they apply for a different procedure 
than the other public notice and hearing requirements under 40 CFR 
60.23a. As provided in 40 CFR 60.23a(h), the EPA is proposing that 
States may also apply for, and the EPA may approve, alternate 
meaningful engagement procedures if, in the judgement of the 
Administrator, the procedures, although different from the requirements 
of within EG OOOOc, in fact provide for adequate notice to and 
meaningful participation of the public.

D. Components of State Plan Submission

    Under CAA section 111(d)(2), the EPA has an obligation to determine 
whether each State plan is ``satisfactory.'' Therefore, in addition to 
identifying the components that the EG must include, the EPA's 
implementing regulations for CAA section 111(d) identify additional 
components that a State plan must include. Many of these requirements 
are found in 40 CFR 60.23a, 60.24a, 60.25a, and 60.26a. These 
provisions include requirements for components such as the following: 
Procedures a State must go through for adopting a plan before 
submitting it to the EPA; the stringency of standards of performance 
and compliance timelines; emission inventories, reporting, and 
recordkeeping; and, the legal authority a State must show in adopting a 
plan. These requirements are also generally contained in a list of 
required State plan elements, referred to as the State plan 
completeness criteria, found at 40 CFR 60.27a(g)(2)-(3). If the EPA 
determines that a submitted plan does not meet these criteria then the 
State is treated as not submitting a plan and the EPA has a duty to 
promulgate a Federal plan for that State. See CAA section 111(d)(2)(A) 
and 40 CFR 60.27a(g)(1). If the EPA determines a plan submission is 
complete, such determination does not reflect a judgment on the 
eventual approvability of the submitted portions of the plan, which 
instead must be made through notice-and-comment rulemaking. The 
completeness criteria do not apply to States without any designated 
facilities because these States are directed to submit to the 
Administrator a letter of negative declaration certifying that there 
are no designated facilities, as defined by the EPA's emissions 
guidelines, located within the State. See 40 CFR 60.23a(b). No plan is 
required for States that do not have any designated facilities. 
Designated facilities located in States that mistakenly submit a letter 
of negative declaration would be subject to a Federal plan until a 
State plan regulating those facilities becomes approved by the EPA.
    The EPA established nine administrative and six technical criteria 
for complete State plans under CAA section 111(d). See 40 CFR 
60.27a(g)(2)-(3). If a State plan does not include even one of these 
criteria, then the State plan may be deemed incomplete by the EPA. 
States that are familiar with the SIP submittal process under CAA 
section 110 will be familiar with the completeness criteria found in 40 
CFR part 51, appendix V. While the completeness criteria for State plan 
submittals found at 40 CFR 60.27a(g)(2)-(3) is somewhat similar to the 
SIP submittal criteria in appendix V, it is not exactly the same. As 
such, even States that are familiar with the SIP submittal process 
under CAA section 110 are strongly encouraged to review the 
completeness criteria in 40 CFR 60.27a(g)(2)-(3) as well as the other 
State plan requirements found in 40 CFR 60.23a, 60.24a, 60.25a, and 
60.26a early in their planning process.
    In short, the administrative completeness criteria require that the 
State's plan include a formal submittal letter and a copy of the actual 
State regulations themselves, as well as evidence that the State has 
legal authority to adopt and implement the plan, actually adopted the 
plan, followed State procedural laws when adopting the plan, gave 
public notice of the changes to State law, held public hearing(s) if 
applicable, and responded to State-level comments. For a detailed 
description regarding the public hearing requirement, see 40 CFR 
60.23a. For a detailed description of what the State plan must include 
in terms of evidence that the State has legal authority to adopt and 
implement the plan, see 40 CFR 60.26a. States are strongly encouraged 
to review the State plan requirements included in 40 CFR 60.23a and 
60.26a in conjunction with the administrative completeness criteria in 
40 CFR 60.27a.
    The technical criteria require that the State's plan identify the 
designated facilities, the standards of performance, the geographic 
scope of the plan, monitoring, recordkeeping and reporting requirements 
(both for facilities to ensure compliance and for the State to ensure 
performance of the plan as a whole), and compliance schedules. The 
technical criteria further require that the State demonstrate that the 
plan is projected to achieve emission performance under the EG and that 
each emission standard is quantifiable, non-duplicative, permanent, 
verifiable, and enforceable. As previously described, it may not be 
feasible to quantify certain non-numerical standards of performance. 
The EPA is proposing to require States demonstrate that each standard 
of performance is quantifiable, as feasible. For a detailed description 
of the State plan requirements regarding standards of performance, see 
section XIV.C and 40 CFR 60.24a.
    In addition to these technical criteria, 40 CFR 60.25a(a) requires 
that State plans include certain emissions data for the designated 
facilities. As explained previously, the EPA is soliciting comment on 
superseding that requirement for this EG. Further, Sec.  60.25a 
provides a detailed description of what the State plan is required to 
include in terms of certain compliance monitoring and reporting. States 
are strongly encouraged to review the State plan requirements included 
in 40 CFR 60.24a and 60.25a in conjunction with the technical 
completeness criteria in 40 CFR 60.27a.

E. Timing of State Plan Submissions and Compliance Times

    The EPA acknowledges that the D.C. Circuit has vacated certain 
timing provisions within 40 CFR part 60, subpart Ba. Am. Lung Assoc. v. 
EPA, 985 F.3d at 991 (DC Cir. 2021). These provisions include timing 
requirements for when State plans are due upon publication of a final 
EG, for EPA's action on a State plan submission, and for EPA's 
promulgation of a Federal plan. The Agency plans to undertake 
rulemaking to address the provisions vacated under the court's decision 
in the near future. At this time, the EPA is soliciting comment on any 
facts and circumstances that are unique to the oil and natural gas 
industry that the EPA should consider when proposing a timeline for 
plan submission applicable to a final EG for this source category. We 
recognize that the public needs to have an opportunity to review and 
comment on the new timelines that will address these regulatory gaps, 
including in particular the timeline for State plan submission, and the 
Agency is committed to publishing this proposed timeline for comment 
when available.
    In accordance with 40 CFR 60.22a(b)(5), the EPA's EG is to provide 
information for the development of State plans that includes, among 
other things, ``the time within which compliance with standards of 
performance can be achieved.'' The EPA is proposing those compliance 
times for comment. See 40 CFR 60.25a(c). Each State plan must include 
compliance schedules that, subject to certain exception, require 
compliance as expeditiously as practicable but no later

[[Page 63256]]

than the compliance times included in the relevant EG. Id. at 60.24a(a) 
and (c). States are free to include compliance times in their plans 
that are earlier than those included in the final EG. Id. at 40 CFR 
60.24a(f)(2). If a State chooses to include a compliance schedule in 
their plan that extends for a certain period beyond the date required 
for submittal of the plan, then ``the plan must include legally 
enforceable increments of progress to achieve compliance for each 
designated facility.'' \341\ Id. at 40 CFR 60.24a(d). To the extent a 
State accounts for remaining useful life and other factors in applying 
a less stringent standard of performance (than required by the EPA in 
the final EG), the State must also include a compliance deadline that 
it can demonstrate appropriately correlates with that standard.
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    \341\ As previously noted, the timing aspect of this provision 
was vacated by the D.C. Circuit. Am. Lung Assoc. v. EPA, 985 F.3d 
914 at 991. The EPA intends to address the timing aspect of this 
provision in the near future.
---------------------------------------------------------------------------

    The EPA is proposing to require that State plans impose a 
compliance timeline on designated facilities to require final 
compliance with the standards of performance as expeditiously as 
practicable, but no later than two years following the State plan 
submittal deadline. As explained above, the EPA anticipates proposing a 
State plan submission deadline in a separate document. The EPA believes 
that two years is an appropriate amount of time for designated 
facilities to ensure compliance based on the EPA's general 
understanding of the industry and the proposed presumptive standards. 
However, the EPA recognizes that there are many existing sources in the 
oil and natural gas industry that would be subject to a State plan if 
the presumptive standards are finalized in a similar manner as proposed 
in this document, and that there may be a wide range of configurations 
that may be present at any given facility. Further, the EPA recognizes 
that it may be appropriate to require different compliance times for 
different designated facilities. For example, it may be appropriate to 
require one compliance schedule for reciprocating compressors and a 
different compliance schedule for storage vessels. There may not be a 
one-size-fits-all approach to compliance times that is appropriate for 
all designated facilities.
    Accordingly, the EPA is soliciting comment on whether a two-year 
compliance schedule is appropriate for all designated facilities, or 
whether the EG should require a shorter or longer compliance schedule. 
The EPA is further soliciting comment on whether it would be 
appropriate to establish different compliance schedules for different 
designated facilities, and if so, what are the appropriate timelines 
for each designated facility. The EPA is soliciting comment on this 
matter to collect information that might inform different compliance 
timeline(s) that Agency may propose for comment in the future via a 
supplemental proposal.

F. EPA Action on State Plans and Promulgation of Federal Plans

    While CAA section 111(d)(1) authorizes States to develop State 
plans that establish standards of performance and provides States with 
certain discretion in determining the appropriate standards, CAA 
section 111(d)(2) provides the EPA a specific oversight role with 
respect to such State plans. This latter provision authorizes the EPA 
to prescribe a Federal plan for a State ``in cases where the State 
fails to submit a satisfactory plan.'' The States must therefore submit 
their plans to the EPA, and the EPA must evaluate each State plan to 
determine whether each plan is ``satisfactory.'' The EPA's implementing 
regulations for CAA section 111(d) accordingly provide procedural 
requirements for the EPA to make such a determination. See 40 CFR 
60.27a.
    Upon receipt of a State plan, the EPA is first required to 
determine whether the State plan submittal is complete in accordance 
with the completeness criteria explained above. See 40 CFR 
60.27a(g)(1). The EPA would then have a set period of time to act on 
any State plan that is deemed complete.\342\ If the EPA determines that 
the State plan submission is incomplete, then the State will be treated 
as not having made the submission, and the EPA would be required to 
promulgate a Federal plan for the designated facilities in that State. 
Likewise, if a State does not make any submission then the EPA is 
required to promulgate a Federal plan. If the EPA does not make an 
affirmative determination regarding completeness of the State plan 
submission within a certain amount of time from receiving the State 
plan, then the submission is deemed complete by operation of law. Id.
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    \342\ As explained above, the D.C. Circuit vacated the timing 
provisions regarding EPA's action on a state plan submission, and 
EPA's promulgation of a Federal plan. Am. Lung Assoc. v. EPA, 985 
F.3d at 991. The Agency plans to undertake rulemaking to address the 
provisions vacated under the court's decision in the near future.
---------------------------------------------------------------------------

    If a State has submitted a complete plan, then the EPA is required 
to evaluate that plan submission for approvability in accordance with 
the CAA, EPA's implementing regulations, and the applicable EG. The EPA 
may approve or disapprove the State plan submission in whole or in 
part. See 40 CFR 60.27a(b). If the EPA approves the State plan 
submission, then that State plan becomes Federally enforceable. If the 
EPA disapproves the required State plan submission, in whole or in 
part, then the EPA is required to promulgate a Federal plan for the 
designated facilities in that State via a notice-and-comment 
rulemaking, and with an opportunity for public hearing. See 40 CFR 
60.27a(c) and (f). In either scenario that would give rise to the EPA's 
duty to promulgate a Federal plan (a finding that a State did not 
submit a complete plan or a disapproval of a State plan), the EPA would 
not be required to promulgate the Federal plan if the State corrects 
the deficiency giving rise to the EPA's duty and the EPA approves the 
State's plan before promulgating the Federal plan. Requirements 
regarding the content of a Federal plan are included in 40 CFR 
60.27a(e).

G. Tribes and the Planning Process Under CAA Section 111(d)

    Under the Tribal Authority Rule (TAR) adopted by the EPA, Tribes 
may seek authority to implement a plan under CAA section 111(d) in a 
manner similar to a State. See 40 CFR part 49, subpart A. Tribes may, 
but are not required to, seek approval for treatment in a manner 
similar to a State for purposes of developing a Tribal Implementation 
Plan (TIP) implementing the EG. If a Tribe obtains approval and submits 
a TIP, the EPA will generally use similar criteria and follow similar 
procedures as those described above for State plans when evaluating the 
TIP submission, and will approve the TIP if appropriate. The EPA is 
committed to working with eligible Tribes to help them seek 
authorization and develop plans if they choose. Tribes that choose to 
develop plans will generally have the same flexibilities available to 
States in this process. If a Tribe does not seek and obtain the 
authority from the EPA to establish a TIP, the EPA has the authority to 
establish a Federal CAA section 111(d) plan for areas of Indian country 
where designated facilities are located. A Federal plan would apply to 
all designated facilities located in the areas of Indian country 
covered by the Federal plan unless and until the EPA approves an 
applicable TIP applicable to those facilities.

[[Page 63257]]

XV. Prevention of Significant Deterioration and Title V Permitting

    In this section, the EPA is addressing how regulation of GHGs under 
CAA section 111 could have implications for other EPA rules and for 
permits written under the CAA PSD preconstruction permit program and 
the CAA title V operating permit program. The EPA is proposing to 
include provisions in the regulations that explicitly address some of 
these potential implications, consistent with our experience in prior 
rules regulating GHGs. The EPA included and explained the basis for 
similar provisions when promulgating 2016 NSPS OOOOa, as well as the 
2015 subpart TTTT NSPS for electric utility generating units. See 81 FR 
35823, 35871 (June 3, 2016); 80 FR 64509, 64628 (October 23, 2015). The 
discussion in these prior rule preambles equally applies to the oil and 
gas sources subject to NSPS OOOOb and EG OOOOc.
    In summary, in light of the U.S. Supreme Court's decision in 
Utility Air Regulatory Group v. Environmental Protection Agency, 573 
U.S. 302 (2014) (UARG), the EPA may not treat GHGs as an air pollutant 
for purposes of determining whether a source is a major source (or 
modification thereof) for the purpose of PSD applicability. Certain 
portions of the EPA's PSD regulations (specifically, the definition of 
``subject to regulation'') effectively ensure that most sources will 
not trigger PSD solely by virtue of their GHG emissions. E.g., 40 CFR 
51.166(b)(48)(iv), 52.21(b)(49)(iv).\343\ However, the EPA's PSD 
regulations (specifically, the definition of ``regulated NSR 
pollutant'') provide additional bases for PSD applicability for 
pollutants that are regulated under CAA section 111. To address this 
latter component of PSD applicability, the EPA is proposing to add 
provisions within the subpart OOOOb NSPS and subpart OOOOc EG to help 
clarify that the promulgation of GHG standards under section 111 will 
not result in additional sources becoming subject to PSD based solely 
on GHG emissions, which would be contrary to the holding in UARG. These 
provisions will be similar to those in the 2016 NSPS OOOOa and other 
section 111 rules that regulate GHGs. See, e.g., 40 CFR 60.5360a(b)(1)-
(2), 60.5515(b)(1)-(2).
---------------------------------------------------------------------------

    \343\ In 2016, the EPA proposed additional revisions to the PSD 
and title V regulations that would address these and other concerns. 
81 FR 58110 (October 3, 2016).
---------------------------------------------------------------------------

    The EPA understands there are also concerns that if methane were to 
be subject to regulation as a separate air pollutant from GHGs, sources 
that emit methane above the PSD thresholds or modifications that 
increase methane emissions could be subject to the PSD program. To 
address this concern and for purposes of clarity, the EPA is proposing 
to adopt regulatory text within subpart OOOOb NSPS and subpart OOOOc EG 
to clarify that the air pollutant that is subject to regulation is 
GHGs, even though the standard is expressed in the form of a limitation 
on emission of methane. This language will be substantially similar to 
language found in, for example, the 2016 NSPS OOOOa and other rules. 
See, e.g., 40 CFR 60.5360a(a), 60.5515(a).
    For sources that are subject to the PSD program based on non-GHG 
emissions, the CAA continues to require that PSD permits satisfy the 
best available control technology (BACT) requirement for GHGs. Based on 
the language in the PSD regulations, the EPA and States may continue to 
limit the application of BACT to GHG emissions in those circumstances 
where a new source emits GHGs in the amount of at least 75,000 tpy on a 
CO2 Eq. basis or an existing major source increases 
emissions of GHGs by more than 75,000 tpy on a CO2 Eq. 
basis. See 40 CFR 51.166(b)(48)(iv), 52.21(b)(49)(iv). The proposed 
revisions to the regulatory text within subparts OOOOb NSPS and OOOOc 
EG will ensure that this BACT applicability level remains operable to 
sources of GHGs regulated under CAA section 111, as have similar 
revisions in prior rules. See, e.g., 40 CFR 60.5360a(b)(1)-(2), 
60.5515(b)(1)-(2). This proposed rule will not require any additional 
revisions to SIPs.
    Regarding title V, the UARG decision similarly held that the EPA 
may not treat GHGs as an air pollutant for purposes of determining 
whether a source is a major source for the purpose of title V 
applicability. Promulgation of CAA section 111 requirements for GHGs 
will not result in the EPA imposing a requirement that stationary 
sources obtain a title V permit solely because such sources emit or 
have the potential to emit GHGs above the applicable major source 
thresholds.\344\
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    \344\ Additional regulatory text, based on that in prior rules, 
will further ensure that title V regulations are not applied to GHGs 
solely because they are regulated under CAA section 111. See, e.g., 
40 CFR 60.5360a(b)(3)-(4), 60.5515(b)(3)-(4). The EPA understands 
that concerns regarding the regulation of methane as a separate air 
pollutant (described with respect to PSD) also apply to title V. The 
EPA's proposed regulatory text--clarifying that the pollutant 
subject to regulation is GHGs--will similarly address these concerns 
with respect to title V. See, e.g., 40 CFR 60.5360a(a), 60.5515(a).
---------------------------------------------------------------------------

    To be clear, however, unless exempted by the Administrator through 
regulation under CAA section 502(a), any source, including a ``non-
major source,'' subject to a standard or regulation under section 111 
is required to apply for, and operate pursuant to, a title V permit 
that ensures compliance with all applicable CAA requirements for the 
source, including any GHG-related applicable requirements. This aspect 
of the title V program is not affected by UARG.\345\ The EPA proposes 
to include an exemption from the obligation to obtain a title V permit 
for sources subject to NSPS OOOOb and EG OOOOc, unless such sources 
would otherwise be required to obtain a permit under 40 CFR 70.3(a) or 
40 CFR 71.3(a), as the EPA did in NSPS OOOO and OOOOa.\346\ See 40 CFR 
60.5370, 60.5370a. However, sources that are subject to the CAA section 
111 standards promulgated in this rule and that are otherwise required 
to obtain a title V permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) will 
be required to apply for, and operate pursuant to, a title V permit 
that ensures compliance with all applicable CAA requirements, including 
any GHG-related applicable requirements.
---------------------------------------------------------------------------

    \345\ See Memorandum from Janet G. McCabe, Acting Assistant 
Administrator, Office of Air and Radiation, and Cynthia Giles, 
Assistant Administrator, Office of Enforcement and Compliance 
Assurance, to Regional Administrators, Regions 1-10, Next Steps and 
Preliminary Views on the Application of Clean Air Act Permitting 
Programs to Greenhouse Gases Following the Supreme Court's Decision 
in Utility Regulatory Group v. Environmental Protection Agency (July 
24, 2014) at 5.
    \346\ The EPA provided the rationale for exempting this source 
category from the title V permitting requirements during the 
rulemaking for the 2012 NSPS OOOO. See 76 FR 52737, 52751 (August 
23, 2011). That rationale continues to apply to this source 
category.
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XVI. Impacts of This Proposed Rule

A. What are the air impacts?

    The EPA projected that, from 2023 to 2035, relative to the 
baseline, the proposed NSPS OOOOb and EG OOOOc will reduce about 41 
million short tons of methane emissions reductions (920 million tons 
CO2 Eq.), 12 million short tons of VOC emissions reductions, 
and 480 thousand short tons of HAP emission reductions from facilities 
that are potentially affected by this proposal. The EPA projected 
regulatory impacts beginning in 2023 as that year represents the first 
full year of implementation of the proposed NSPS OOOOb. The EPA assumes 
that emissions impacts of the proposed EG OOOOc will begin in 2026. The 
EPA projected impacts through 2035 to illustrate the accumulating 
effects of this rule over a longer period. The EPA

[[Page 63258]]

did not estimate impacts after 2035 for reasons including limited 
information, as explained in the RIA.

B. What are the energy impacts?

    The energy impacts described in this section are those energy 
requirements associated with the operation of emission control devices. 
Potential impacts on the national energy economy from the rule are 
discussed in the economic impacts section in XVI.D. There will likely 
be minimal change in emissions control energy requirements resulting 
from this rule. Additionally, this proposed action continues to 
encourage the use of emission controls that recover hydrocarbon 
products that can be used on-site as fuel or reprocessed within the 
production process for sale.

C. What are the compliance costs?

    The PV of the regulatory compliance cost associated with the 
proposed NSPS OOOOb and EG OOOOc over the 2023 to 2035 period was 
estimated to be $13 billion (in 2019 dollars) using a 3-percent 
discount rate and $10 billion using a 7-percent discount rate. The EAV 
of these cost reductions is estimated to be $1.2 billion per year using 
a 3-percent discount rate and $1.2 billion per year using a 7-percent 
discount rate.
    These estimates do not, however, include the producer revenues 
associated with the projected increase in the recovery of saleable 
natural gas. Estimates of the value of the recovered product have been 
included in previous regulatory analyses as offsetting compliance 
costs. Using the 2021 Annual Energy Outlook (AEO) projection of natural 
gas prices to estimate the value of the change in the recovered gas at 
the wellhead projected to result from the proposed action, the EPA 
estimated a PV of regulatory compliance costs of the proposed rule over 
the 2023 to 2035 period of $7.2 billion using a 3-percent discount rate 
and $6.3 billion using a 7-percent discount rate. The corresponding 
estimates of the EAV of compliance costs after accounting for the 
recovery of saleable natural gas were $680 million per year using a 3-
percent discount rate and $760 million using a 7-percent discount rate.

D. What are the economic and employment impacts?

    The EPA conducted an economic impact and distributional analysis 
for this proposal, as detailed in section 4 of the RIA for this 
proposal. To provide a partial measure of the economic consequences of 
the proposed NSPS OOOOb and EG OOOOc, the EPA developed a pair of 
single-market, static partial-equilibrium analyses of national crude 
oil and natural gas markets. We implemented the pair of single-market 
analyses instead of a coupled market or general equilibrium approach to 
provide broad insights into potential national-level market impacts 
while providing maximum analytical transparency. We estimated the price 
and quantity impacts of the proposed NSPS OOOOb and EG OOOOc on crude 
oil and natural gas markets for a subset of years within the time 
horizon analyzed in the RIA. The models are parameterized using 
production and price data from the U.S. Energy Information 
Administration and supply and demand elasticity estimates from the 
economics literature.
    The RIA projects that regulatory costs are at their highest in 
2026, the first year the requirements of both the proposed NSPS OOOOb 
and EG OOOOc are assumed to be in effect and will represent the year 
with the largest market impacts based upon the partial equilibrium 
modeling. We estimated that the proposed rule could result in a maximum 
decrease in annual natural gas production of about 249 million Mcf in 
2026 (or about 0.8 percent of natural gas production) with a maximum 
price increase of $0.05 per Mcf (or about 1.8 percent). We estimated 
the maximum annual reduction in crude oil production would be about 
12.2 million barrels (or about 0.3 percent of crude oil production) 
with a maximum price increase of about $0.06 per barrel (or less than 
0.1 percent).
    Before 2026, the modeled market impacts are much smaller than the 
2026 impacts as only the incremental requirements under the proposed 
NSPS OOOOb are assumed to be in effect. As regulatory costs are 
projected to decline after 2026, the modelled market impacts for years 
after 2026 are smaller than the peaks estimated for 2026. Please see 
section 4.1 of the RIA for more detail on the formulation and 
implementation of the model as well as a discussion of several 
important caveats and limitations associated with the approach.
    As discussed in the RIA for this proposal, employment impacts of 
environmental regulations are generally composed of a mix of potential 
declines and gains in different areas of the economy over time. 
Regulatory employment impacts can vary across occupations, regions, and 
industries; by labor and product demand and supply elasticities; and in 
response to other labor market conditions. Isolating such impacts is a 
challenge, as they are difficult to disentangle from employment impacts 
caused by a wide variety of ongoing, concurrent economic changes.
    The oil and natural gas industry directly employs approximately 
140,000 people in oil and natural gas extraction, a figure which varies 
with market prices and technological change, and employs a large number 
of workers in related sectors that provide materials and services.\347\ 
As indicated above, the proposed NSPS OOOOb and EG OOOOc are projected 
to cause small changes in oil and natural gas production and prices. As 
a result, demand for labor employed in oil and natural gas-related 
activities and associated industries might experience adjustments as 
there may be increases in compliance-related labor requirements as well 
as changes in employment due to quantity effects in directly regulated 
sectors and sectors that consume oil and natural gas products.
---------------------------------------------------------------------------

    \347\ Employment figure drawn from the Bureau of Labor 
Statistics Current Employment Statistics for NAICS code 211.
---------------------------------------------------------------------------

E. What are the benefits of the proposed standards?

    To satisfy the requirement of E.O. 12866 and to inform the public, 
the EPA estimated the climate and health benefits due to the emissions 
reductions projected under the proposed NSPS OOOOb and EG OOOOc. The 
EPA expects climate and health benefits due to the emissions reductions 
projected under the proposed NSPS OOOOb and EG OOOOc. The EPA estimated 
the global social benefits of CH4 emission reductions 
expected from this proposed rule using the SC-CH4 estimates 
presented in the ``Technical Support Document: Social Cost of Carbon, 
Methane, and Nitrous Oxide Interim Estimates under E.O. 13990 (IWG 
2021)'' published in February 2021 by the Interagency Working Group on 
the Social Cost of Greenhouse Gases (IWG). The SC-CH4 is the 
monetary value of the net harm to society associated with a marginal 
increase in emissions in a given year, or the benefit of avoiding that 
increase. In principle, SC-CH4 includes the value of all 
climate change impacts, including (but not limited to) changes in net 
agricultural productivity, human health effects, property damage from 
increased flood risk and natural disasters, disruption of energy 
systems, risk of conflict, environmental migration, and the value of 
ecosystem services. The SC-CH4 therefore, reflects the 
societal value of reducing emissions of the gas in question by one 
metric ton and is the theoretically appropriate value to use in 
conducting benefit-cost

[[Page 63259]]

analyses of policies that affect CH4 emissions.
    The interim SC-GHG estimates were developed over many years, using 
a transparent process, peer-reviewed methodologies, the best science 
available at the time of that process, and with input from the public. 
As a member of the IWG involved in the development of the February 2021 
Technical Support Document (TSD): Social Cost of Carbon, Methane, and 
Nitrous Oxide Interim Estimates under Executive Order 13990 (IWG 2021), 
the EPA agrees that the interim SC-GHG estimates represent the most 
appropriate estimate of the SC-GHG until revised estimates have been 
developed reflecting the latest, peer-reviewed science.
    The EPA estimated the PV of the climate benefits over the 2023 to 
2035 period to be $55 billion at a 3-percent discount rate. The EAV of 
these benefits is estimated to be $5.2 billion per year at a 3-percent 
discount rate. These values represent only a partial accounting of 
climate impacts from methane emissions and do not account for health 
effects of ozone exposure from the increase in methane emissions.
    Under the proposed NSPS OOOOb and EG OOOOc, the EPA expects that 
VOC emission reductions will improve air quality and are likely to 
improve health and welfare associated with exposure to ozone, 
PM2.5, and HAP. Calculating ozone impacts from VOC emissions 
changes requires information about the spatial patterns in those 
emissions changes. In addition, the ozone health effects from the 
proposed rule will depend on the relative proximity of expected VOC and 
ozone changes to population. In this analysis, we have not 
characterized VOC emissions changes at a finer spatial resolution than 
the national total. In light of these uncertainties, we present an 
illustrative screening analysis in Appendix B of the RIA based on 
modeled oil and natural gas VOC contributions to ozone concentrations 
as they occurred in 2017 and do not include the results of this 
analysis in the estimate of benefits and net benefits projected from 
this proposal.

XVII. Statutory and Executive Order Reviews

    Additional information about these statutes and EOs can be found at 
https://www.epa.gov/laws-regulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This proposed action is an economically significant regulatory 
action that was submitted to the OMB for review. Any changes made in 
response to OMB recommendations have been documented in the docket. The 
EPA prepared an analysis of the potential costs and benefits associated 
with this action. This analysis, ``Regulatory Impact Analysis for the 
Proposed Standards of Performance for New, Reconstructed, and Modified 
Sources and Emissions Guidelines for Existing Sources: Oil and Natural 
Gas Sector Climate Review'', is available in the docket and describes 
in detail the EPA's assumptions and characterizes the various sources 
of uncertainties affecting the estimates.

B. Paperwork Reduction Act (PRA)

    The information collection activities in the proposed amendments 
for 40 CFR part 60, subparts OOOO and OOOOa, have been submitted for 
approval to the Office of Management and Budget (OMB) under the PRA. 
The information collection activities in the proposed rules for 40 CFR 
part 60, subparts OOOOb and OOOOc, will be submitted for approval to 
OMB under the PRA as part of a supplemental proposed rule.\348\ The 
Information Collection Request (ICR) document that the EPA prepared has 
been assigned EPA ICR number 2523.04. You can find a copy of the ICR in 
the docket for this rule, and it is briefly summarized here.
---------------------------------------------------------------------------

    \348\ While not quantified in this proposal, the EPA anticipates 
the estimated ICR burden of proposed NSPS OOOOb and EG OOOOc to be 
at least as burdensome as NSPS OOOOa. The EPA anticipates some 
sources may have similar ICR burden to NSPS OOOOa. Examples of these 
include fugitive emissions from compressor stations, pneumatic 
controllers at gas processing, centrifugal compressors, pneumatic 
pumps, well completions, and sweetening units. The EPA anticipates 
other sources could have dissimilar burden to NSPS OOOOa because the 
standards are different or are brand new to this proposal. Examples 
of these include fugitive emissions from well sites, storage 
vessels, pneumatic controllers, reciprocating compressors, liquids 
unloading, and equipment leaks at gas plants.
---------------------------------------------------------------------------

    The final rule for this action will include updates to the CFR to 
reflect the disapproval of the 2020 Policy Rule that was effectuated by 
the joint resolution enacted pursuant to the CRA on June 30, 2021. The 
EPA is not soliciting comment on these updates. In addition, this rule 
proposes amendments to the 2016 NSPS OOOOa to address (1) certain 
resulting inconsistencies between the VOC and methane standards 
resulting from the CRA, and (2) rescind certain determinations made in 
the 2020 Technical Rule, with respect to fugitive emissions monitoring 
at low production well sites and gathering and boosting stations as 
they were not supported by the record for that rule, or by our 
subsequent information and analysis. The EPA is also proposing further 
amendments to its 2016 NSPS OOOOa to address technical and 
implementation issues.
    This ICR reflects the EPA's proposed amendments to the 2016 NSPS 
OOOOa. The information collected will be used by the EPA and delegated 
State and local agencies to determine the compliance status of affected 
facilities subject to the rule.
    The respondents are owners or operators of onshore oil and natural 
gas affected facilities (40 CFR 60.5365a). For the purposes of this 
ICR, it is assumed that oil and natural gas affected facilities located 
in the U.S. are owned and operated by the oil and natural gas industry, 
and that none of the affected facilities in the U.S. are owned or 
operated by State, local, Tribal or the Federal government. All 
affected facilities are assumed to be privately owned for-profit 
businesses.
    The EPA estimates an average of 3,268 respondents will be affected 
by NSPS OOOOa over the three-year period (2021-2023). The average 
annual burden for the recordkeeping and reporting requirements for 
these owners and operators is 283,030 person-hours, with an average 
annual cost of $93,779,839 over the three-year period (2021-2023).
    Respondents/affected entities: Oil and natural gas operators and 
owners.
    Respondent's obligation to respond: Mandatory.
    Estimated number of respondents: 3,268.
    Frequency of response: Varies depending on affected facility.\349\
---------------------------------------------------------------------------

    \349\ The specific frequency for each information collection 
activity within this request is shown in Tables 1a through 1d of the 
Supporting Statement in the public docket.
---------------------------------------------------------------------------

    Total estimated burden: 283,030 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $93,779,839 (2019$), which includes no 
capital or O&M costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. Submit your 
comments on the Agency's need for this information, the accuracy of the

[[Page 63260]]

provided burden estimates and any suggested methods for minimizing 
respondent burden to the EPA using the docket identified at the 
beginning of this rule. You may also send your ICR-related comments to 
OMB's Office of Information and Regulatory Affairs via email to 
[email protected], Attention: Desk Officer for the EPA. Since 
OMB is required to make a decision concerning the ICR between 30 and 60 
days after receipt, OMB must receive comments no later than December 
15, 2021. The EPA will respond to any ICR-related comments in the final 
rule.

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of this rule on small 
entities, a small entity is defined as: (1) A small business in the oil 
or natural gas industry whose parent company has revenues or numbers of 
employees below the SBA Size Standards for the relevant NAICS code; (2) 
a small governmental jurisdiction that is a government of a city, 
county, town, school district, or special district with a population of 
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not 
dominant in its field.
    Pursuant to section 603 of the RFA, the EPA prepared an initial 
regulatory flexibility analysis (IRFA) that examines the impact of the 
proposed rule on small entities along with regulatory alternatives that 
could minimize that impact. The complete IRFA is available for review 
in the docket and is summarized here.
    The IRFA describes the reason why the proposed rule is being 
considered and describes the objectives and legal basis of the proposed 
rule, as well as discusses related rules affecting the oil and natural 
gas sector. The IRFA describes the EPA's examination of small entity 
effects prior to proposing a regulatory option and provides information 
about steps taken to minimize significant impacts on small entities 
while achieving the objectives of the rule.
    The EPA also summarized the potential regulatory cost impacts of 
the proposed rule and alternatives in Section 2 of the RIA. The 
analysis in the IRFA drew upon some of the same analyses and 
assumptions as the analyses presented in the RIA. The IRFA analysis is 
presented in its entirely in Section 4.3 of the RIA.
    We estimated cost-to-sales ratios (CSR) for each small entity to 
summarize the impacts of the proposed rule on small entities. In the 
processing segment, we find that average compliance costs are expected 
to be negative, and no entity has a cost-to-sales ratio greater than 
either 1 percent or 3 percent. In the production segment, when expected 
revenues from natural gas product recovery are included, 101 small 
entities (7.2 percent) have cost-to-sales ratios greater than 1 
percent, but none have cost-to-sales ratios greater than 3 percent. 
When expected revenues from natural gas product recovery are excluded, 
the number of small entities with cost-to-sales ratios greater than 1 
percent increases to 331 (23 percent); about half of those small 
entities (11 percent) also have cost-to-sales ratios greater than 3 
percent.
    The analysis above is subject to a number of caveats and 
limitations. These are discussed in detail in the IRFA, as well as in 
Section 4.3 of the RIA. As required by section 609(b) of the RFA, the 
EPA also convened a Small Business Advocacy Review (SBAR) Panel to 
obtain advice and recommendations from small entity representatives 
that potentially would be subject to the rule's requirements. The SBAR 
Panel evaluated the assembled materials and small-entity comments on 
issues related to elements of an IRFA. A copy of the full SBAR Panel 
Report is available in the rulemaking docket.

D. Unfunded Mandates Reform Act (UMRA)

    The proposed NSPS and EG do not contain an unfunded mandate of $100 
million or more as described in UMRA, 2 U.S.C. 1531-1538, and do not 
significantly or uniquely affect small governments. The proposed NSPS 
does not contain a Federal mandate that may result in expenditures of 
$100 million or more for State, local, and Tribal governments, in the 
aggregate or the private sector in any one year. For projected cost 
estimates, see ``Regulatory Impact Analysis for the Proposed Standards 
of Performance for New, Reconstructed, and Modified Sources and 
Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector 
Climate Review'', which is available in the docket. The EG is proposed 
under CAA section 111(d) and does not impose any direct compliance 
requirements on designated facilities, apart from the requirement for 
States to develop State plans. As explained in section XIV.G., the EG 
also does not impose specific requirements on Tribal governments that 
have designated facilities located in their area of Indian country. The 
burden for States to develop State plans following promulgation of the 
rule is estimated to be below $100 million in any one year. Thus, the 
EG is not subject to the requirements of section 203 or section 205 of 
the UMRA.
    The NSPS and EG are also not subject to the requirements of section 
203 of UMRA because, as described in 2 U.S.C. 1531-38, they contain no 
regulatory requirements that might significantly or uniquely affect 
small governments. The NSPS and EG action imposes no enforceable duty 
on any State, local, or Tribal governments or the private sector. 
Specifically, for the EG the State governments to which rule 
requirements apply are not considered small governments. In light of 
the interest among governmental entities, the EPA conducted pre-
proposal outreach with national organizations representing States and 
Tribal governmental entities while formulating the proposed rule as 
discussed in section VII. The EPA considered the stakeholders' 
experiences and lessons learned to help inform how to better structure 
this proposal and consider ongoing challenges that will require 
continued collaboration with stakeholders. With this proposal, the EPA 
seeks further input from States and Tribes. For public input to be 
considered during the formal rulemaking, please submit comments on this 
proposed action to the formal regulatory docket at EPA Docket ID No. 
EPA-HQ-OAR-2021-0317 so that the EPA may consider those comments during 
the development of the final rule.

E. Executive Order 13132: Federalism

    Under Executive Order 13132, the EPA may not issue an action that 
has federalism implications, that imposes substantial direct compliance 
costs, and that is not required by statute, unless the Federal 
Government provides the funds necessary to pay the direct compliance 
costs incurred by State and local governments, or the EPA consults with 
State and local officials early in the process of developing the 
proposed action.
    The proposed NSPS OOOOb does not have federalism implications. It 
will not have substantial direct effects on the

[[Page 63261]]

States, on the relationship between the Federal Government and the 
States, or on the distribution of power and responsibilities among the 
various levels of government.
    The proposed EG OOOOc may have federalism implications because 
development of State plans may entail many hours of staff time to 
develop and coordinate programs for compliance with the proposed rule, 
as well as time to work with State legislatures as appropriate, and 
develop a plan submittal. The Agency understands that the EG may impose 
a burden on States and is committed to providing aid and guidance to 
States through the plan development process. In the spirit of E.O. 
13132 and consistent with the EPA policy to promote communications 
between the EPA and State and local governments, the EPA specifically 
solicits comment on this proposed rule from State and local officials 
including information on costs associated with developing and 
submitting State plans in accordance with EG OOOOc.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action has Tribal implications. However, it will neither 
impose substantial direct compliance costs on Federally recognized 
Tribal governments, nor preempt Tribal law, and does not have 
substantial direct effects on the relationship between the Federal 
Government and Indian Tribes or on the distribution of power and 
responsibilities between the Federal Government and Indian Tribes, as 
specified in E.O. 13175. 65 FR 67249 (November 9, 2000). The majority 
of the designated facilities impacted by proposed NSPS and EG on Tribal 
lands are owned by private entities, and Tribes will not be directly 
impacted by the compliance costs associated with this rulemaking. There 
would only be Tribal implications associated with this rulemaking in 
the case where a unit is owned by a Tribal government or in the case of 
the NSPS, a Tribal government is given delegated authority to enforce 
the rulemaking. Tribes are not required to develop plans to implement 
the EG under CAA section 111(d) for designated existing sources. The 
EPA notes that this proposal does not directly impose specific 
requirements on designated facilities, including those located in 
Indian country, but before developing any standards for sources on 
Tribal land, the EPA would consult with leaders from affected Tribes.
    Consistent with previous actions affecting the Crude Oil and 
Natural Gas source category, there is significant Tribal interest 
because of the growth of the oil and natural gas production in Indian 
country. Consistent with the EPA Policy on Consultation and 
Coordination with Indian Tribes, the EPA will engage in consultation 
with Tribal officials during the development of this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is subject to E.O. 13045 (62 FR 19885, April 23, 1997) 
because it is an economically significant regulatory action as defined 
by E.O. 12866, and the EPA believes that the environmental health or 
safety risk addressed by this action has a disproportionate effect on 
children. Accordingly, the agency has evaluated the environmental 
health and welfare effects of climate change on children. GHGs, 
including methane, contribute to climate change and are emitted in 
significant quantities by the oil and gas industry. The EPA believes 
that the GHG emission reductions resulting from implementation of these 
proposed standards and guidelines, if finalize will further improve 
children's health. The assessment literature cited in the EPA's 2009 
Endangerment Findings concluded that certain populations and life 
stages, including children, the elderly, and the poor, are most 
vulnerable to climate-related health effects. The assessment literature 
since 2009 strengthens these conclusions by providing more detailed 
findings regarding these groups' vulnerabilities and the projected 
impacts they may experience. These assessments describe how children's 
unique physiological and developmental factors contribute to making 
them particularly vulnerable to climate change. Impacts to children are 
expected from heat waves, air pollution, infectious and waterborne 
illnesses, and mental health effects resulting from extreme weather 
events. In addition, children are among those especially susceptible to 
most allergic diseases, as well as health effects associated with heat 
waves, storms, and floods. Additional health concerns may arise in low 
income households, especially those with children, if climate change 
reduces food availability and increases prices, leading to food 
insecurity within households. More detailed information on the impacts 
of climate change to human health and welfare is provided in section 
III of this preamble.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action, which is a significant regulatory action under 
Executive Order 12866, has a significant adverse effect on the supply, 
distribution or use of energy. To estimate the potential impacts of the 
proposed NSPS OOOOb and EG OOOOc on crude oil and natural gas 
production, the EPA developed a pair of single-market, static partial-
equilibrium analyses of national crude oil and natural gas markets. 
These analyses are presented in the RIA for this action, which is in 
the public docket. We treat crude oil markets and natural gas markets 
separately in these models. The EPA estimated that the proposed rule 
could result in a maximum decrease in annual natural gas production of 
about 249 million Mcf in 2026 (or about 0.8 percent of natural gas 
production). We estimated the maximum annual reduction in crude oil 
production would be about 12.2 million barrels (or about 0.3 percent of 
crude oil production). Before 2026, the modeled market impacts are much 
smaller than the 2026 impacts as only the incremental requirements 
under the proposed NSPS OOOOb are assumed to be in effect. As 
regulatory costs are projected to decline after 2026, the modelled 
market impacts for years after 2026 are smaller than the peaks 
estimated for 2026. As regulatory costs are projected to decline after 
2026, the modelled market impacts for years after 2026 are smaller than 
the peaks estimated for 2026. The energy impacts the EPA estimates from 
these rules may be under- or over-estimates of the true energy impacts 
associated with this action. For more information on the estimated 
energy effects, please refer to the RIA for this rulemaking.

I. National Technology Transfer and Advancement Act (NTTAA)

    This proposed action for NSPS OOOOb and EG OOOOc involves technical 
standards.\350\ Therefore, the EPA conducted searches for the Standards 
of Performance for New, Reconstructed, and Modified Sources and 
Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector 
Climate Review through the Enhanced National Standards Systems Network 
(NSSN) Database managed by the American National Standards Institute

[[Page 63262]]

(ANSI). Searches were conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 
3A, 3B, 3C, 4, 6, 10, 15, 16, 16A, 18, 21, 22, and 25A of 40 CFR part 
60, appendix A. No applicable voluntary consensus standards were 
identified for EPA Methods 1A, 2A, 2D, 21, and 22 and none were brought 
to its attention in comments. All potential standards were reviewed to 
determine the practicality of the voluntary consensus standards (VCS) 
for this rule. Two VCS were identified as an acceptable alternative to 
EPA test methods for the purpose of this proposed rule. First, ANSI/
ASME PTC 19-10-1981, Flue and Exhaust Gas Analyses (Part 10) (manual 
portions only and not the instrumental portion) was identified to be 
used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A and 16A. This standard 
includes manual and instructional methods of analysis for carbon 
dioxide, carbon monoxide, hydrogen sulfide, nitrogen oxides, oxygen, 
and sulfur dioxide. Second, ASTM D6420-99 (2010), ``Test Method for 
Determination of Gaseous Organic Compounds by Direct Interface Gas 
Chromatography/Mass Spectrometry'' is an acceptable alternative to EPA 
Method 18 with the following caveats, only use when the target 
compounds are all known and the target compounds are all listed in ASTM 
D6420 as measurable. ASTM D6420 should never be specified as a total 
VOC Method. (ASTM D6420-99 (2010) is not incorporated by reference in 
40 CFR part 60.) The search identified 19 VCS that were potentially 
applicable for this proposed rule in lieu of EPA reference methods. 
However, these have been determined to not be practical due to lack of 
equivalency, documentation, validation of data and other important 
technical and policy considerations. For additional information, please 
see the September 10, 2021, memo titled, ``Voluntary Consensus Standard 
Results for New, Reconstructed, and Modified Sources and Emissions 
Guidelines for Existing Sources: Oil and Natural Gas Sector Climate 
Review'' in the public docket. The EPA plans to propose the regulatory 
language for NSPS OOOOb and EG OOOOc through a supplemental action. At 
that time, the EPA will include any appropriate incorporation by 
reference in accordance with requirements of 1 CFR 51.5 as discussed 
below. The EPA anticipates that the following ten standards would be 
incorporated by reference.
---------------------------------------------------------------------------

    \350\ The EPA is not proposing changes to previously conducted 
searches for 40 CFR part 60, subparts OOOO and OOOOa. Therefore, 
this section only describes proposed NSPS OOOOb and EG OOOOc 
standards and searches.
---------------------------------------------------------------------------

     ASTM D86-96, Distillation of Petroleum Products (Approved 
April 10, 1996) covers the distillation of natural gasolines, motor 
gasolines, aviation gasolines, aviation turbine fuels, special boiling 
point spirits, naphthas, white spirit, kerosines, gas oils, distillate 
fuel oils, and similar petroleum products, utilizing either manual or 
automated equipment.
     ASTM D1945-03 (Reapproved 2010), Standard Test Method for 
Analysis of Natural Gas by Gas Chromatography covers the determination 
of the chemical composition of natural gases and similar gaseous 
mixtures within a certain range of composition. This test method may be 
abbreviated for the analysis of lean natural gases containing 
negligible amounts of hexanes and higher hydrocarbons, or for the 
determination of one or more components.
     ASTM D3588-98 (Reapproved 2003), Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuel covers procedures for calculating heating value, relative 
density, and compressibility factor at base conditions for natural gas 
mixtures from compositional analysis. It applies to all common types of 
utility gaseous fuels.
     ASTM D4891-89 (Reapproved 2006), Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion covers the determination of the heating value of natural 
gases and similar gaseous mixtures within a certain range of 
composition.
     ASTM D6522-00 (Reapproved December 2005), Standard Test 
Method for Determination of Nitrogen Oxides, Carbon Monoxide, and 
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating 
Engines, Combustion Turbines, Boilers, and Process Heaters Using 
Portable Analyzers covers the determination of nitrogen oxides, carbon 
monoxide, and oxygen concentrations in controlled and uncontrolled 
emissions from natural gas-fired reciprocating engines, combustion 
turbines, boilers, and process heaters.
     ASTM E168-92, General Techniques of Infrared Quantitative 
Analysis covers the techniques most often used in infrared quantitative 
analysis. Practices associated with the collection and analysis of data 
on a computer are included as well as practices that do not use a 
computer.
     ASTM E169-93, General Techniques of Ultraviolet 
Quantitative Analysis (Approved May 15, 1993) provide general 
information on the techniques most often used in ultraviolet and 
visible quantitative analysis. The purpose is to render unnecessary the 
repetition of these descriptions of techniques in individual methods 
for quantitative analysis.
     ASTM E260-96, General Gas Chromatography Procedures 
(Approved April 10, 1996) is a general guide to the application of gas 
chromatography with packed columns for the separation and analysis of 
vaporizable or gaseous organic and inorganic mixtures and as a 
reference for the writing and reporting of gas chromatography methods.
     ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses 
[Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers 
measuring the oxygen or carbon dioxide content of the exhaust gas.
     EPA-600/R-12/531, EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards (Issued May 2012) is 
mandatory for certifying the calibration gases being used for the 
calibration and audit of ambient air quality analyzers and continuous 
emission monitors that are required by numerous parts of the CFR.
    The EPA determined that the ASTM and ASME/ANSI standards, 
notwithstanding the age of the standards, are reasonably available 
because it they are available for purchase from the following 
addresses: American Society for Testing and Materials (ASTM), 100 Barr 
Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428-2959; 
or ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106 and the American 
Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 
10016-5990. The EPA determined that the EPA standard is reasonably 
available because it is publicly available through the EPA's website: 
https://nepis.epa.gov/Adobe/PDF/P100EKJR.pdf.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    The EPA believes that this action does not have disproportionately 
high and adverse human health or environmental effects on minority 
populations, low-income populations, and/or indigenous peoples, as 
specified in Executive Order 12898 (59 FR 7629, February 16, 1994). The 
documentation for this decision is contained in the RIA prepared under 
E.O. 12866 for this proposal. In Section 4 of the RIA, the EPA presents 
a qualitative discussion of the climate impacts of GHGs and 
environmental justice. The section also presents a set of limited 
quantitative environmental justice analyses focused on the current 
distribution of VOC and HAP emissions from oil and natural gas sector. 
These analyses evaluated baseline scenarios

[[Page 63263]]

and enabled us to characterize risks due to oil and natural gas VOC and 
HAP emissions prior to implementation of the proposed rule. These 
analyses potentially suggest that VOC and HAP emissions from the oil 
and natural gas sector may disproportionately impact vulnerable 
populations or overburdened communities under baseline scenarios; 
however, various uncertainties and data gaps remain, and should be 
taken into consideration when interpreting these results. Additionally, 
we lack key information that would be needed to characterize post-
control risks under the proposed NSPS OOOOb and EG OOOOc or the 
regulatory alternatives analyzed in the RIA, preventing the EPA from 
analyzing spatially differentiated outcomes. While a definitive 
assessment of the impacts of this proposed rule on minority 
populations, low-income populations, and/or indigenous peoples was not 
performed, the EPA believes that this action will achieve substantial 
methane, VOC, and HAP emission reductions and will further improve 
environmental justice community health and welfare. The EPA believes 
that any potential environmental justice populations that may 
experience disproportionate impacts in the baseline may realize 
disproportionate improvements in air quality resulting from emission 
reductions.
    In addition, the EPA provided the public, including those 
communities disproportionately impacted by the burdens of pollution, 
opportunities for meaningful engagement with the EPA on this action. A 
summary of outreach activities conducted by the Agency and what we 
heard from communities is provided in section VI of this preamble.

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Reporting and recordkeeping requirements.

Michael S. Regan,
Administrator.
[FR Doc. 2021-24202 Filed 11-5-21; 4:15 pm]
BILLING CODE 6560-50-P

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