Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems, 13393-13460 [2014-04408]

Download as PDF Vol. 79 Monday, No. 46 March 10, 2014 Part II Environmental Protection Agency emcdonald on DSK67QTVN1PROD with PROPOSALS2 40 CFR Part 98 Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00001 Fmt 4717 Sfmt 4717 E:\FR\FM\10MRP2.SGM 10MRP2 13394 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 98 [EPA–HQ–OAR–2011–0512; FRL–9906–85– OAR] RIN 2060–AR96 Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems Environmental Protection Agency (EPA). ACTION: Proposed rule. AGENCY: The EPA is proposing revisions and confidentiality determinations for the petroleum and natural gas systems source category and the general provisions of the Greenhouse Gas Reporting Rule. In particular, the EPA is proposing to revise certain calculation methods, amend certain monitoring and data reporting requirements, clarify certain terms and definitions, and correct certain technical and editorial errors that have been identified during the course of implementation. This action also proposes confidentiality determinations for new or substantially revised data elements contained in these proposed amendments, as well as proposes a revised confidentiality determination for one existing data element. SUMMARY: Comments. Comments must be received on or before April 24, 2014. Public Hearing. The EPA does not plan to conduct a public hearing unless requested. To request a hearing, please contact the person listed in the following FOR FURTHER INFORMATION CONTACT section by March 17, 2014. If requested, the hearing will be conducted on March 25, 2014, in the Washington, DC area. The EPA will provide further information about the hearing on the Greenhouse Gas Reporting Rule Web site, https:// www.epa.gov/ghgreporting/ if a hearing is requested. ADDRESSES: Submit your comments, identified by Docket ID No. EPA–HQ– OAR–2011–0512 by any of the following methods: • Federal eRulemaking Portal: https:// www.regulations.gov. Follow the online instructions for submitting comments. • Email: GHG_Reporting_Rule_Oil_ And_Natural_Gas@epa.gov. Include Docket ID No. EPA–HQ–OAR–2011– 0512 or RIN No. 2060–AR96 in the subject line of the message. • Fax: (202) 566–9744. emcdonald on DSK67QTVN1PROD with PROPOSALS2 DATES: VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 • Mail: Environmental Protection Agency, EPA Docket Center (EPA/DC), Mailcode 28221T, Attention Docket ID No. OAR–2011–0512, 1200 Pennsylvania Avenue NW., Washington, DC 20460. • Hand/Courier Delivery: EPA Docket Center, Public Reading Room, William Jefferson Clinton (WJC) West Building, Room 3334, 1301 Constitution Avenue NW., Washington, DC 20004. Such deliveries are accepted only during the normal hours of operation of the Docket Center, and special arrangements should be made for deliveries of boxed information. Additional Information on Submitting Comments: To expedite review of your comments by agency staff, you are encouraged to send a separate copy of your comments, in addition to the copy you submit to the official docket, to Carole Cook, U.S. EPA, Office of Atmospheric Programs, Climate Change Division, Mail Code 6207–J, 1200 Pennsylvania Avenue NW., Washington, DC 20460, telephone (202) 343–9263, email address: GHGReportingRule@ epa.gov. Instructions: Direct your comments to Docket ID No. EPA–HQ–OAR–2011– 0512, Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule. 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 confidential business information (CBI) or other information whose disclosure is restricted by statute. Should you choose to submit information that you claim to be CBI, clearly mark the part or all of the information that you claim to be CBI. For information that you claim to be CBI in a disk or CD–ROM that you mail to the EPA, mark the outside of the disk or CD–ROM as CBI and then identify electronically within the disk or CD– ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. 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 to only the mail or hand/courier delivery address listed above, attention: Docket ID No. EPA–HQ–OAR–2011–0512. If you have PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 any questions about CBI or the procedures for claiming CBI, please consult the person identified in the FOR FURTHER INFORMATION CONTACT section. Do not submit information that you consider to be CBI or otherwise protected through https:// www.regulations.gov or email. The https://www.regulations.gov Web site is an ‘‘anonymous access’’ system, 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 disk or CD–ROM 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 avoid the use of special characters, any form of encryption, and be free of any defects or viruses. Docket: All documents in the docket are listed in the https:// www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in https:// www.regulations.gov or in hard copy at the Air Docket, EPA/DC, WJC West Building, Room 3334, 1301 Constitution Ave. NW., Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566–1744, and the telephone number for the Air Docket is (202) 566–1742. FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division, Office of Atmospheric Programs (MC– 6207J), Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 343–9263; fax number: (202) 343–2342; email address: GHGReportingRule@epa.gov. For technical information, please go to the Greenhouse Gas Reporting Rule Web site, https://www.epa.gov/ghgreporting/ E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules index.html. To submit a question, select Help Center, followed by ‘‘Contact Us.’’ Worldwide Web (WWW). In addition to being available in the docket, an electronic copy of today’s proposal will also be available through the WWW. Following the Administrator’s signature, a copy of this action will be posted on EPA’s Greenhouse Gas Reporting Rule Web site at https://www.epa.gov/ ghgreporting/. SUPPLEMENTARY INFORMATION: Regulated Entities. The Administrator determined that this action is subject to the provisions of Clean Air Act (CAA) section 307(d). See CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to ‘‘such other actions as 13395 the Administrator may determine’’). These are proposed amendments to existing regulations. If finalized, these amended regulations would affect owners or operators of petroleum and natural gas systems that directly emit greenhouse gases (GHGs). Regulated categories and entities include those listed in Table 1 of this preamble: TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY Category NAICS Petroleum and Natural Gas Systems ......................................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 Table 1 of this preamble is not intended to be exhaustive, but rather provides a guide for readers regarding facilities likely to be affected by this action. Other types of facilities than those listed in the table could also be subject to reporting requirements. To determine whether you are affected by this action, you should carefully examine the applicability criteria found in 40 CFR part 98, subpart A and 40 CFR part 98, subpart W. If you have questions regarding the applicability of this action to a particular facility, consult the person listed in the preceding FOR FURTHER INFORMATION CONTACT section. Acronyms and Abbreviations. The following acronyms and abbreviations are used in this document. BAMM best available monitoring methods CAA Clean Air Act CBI confidential business information CFR Code of Federal Regulations CH4 methane CO2 carbon dioxide CO2e carbon dioxide equivalent EIA Energy Information Administration EOR enhanced oil recovery EPA U.S. Environmental Protection Agency FERC Federal Energy Regulatory Commission FR Federal Register GHG greenhouse gas GOR gas to oil ratio GWP global warming potential LNG liquefied natural gas MMscf million standard cubic feet per day N2O nitrous oxide NAICS North American Industry Classification System NGL natural gas liquids NTTAA National Technology Transfer and Advancement Act OMB Office of Management and Budget QA/QC quality assurance/quality control RFA Regulatory Flexibility Act scf standard cubic feet TSD Technical Support Document UIC underground injection control U.S. United States VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 486210 221210 211111 211112 Examples of affected facilities Pipeline transportation of natural gas. Natural gas distribution. Crude petroleum and natural gas extraction. Natural gas liquid extraction. UMRA Unfunded Mandates Reform Act of 1995 Organization of This Document. The following outline is provided to aid in locating information in this preamble. I. Background A. Organization of This Preamble B. Background on the Proposed Action C. Legal Authority D. How would these amendments apply to 2014 and 2015 reports? II. Revisions and Other Amendments A. Proposed Revisions To Provide Consistency Throughout Subpart W B. Proposed Changes to Calculation Methods and Reporting Requirements C. Proposed Revisions to Missing Data Provisions D. Proposed Amendments to Best Available Monitoring Methods III. Proposed Confidentiality Determinations A. Overview and Background B. Approach to Proposed CBI Determinations for New or Revised Subpart W Data Elements C. Proposed Confidentiality Determinations for Data Elements Assigned to the ‘‘Unit/Process ‘Static’ Characteristics That Are Not Inputs to Emission Equations’’ and ‘‘Unit/Process Operating Characteristics That Are Not Inputs to Emission Equations’’ Data Categories D. Other Proposed or Re-Proposed Case-byCase Confidentiality Determinations for Subpart W E. Request for Comments on Proposed Confidentiality Determinations IV. Impacts of the Proposed Amendments to Subpart W V. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act 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 PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations I. Background A. Organization of This Preamble The first section of this preamble provides background information regarding the origin of the proposed amendments. This section also discusses the EPA’s legal authority under the CAA to promulgate and amend 40 CFR part 98 of the Greenhouse Gas Reporting Rule (hereinafter referred to as ‘‘Part 98’’) as well as the legal authority for making confidentiality determinations for the data to be reported. Section II of this preamble contains information on the proposed revisions to 40 CFR part 98, subpart W (hereafter referred to as ‘‘subpart W’’). Section III of this preamble discusses proposed confidentiality determinations for new or substantially revised (i.e., requiring additional or different data to be reported) data reporting elements, as well as a proposed revised confidentiality determination for one existing data element. Section IV of this preamble discusses the impacts of the proposed amendments to subpart W. Finally, Section V of this preamble describes the statutory and executive order requirements applicable to this action. B. Background on the Proposed Action On October 30, 2009, the EPA published Part 98 for collecting information regarding greenhouse gases (GHGs) from a broad range of industry sectors (74 FR 56260). The 2009 rule, E:\FR\FM\10MRP2.SGM 10MRP2 13396 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 which finalized reporting requirements for 29 source categories, did not include the petroleum and natural gas systems source category. A subsequent rule was published on November 20, 2010 finalizing the requirements for the petroleum and natural gas systems source category at 40 CFR part 98, subpart W (75 FR 74458) (hereafter referred to as ‘‘the final subpart W rule’’). Following promulgation, the EPA finalized actions revising subpart W (76 FR 22825, April 25, 2011; 76 FR 59533, September 27, 2011; 76 FR 80554, December 23, 2011; 77 FR 51477, August 24, 2012; 78 FR 25392, May 1, 2013; 78 FR 71904, Nov. 29, 2013). In this action, the EPA is proposing to make certain revisions to the petroleum and natural gas systems source category GHG reporting requirements (Part 98, subpart W) and one clarifying edit to a definition in the general provisions source category (Part 98, subpart A). The proposed changes revise certain calculation methods, amend certain monitoring and data reporting requirements, clarify certain terms and definitions, and correct certain technical and editorial errors identified during the course of implementation. The proposed revisions were identified from the verification of annual reports, review of Best Available Monitoring Method (BAMM) request submittals, and questions raised by reporting entities. In conjunction with this action, we are proposing confidentiality determinations for the new and substantially revised (i.e., requiring additional or different data to be reported) data elements contained in these proposed amendments, as well as proposing a revised confidentiality determination for one existing data element. C. Legal Authority The EPA is proposing these rule amendments under its existing CAA authority provided in CAA section 114. As stated in the preamble to the 2009 final GHG reporting rule (74 FR 56260, October 30, 2009), CAA section 114(a)(1) provides the EPA broad authority to require the information proposed to be gathered by this rule because such data would inform and are relevant to the EPA’s carrying out a wide variety of CAA provisions. See the preambles to the proposed (74 FR 16448, April 10, 2009) and final GHG reporting rule (74 FR 56260, October 30, 2009) for further information. In addition, the EPA is proposing confidentiality determinations for proposed new or substantially revised data elements in subpart W, as well as proposing a revised confidentiality VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 determination for one existing data element, under its authorities provided in sections 114, 301, and 307 of the CAA. Section 114(c) requires that the EPA make information obtained under section 114 available to the public, except where information qualifies for confidential treatment. The Administrator has determined that this action is subject to the provisions of section 307(d) of the CAA. contained in the proposed regulatory text are further explained in the memorandum, ‘‘Proposed Minor Technical Corrections to Subpart W, Petroleum and Natural Gas Systems, in the Greenhouse Gas Reporting Program’’ in Docket ID No. EPA–HQ–OAR–2011– 0512. The EPA invites public comment on the revisions identified in this memorandum, as well as those outlined in this preamble. D. How would these amendments apply to 2014 and 2015 reports? The EPA is planning to address the comments we receive on these proposed changes and publish the final amendments before the end of 2014. If finalized, these amendments would become effective on January 1, 2015. Facilities would therefore be required to follow the revised methods in subpart W, as amended, to calculate emissions beginning January 1, 2015 (i.e., beginning with the 2015 reporting year). The first annual reports of emissions calculated using the amended requirements would be those submitted by March 31, 2016, which would cover the 2015 reporting year. For the 2014 reporting year, reporters would continue to calculate emissions and other relevant data for the reports that are submitted according to the requirements of 40 CFR part 98 that are applicable to the 2014 reporting year (i.e. those currently in effect). A. Proposed Revisions To Provide Consistency Throughout Subpart W II. Revisions and Other Amendments The amendments to subpart W that the EPA is proposing include the following types of changes: • Changes to clarify or simplify calculation methods for certain sources at a facility, and reduce some of the burden associated with data collection and reporting. • Revisions to units of measure, terms, and definitions in certain equations to provide consistency throughout the rule, provide clarity, or better reflect facility operations. • Revisions to reporting requirements to clarify and align more closely with the calculation methods and to clearly identify the data that must be reported for each source type. • Other amendments and revisions identified as a result of working with the affected sources during rule implementation and outreach. In addition to the specific revisions or amendments discussed in this section of the preamble, the EPA is proposing several minor technical revisions to subpart W to improve readability, to create consistency in terminology, and/ or to correct typographical or other errors. These proposed revisions PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 1. Consistency in Units of Measure for Emissions Reporting Currently, subpart W requires that reported GHG emissions be expressed in metric tons of CO2 equivalent (CO2e). The EPA is proposing to amend 40 CFR 98.236 to revise the reporting of GHG emissions from units of metric tons of CO2e of each reported GHG to metric tons of each reported GHG. These proposed changes would increase consistency between the reporting requirements for subpart W and the rest of Part 98, because other subparts of Part 98 generally require the reporting of metric tons of individual GHGs instead of metric tons of CO2e. Reporters would use the global warming potentials (GWPs) in Table A–1 of 40 CFR Part 98, subpart A, as required in 40 CFR 98.2(b)(4), to calculate annual emissions aggregated for all GHGs from all applicable source categories in metric tons of CO2e for their annual reports. Specifically, we are proposing to revise the units of emissions reported in 40 CFR 98.236 to require reporting in metric tons of methane (CH4), carbon dioxide (CO2), and nitrous oxide (N2O), as applicable, instead of reporting each gas in metric tons of CO2e. We are also proposing to revise certain calculation methods that require the calculation of emissions in CO2e. For example, subpart W total GHG emissions are calculated using equations that reference GWPs (Equations W–36 and W–40). We are proposing to amend each equation referencing GWPs separately to remove the conversion factors and GWPs that are built into the equations, and allow for calculation of individual GHG emissions in metric tons. The proposed revisions reduce the likelihood of errors and inconsistencies, because it reduces the number of calculations that need to be completed by reporters and removes some variability in how different reporters may complete these calculations (e.g., a reporter could inadvertently use the wrong GWP). The proposed changes would also simplify analysis of emissions on a GHG-specific basis, E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules which would facilitate the verification of reported data. In addition, this proposed change would align subpart W with the manner of reporting for most other subparts of Part 98. emcdonald on DSK67QTVN1PROD with PROPOSALS2 2. Onshore Production Source Category Definition We are proposing to revise the source category definition of onshore petroleum and natural gas production at 40 CFR 98.230(a)(2) to clarify the emission sources covered for purposes of GHG reporting. The proposed amendments clarify the types of emission sources in the onshore petroleum and natural gas production source category to which the reporting requirements of subpart W apply. Specifically, we are proposing to add references to engines, boilers, heaters, flares, separation and processing equipment, and maintenance and repair equipment and to remove references to gravity separation equipment and auxiliary non-transportation-related equipment. Thus, the first sentence of 40 CFR 98.230(a)(2) is proposed to read as follows: ‘‘Onshore petroleum and natural gas production means all equipment on a single well-pad or associated with a single well-pad (including but not limited to compressors, generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and processing equipment, and portable non-selfpropelled equipment which includes well drilling and completion equipment, workover equipment, maintenance and repair equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/ or natural gas (including condensate).’’ The references to gravity separation equipment and auxiliary nontransportation-related equipment in the current rule are redundant with other sources specified in the definition. The proposed amendments do not subject new emission sources to the reporting requirements and do not remove sources currently covered from the reporting requirements, but rather provide a more accurate description of the industry segment for purposes of GHG reporting. 3. Definition of Sub-Basin Category The EPA is proposing to revise the definition of sub-basin category at 40 CFR 98.238 to clarify coverage for purposes of GHG reporting due to issues identified during implementation. Specifically, we are proposing to define sub-basin category as ‘‘a subdivision of a basin into the unique combination of wells with the surface coordinates VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 within the boundaries of an individual county and subsurface completion in one or more of each of the following five formation types: Oil, high permeability gas, shale gas, coal seam, or other tight gas reservoir rock. The distinction between high permeability gas and tight gas reservoirs shall be designated as follows: High permeability gas reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs with ≤0.1 millidarcy permeability. Permeability for a reservoir type shall be determined by engineering estimate. Wells that produce only from high permeability gas, shale gas, coal seam, or other tight gas reservoir rock are considered gas wells; gas wells producing from more than one of these formation types shall be classified into only one type based on the formation with the most contribution to production as determined by engineering knowledge. All wells that produce hydrocarbon liquids (with or without gas) and do not meet the definition of a gas well in this sub-basin category definition are considered to be in the oil formation. All emission sources that handle condensate from gas wells in high permeability gas, shale gas, or tight gas reservoir rock formations are considered to be in the formation that the gas well belongs to and not in the oil formation.’’ The EPA is proposing these edits to clarify that ‘‘tight gas reservoir rock’’ generally refers to tight reservoir rock formations that produce gas, and not tight reservoir rock formations that produce only oil, and that wells that produce liquids in a sub-basin from formations other than high permeability gas, shale gas, coal seam, or other tight gas reservoir rock are considered oil wells. B. Proposed Changes to Calculation Methods and Reporting Requirements This section describes proposed changes or corrections to calculation methods and reporting requirements. In general, the proposed revisions to calculation methods would provide greater flexibility and potentially reduce burden to facilities (e.g., by increasing options for calculating emissions from compressors), and increase clarity and congruency of calculation and reporting requirements (e.g., by clarifying which reporting requirements apply to which calculation methods). The EPA is also proposing minor technical revisions to the calculation methods of subpart W, such as making equation variables and definitions consistent across multiple equations that identify the same parameters, or clarifying requirements that have caused confusion. Please see the memo, ‘‘Proposed Minor Technical PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 13397 Corrections to Subpart W, Petroleum and Natural Gas Systems, in the Greenhouse Gas Reporting Program’’ in Docket ID No. EPA–HQ–OAR–2011– 0512, for more information on the minor technical revisions included in this proposal. We are also proposing revisions to the reporting requirements in 40 CFR 98.236. The proposed revisions would restructure the reporting requirements, make reporting requirements consistent with the calculation methods, clarify the data elements to be reported, and improve data utility. In the current subpart W rule, slight inconsistencies between the calculation and the reporting sections have caused confusion among some reporters. In order to improve the quality of the data reported, we are proposing to revise reporting requirements that more clearly align with the calculation methods for each source type. We are proposing to reorganize the reporting section by source type (e.g., natural gas pneumatic device venting, acid gas removal vents, etc.) and, for each industry segment, list which source types must be reported. These proposed changes would clarify the reporting requirements for each industry segment and streamline verification by reducing the amount of correspondence with facilities during verification regarding required data elements that were not reported. Although the proposed reporting requirements appear lengthier, the revisions separate the requirements into discrete reporting elements in order to facilitate reporting and improve data collection. The proposed revisions to the reporting requirements in 40 CFR 98.236 will clarify which data elements are required to be reported for which facilities. For example, in reviewing the current subpart W reporting forms, if a reporter left certain fields blank in the reporting form (e.g., emissions from flaring), the EPA has been unable to discern whether the field was left blank intentionally. Because the proposed 40 CFR 98.236 would clearly define each data element for each emission source in each industry segment that must be reported, it would clarify which fields in the subpart W reporting form should be populated. In some cases, we are also proposing to add additional data elements to improve the quality of the data reported. The reporting of these proposed data elements would improve verification of reported emissions and reduce the amount of correspondence with reporters that is associated with follow-up and revision of annual reports. In nearly all cases, the new data elements are based on data that are E:\FR\FM\10MRP2.SGM 10MRP2 13398 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 already collected by the reporter or are readily available to the reporter, and would not require additional monitoring or data collection. For additional information on the proposed changes to the reporting section, see the memo, ‘‘Proposed Revisions to the Subpart W Reporting Requirements’’ in Docket Id. No. EPA–HQ–OAR–2011–0512. 1. Natural Gas Pneumatic Device Venting The EPA is proposing to revise the calculation method for natural gas pneumatic device venting to expand the use of site-specific data on gas compositions, if available, for facilities in the onshore natural gas transmission compression and underground natural gas storage industry segments. The final subpart W rule provides default natural gas compositions of 95 percent CH4 and 1 percent CO2 for onshore natural gas transmission compression and underground natural gas storage, when calculating CH4 and CO2 volumetric emissions from transmission storage tanks (transmission compression), blowdown vent stacks (transmission compression), and compressor venting (40 CFR 98.233(u)(2)(iii) and (iv)). The provisions of 40 CFR 98.233(u)(2) only allow default gas compositions to be used, unless otherwise specified in 40 CFR 98.233(u)(2) (i.e., for onshore production and natural gas processing). We are proposing to allow either the use of site-specific composition data for natural gas transmission compression and underground natural gas storage facilities or the use of a default gas composition (95 percent CH4 and 1 percent CO2). Specifically, we are proposing to revise the parameter ‘‘GHGi’’ in Equation W–1 to remove the default gas composition for CH4 and CO2 and to direct reporters to use the concentrations determined as specified in 40 CFR 98.233(u)(2)(i), (iii), and (iv). This amendment addresses reporter concerns and improves data quality for those using site-specific data. The proposed changes are consistent with provisions for other applicable emission sources at natural gas transmission compression and underground storage facilities and would allow a consistent gas composition to be used for all sources at a facility. The calculation still must be conducted in much the same way that is currently required; however, we are proposing that reporters be allowed to use site-specific data if they are available. Therefore, the EPA does not anticipate that this proposed change will significantly affect the reporting burden. The EPA requests comment on whether the use of site-specific composition data for calculating VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 emissions should be required or optional. The EPA also requests comment and specific details on when, if ever, a facility would not have sitespecific gas composition data available. We are also proposing to revise the natural gas pneumatic device venting calculations (40 CFR 98.233(a)(1), (a)(2), and (a)(3)) to simplify how ‘‘Countt’’ of Equation W–1 (total number of natural gas pneumatic devices) must be calculated each year as new devices are added. The revisions clarify that for all industry segments, the reported number of devices must represent the total number of devices for the reporting year. For the onshore petroleum and natural gas production industry segment, reporters would continue to have the option in the first two reporting years to estimate ‘‘Countt’’ using engineering estimates. 2. Acid Gas Removal Vents For acid gas removal vents, we are proposing minor clarifying edits to 40 CFR 98.233(d) to clearly label each calculation method and to clarify provisions by providing references to equations where appropriate. We are also proposing to revise the parameters ‘‘VolCO2’’ in Equation W–3 and parameters ‘‘VolI’’ and ‘‘VolO’’ in Equation W–4A and W–4B to clarify that the volumetric fraction used should be the annual average. We are also proposing to specify in 40 CFR 98.233(d)(8) that reporters may use sales line quality specifications for CO2 in natural gas only if a continuous gas analyzer is not available. 3. Dehydrators We are proposing to revise the dehydrator vents source by renumbering and revising the dehydrator calculation method for desiccant dehydrators in order to clarify the adjustment of emissions to account for venting to a vapor recovery system or to a flare (40 CFR 98.233(e)). The proposed amendments provide for the adjustment of emissions vented to a vapor recovery system or flare (40 CFR 98.233(e)(5) and (e)(6)) for desiccant dehydrators because in the final subpart W rule, it was not clear how such an adjustment would be made. As such, we are clarifying the calculation methods for desiccant dehydrators that vent to a flare or vapor recovery device. 4. Well Venting for Liquids Unloading The EPA is proposing to revise the calculation and reporting requirements for well venting from liquids unloading to allow for annualizing venting data for facilities that calculate emissions using a recording flow meter (Calculation PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 Method 1). This proposed amendment would address reporter concerns and simplify reporting. Some reporters have expressed difficulty in collecting well venting data using a recording flow meter for the exact period of January 1 to December 31, because they contend that it would require them to be physically present at each recording flow meter on December 31. The EPA is proposing to revise Calculation Method 1 (40 CFR 98.233(f)(1)) such that reporters may use an annualized value to determine the cumulative amount of time of venting (‘‘Tp’’ in Equation W–7A and W–7B) if data are not available for the specific time period January 1 to December 31. We are specifying that if an annualized value is used, the monitoring period must begin before February 1 and must not end before December 1 of the reporting year, and that a minimum of 300 consecutive days must be used by reporters to determine the annualized vent time. The EPA is also proposing that the date of the end of one monitoring period must be the start of the next monitoring period for the next reporting year, and that all days must be monitored and all venting accounted for. We are proposing that if a reporter uses a monitoring period other than a full calendar year for any well, they must report the percentage of wells for which a monitoring period other than a full calendar year is used. Although the proposed change increases flexibility, the calculation still must be conducted in much the same way that is currently required. Therefore, the EPA does not anticipate that this proposed change will significantly affect reporting burden. We are proposing to change Calculation Method 1 at 40 CFR 98.233(f)(1) to separate the calculation and reporting of emissions from wells that have plunger lifts and wells that do not have plunger lifts. This separation would allow the EPA and the public to more easily disaggregate emission data and activity data for wells that have plunger lifts and wells that do not have plunger lifts. We are proposing a clarification to Calculation Method 2 in 40 CFR 98.233(f)(2) to clarify that this method is used for wells without plunger lifts. In a harmonizing change, the EPA is proposing to revise the reporting requirement for reporters using Calculation Method 1, under 40 CFR 98.236 such that reporters would be required to report the cumulative amount of time of venting for each group of wells during the year. Calculation Method 1 uses the cumulative amount of time of venting and not the number of venting events, E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 to calculate emissions; therefore, this revision would align the reporting requirement with the calculation method. We are proposing harmonizing changes to 40 CFR 98.236 to separate the reporting of emissions from wells with and without plunger lifts when Calculation Method 1 is used. We are also proposing to amend the definition of the term ‘‘SPp’’ in Equation W–8 (40 CFR 98.233(f)(2)) to clarify that if casing pressure is not available for each well, reporters may determine the casing pressure using a ratio of the casing pressure to tubing pressure from a well in the same sub-basin where the casing pressure is known. This amendment would improve the consistency of the calculation method used to determine casing pressure across reporters. We are also proposing to revise 40 CFR 98.236 to require that facilities using Calculation Methods 1, 2, and 3 report a separate count of wells with plunger lifts and wells without plunger lifts, and to report annual emissions separately from each of those sources, respectively. We are also proposing to amend 40 CFR 98.236 to require the reporting of the cumulative number of unloadings from wells with plunger lifts and unloadings from wells without plunger lifts, the average flow rate of the measured well venting for wells with and without plunger lifts, and the internal casing or tubing diameters and pressures for wells with and without plunger lifts, as applicable. These proposed revisions break out the existing count and emissions reporting requirements to more clearly specify the sources of emissions at facilities. For further information on well venting for liquids unloading, see the Technical Support Document (TSD) ‘‘Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule’’ in Docket ID No. EPA–HQ–OAR–2011– 0512. 5. Gas Well Completions And Workovers The EPA is proposing to amend 40 CFR 98.238 to add definitions for ‘‘reduced emissions completion’’ and ‘‘reduced emissions workover’’. Currently, reduced emissions completions and reduced emission workovers are mentioned in the relevant calculation method as equipment that separates natural gas from the backflow and sends this natural gas to a flow-line. However, there are currently no defined terms for reduced emissions completions and reduced emissions workovers. The EPA notes that since the VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 time that subpart W was promulgated, the EPA promulgated new source performance standards for the oil and natural gas sector under 40 CFR Part 60, subpart OOOO, that requires the use of a reduced emissions completion in specified circumstances. The EPA proposes to add a definition for ‘‘reduced emissions completion’’ to subpart W that would be consistent with the description of that term in the new source performance standard rulemaking (see 76 FR 52757–8). Specifically, the EPA is proposing to amend 40 CFR 98.238 to define a ‘‘reduced emissions completion’’ as a well completion following fracturing where gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or collection system, reinjected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere. We are proposing to amend 40 CFR 98.238 to define a ‘‘reduced emissions workover’’ as a well workover with hydraulic fracturing (i.e., refracturing) where gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere. The EPA does not anticipate these definitional changes would impact current reporters under Part 98 because these changes are clarifying in nature and do not change any requirements of subpart W. The EPA is also proposing to amend the definition of ‘‘well completions’’ in 40 CFR 98.6 to delete the term ‘‘refracture’’ as this term applies to an already producing well and is considered a well workover, not a well completion, for the purposes of part 98. This amendment is intended to avoid potential confusion concerning whether a re-fracture is a completion or workover in the context of subpart W. This change will also better align the existing definition of ‘‘well completions’’ with the new proposed definition of a ‘‘reduced emissions completion’’ by clarifying that a reduced emission completion only applies to new fractures and that re-fractures are potentially covered under the new definition of ‘‘reduced emission workover’’. The definition of ‘‘well workover’’ in 40 CFR 98.6 already refers to re-fractures, so no clarifying change is needed for that definition. We are also proposing to revise reporting requirements for completions PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 13399 and workovers to differentiate between completions and workovers with different well type combinations in each sub-basin category. A well type combination is a unique combination of the following factors: Vertical or horizontal, with flaring or without flaring, and reduced emission completion/workover or not reduced emission completion/workover. Specifically, for well completions and workovers with hydraulic fracturing, we are proposing to require separate counts and separate reporting of emissions for the different well type combinations. These revisions would improve data quality for emissions from wells with hydraulic fracturing. Because the EPA is proposing to expand the well type definition for completions and workovers with hydraulic fracturing to include whether the well completions/ workovers are flared or not, and whether it is a reduced or not reduced emission completion/workover, it is possible that reporters will have more than one reporting category (i.e., different well types in each sub-basin) for completions and workovers with hydraulic fracturing. Therefore, some reporters will be required to further categorize their calculated emissions from completions and workovers with hydraulic fracturing, which they did not have to do before. We anticipate that these proposed changes will increase burden to some reporters somewhat. Reporters will be required to separate and report their calculated emissions from completions and workovers without hydraulic fracturing by whether the emissions are related to completions or workovers, which they do not have to do under the current version of the rule. We anticipate that those proposed changes would only slightly increase burden to reporters. We are also proposing revisions to Equation W–10A that would add clarity and increase the accuracy of emissions calculations for gas well completions and workovers with hydraulic fracturing. In the final subpart W rule, the measurement or calculation for determining the ratio of flowback during well completions and workovers to 30day production rate in Equation W–10A (40 CFR 98.233(g)) begins immediately upon initiating flowback of a well. Some reporters have asserted that the flowback characteristics of a well following hydraulic fracturing do not enable measurement or calculation to begin immediately upon initiating flowback due to a lack of sufficient gas being present, and the calculation needs to be revised to account for this fact. Therefore, the EPA is proposing to E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 13400 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules modify the calculation to require the measurement of flow rate only when sufficient gas is present to enable flow rate measurement. In addition, some reporters have asserted that the accuracy of emissions calculations could be affected by the combined use of sales gas volume and approximations on flow rates for non-measured wells. To resolve this apparent issue, the time variable ‘‘Tp’’ in Equation W–10A and W–10B is being modified. Time that the gas is routed to production would no longer be included, so it would no longer be necessary to subtract the volume of gas being sent to sales. This amendment would not significantly change the reporting burden. The proposed equations are similar in complexity as the previous equations and use measurements that are of similar complexity. This proposed revision would improve data quality and provide flexibility by providing an estimation method for data that could not likely be measured accurately. We are also proposing changes to the calculation section at 40 CFR 98.233(g) and (h) to support the separate calculation of emissions from completions and workovers that are vented, flared, or use equipment that separates natural gas from the backflow and sends this natural gas to a flow-line (e.g., reduced emissions completions or reduced emissions workovers). Reporters currently calculate emissions from all completion and workover activities, but the equations do not facilitate the classification of the activity needed for separate reporting. We are proposing to revise Equation W–13 in 40 CFR 98.233(h) to separate the calculation of emissions from workovers from the calculation of completions into two equations. This amendment will improve data quality. We are also proposing to clarify that reporters must calculate the annual volumetric natural gas emissions from each gas well venting during workovers without hydraulic fracturing using Equation W– 13A and from each gas well venting from completions without hydraulic fracturing using new Equation W–13B. We do not anticipate that this proposed change would significantly increase the reporting burden, because the proposed calculations are the same as the current calculation; we only propose to break it into two steps. The proposed methodology also requires the addition of parameter ‘‘Es,p’’ for Equation W–13B to specify the annual volumetric natural gas emissions in standard cubic feet from well completions. We are also proposing to revise 40 CFR 98.233(g)(1) to clarify the number of measurements VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 or calculations that must be taken to estimate the average ratio of flowback rate (FRM). We are proposing to revise 40 CFR 98.233(g)(2) to clarify that measurements from the well flowing pressure upstream of a well choke to calculate well backflow must be collected for each sub-basin and well type combination. We are also proposing to revise parameter ‘‘PRs,p’’ in Equations W–10A and W–10B and Equation W–12 to clarify that the first 30 day average production flow rate is the average taken after completions of newly drilled gas wells or workovers. For further information on gas well venting during completions and workovers, see the TSD ‘‘Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule’’ in Docket ID No. EPA–HQ–OAR–2011– 0512. 6. Blowdown Vents Based on questions received during implementation of the final subpart W rule and reporter concerns, the EPA is proposing to revise Equations W–14A and W–14B to include a compressibility term. Specifically, some reporters requested that the EPA allow the use of a factor to adjust for compressibility when calculating emissions from blowdown vents. The calculation method for blowdown vents included in the existing subpart W rule assumes natural gas is an ideal gas with a compressibility factor of 1, and does not include an adjustment for compressibility in the calculation. Although the EPA had previously considered including the compressibility term (76 FR 56010, September 9, 2011), the EPA ultimately did not propose including the factor, because we then concluded that including a compressibility adjustment could create a degree of uncertainty between reporters on how their reported blowdown values compared (on a volume basis). We noted at that time that although the compressibility of pure light hydrocarbon substances is well known, the compressibility of hydrocarbon mixtures is less well known and the composition of natural gas throughout the segments covered by subpart W can be variable. At that time, we determined that ideal gas law calculations were adequate for reporting purposes under Part 98. The EPA notes that the circumstances surrounding this issue are now different because, as discussed in Section III.B.1 of this preamble, the EPA is proposing to require the use of site-specific data on PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 gas compositions, if available. In addition, we have determined that at high pressures and low temperatures, the accuracy of the emission estimate would be improved if a compressibility factor were included in the calculation. The compressibility of methane at standard conditions is close to one. However, the compressibility of methane at low temperatures and high pressures is lower than one, which may affect the accuracy of the emission calculation if not included in that calculation. Therefore, the EPA proposes to revise Equations W–14A and W–14B in 40 CFR 98.233(i) to include the compressibility term ‘‘Za’’. A default compressibility term of 1 may be used at conditions where the pressure is below 5 atmospheres, and the temperature is above ¥10 degrees Fahrenheit, or if the compressibility factor at the actual temperature and pressure is 0.98 or greater. We are proposing harmonizing changes to Equations W–33 and W–34 in 40 CFR 98.233(t) to include the compressibility term ‘‘Za’’ for conversion of volumetric emissions at actual conditions to standard conditions. Because it is likely that most facilities handle gas within the proposed compressibility factor default ranges, it is unlikely that adding this compressibility factor term into the blowdown vent stack calculations will significantly increase the reporting burden. The EPA is also proposing to simplify the reporting for blowdowns. In the final subpart W rule, reporters must calculate and record emissions for each blowdown event that is greater than or equal to 50 cubic feet of actual volume. Currently, for each piece of equipment (unique physical volume) that is blown down more than one time in a calendar year, reports are submitted for the total number of blowdowns, the emissions for each unique physical volume, and the name or ID number for the unique physical volume. For all equipment that is blown down only once during the calendar year, reports are submitted as an aggregate for all such equipment at each facility. Reports include the total number of blowdowns and the emissions from all equipment with unique physical volumes that are blown down only once. The volume of gas vented is calculated for each blowdown event using the conditions specific to the event. However, the reporting of each ‘‘unique physical volume’’ blown down more than once in a year may be an extensive list of unique equipment. A similar reporting approach was adopted by the EPA in the November 2010 version of subpart W (75 FR 74458). There, the reporting E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 requirement specified that emissions be reported collectively per equipment type. This approach caused some confusion because a list of equipment types was not provided. Therefore we are proposing to revise the current reporting requirements in 40 CFR 98.236(c)(7) to simplify the reporting structure to report blowdown emissions aggregated by seven categories: station piping, pipeline venting, compressors, scrubbers/strainers, pig launchers and receivers, emergency shutdowns, and all other blowdowns greater than or equal to 50 cubic feet. Although facilities are no longer required to report blowdown vent stack emissions by each unique physical volume, facilities still have to calculate blowdown vent stack emissions from each unique physical volume and categorize the emissions by equipment. Therefore, the EPA has determined that this proposed change would not significantly impact burden to reporters. The EPA is also proposing an optional calculation method for blowdown emissions for situations where a flow meter is in place to measure the emissions directly. If a blowdown vent is equipped with a flow meter, there would not be an advantage to calculating the emissions using the unique volume, temperature, and pressure conditions of the equipment instead of the directly measured flow rate. We are proposing this alternative calculation method in 40 CFR 98.233(i), along with associated reporting requirements in 40 CFR 98.236. We are also proposing additional clarifying edits for both the blowdown calculation and reporting sections of the rule. If a flow meter is in place to measure emissions, the emissions would be reported on a facility basis, and would not be aggregated by emission type per 40 CFR 98.236(i)(2). For further information on blowdown vents, see the TSD ‘‘Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule’’ in Docket ID No. EPA– HQ–OAR–2011–0512. 7. Onshore Production Storage Tanks We are proposing to revise the method for estimating emissions from occurrences of well pad gas-liquid separator liquid dump valves that are not properly operating for onshore production storage tanks. The EPA initiated this revision to address reporter concerns and to improve data quality. Specifically, reporters expressed concern with the burden associated with quantifying and recording information for all properly VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 functioning dump valves. The proposed revisions would require the detection of an anomaly and only then require quantification. Hence only those dump valves found to not be closing properly (i.e., stuck dump valves) would have to be quantified. Specifically, the EPA is proposing to simplify Equation W–16 to calculate emissions for only periods when the dump valve is not closing properly. The EPA is also proposing to revise the reporting section to make it clear that facilities are to separately report the emissions from onshore production storage tanks attributable to periods when dump valves are not closing properly, as opposed to emissions that occur when dump valves are closing properly. In the final subpart W rule, 40 CFR 98.236(c)(8)(iv) requires that facilities report annual total volumetric GHG emissions that resulted from dump valves that are not closing properly. However, Equation W–16 in the final subpart W rule sums the total emissions for periods when the dump valve is closing properly and periods when the dump valve is not closing properly. The EPA is clarifying 40 CFR 98.236 to specify that facilities that use Equation W–16 should report only emissions that result from dump valves that are not closing properly. Note that emissions from atmospheric tanks that are not a result of dump valves not closing properly would continue to be reported in this proposed revision outside of Equation W–16. There is no significant additional burden to facilities, because reporters already use these data elements in Equation W–16: separate tank and dump valve emissions already need to be calculated separately, but would now also be reported separately. This revision would eliminate potential confusion for reporters, clarify recordkeeping requirements, and improve the ability to quantify emissions from stuck dump valves. For further information on emissions from improperly functioning dump valves, see the TSD ‘‘Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule’’ in Docket ID No. EPA– HQ–OAR–2011–0512. These proposed revisions would improve the quality of data collected. 8. Associated Gas Venting and Flaring The EPA is proposing to add a term to Equation W–18 (40 CFR 98.233(m)(3)) to account for situations where part of the associated gas from a well goes to a sales line while another part of the gas is flared or vented. These amendments improve data quality by eliminating PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 13401 duplicate reporting. Emissions are currently calculated based on the gas-tooil ratio (GOR) and volume of oil produced during the flaring period. The GOR is based on total gas from the well, which means all the gas would currently be reported as flared even though a portion of the gas goes to a sales line. The proposed revision to Equation W–18 subtracts the volume of associated gas sent to sales from the annual volumetric natural gas emissions from associated gas venting. The EPA has also included in the equation a term (EREp,q) for emissions reported under other sources included in this subpart (i.e., tank venting) to avoid double counting of these emissions. The EPA also proposes updating the definition of the term GORp,q and the emission result Ea,n in Equation W–18 to specify that the gas to oil ratio and the result of the calculation are calculated at standard conditions rather than actual conditions. Because the GOR is measured in standard cubic feet, this change would harmonize the equation terms and the result of the emission calculation equation would be at standard conditions. Although the proposed calculation method modifies the current equation to include two new terms, these terms are already being calculated elsewhere and/or can be estimated. Therefore, the EPA does not anticipate that this proposed change will significantly affect the reporting burden. The EPA is also proposing to add a definition for the term ‘‘Associated gas venting or flaring’’ to clarify what is included in this source. The EPA is proposing to define ‘‘Associated gas venting or flaring’’ as ‘‘the venting or flaring of natural gas which 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. This definition does not include venting or flaring resulting from activities that are reported elsewhere, including tank venting, well completions, and well workovers.’’ The proposed definition allows for greater consistency with the changes made to the calculation method. This is a clarifying proposed change that improves data quality and should not significantly affect the burden to current reporters. For further information on emissions from associated gas, see the TSD ‘‘Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; E:\FR\FM\10MRP2.SGM 10MRP2 13402 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 Proposed Rule’’ in Docket ID No. EPA– HQ–OAR–2011–0512. 9. Flare Stack Emissions The EPA is proposing to amend the calculation method for emissions from a flare stack to simplify the calculation to standard conditions and to account for gas that is sent to an unlit flare. Specifically, we are proposing to revise Equation W–19 and combine Equations W–20, and W–21. The EPA also proposes to revise the equations such that the emissions of CH4 and CO2 are calculated in standard conditions. We propose to remove paragraph 40 CFR 98.233(n)(11), which specifies estimating emissions for the volume of gas flared under actual conditions. We also propose to add the terms ‘‘ZU’’ and ‘‘ZL’’ to Equation W–19 and the terms ‘‘ZU’’ and ‘‘ZL’’ to Equation W–20 to account for the fraction of gas sent to an unlit flare and the fraction of gas sent to a burning flare. The fraction of feed gas sent to an unlit flare would be determined by using engineering estimates and process knowledge. The proposed changes simplify and clarify the calculation requirements and would improve the accuracy of the collected data by accounting for the fraction of emissions that are not combusted when sent to an unlit flare. The EPA is also proposing a revision to the onshore natural gas transmission compression, underground natural gas storage, liquefied natural gas (LNG) storage, LNG import and export equipment industry segments to clarify that emissions from any flares in these segments must be reported using the calculation method for emissions from a flare stack. This clarifying revision is consistent with the treatment of flares in other parts of subpart W and is necessary to calculate emissions for compressors routed to flares under the proposed compressor calculation requirement modifications. We anticipate that this proposed change may slightly increase burden for select reporters and will not significantly affect burden for most reporters; however, this clarifying revision is consistent with the treatment of flares in other parts of subpart W and is necessary to calculate emissions for compressors routed to flares under the proposed compressor calculation requirement modifications. 10. Centrifugal and Reciprocating Compressors Some reporters have contended that the current monitoring requirements for compressor venting are overly burdensome and present safety and operational process concerns. These VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 reporters asserted that it is not practical to require a measurement from each individual compressor for groups of compressors that are routed to a common vent manifold (or flare header), because this would require the entire group of compressors that are connected to the common manifold (or flare header) to be shutdown, blown down, and purged in order to safely install meters (or ports for temporary meters) and enable individual measurements. The reporters stated that it is extremely rare that entire groups of compressors are shutdown at the same time. In the November 2010 response to public comments on the subpart W final rule (Docket ID No. EPA–HQ–OAR–2009– 0923), the EPA noted that commenters requested that the EPA allow direct measurements of common manifolded vent lines on compressors. At least one commenter stated that if continuous measurement of manifolded vent lines and aggregate annual emissions reporting were allowed as an option for measuring compressors, they would be able to safely collect and report to the EPA continuously measured data. The EPA did not include this option in the 2010 final subpart W rule because it was not clear whether measurements at a common vent outlet could be used to correctly characterize annual emissions from individual compressors. In today’s action, we are proposing changes to the centrifugal and reciprocating compressor calculation sections (see 40 CFR 98.233(o) and (p)) in order to address reporter concerns related to measuring centrifugal and reciprocating compressor emissions that are routed to a common vent manifold (or flare header). For those compressors, the EPA is proposing an option where reporters would take at least three measurements per year and report the average of the measurements. These measurements would need to be taken before emissions are comingled with other non-compressor emission sources. This option would address reporter’s safety concerns for facilities that need to shut down equipment to install individual meters and maintain accurate characterization of annual emissions from compressors at the facility. Annual volumetric emissions would be determined for each manifolded group of compressors combined for all operating conditions (mode-source combinations). Reporters would still be required to report activity data for any individually measured sources (i.e., non-manifolded sources) at the compressor level. Activity data reported would include information about the individual compressors included in the PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 manifolded vent. This proposed measurement option would allow the EPA to correctly characterize and analyze GHG emissions from all compressors at individual facilities in the petroleum and natural gas systems source category while potentially reducing burden to the industry. Although reporting elements include new activity data, reporters would no longer be required to sample manifolded compressor sources individually, thus decreasing overall burden and providing flexibility. For example, if a reporter operates seven compressors that have their blowdown vent stacks manifolded, the reporter would no longer have to conduct seven measurements every year (one for each blowdown vent stack) as required by the current rule. Instead, for this example, the reporter would be required to only conduct a measurement three times per year on the common vent stack that is associated with the manifolded group of seven compressor sources, which would decrease burden for the reporter compared to the seven measurements currently required. The EPA considered requiring only one or two measurements per year for these manifolded sources (as opposed to the EPA proposal above for the average of three measurements). The EPA concluded that the annual process variability for these sources was high enough to warrant more than one or two measurements per year. Please see the TSD ‘‘Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule’’ in Docket ID No. EPA– HQ–OAR–2011–0512, for more background and information on the options considered. In addition to seeking comment on our proposed option, the EPA is specifically seeking comment on the two other options that were considered and other derivations of these options (i.e., four measurements per year instead of three). Comments should include justification why the specific option receiving comment does not negatively impact safety, is technical and economically feasible, does not impose undue burden on reporters, and how the option is sufficiently accurate given the annual process variability for these sources. We are also proposing to include four definitions in 40 CFR 98.238 to support the addition of the calculation method for manifolded vents. We are proposing a definition for ‘‘compressor’’ to mean ‘‘any type of vent or valve (i.e., wet seal, blowdown valve, isolation valve, or rod packing) on a centrifugal or reciprocating compressor.’’ We are proposing a definition for ‘‘compressor E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules mode’’ to mean ‘‘means the operational and pressurized status of a compressor. For a centrifugal compressor, ‘‘mode’’ refers to either operating-mode or notoperating-depressurized-mode. For a reciprocating compressor, ‘‘mode’’ refers to either: Operating-mode, standbypressurized-mode, or not-operatingdepressurized-mode.’’ We are proposing a definition for ‘‘manifolded compressor source’’ to mean ‘‘a compressor source that is manifolded to a common vent that routes gas from multiple compressors.’’ We are also proposing a definition of ‘‘manifolded group of compressor sources’’ to mean ‘‘a collection of any combination of compressor sources that are manifolded to a common vent.’’ In addition, for compressors that are routed to an operational flare, we are proposing to allow operators to calculate and report emissions with other flare emissions (in lieu of estimating compressor emissions based on knowledge of the total flare emissions and the portion of those flare emissions that can be attributed to compressors). This proposed change addresses reporter concerns, provides flexibility, and potentially decreases burden without affecting data quality. Although operators would still be required to report certain compressorrelated activity data for each compressor that is routed to an operational flare (as provided for in 40 CFR 98.236(o)(1) and (p)(1)), reporting emissions from compressors (that are routed to an operational flare) with other flare emissions would reduce burden, because reporters would not be required to sample compressors individually or be required to portion flare emissions attributed to compressors. It was brought to the EPA’s attention that the 3-year cycle requirement for measuring compressors in the notoperating-depressurized-mode could present a compliance challenge for some facilities, because not every facility schedules routine shutdowns for maintenance within 3 years. The EPA did not intend for reporters to perform an unscheduled shutdown of a facility for the sole purpose of taking a measurement of the compressor in the not-operating-depressurized-mode. Therefore, we are proposing to revise the requirement to measure each compressor in the not-operatingdepressurized-mode at least once in any 3 consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar years, the EPA proposes that a measurement must be made at the next scheduled VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 depressurized compressor shutdown (for reciprocating compressors, this measurement can be taken during the next scheduled shutdown when the compressor rod packing is replaced). By allowing the measurement to be taken at these specified scheduled shutdowns, operators would not have to plan a shutdown of their equipment to take a measurement of their compressor in the not-operating-depressurized-mode. This proposed amendment addresses reporters’ concerns and potentially decreases burden without affecting data quality. Even though the ‘‘not-operatingdepressurized-mode’’ is measured only at scheduled shutdowns (which might be every 3 years or greater), the reporter is still required to conduct an annual measurement in whatever mode the compressor is found. Therefore, the frequency in measurements is unchanged. The EPA also considered modifying the existing requirement to measure each compressor in the notoperating-depressurized-mode at least once every 3 years to correspond to a longer term, such as every 5 years. However, such an extension might not resolve the issue for all reporters. The EPA is specifically seeking comment on our proposed option as well as the additional option that was considered. The EPA is also clarifying that for reporters that elect to conduct as found leak measurements for individual compressor sources, all measurements from a single owner or operator may be used when developing an emission factor (using Equation W–24 or W–28 of 40 CFR 98.233) for each compressor mode-source combination. If the reporter elects to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator. Although this option may make it easier for some reporters to keep track of their calculated reporter emission factors, all reporters are still required to calculate reporter emission factors if they use the as found leak measurement option. Therefore, the EPA does not anticipate that this clarifying edit will significantly affect the reporting burden. We are also proposing to restructure and revise the centrifugal and reciprocating compressor sections (see 40 CFR 98.233(o) and 40 CFR 98.233(p)) in order to improve clarity for reporters. Because the restructuring was extensive, entirely new text appears for 40 CFR 98.233(o) and 40 CFR 98.233(p). Although the proposed restructuring changes would not significantly change any of the requirements or burden, the proposed restructuring and revisions would clarify current requirements that are vague or confusing. For example, we PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 13403 are proposing to retain the current equations for determining emissions from each compressor’s measured mode-source combination and unmeasured mode-source combination; however, we are proposing language that would explain when to use the equation(s). We are also proposing revisions to improve consistency between the centrifugal and reciprocating compressor sections (see 40 CFR 98.233(o) and 40 CFR 98.233(p)). For example, we are proposing to revise the equation variables to bring consistency between the two sections. It is our view that the restructuring and clarification revisions that we are proposing in this action for the centrifugal and reciprocating compressor sections would improve readability and usability for both industry and government regulators. For further information on measuring emissions from compressors, see the TSD ‘‘Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule’’ in Docket ID No. EPA– HQ–OAR–2011–0512. 11. Natural Gas Distribution: Leak Detection Equipment and Emissions From Components For natural gas distribution, the final subpart W rule requires reporters to calculate a facility emission factor for a meter/regulator run per component type at above grade metering-regulating (M– R) stations. The calculation of the emission factor using Equation W–32 in 40 CFR 98.233(r) based on the results of equipment leak surveys that are required under 40 CFR 98.233(q) at above grade transmission-distribution (T–D) stations and the subsequent annual emissions calculated for those stations using Equations W–30B. Reporters have pointed out that the nomenclature and inter-related calculations between 40 CFR 98.233(q) and (r) has caused confusion. Therefore, the EPA is proposing to revise the calculation requirements for natural gas distribution facilities and associated terminology in 40 CFR 98.233(q) and (r). Specifically, the EPA is proposing to place the facility meter/regulator run emission factor calculation in 40 CFR 98.233(q) instead of 40 CFR 98.233(r) and clarify that the emission factor is calculated separately for CO2 and CH4 and is on a meter/regulator run operational hour basis, instead of on a meter/regulator run component basis. Facilities calculate annual emissions from above grade transmissiondistribution transfer stations using Equation W–30 of 40 CFR 98.233(q). E:\FR\FM\10MRP2.SGM 10MRP2 13404 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 The emissions are calculated in Equation W–30 on a per component basis based on equipment leak survey results and leaker emission factors for transmission-distribution transfer station components listed in Table W– 7. The results of the component level annual emissions calculations using Equation W–30 are then summed for all component types in Equation W–31 to develop the annual facility meter/ regulator run emission factors for CO2 and CH4. Those facility emission factors must be recalculated annually as additional equipment leak survey data becomes available from above grade transmission-distribution transfer stations. To calculate annual emissions from above grade metering-regulating stations that are not above grade transmission-distribution transfer stations, facilities must use the emission factors (calculated in Equation W–31) in the annual emissions calculation of Equation W–32B in 40 CFR 98.233(r). Emissions from below grade meteringregulating stations, below grade transmission-distribution transfer stations, distribution mains, and distribution services are calculated using Equation W–32A of 40 CFR 98.233(r) using population emission factors listed in Table W–7. These proposed revisions will alleviate the current confusion with the calculation and reporting requirements for natural gas distribution facilities while capturing the same emissions sources from this industry segment and maintaining the same level of data accuracy. Data are generally reported at a less detailed level, but there is no change in emissions coverage. 12. Onshore Petroleum and Natural Gas Production and Natural Gas Distribution Combustion Emissions The EPA is proposing to clarify that emissions and volume of fuel combusted must be reported for all compressor driven internal combustion units in 40 CFR 98.236. The EPA is proposing to revise this reporting requirement to be consistent with the emission estimation methods in 40 CFR 98.233(z)(4) that specify the exemption from reporting emissions for internal combustion units with a rated heat input capacity less than or equal to 1 MMBtu/hr (130 horsepower) does not apply to internal fuel combustion sources that are compressor drivers. C. Proposed Revisions to Missing Data Provisions We are proposing to revise 40 CFR 98.235 to clarify the procedures for estimating missing data. We are proposing to increase the specificity VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 regarding how to use, treat, and report missing data for each calculation specified in 40 CFR 98.233.These proposed revisions would increase clarity for reporters and improve the accuracy of the data reported by ensuring that the data substituted for missing values is limited in use, and, where necessary, well-documented and quality-assured or based on the best available estimates. To address newly acquired wells, the EPA is also proposing missing data procedures specific to facilities that are newly subject to subpart W and to existing onshore petroleum and natural gas production facilities that acquire wells that were not subject to subpart W prior to the acquisition. In these specific cases, the EPA is proposing to allow best engineering estimates for any parameter that cannot be reasonably measured or obtained according to the requirements in subpart W for up to six months from the first date of subpart W applicability. Where facilities acquired additional wells, only data and calculations associated with those newly acquired wells would fall within this proposed provision. This proposed revision provides flexibility for newly acquired facilities or wells. Missing data procedures were previously not allowed for many areas of subpart W; however, with the proposed removal of BAMM, the missing data procedures provide clarity for reporters who may have unintentionally missed required data. D. Proposed Amendments to Best Available Monitoring Methods In order to provide facilities with time to adjust to the requirements of the rule, subpart W has provisions allowing the optional use of best available monitoring methods (BAMM) for unique or unusual circumstances. Where a facility uses BAMM, it is required to follow emission calculations specified by the EPA, but is allowed to use alternative methods for determining inputs to calculate emissions. Inputs are the values used by facilities to calculate equation outputs. Examples of BAMM include: Monitoring methods used by the facility that do not meet the specifications of subpart W, supplier data, engineering calculations, and other company records. Facilities are required to receive approval from the EPA prior to using BAMM and these facilities are required to specify in their GHG annual reports when BAMM is used for an emission source. The EPA has previously noted that the Agency intended to ‘‘approve the use of BAMM beyond 2011 only in cases that are unique or unusual’’ (76 FR 59538). Furthermore, the EPA limited the PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 approvals of BAMM to one reporting year in keeping with the intent to allow use of BAMM as a transitional provision until facilities come into compliance with the final rule. While the EPA occasionally uses BAMM for targeted, short-term monitoring flexibilities (i.e., provision for reporters who become subject to Part 98 from the recent GWP changes to subpart A to have automatic BAMM for the first three months of reporting), no industry-specific subpart within Part 98 continues to use the BAMM flexibility except subpart W. In this action, the EPA is proposing to remove all provisions in 40 CFR 98.234(f) for BAMM. We are also proposing to remove and reserve 40 CFR 98.234(g), which is a provision specific to the 2011 and 2012 reporting years. The removal of BAMM will improve data quality by requiring consistent reporting for each segment in subpart W. We are proposing these amendments because we expect facilities would be able to comply with the monitoring and QA/QC methods required under subpart W after this proposed rule is finalized and effective. Reporters with issues that were unidentified at the time of the final rule will, by January 1, 2015, have had adequate time to resolve these issues. It has been the EPA’s intent throughout implementation of subpart W that BAMM be available as a limited, transitional program to serve as a bridge to full compliance with the rule for cases where reporters faced reasonable impediments to compliance. The EPA never intended to extend BAMM requirements indefinitely. The proposed amendments are therefore in keeping with the EPA’s stated intent to transition to reporting without BAMM. We also believe, based on several years of experience with the industry and these reporting requirements, that facilities have successfully transitioned so that they either no longer need to use BAMM or will not need to use BAMM if these proposed revisions are finalized. In a review of BAMM request submittals for the 2014 reporting year, the EPA found that the sources with the most frequent BAMM requests included centrifugal compressors, reciprocating compressors, blowdown vent stacks, and combustion emissions, which are addressed in this rulemaking. The proposed revisions would also resolve the need for BAMM for certain facilities for which the final subpart W monitoring requirements were technically infeasible. For example, the most common concerns raised in BAMM requests associated with technical infeasibility included concerns related to having to shut down a facility to install access ports to E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules conduct compressor measurements. As discussed in Section II.B.10 of this preamble, we are making revisions that allow the testing of a common vent and that clarify that operators do not have to shut a facility down for the sole purpose to test a compressor in its non-operating mode, but that the measurement must be made at the next scheduled shutdown. In light of the extended time period in which the EPA has granted BAMM to allow facilities to come into compliance with subpart W requirements, the revisions that the EPA is proposing to make to the final rule, and the fact that all other industry-specific subparts in Part 98 no longer have continual BAMM, we expect that facilities would be in compliance with the monitoring and QA/QC methods required under subpart W for the 2015 calendar year. The EPA requests comment and strong technical evidence for sitespecific unique or unusual circumstances that would require the use of BAMM after January 1, 2015. These comments should include the details of how and why the special circumstances exist, why the data collection methods in subpart W (including those in this proposal) are not feasible, the data that could not be monitored in order to comply with subpart W, and how specifically the data could otherwise be collected. For further information on BAMM, see the TSD ‘‘Greenhouse Gas Reporting Rule: Technical Support for Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed Rule’’ in Docket ID No. EPA– HQ–OAR–2011–0512. emcdonald on DSK67QTVN1PROD with PROPOSALS2 III. Proposed Confidentiality Determinations A. Overview and Background In this proposed rule we are proposing confidentiality determinations for new and subtantially revised reporting data elements in the proposed amendments, with certain exceptions as discussed in more detail below. These new and substantially revised data elements would result from the proposed corrections, clarifying, and other amendments that are described in Section II of this preamble, which would also result in substantial changes to the data elements that are reported. We are also proposing to revise the confidentiality determination for one existing data element that is not being amended, as discussed in Section III.B of this preamble. The final confidentiality determinations the EPA has previously made for the remainder of the subpart W data elements are VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 unaffected by the proposed amendments and continue to apply. For information on confidentiality determinations for the GHGRP and subpart W data elements, see: 75 FR 39094, July 7, 2010; 76 FR 30782, May 26, 2011; 77 FR 48072, August 13, 2012; and 78 FR 55994, September 11, 2013. These proposed confidentiality determinations would be finalized after considering public comment. The EPA plans to finalize these determinations at the same time the proposed rule amendments described in this action are finalized. B. Approach to Proposed CBI Determinations for New or Revised Subpart W Data Elements For the proposed new and substantially revised data elements, except for the specific data elements separately addressed below, we are applying the same approach as previously used for making confidentiality determinations for data elements reported under the GHGRP. In the ‘‘Confidentiality Determinations for Data Required Under the Mandatory Greenhouse Gas Reporting Rule and Amendments to Special Rules Governing Certain Information Obtained Under the Clean Air Act’’ (hereinafter referred to as ‘‘2011 Final CBI Rule’’) (76 FR 30782, May 26, 2011), the EPA grouped Part 98 data elements into 22 data categories (11 direct emitter data categories and 11 supplier data categories) with each of the 22 data categories containing data elements that are similar in type or characteristics. The EPA then made categorical confidentiality determinations for eight direct emitter data categories and eight supplier data categories and applied the categorical confidentiality determination to all data elements assigned to the category. Of these data categories with categorical determinations, the EPA determined that four direct emitter data categories are comprised of those data elements that meet the definition of ‘‘emissions data,’’ as defined at 40 CFR 2.301(a), and that, therefore, are not entitled to confidential treatment under section 114(c) of the CAA.1 The EPA determined that the other four direct emitter data categories and the eight supplier data categories do not meet the definition of ‘‘emission data.’’ For these data categories that are determined not 1 Direct emitter data categories that meet the definition of ‘‘emission data’’ in 40 CFR 2.301(a) are Facility and Unit Identifier Information, Emissions, Calculation Methodology and Methodological Tier, Data Elements Reported for Periods of Missing Data that are not Inputs to Emission Equations, and Inputs to Emission Equations. PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 13405 to be emission data, the EPA determined categorically that data in three direct emitter data categories and five supplier data categories are eligible for confidential treatment as CBI, and that the data in one direct emitter data category and three supplier data categories are ineligible for confidential treatment as CBI. For two direct emitter data categories, ‘‘Unit/Process ‘Static’ Characteristics that Are Not Inputs to Emission Equations’’ and ‘‘Unit/Process Operating Characteristics that Are Not Inputs to Emission Equations,’’ and three supplier data categories, ‘‘GHGs Reported,’’ ‘‘Production/Throughput Quantities and Composition,’’ and ‘‘Unit/Process Operating Characteristics,’’ the EPA determined in the 2011 Final CBI Rule that the data elements assigned to those categories are not emission data, but the EPA did not make categorical CBI determinations for them. Rather, the EPA made CBI determinations for each individual data element included in those categories on a case-by-case basis taking into consideration the criteria in 40 CFR 2.208. No final confidentiality determination was made for the inputs to emission equation data category (a direct emitter data category). For this rulemaking, we are proposing to assign 243 new or revised data elements to the appropriate direct emitter data categories created in the 2011 Final CBI Rule based on the type and characteristics of each data element. Note that subpart W is a direct emitter source category, thus, no data are assigned to any supplier data categories. For data elements the EPA has assigned in this proposed action to a direct emitter category with a categorical determination, the EPA is proposing that the categorical determination for the category be applied to the proposed new or revised data element. For the proposed categorical assignment of the data elements in these eight categories with categorical determinations, see Memorandum Data Category Assignments and Confidentiality Determinations for all Data Elements (excluding inputs to emission equations) in the Proposed ‘‘Technical Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems’’ in Docket ID No. EPA–HQ–OAR–2011–0512. For data elements assigned to the ‘‘Unit/Process ‘Static’ Characteristics that Are Not Inputs to Emission Equations’’ and ‘‘Unit/Process Operating Characteristics that Are Not Inputs to Emission Equations,’’ we are proposing confidentiality determinations on a case-by-case basis taking into E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 13406 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules consideration the criteria in 40 CFR 2.208, consistent with the approach used for data elements previously assigned to these two data categories. For the proposed categorical assignment of these data elements, see Memorandum Data Category Assignments and Confidentiality Determinations for all Data Elements (excluding inputs to emission equations) in the Proposed ‘‘Technical Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems’’ in Docket ID No. EPA–HQ–OAR–2011–0512. For the results of our case-by-case evaluation of these data elements, see Sections III.C and III.D of this preamble. For the reasons stated below, we are proposing individual confidentiality deteminations for 11 new or substantially revised data elements without making a data category assignment. In the 2011 Final CBI rule, although the EPA grouped similar data into categories and made categorical confidentiality determinations for a number of data categories, the EPA also recognized that similar data elements may not always have the same confidentiality status, in which case the EPA made individual instead of categorical determinations for the data elements within such data categories.2 Similarly, while the 11 proposed new or substantially revised data elements are similar in type or certain characteristics to data elements previously assigned to the ‘‘Production/Throughput Data Not Used as Input’’ and ‘‘Raw Materials Consumed that are Not Inputs to Emission Equations’’ data categories, we do not believe that they share the same confidentiality status as the non-subpart W data elements already assigned to those two data categories, which the EPA has determined categorically to be CBI based on the data elements assigned to those categories at the time of the 2011 Final CBI Rule. As discussed in more detail below, our review showed that these 11 subpart W production and throughput-related data elements fail to qualify for confidential treatment. Therefore, we do not believe that the categorical determinations for the ‘‘Production/Throughput Data Not Used as Input’’ and ‘‘Raw Materials Consumed that are Not Inputs to Emission Equations’’ data categories are appropriate for these 11 data elements; accordingly, these data elements should not be assigned to these data categories. Not assigning these 11 data elements to these two data categories would also 2 In the 2011 Final CBI rule, several data categories include both CBI and non-CBI data elements. See 76 FR 30786. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 leave unaffected the existing categorical determinations for these data categories, which remain valid and applicable to the data elements assigned to those data categories. For the reasons stated above, we are proposing individual confidentiality determinations for these 11 data elements without making categorical assignment. Our proposed individual determinations follow the same twostep evaluation process as set forth in the 2011 Final CBI Rule and subsequent confidentiality determinations for Part 98 data. Specifically, we first determined whether the data element meets the definition of emission data in 40 CFR 2.301(a). Data elements that meet the definition of emission data are required to be released under section 114 of the Clean Air Act. For data elements found to not meet the definition of emission data, we evaluated whether a data element meets the criteria in 40 CFR 2.208 for confidential treatment. In particular, we focus on: (1) Whether the data are already public; and (2) whether ‘‘. . . disclosure of the information is likely to cause substantial harm to the business’s competitive position.’’ For the results of our case-by-case evaluation of these proposed new subpart W data elements, see Section III.D of this preamble. We are also proposing to revise the confidentiality determinations for one existing subpart W data element. Our review of the 11 proposed data elements discussed above led us to re-examine our previous determination for this data element, which is similar in type or characteristics to the 11 proposed data elements for which the EPA is choosing to make case-by-case determinations. This one data element is the only subpart W data element currently assigned to ‘‘Production/Throughput Data Not Used as Input’’ data category. As discussed in more detail in Section III.D of this preamble, our review showed that this data element fails to qualify for confidential treatment. For the same reasons set forth above for not proposing categorical assignments for the 11 data elements, we are proposing to remove this data element’s current category assignment, as well as the application of the categorical CBI determination to this data element. Instead, we are re-proposing a confidentiality determination based on the two-step process discussed above for the proposed 11 new data elements. For the results of our case-by-case evaluation of the proposed subpart W data elements, see Section III.D of this preamble. We are proposing to assign 40 new or substantially revised data elements used PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 to calculate GHG emissions in subpart W to the ‘‘Input to Emission Equation’’ data category. To date, the EPA has not made confidentiality determinations for any data element, including any subpart W data element, assigned to the ‘‘Inputs to Emission Equation’’ data category. We are therefore not proposing confidentiality determinations for the 40 proposed new or substantially revised inputs to emission equations data elements. However, due to concerns expressed by reporters with the potential release of inputs to emission equations, we previously established a process for evaluating ‘‘inputs to emission equation’’ data elements to identify potential disclosure concerns and actions to address such concerns if appropriate.3 The EPA has used this process to evaluate inputs to emission equations, including the subpart W data elements that are already assigned to the inputs to emission equations data category.4 We performed a similar evaluation for the 40 proposed new and substantially revised subpart W inputs to emission equations and did not identify any potential disclosure concerns. Accordingly, the proposal would require reporting of these data elements by March 31, 2016, which is the reporting deadline for the 2015 reporting year. For the list of new and revised subpart W inputs to emission equations and the results of our evaluation, see memorandum titled ‘‘Review of Public Availability and Harm Evaluation for Proposed New Inputs to Emission Equations in the Proposed ‘Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems’ ’’ in Docket ID No. EPA–HQ–OAR–2011–0512. The proposed amendments include revisions a number of subpart W data reporting elements for which confidentiality determinations were previously finalized in the August 13, 2012 ‘‘Final Confidentiality Determinations for Regulations Under the Mandatory Reporting of Greenhouse Gases Rule’’ (77 FR 48072). The proposed revisions relative to some of 3 See the ‘‘Change to the Reporting Date for Certain Data Elements Required Under the Mandatory Reporting of Greenhouse Gases Rule’’ (hereinafter referred to as the ‘‘Final Deferral Notice’’) (76 FR 53057, August 25, 2011) and the accompanying memorandum entitled ‘‘Process for Evaluating and Potentially Amending Part 98 Inputs to Emission Equations’’ (Docket ID EPA–HQ–OAR– 2010–0929). 4 See the memoranda titled ‘‘Summary of Data Collected to Support Determination of Public Availability of Inputs to Emission Equations for which Reporting was Deferred to March 31, 2015’’ and ‘‘Evaluation of Competitive Harm from Disclosure of Inputs to Equations Data Elements Deferred to March 31, 2015.’’ (Docket ID EPA–HQ– OAR–2010–0929). E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules these data reporting elements would not require different or additional data to be reported under these data elements. The proposed revisions include a reorganization of the reporting requirements so that the data elements more close align with the calculation methodologies. This reorganization of the reporting section would result in changes to many of the rule citations for data elements. In addition to restructuring the reporting section, the EPA has proposed other minor revisions designed to clarify the existing reporting requirements. For example, some of the proposed changes would clarify the source type (e.g., natural gas pneumatic device venting, acid gas removal vents, etc.) and industry segment that is required to report the data element. The proposed revisions also include corrections of typographical and other clerical errors. These corrections would not change the data to be reported. Although the proposed revisions would separate the requirements into a larger number of discrete reporting elements and would clarify and correct typographical errors, they would not change the underlying data elements to be reported for many data elements. Therefore, the confidentiality determinations finalized in the August 13, 2012 rule continue to apply. We are therefore not proposing revisions to the existing confidentially determinations for the data reporting elements that either would not require different or additional data to be reported under the proposed revisions or the proposed revisions would not change the underlying data elements to be reported. For a summary of the proposed reporting requirements for subpart W that incorporate these changes to data organization and descriptions, see the memo, ‘‘Proposed Revisions to the Subpart W Reporting Requirements’’ in Docket ID No. EPA–HQ–OAR–2011– 0512. C. Proposed Confidentiality Determinations for Data Elements Assigned to the ‘‘Unit/Process ‘Static’ Characteristics That Are Not Inputs to Emission Equations’’ and ‘‘Unit/Process Operating Characteristics That Are Not Inputs to Emission Equations’’ Data Categories The EPA is proposing to assign 101 proposed new or substantially revised data elements for subpart W to the ‘‘Unit/Process ‘Operating’ Characteristics That Are Not Inputs to Emission Equations’’ data category or the ‘‘Unit/Process ‘Static’ Characteristics That Are Not Inputs to Emission Equations’’ data category, because the proposed new or substantially revised data elements share the same characteristics as the other data elements previously assigned to the category. We are proposing confidentiality determinations for these 13407 proposed new or substantially revised data elements based on the approach set forth in the 2011 Final CBI Rule for data elements assigned to these two data categories. In that rule, the EPA determined categorically that data elements assigned to these two data categories do not meet the definition of emission data in 40 CFR 2.301(a); the EPA then made individual, instead of categorical, confidentiality determinations for these data elements. As with all other data elements assigned to these two categories, the proposed new or substantially revised data elements do not meet the definition of emissions data in 40 CFR 2.301(a). The EPA then considered the confidentiality criteria at 40 CFR 2.208 in making our proposed confidentiality determinations. Specifically, we focused on whether the data are already publicly available from other sources and, if not, whether disclosure of the data is likely to cause substantial harm to the business’ competitive position. Table 2 of this preamble lists the data elements the EPA proposes to assign to the ‘‘Unit/ Process ‘Operating’ Characteristics That Are Not Inputs to Emission Equations’’ and ‘‘Unit/Process ‘Static’ Characteristics That Are Not Inputs to Emission Equations’’ data categories, the proposed confidentiality determination for each data element, and our rationale for each determination. TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES Citation Data element Proposed confidentiality determination and rationale ‘‘Unit/Process ‘Operating’ Characteristics That Are Not Inputs to Emission Equations’’ Data Category emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(d)(1)(iv) ......................... VerDate Mar<15>2010 18:44 Mar 07, 2014 Whether any CO2 emissions are recovered and transferred outside the facility. Jkt 232001 PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 This proposed data element would be reported by onshore petroleum and natural gas production facilities and by onshore natural gas processing plants. This data element indicates that a facility is operating an acid gas removal unit and indicates how the facility handles the CO2 emissions it generates. Acid gas removal units are used to remove carbon dioxide and hydrogen sulfide from raw natural gas streams and are commonly found at gas processing facilities. These units are listed in a facility’s construction and operating permits, which are publicly available. Because this information is routinely available through required permits, we propose these data elements be designated as ‘‘not CBI.’’ E:\FR\FM\10MRP2.SGM 10MRP2 13408 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Citation Data element Proposed confidentiality determination and rationale 98.236(e)(1)(xvii) ....................... For each absorbent dehydrator, whether any dehydrator emissions are vented to the atmosphere without being routed to a flare or regenerator firebox. For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd, the total number of dehydrators at the facility. For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd, the total number of dehydrators venting to a vapor recovery device. For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd, the number of dehydrators venting to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd, whether any glycol dehydrator emissions are vented to a flare or regenerator firebox/fire tubes. For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 MMscfd and vented to a flare or regenerator firebox, the total number of dehydrators. For dehydrators that use desiccant, the total number of dehydrators at the facility. For dehydrators that use desiccant, whether any dehydrator emissions are vented to a vapor recovery device. For dehydrators that use desiccant, the total number of dehydrators venting to a vapor recovery device. For dehydrators that use desiccant, whether any dehydrator emissions are vented to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes, and the control device type. For dehydrators that use desiccant, whether any dehydrator emissions are vented to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. For dehydrators that use desiccant, the number of dehydrators venting to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. For dehydrators that use desiccant, whether any glycol dehydrator emissions are vented to a flare or regenerator firebox/fire tubes. For dehydrators that use desiccant and vent to a flare or regenerator firebox, the total number of dehydrators. These proposed data elements would be reported by onshore petroleum and natural gas production facilities and by onshore natural gas processing plants. These data elements indicate that a facility is equipped with dehydration units, the number of dehydrators used, the design of dehydrator used (glycol or desiccant), and how emissions from dehydration units are handled by the facility. Dehydration units are used to remove water from natural gas streams. Most natural gas processing facilities are equipped with these units and because they are a source of hazardous air pollutants, these units are subject to rigorous emissions control requirements (e.g., 40 CFR part 63, subpart HH). Dehydration units and their associated control devices are listed in a facility’s construction and operating permits, which are publicly available. For this reason, we propose these data elements be designated as ‘‘not CBI’’ for both onshore production and natural gas processing plants. 98.236(e)(2)(i) ........................... 98.236(e)(2)(ii) .......................... 98.236(e)(2)(iii) .......................... 98.236(e)(2)(iv) ......................... 98.236(e)(2)(iv)(A) ..................... 98.236(e)(3)(i) ........................... 98.236(e)(3)(i) ........................... 98.236(e)(3)(i) ........................... 98.236(e)(3)(i) ........................... 98.236(e)(3)(i) ........................... 98.236(e)(3)(i) ........................... 98.236(e)(3)(i) ........................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(e)(3)(i) ........................... VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13409 TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Citation Data element Proposed confidentiality determination and rationale 98.236(f) .................................... Liquids unloading. You must indicate whether well venting for liquids unloading occurs at your facility. For each Sub-basin and well tubing diameter and pressure group for which you used Calculation Method 1 (reported separately for wells with plunger lifts and wells without plunger lifts), the count of wells vented to the atmosphere for this grouping. These proposed data element would be reported by onshore petroleum and natural gas production facilities. Liquid unloading is conducted in mature gas wells that have an accumulation of liquids which impede the steady flow of natural gas. This is a common occurrence in reservoirs where the pressure is depleted and liquids enter the well bore. The fact that liquids unloading occurs and the number of unloading wells with and without plungers vented to the atmosphere indicate that the wells in a basin are older and may indicate changes in production rates. However, the age and production rates for wells are information that can be derived from or are already available to the public through state oil and gas commissions. Hence, this information is routinely publicly available, so we propose these data elements be designated as ‘‘not CBI.’’ These proposed data elements would be reported by onshore petroleum and natural gas production facilities and provide information on whether the facility conducted any well completions or workovers during the reporting year, and for those facilities that had well completions and/or workovers, the number of completions and workovers that were completed. Information on the number of completions and workovers performed by an oil and gas operator in a given year and the age and production rates for wells can be derived from or is available publicly on state oil and gas commission Web sites. Because disclosure of these data elements would not be likely to cause substantial competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ This proposed data element would be reported by onshore petroleum and natural gas production facilities and provides information on whether the facility conducted any well completions or workovers during the reporting year and whether the emissions were flared. Information on completions and workovers performed in a given year and the age and production rates for wells can be derived from or is available publicly on state oil and gas commission Web sites and from the Energy Information Administration (EIA). Whether the emissions from well completions and workovers are sent to a flare provides only information about how the emissions are handled by the facility, which is not considered to be sensitive information by the industry. Because disclosure of these data elements would not be likely to cause substantial competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ These proposed data elements would be reported by onshore petroleum and natural gas production facilities and provide information on the number of completions where gas is vented to the atmosphere and the number of completions where the gas is vented to a flare. The number of completions that vent gas directly to the atmosphere and the number of completions that send the gas to a flare provides only information about the number of well completions that were performed in a sub-basin during a reporting year and how the emissions are handled by the facility. The number of completions performed each year is available publicly on state oil and gas commission Web sites and from the EIA. Thus, disclosure of these data elements would not be likely to cause substantial competitive harm and we propose these data elements be designated as ‘‘not CBI.’’ 98.236(f)(1)(iv) .......................... 98.236(g) ................................... 98.236(g)(3) .............................. Whether the facility had any gas well completions or workovers with hydraulic fracturing in the calendar year. For each completion or workover and well type combination, the total number of completions or workovers. 98.236(h)(1) .............................. You must indicate whether the facility had any gas well completions without hydraulic fracturing or any gas well workovers without hydraulic fracturing, and if the activities occurred with or without flaring. 98.236(h)(1)(ii) .......................... For each sub-basin with gas well completions without hydraulic fracturing and without flaring, the number of completions that vented gas to the atmosphere. For each sub-basin with gas well completions without hydraulic fracturing with flaring, the number of well completions that flared gas. emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(h)(2)(ii) .......................... VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 13410 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Data element Proposed confidentiality determination and rationale 98.236(h)(1)(iv) ......................... Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin without flaring, in standard cubic feet per hour (average of all ‘‘Vp’’ as used in Equation W–13B). 98.236(h)(2)(iii) .......................... Total number of hours that gas vented to a flare during backflow for all completions in the sub-basin category (sum of all ‘‘Tp’’ for completions that vented to a flare as used in Equation W–13B). 98.236(h)(2)(iv) ......................... Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin with flaring, in standard cubic feet per hour (the average of all ‘‘Vp’’ from Equation W–13B). 98.236(i)(1)(i) ............................ emcdonald on DSK67QTVN1PROD with PROPOSALS2 Citation Total number of blowdowns in the calendar year for the equipment type (sum equation variable ‘‘N’’ from Equation W–14A or Equation W–14B of this subpart for all unique physical volumes for the equipment type). This proposed data element would be reported by onshore petroleum and natural gas production facilities. This data element potentially provides information about the productivity of wells where hydraulic fracturing is not conducted and the emissions are not flared. Because production data for individual production wells are publicly available, the average daily production for all wells in a basin presents no information that is not already publicly available. Because disclosure of this data element would not be likely to cause substantial competitive harm, we propose this data element be designated as ‘‘not CBI.’’ This proposed data element would be reported by onshore petroleum and natural gas production facilities and potentially provides information on the time spent on well completions. Information specific to exploratory wells is generally considered proprietary information by the industry. However, by reporting this data as the total for all completed wells in a sub-basin category, data for individual wells would not be disclosed because of the large number of wells per sub-basin category. Because disclosure of this data element would not be likely to cause substantial competitive harm, we propose this data element be designated as ‘‘not CBI.’’ This proposed data element would be reported by onshore petroleum and natural gas production facilities. This data element potentially provides information about the productivity of wells where hydraulic fracturing is not conducted and the emissions are flared. Because production data for individual production wells are publicly available, the average daily production for all wells in a basin presents no information that is not already publicly available. Because disclosure of this data element would not be likely to cause substantial competitive harm, we propose this data element be designated as ‘‘not CBI.’’ This proposed data element would be reported by the onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission compression, and LNG import and export facilities. Blowdowns occur when equipment is taken out of service, either to be placed on standby or for maintenance purposes, and the natural gas in the equipment is typically released to the atmosphere. This practice may occur as part of a routine scheduled maintenance or as the result of an un-planned event (e.g., equipment breakdown). Although blowdown events may be associated with periods of reduced production or throughput, natural gas processing plants and LNG import/export facilities typically have backup units that can be used to avoid production shutdowns. Hence, the number of blowdown events that occur during a reporting year does not indicate a plant was shut down and would not provide any potentially sensitive information on the impact of such events on a facility’s production or throughput. Hence, the disclosure of the number of blowdowns occurring during a reporting year is not likely to cause substantial competitive harm. For this reason, we propose that this data element be designated ‘‘not CBI’’ when reported by onshore natural gas processing plants and LNG import/export facilities. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13411 TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Citation Data element Proposed confidentiality determination and rationale 98.236(j) .................................... You must indicate whether your facility sends produced oil to atmospheric tanks. 98.236(j) .................................... If any of the atmospheric tanks are observed to have malfunctioning dump valves, indicate that dump valves were malfunctioning. If any of the gas-liquid separator liquid dump valves did not close properly during the reporting year, the total time, in hours, the dump valves on gas-liquid separators did not close properly (‘‘Tn’’ in equation W–16). 98.236(j)(3)(ii) ............................ 98.236(k)(1)(iii) .......................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(k)(1)(iv) .......................... VerDate Mar<15>2010 18:44 Mar 07, 2014 For each transmission storage tank vent stack, indicate whether scrubber dump valve leakage is occurring for the underground storage vent. For each transmission storage tank vent stack, indicate if there is a flare attached to the vent stack. Jkt 232001 PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 These proposed data elements would also be reported by the natural gas transmission compression sector. Companies operating in this sector are subject to regulatory oversight by the Federal Energy Regulatory Commission (FERC), state utility commissions, and other federal agencies because they operate in an industry that is inherently uncompetitive. FERC controls pricing, sets rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and operations of companies operating in this sector. The rate charged for transporting gas is regulated. Hence the tightly regulated natural gas transmission sector is inherently less competitive than other industries. Because disclosure of the number of blowdowns occurring during a reporting year would not be likely to cause substantive competitive harm, we propose this data element be designated as ‘‘not CBI’’ when reported by the natural gas transmission sector. This proposed data element would be reported by onshore petroleum and natural gas production facilities and indicates only that a facility is equipped with atmospheric storage tanks. Atmospheric storage tanks are used to store hydrocarbon liquids from separators or production wells. Atmospheric tanks are a typical part of onshore production facilities and are listed in each facility’s construction and operating permits, which have to be reissued when modifications are made to the facility. Hence, disclosure of this data element would not be likely to cause substantial competitive harm and we propose that this data element be designated as ‘‘not CBI.’’ These proposed data elements would be reported by onshore petroleum and natural gas production facilities and provide information on malfunctioning of dump valves on gas-liquid separators. Separators are used to separate hydrocarbons into liquid and gas phases and are typically connected to atmospheric storage tanks where the hydrocarbon liquids are stored. Dump valves on separators periodically release liquids from the separator. The time period during which a dump valve is malfunctioning provides little insight into maintenance practices or the nature or cost of repairs that are needed. Therefore, this information would not be likely to cause substantial competitive harm to reporters. For this reason, we are proposing these data elements be designated as ‘‘not CBI.’’ These proposed data elements would be reported by the onshore natural gas transmission compression sector. Companies operating in this sector are subject to regulatory oversight by FERC, state utility commissions, and other federal agencies because they operate in an industry that is inherently uncompetitive. FERC controls pricing, sets rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and operations of companies operating in this sector. The rate charged for transporting gas is regulated. Hence the natural gas transmission sector is inherently less competitive than other industries and there is little incentive to build additional pipelines and compressor stations within the same corridors as existing transmission lines. Because disclosure of these data elements would not be likely to cause substantive competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ E:\FR\FM\10MRP2.SGM 10MRP2 13412 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Citation Data element Proposed confidentiality determination and rationale 98.236(l)(1)(iv) ........................... If oil well testing is performed where emissions are not vented to a flare, the average flow rate in barrels of oil per day for well(s) tested. If oil well testing is performed where emissions are vented to a flare, the average flow rate in barrels of oil per day for well(s) tested. If gas well testing is performed where emissions are not vented to a flare, the average annual production rate in actual cubic feet per day for well(s) tested. If gas well testing is performed where emissions are vented to a flare, the average annual production rate in actual cubic feet per day for well(s) tested. You must indicate whether any associated gas was vented or flared during the reporting year. For each sub-basin, indicate whether any associated gas was vented without flaring. For each sub-basin, indicate whether any associated gas was flared. This proposed data element would be reported by onshore petroleum and natural gas production facilities. These data elements provide information on the oil flow and gas production rates of wells. Oil and gas production data for individual wells are publicly available. Because production data for individual production wells are publicly available, the average of all wells tested presents no information that is not already publicly available. Because disclosure of these data elements would not be likely to cause substantial competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ 98.236(l)(2)(iv) ........................... 98.236(l)(3)(iii) ........................... 98.236(l)(4)(iii) ........................... 98.236(m) .................................. 98.236(m)(2) ............................. 98.236(m)(3) ............................. 98.236(m)(5) ............................. 98.236(m)(6) ............................. 98.236(o)(1)(xvi) ........................ emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(o)(2)(viii) ........................ VerDate Mar<15>2010 18:44 Mar 07, 2014 For each sub-basin, the volume of oil produced during time periods in which associated gas was vented or flared (barrels). For each sub-basin, the total volume of associated gas sent to sales during time periods in which associated gas was vented or flared (scf). Date of last maintenance shutdown that the compressor was depressurized. If the emission vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational. Jkt 232001 PO 00000 Frm 00020 Fmt 4701 Sfmt 4702 These proposed data elements would be reported by onshore petroleum and natural gas production facilities and indicate whether associated gas is flared or vented directly to the atmosphere. Information on how emissions are handled does not provide any insight into the operation of the emission source. Therefore, disclosure of these data elements would be unlikely to cause competitive harm. For this reason, we are proposing these data elements be designated as ‘‘not CBI.’’ These proposed data elements would be reported by onshore petroleum and natural gas production facilities and provide production related information during periods when associated gas is vented or flared. Associated gas is vented or flared when it is not being captured for sales. Oil and gas production data for individual production wells are publicly available, By reporting this data as total for all production wells in a sub-basin category, no data for individual wells is disclosed that is not already publicly available. Because disclosure of these data elements would not be likely to cause substantial competitive harm, we propose they be designated as ‘‘not CBI.’’ These proposed data elements would be reported by onshore petroleum and natural gas production facilities, onshore natural gas processing plants, LNG import/export terminals, natural gas transmission compression, underground natural gas storage facilities, and LNG storage facilities. These data elements provide information about the operation and maintenance of centrifugal compressors. Centrifugal compressors are used to move gas at high pressure through pipelines and are standard equipment found at all types of natural gas facilities. Facilities typically have backup compressors to allow operations to continue without interruption during periods of maintenance and repair. Hence, the percentage of time a compressor was operational and the date of last maintenance shutdown would be not likely to cause substantial competitive harm to any type of natural gas facility. For these reasons, we propose these data elements be designated as ‘‘not CBI.’’ E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13413 TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Citation Data element Proposed confidentiality determination and rationale 98.236(p)(1)(xvi) ........................ Date of last maintenance shutdown for rod packing replacement. If the emission vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational. These proposed data elements would be reported by onshore petroleum and natural gas production facilities, onshore natural gas processing plants, LNG import/export terminals, natural gas transmission compression, underground natural gas storage facilities, and LNG storage facilities. These data elements provide information about the operation and maintenance of reciprocating compressors. Reciprocating compressors are used to move gas at high pressure through pipelines and are standard equipment found at all types of natural gas facilities. Facilities typically have backup compressors to allow operations to continue without interruption during periods of compressor maintenance and repair. Hence, the percentage of time a compressor is operational and date of last maintenance shutdown would be not likely to cause substantial competitive harm to any type of natural gas facility. For these reasons, we propose these data elements be designated as ‘‘not CBI.’’ This proposed data element would provide information on the amount of time operational components were found to be leaking. This information would provide little insight into maintenance practices at a facility because it would not identify the cause of the leaks or the nature and cost of repairs. Therefore, this information would not be likely to cause substantial competitive harm to reporters. For this reason, we are proposing the average time operational components were found leaking be designated as ‘‘not CBI.’’ These proposed data elements would be reported by natural gas distribution facilities. Natural gas distribution companies are subject to regulatory oversight by state utility commissions because they operate in an industry that is inherently not competitive. The state utility commission controls pricing, sets rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and operations of companies operating in this sector. Because disclosure of these data elements would not be likely to cause substantive competitive harm, we propose these data elements be designated as ‘‘not CBI’’ when reported by natural gas distributors. 98.236(p)(2)(viii) ........................ 98.236(q)(2)(iii) .......................... Average time the surveyed components were found leaking and operational, in hours (average of Tp,z in Equation W–30 of this subpart). 98.236(q)(3)(ii) .......................... Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in the calendar year. Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of Tw,y in Equation W–31 of this subpart, for the current calendar year). Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in current leak survey cycle. Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours. Whether CO2 enhanced oil recovery (EOR) injection was used at the facility. 98.236(q)(3)(iii) .......................... 98.236(q)(3)(v) .......................... 98.236(q)(3)(vi) ......................... 98.236(w) .................................. emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(w) .................................. VerDate Mar<15>2010 18:44 Mar 07, 2014 You must indicate whether any EOR injection pump blowdowns occurred during the year. Jkt 232001 PO 00000 Frm 00021 Fmt 4701 Sfmt 4702 This proposed data element would be reported by onshore petroleum and natural gas production facilities. This data element indicates whether EOR is performed. However, underground injection of CO2 is regulated under 40 CFR parts 124, 144 and 146. Facilities that inject CO2 underground are required to have an Underground Injection Control (UIC) permit, which is a public document issued by the EPA or by states that have primary enforcement authority for permitting injection wells. Since this information is already available through other public documents, we propose this data be designated as ‘‘not CBI.’’ This proposed data element would be reported by the onshore petroleum and natural gas production facilities using EOR. Blowdowns are a typical operation undertaken by EOR operators and occur when equipment is taken out of service either to be placed on standby or for maintenance purposes. This practice may occur as part of a routine scheduled maintenance or be the result of an un-planned event (e.g., equipment breakdown). Although blowdown events may be associated with periods of reduced production, facilities typically have backup pumps that can be used to avoid production shutdowns. Hence, the disclosure of the number of blowdowns occurring during a reporting year is not likely to cause substantial competitive harm. For this reason, we propose that this data element be designated ‘‘not CBI.’’ E:\FR\FM\10MRP2.SGM 10MRP2 13414 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Citation Data element Proposed confidentiality determination and rationale 98.236(x) ................................... Whether hydrocarbon liquids were produced through EOR operations. 98.236(z)(2)(i) ........................... The type of combustion unit ............................ 98.236(z)(2)(ii) ........................... Type of fuel combusted ................................... 98.236(aa)(1)(ii)(I) ..................... For each sub-basin category, the average mole fraction CH4 in produced gas. For each sub-basin category, the average mole fraction CO2 in produced gas. This proposed data element would be reported by onshore petroleum and natural gas production facilities using EOR and provides production related information about EOR operations. However, production data for wells is available to the public through state oil and gas commissions. Since this information is already available through other public documents, we propose this data be designated as ‘‘not CBI.’’ This data element would be reported by onshore petroleum and gas production facilities and natural gas distribution. This data element would provide information on the types of combustion units. Information on the types of combustion units located at a facility is often available in a facility’s construction and operating permits. For these reasons, we consider information on the types of combustion units in production and distribution facilities would not be likely to cause substantive competitive harm and propose this data element be designated as ‘‘not CBI’’ for both industry sectors. This data element would be reported by onshore petroleum and gas production facilities and natural gas distribution. This data element would provide information on the types of fuel burned. However, facilities in both these sectors generally burn fuels that are readily available to them as part of their operations. Information on the types of fuels burned by a facility is often available in a facility’s construction and operating permits. For these reasons, we consider information on the types of fuels burned by production and distribution facilities would not be likely to cause substantive competitive harm and propose this data element be designated as ‘‘not CBI’’ for both industry sectors. This proposed data element would be reported by onshore petroleum and natural gas production facilities. The typical composition of produced gas is available through the Gas Technology Institute and the Department of Energy, Gas Information System (GASIS) Database.5 Both of these sources are made available to the public. Since these data are publicly available we are proposing these data elements be designated as ‘‘not CBI.’’ These proposed data elements would be reported by the onshore natural gas transmission compression sector. Companies operating in this sector are subject to regulatory oversight by FERC, state utility commissions, and other federal agencies because they operate in an industry that is inherently uncompetitive. FERC controls pricing, sets rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and operations of companies operating in this sector. The rate charged for transporting gas is regulated. Hence the natural gas transmission sector is inherently less competitive than other industries and there is little incentive to build additional pipelines and compressor stations within the same corridors as existing transmission lines. Because disclosure of pipeline pressures and the quantity of gas transported through the compressor would not be likely to cause substantive competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ 98.236(aa)(1)(ii)(J) .................... 98.236(aa)(4)(i) ......................... 98.236(aa)(4)(iv) ....................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(aa)(4)(v) ........................ VerDate Mar<15>2010 18:44 Mar 07, 2014 The quantity of gas transported through the compressor station in the calendar year, in thousand standard cubic feet. The average upstream pipeline pressure in pounds per square inch gauge. The average downstream pipeline pressure in pounds per square inch gauge. Jkt 232001 PO 00000 Frm 00022 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13415 TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Citation Data element Proposed confidentiality determination and rationale 98.236(aa)(5)(i) ......................... The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet. The quantity of gas withdrawn from storage in the calendar year, in thousand standard cubic feet. These proposed data elements would be reported by underground natural gas storage facilities. Underground storage facilities are closely associated with and are part of the utilities’ integrated distribution systems. Some are owned by natural gas distribution companies. Distribution companies are regulated by state commissions, because they operate in an industry that is inherently not competitive. Underground storage facilities are constrained by geographical and geological requirements. These facilities must be located in areas where appropriate geologic conditions exist for gas storage, while also located near regions of the country where gas usage fluctuates during the year. Typically, gas is injected into underground storage during the summer months, when consumer demand is low, and withdrawn during the winter months, when demand peaks. These factors provide significant barriers to new companies moving into the underground storage sector or existing companies increasing their market share. Because disclosure of these proposed new data elements would not be likely to cause substantive competitive harm to underground storage facilities, we propose these data elements be designated as ‘‘not CBI.’’ Quantities of LNG imported to the U.S. together with the name of the importer are published by EIA in quarterly reports. Because disclosure of this proposed new data element would not be likely to cause substantive competitive harm, we propose this data element be designated as ‘‘not CBI.’’ Quantities of natural gas exported from the U.S. are published by EIA in quarterly reports. Because disclosure of this proposed new data element would not be likely to cause substantive competitive harm, we propose this data element be designated as ‘‘not CBI.’’ These proposed data elements would be reported by LNG storage facilities. Most LNG storage facilities are owned by distributors whose operations are regulated by FERC and state commissions, because they operate in an industry that is inherently not competitive. FERC controls pricing, sets rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and operations of companies operating in this sector. Because disclosure of these proposed new data elements would not be likely to cause substantive competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ Natural gas distribution companies are subject to regulatory oversight by state utility commissions, because they operate in an industry that is inherently not competitive. Many of these data elements are also reported to EIA on a monthly basis (e.g., natural gas withdrawn from storage, natural gas stored, gas received at city gate). EIA publishes the data on their Web site on an annual basis. Because disclosure of these proposed new data elements would not be likely to cause substantive competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ 98.236(aa)(5)(ii) ........................ 98.236(aa)(6) ............................ For LNG import equipment, the quantity of LNG imported in the calendar year, in thousand standard cubic feet. 98.236(aa)(7) ............................ For LNG export equipment, the quantity of LNG exported in the calendar year, in thousand standard cubic feet. 98.236(aa)(8)(i) ......................... The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet. The quantity of LNG withdrawn from storage in the calendar year, in thousand standard cubic feet. 98.236(aa)(8)(ii) ........................ 98.236(aa)(9)(i) ......................... 98.236(aa)(9)(ii) ........................ 98.236(aa)(9)(iii) ........................ emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(aa)(9)(iv) ....................... 98.236(aa)(9)(v) ........................ 98.236(aa)(9)(vi) ....................... 98.236(aa)(9)(vii) ....................... VerDate Mar<15>2010 18:44 Mar 07, 2014 The quantity of natural gas received at all custody transfer stations in the calendar year in thousand standard cubic feet. The quantity of natural gas withdrawn from insystem storage in the calendar year in thousand cubic feet. The quantity of natural gas added to in-system storage in the calendar year in thousand cubic feet. The quantity of natural gas delivered to end users in thousand cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for The quantity of natural gas transferred to third parties such as other LDCs or pipelines in thousand cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for. The quantity of natural gas consumed by the LDC for operational purposes in thousand cubic feet. The estimated quantity of gas stolen in the calendar year in thousand cubic feet. Jkt 232001 PO 00000 Frm 00023 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 13416 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Citation Data element Proposed confidentiality determination and rationale ‘‘Unit/Process ‘Static’ Characteristics That Are Not Inputs to Emission Equations’’ Data Category 98.236(o)(1)(iv) operating mode (v) not operating mode. 98.236(o)(1)(vii) ......................... 98.236(o)(1)(viii) ........................ 98.236(o)(1)(ix) ......................... 98.236(o)(1)(x) .......................... 98.236(o)(1)(xi) ......................... 98.236(o)(1)(xiii) ........................ 98.236(o)(1)(xiv) ........................ 98.236(o)(1)(xv) ........................ 98.236(p)(1)(viii) ........................ For non-manifolded compressors, whether the compressor was measured in the operatingmode or the not-operating-depressurized– mode. Indicate whether any compressor sources are routed to a flare. Indicate whether any compressor sources have vapor recovery. Indicate whether emissions from any compressor sources are captured for fuel use or are routed to a thermal oxidizer. Indicate whether the compressor has blind flanges installed. Indicate whether the compressor has wet or dry seals. Compressor power rating (hp). Year compressor was installed. Compressor model name and description. 98.236(p)(1)(xiii) ........................ 98.236(p)(1)(xiv) ........................ 98.236(p)(1)(xv) ........................ Indicate whether any compressor sources are part of a manifolded group of compressor sources. Indicate whether any compressor sources are routed to a flare. Indicate whether any compressor sources have vapor recovery. Indicate whether emissions from any compressor sources are captured for fuel use or are routed to a thermal oxidizer. Indicate whether the compressor has blind flanges installed. Compressor power rating (hp). Year compressor was installed. Compressor model name and description. 98.236(z)(1)(ii) ........................... The total number of combustion units ............. 98.236(p)(1)(ix) ......................... 98.236(p)(1)(x) .......................... 98.236(p)(1)(xi) ......................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(p)(1)(xii) ......................... VerDate Mar<15>2010 19:36 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00024 Fmt 4701 Sfmt 4702 These proposed data elements would be reported by onshore petroleum and natural gas production facilities, onshore natural gas processing plants, LNG import/export terminals, natural gas transmission compression, underground natural gas storage facilities, and LNG storage facilities. These data elements indicate whether a facility has centrifugal compressors, how emissions from each unit are handled, and specific information about the design and age of each centrifugal compressor. Centrifugal compressors are used to move gas at high pressure through pipelines and are standard equipment found at all types of natural gas facilities. Centrifugal compressors are also listed in each facility’s construction and operating permits, which must be updated and reissued when modifications are made. Hence, the fact that a facility has a centrifugal compressor, its age and design, and emissions handling reveals no sensitive information that would be likely to cause substantial competitive harm to any type of natural gas facility. For these reasons, we propose these data elements be designated as ‘‘not CBI.’’ These proposed data elements would be reported by onshore petroleum and natural gas production facilities, onshore natural gas processing plants, LNG import/export terminals, natural gas transmission compression, underground natural gas storage facilities, and LNG storage facilities. These data elements indicate whether a facility has reciprocating compressors, how emissions from each unit are handled, and specific information about the design and age of each reciprocating compressor. Reciprocating compressors are used to move gas at high pressure through pipelines and are standard equipment found at all types of natural gas facilities. Reciprocating compressors are also listed in each facility’s construction and operating permit, which must be updated and reissued when modifications are made. Because disclosure of these data elements would be not likely to cause substantial competitive harm to any type of natural gas facility, we propose these data elements be designated as ‘‘not CBI.’’ This data element would be reported by onshore petroleum and gas production facilities and natural gas distribution. This data element provides information on the number of internal and external combustion units located at onshore petroleum and natural gas production facilities. However, this information would not be likely to cause substantial competitive harm if released to the public, since internal and external combustion units are typical parts of an onshore petroleum and natural gas production facility and the total number of such units is not considered to be competitively sensitive information by this industry sector. Because disclosure of the number of combustion units would not be likely to cause substantive competitive harm to this sector, we propose this data element be designated as ‘‘not CBI’’ when reported by onshore petroleum and natural gas production facilities. Natural gas distribution companies are subject to regulatory oversight by state utility commissions, because they operate in an industry that is inherently not competitive. Because disclosure of the number combustion units would not be likely to cause substantive competitive harm, we propose this data element be designated as ‘‘not CBI’’ when reported by natural gas distributors. E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13417 TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued Citation Data element Proposed confidentiality determination and rationale 98.236(aa)(1)(ii)(C) ................... For each sub-basin category, the formation type. 98.236(aa)(1)(ii)(D) ................... For each sub-basin category, the number of producing wells at the end of the calendar year. For each sub-basin category, the number of producing wells acquired during the calendar year. For each sub-basin category, the number of producing wells divested during the calendar year. For each sub-basin category, the number of wells completed during the calendar year. For each sub-basin category, the number of wells taken out of production during the calendar year. Whether the onshore natural gas processing facility fractionates natural gas liquids (NGLs). The formation type refers to the following types of formations: Oil, high permeability gas, shale gas, coal seam, or other tight gas reservoir rock. The location of these formations is general information that is publicly available from EIA. Because disclosure of the formation would not be likely to cause substantive competitive harm, we propose this data element be designated as ‘‘not CBI.’’ We are proposing that each of these proposed new data elements be assigned to the Unit/Process Static Characteristics That Are Not Inputs to Emission Equations’’ because each data element provides descriptive information about units at the facility and does not meet the definition of emission data. We propose that each new data element be designated as ‘‘not CBI’’ because detailed information regarding wells is available from state databases and permits. Because disclosure of the formation would not be likely to cause substantive competitive harm, we propose this data element be designated as ‘‘not CBI.’’ 98.236(aa)(1)(ii)(E) .................... 98.236(aa)(1)(ii)(F) .................... 98.236(aa)(1)(ii)(G) ................... 98.236(aa)(1)(ii)(H) ................... 98.236(aa)(3)(vii) ....................... Number of compressors ................................... The total compressor power rating for all compressors combined, in horsepower. 98.236(aa)(5)(iii) ........................ The total storage capacity for underground natural gas storage facilities. 98.236(aa)(8)(iii) ........................ emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(aa)(4)(ii) ........................ 98.236(aa)(4)(iii) ........................ The total LNG storage capacity in the calendar year, in thousand standard cubic feet. D. Other Proposed or Re-Proposed Caseby-Case Confidentiality Determinations for Subpart W The proposed revision includes 11 new or substantially revised data elements relative to production and/or throughput data from subpart W VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 Whether a natural gas processing facility fractionates NGLs is information that is readily available from other public sources, such as the LPG Almanac (updated annually) and other trade journals. For this reason, disclosure of this information would not be likely to cause substantial competitive harm and we propose that this data element be designated as ‘‘not CBI.’’ These data elements would be reported by the onshore natural gas transmission compression sector. Companies operating in this sector are subject to regulatory oversight by FERC, state utility commissions, and other federal agencies because they operate in an industry that is inherently uncompetitive. FERC controls pricing, sets rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and operations of companies operating in this sector. Because disclosure of the number and power rating for compressors would not be likely to cause substantive competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ Companies operating underground gas storage facilities are required to report their storage capacity to the EIA by company on a monthly basis. EIA publishes the data on their Web site on an annual basis. Because disclosure of underground storage capacity would not be likely to cause substantial competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ Most LNG storage facilities are regulated by FERC and state commissions, because they operate in an industry that is inherently not competitive. FERC controls pricing, sets rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and operations of companies operating in this sector. Because disclosure of LNG storage capacity would not be likely to cause substantial competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ facilities from the onshore petroleum and natural gas production, offshore petroleum and natural gas production, and onshore natural gas processing industry sectors. Although these data elements are similar in certain types or characteristics to the data elements in PO 00000 Frm 00025 Fmt 4701 Sfmt 4702 ‘‘Production/Throughput Data that are Not Inputs to Emissions Equations’’ or ‘‘Raw Materials Consumed that are Not Inputs to Emissions Equations’’ data categories, for the reasons provided above in Section III.B of this preamble, we are not proposing to assign these E:\FR\FM\10MRP2.SGM 10MRP2 13418 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 data elements to a data category. Instead, we are proceeding to make individual confidentiality determinations for these data elements. As further explained in Section III.B of this preamble, we are also proposing to remove one existing data element, 40 CFR 98.236(j)(2)(i)(A), from ‘‘Production/Throughput Data Not Used as Input,’’ thereby removing the application of the categorical confidentiality determination for this data category to this data element. We are re-proposing the confidentiality determination for this data element. Table 3 of this preamble lists the 11 new or substantially revised data elements and one existing data element and provides the rationale and proposed confidentiality determination for each data element. As described above in Section III.B of this preamble, our proposed determinations for these data elements were based on a two-step process in which we first evaluated whether the data element met the definition of emission data. This first step in the evaluation is important because emission data are not eligible for confidential treatment pursuant to section 114(c) of the CAA, which precludes emissions data from being considered confidential and requires that such data be made available to the public. The term ‘‘emission data’’ is defined in 40 CFR 2.301(a). We propose to determine that none of these 12 data elements are emission data under 40 CFR 2.301(a)(2)(i), because they do not provide any information characterizing actual GHG emissions or descriptive information about the location or nature of the emissions source. However, we note that this determination is made strictly in the context of the GHGRP and may not apply to other regulatory programs. In the second step, we evaluate whether the data element is entitled to confidentiality treatment, based on the criteria for confidential treatment specified in 40 CFR 2.208. In particular, the EPA focused on the following two factors: (1) Whether the data was VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 already publicly available; and (2) whether ‘‘ . . . disclosure of the information is likely to cause significant harm to the business’ competitive position.’’ See 40 CFR 2.208(e)(1). For each of these 12 data elements, we determined whether the information is already available in the public domain. For those data elements for which no published data could be found, we evaluated whether the publication would be likely to cause competitive harm. Many of the new data elements proposed to be reported by the onshore oil and gas production sector would be reported at an aggregated-level (i.e., subbasin level) that would mask any underlying information for individual production wells. These data elements involve reporting aggregated data covering all individual wells, exploratory wells, and production equipment in a sub-basin, rather than information specific to an individual well or other production unit. Reporting at a sub-basin level is at a large enough scale that disclosure of the collected data would not reveal any proprietary information, such as the sensitive operational information or the cost to do business. Because the proposed new data elements would also be collected at a sub-basin level, they would not disclose production data for individual wells, reveal information about individual exploratory wells, or provide insight into production costs. Therefore, we propose that the new production data proposed to be reported by the onshore oil and gas production sector be designated as non-CBI because its disclosure would not be likely to cause competitive harm. For offshore oil and gas production, the EPA is proposing that the quantity of gas produced for sales, quantity of oil produced for sales, and quantity of condensate produced for sales be reported. These data elements do not provide any competitively sensitive information on the costs of doing business. We note that similar data on throughputs for individual platforms are published annually by the Bureau of Ocean Energy Management. Therefore, PO 00000 Frm 00026 Fmt 4701 Sfmt 4702 we propose that these new production data proposed to be reported by offshore oil and gas platforms be designated as non-CBI because its disclosure would not be likely to cause competitive harm. For natural gas processing, the EPA is proposing that the total quantity of NGLs (bulk and fractionated) received at and leaving the processing plant be reported on an annual basis. Because the reported value would be the annual sum of bulk and fractionated NGLs received and the annual sum of bulk and fractionated NGLs leaving the plant, the data collected would provide very limited information on facility operations and would not disclose any detailed information about the facility’s day-to-day operations, such as the amount, contents, and price of each shipment of bulk material received, the amount, contents, and price of each shipment of NGL product received, the amount of bulk materials fractionated and costs of fractionation, or the type and amounts of each individual NGL product produced. Because these data are to be reported at an aggregated level, these proposed two new data elements would not provide insight on operating costs, or other highly sensitive aspects of operation the disclosure of which would be likely to cause competitive harm. Therefore, we propose that the total quantity of NGLs (bulk and fractionated) received at and leaving the natural gas processing plant be designated as not CBI. In addition, many facilities in this sector already voluntarily report these data to the Worldwide Gas Processing survey and the data at the plant level are published annually in the Oil and Gas Journal. Similar data are also mandatorily reported monthly to the EIA. Although the EIA aggregates the data before publishing data, the EIA also acknowledges that some statistics may be based on data from fewer than three respondents, or that are dominated by data from one or two large respondents, and in these cases, it may be possible for a the information reported by a specific respondent to be accurately estimated. E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13419 TABLE 3—PROPOSED INDIVIDUAL CONFIDENTIALITY DETERMINATION FOR 13 NEW OR SUBSTANTIALLY REVISED DATA ELEMENTS AND RE-PROPOSAL FOR ONE EXISTING DATA ELEMENTS Citation Data element Proposed confidentiality determination and rationale Onshore petroleum and natural gas production 98.236(aa)(1)(i)(A) .................... 98.236(aa)(1)(i)(B) .................... 98.236(aa)(1)(i)(C) .................... 98.236(aa)(1)(i)(D) .................... 98.236(j)(2)(i)(A) ........................ The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production. The quantity of gas produced in the calendar year for sales in thousand standard cubic feet. For each basin, the quantity of crude oil produced in the calendar year for sales, not including lease condensates, in barrels. For each basin, the quantity of lease condensate produced in the calendar year for sales (in barrels). The total annual oil throughput that is sent to all atmospheric tanks in the basin, in barrels. We propose that each of these data elements be designated as ‘‘not CBI.’’ The onshore petroleum production sector is a regionally concentrated sector, with wells located in fixed geological formations and a large number of operators within each formation. Information that is typically considered sensitive to this industry includes data related to production costs for developed fields and information on individual exploratory wells. Information on exploratory wells is sensitive during the time period when a new formation is being developed because lease prices are not stabilized until wells have proven production records. Once the formation has been developed and several wells have been drilled in a basin, production decisions are based on market prices and the ability to control flow from the well. The production data that will be reported at the basin or subbasin level are already publicly available through the Department of Energy. Reporting at the basin or sub-basin level includes data aggregated to a scale large enough that it does not disclose production data for individual wells, reveal sensitive information about individual exploratory wells, or provide insight into production costs. Offshore petroleum and natural gas production 98.236(aa)(2)(i) ......................... 98.236(aa)(2)(ii) ........................ 98.236(aa)(2)(iii) ........................ The quantity of gas produced for sales from the offshore platform in the calendar year for sales, in thousand standard cubic feet. The quantity of oil produced for sales from the offshore platform in the calendar year for sales (in barrels). The quantity of condensate produced for sales from the offshore platform in the calendar year for sales (in barrels). We propose that each of these new data elements be designated as ‘‘not CBI’’ because the production throughput data are published annually on the Bureau of Ocean Energy Management’s Web site. Onshore natural gas processing 98.236(aa)(3)(i) ......................... 98.236(aa)(3)(ii) ........................ 98.236(aa)(3)(iii) ........................ emcdonald on DSK67QTVN1PROD with PROPOSALS2 98.236(aa)(3)(iv) ....................... The quantity of produced gas received at the gas processing plant in thousand standard cubic feet. The quantity of processed (residue) gas leaving the gas processing plant in thousand standard cubic feet. The quantity of NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels. The quantity of NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels. The list of data elements, their data category assignments, and proposed confidentiality determinations can be found in the memorandum titled ‘‘Data Category Assignments and Confidentiality Determinations for all Data Elements (excluding inputs to emission equations) in the Proposed VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 We propose that each of these new data elements be designated as ‘‘not CBI’’ because the average annual flow and plant utilization rates are published quarterly on EIA’s Web site and are already in the public domain. We propose that each of these new data elements be designated as ‘‘not CBI’’ because they are already publicly available. Many facilities in this sector already voluntarily report these data to the Worldwide Gas Processing survey and the data at the plant level are published annually in the Oil and Gas Journal. Similar data are also mandatorily reported monthly to the EIA. Although the EIA aggregates the data before publishing data, the EIA also acknowledges that, ‘‘Disclosure limitation procedures are not applied to the statistical data published from this survey’s information. Thus, there may be some statistics that are based on data from fewer than three respondents, or that are dominated by data from one or two large respondents. In these cases, it may be possible for a knowledgeable person to estimate the information reported by a specific respondent.’’ 6 ‘Technical Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems’’’ in Docket ID No. EPA–HQ–OAR–2011– 0512. PO 00000 Frm 00027 Fmt 4701 Sfmt 4702 E. Request for Comments on Proposed Confidentiality Determinations For the CBI component of this rulemaking, we are specifically soliciting comment on the following issues. First, we specifically seek comment on the proposed data category E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 13420 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules assignments, and application of the established categorical confidentiality determinations to data elements assigned to categories with such determinations. If a commenter believes that the EPA has improperly assigned certain new or substantially revised data elements to any of the data categories established in the 2011 Final CBI Rule, please provide specific comments identifying which of these data elements may be mis-assigned along with a detailed explanation of why you believe them to be incorrectly assigned and in which data category you believe they belong. In addition, if you believe that a data element should be assigned to one of the two direct emitter data categories that do not have a categorical confidentiality determination, please also provide specific comment along with detailed rationale and supporting information on whether such data element does or does not qualify as CBI. We also seek comment on the proposed individual confidentiality determinations for the following data elements: 72 new or substantially revised data elements assigned to the ‘‘Unit/Process ‘Operating’ Characteristics That Are Not Inputs to Emission Equations’’ data category; 29 new or substantially revised data elements assigned to the ‘‘Unit/Process ‘Static’ Characteristics That Are Not Inputs to Emission Equations’’ category; 11 new data elements for which no data category assignment was proposed; and one existing data element for which we are proposing to remove the data category assignment and make a new confidentiality determination. By proposing confidentiality determinations prior to data reporting through this proposal and rulemaking process, we provide reporters an opportunity to submit comments, in particular comments identifying data they consider sensitive and their rationales and supporting documentation; this opportunity is the same opportunity that is afforded to submitters of information in case-bycase confidentiality determinations made in response to individual claims for confidential treatment not made through rulemaking. It provides an opportunity to rebut the Agency’s proposed determinations prior to finalization. We will evaluate the comments on our proposed determinations, including claims of confidentiality and information substantiating such claims, before finalizing the confidentiality determinations. Please note that this will be a reporter’s only opportunity to substantiate a confidentiality claim for these proposed new data elements. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 Upon finalizing the confidentiality determinations of the data elements identified in this rule, the EPA will release or withhold these data in accordance with 40 CFR 2.301, which contains special provisions governing the treatment of Part 98 data for which confidentiality determinations have been made through rulemaking. When submitting comments regarding the confidentiality determinations we are proposing in this action, please identify each individual data element you do or do not consider to be CBI or emission data in your comments. Please explain specifically how the public release of that particular data element would or would not cause a competitive disadvantage to a facility. Discuss how this data element may be different from or similar to data that are already publicly available. Please submit information identifying any publicly available sources of information containing the specific data elements in question. Data that are already available through other sources would likely be found not to qualify for CBI protection. In your comments, please identify the manner and location in which each specific data element you identify is publicly available, including a citation. If the data are physically published, such as in a book, industry trade publication, or federal agency publication, provide the title, volume number (if applicable), author(s), publisher, publication date, and International Standard Book Number (ISBN) or other identifier. For data published on a Web site, provide the address of the Web site and the date you last visited the Web site and identify the Web site publisher and content author. If your concern is that competitors could use a particular data element to discern sensitive information, specifically describe the pathway by which this could occur and explain how the discerned information would negatively affect your competitive position. Describe any unique process or aspect of your facility that would be revealed if the particular data element you consider sensitive were made publicly available. If the data element you identify would cause harm only when used in combination with other publicly available data, then describe the other data, identify the public source(s) of these data, and explain how the combination of data could be used to cause competitive harm. Describe the measures currently taken to keep the data confidential. Avoid conclusory and unsubstantiated statements, or general assertions regarding potential harm. Please be as specific as possible in your comments and include all information PO 00000 Frm 00028 Fmt 4701 Sfmt 4702 necessary for the EPA to evaluate your comments. IV. Impacts of the Proposed Amendments to Subpart W The proposed amendments to subpart W are based on identified improvements in the regulatory language and revisions to calculation methods that do not significantly increase the burden of data collection and reporting, improve the accuracy of the data reported, and provide clarity. The proposed amendments do not impart significant additional burden to reporters and many reduce burden to reporters and regulators in some cases. As discussed in Section II of this preamble, the EPA is proposing to revise the reporting elements that must be reported. Any elements that were not previously required to be reported identify the equipment to be reported for the industry segment or are inputs to an emission equation. These data elements are typically already collected by reporters. These proposed revisions would remove ambiguity for the reporter and would not increase burden significantly, since the reporting elements are already available. As discussed in Section II.D of this preamble, the EPA is proposing to remove the best available monitoring method (BAMM) provisions in 40 CFR 98.234(f). Removing these provisions would not add to previous burden estimates for subpart W reporters; previous burden estimates were prepared based on all reporters complying with the monitoring methods in 40 CFR 98.234 without BAMM. The additional proposed amendments to subpart W are not expected to significantly increase burden. See the memorandum, ‘‘Assessment of Impacts of the 2014 Proposed Revisions to Subpart W’’ in Docket Id. No. EPA–HQ– OAR–2011–0512 for additional information. V. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review This action is not a ‘‘significant regulatory action’’ under the terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011). In addition, the EPA prepared an analysis of the potential costs and benefits associated with the proposed amendments to subpart W. This analysis E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 is contained in ‘‘Assessment of Impacts of the 2014 Proposed Revisions to Subpart W.’’ A copy of the analysis is available in the docket for this action (see Docket Id. No. EPA–HQ–OAR– 2011–0512) and the analysis is briefly summarized in Section IV of this preamble. B. Paperwork Reduction Act The information collection requirements in this proposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The Information Collection Request (ICR) document prepared by the EPA has been assigned EPA ICR number 2300.15. This action proposes to simplify the existing reporting methods in subpart W and clarify monitoring methods and data reporting requirements, and proposes confidentiality determinations for reported data elements. The EPA is proposing to restructure the reporting requirements for clarity and align them with the calculation requirements. OMB has previously approved the information collection requirements for 40 CFR part 98 under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq., and has assigned OMB control number 2060–0629. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. Burden is defined at 5 CFR 1320.3(b). 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. The estimated total projected cost and hour burden associated with reporting for subpart W are $21,964,000 and 244,000 hours, respectively. For the hour burden, the estimated average burden hours per response is 54 hours, the proposed frequency of response is once annually, and the estimated number of likely respondents is 2,885. For the cost burden to respondents or record keepers resulting from the collection of information, the estimated total capital and start-up cost component annualized over its expected useful life is $796,000 per year, the total operation and maintenance component is $1,690,000 per year, and the total labor cost is $19,478,000 per year for all of subpart W. To comment on the Agency’s need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, the EPA has VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 established a public docket for this rule, which includes this ICR, under Docket ID number EPA–HQ–OAR–2011–0512. Submit any comments related to the ICR to the EPA and OMB. See ADDRESSES section at the beginning of this proposed rule for where to submit comments to the EPA. Send comments to OMB at the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention: Desk Office for the EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after March 10, 2014, a comment to OMB is best assured of having its full effect if OMB receives it by April 9, 2014. The final rule will respond to any OMB or public comments on the information collection requirements contained in this proposal. We continue to be interested in the potential impacts of this proposed action on the burden associated with the proposed amendments and welcome comments on issues related to such impacts. C. Regulatory Flexibility Act (RFA) The Regulatory Flexibility Act (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 today’s proposed rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration’s regulations at 13 CFR 121.201; (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-forprofit enterprise which is independently owned and operated and is not dominant in its field. This action proposes to (1) amend monitoring and calculation methodologies in subpart W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a definition in subpart A. After considering the economic impacts of these proposed rule amendments on small entities, I certify that this action would not have a significant economic impact on a substantial number of small entities. PO 00000 Frm 00029 Fmt 4701 Sfmt 4702 13421 The small entities directly regulated by this proposed rule include small businesses in the petroleum and gas industry, small governmental jurisdictions and small non-profits. The EPA has determined that some small businesses would be affected because their production processes emit GHGs exceeding the reporting threshold. This action includes proposed amendments that do not result in a significant burden increase on subpart W reporters. In some cases, the EPA is proposing to increase flexibility in the selection of methods used for calculating GHGs, and is also proposing to revise certain methods that may result in greater conformance to current industry practices. In addition, the EPA is proposing to revise specific provisions to provide clarity on what information is being reported. These proposed revisions would not significantly increase the burden on reporters while maintaining the data quality of the information being reported to the EPA. As part of the process of finalization of the final subpart W rule, the EPA took several steps to evaluate the effect of the rule on small entities. For example, the EPA determined appropriate thresholds that reduced the number of small businesses reporting. In addition, the EPA conducted several meetings with industry associations to discuss regulatory options and the corresponding burden on industry, such as recordkeeping and reporting. Finally, the EPA continues to conduct significant outreach on the GHG reporting rule and maintains an ‘‘open door’’ policy for stakeholders to help inform the EPA’s understanding of key issues for the industries. The EPA continues to be interested in the potential impacts of the proposed rule amendments on small entities and welcomes comments on issues related to such impacts. D. Unfunded Mandates Reform Act (UMRA) Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531–1538, requires federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on state, local, and tribal governments and the private sector. Federal agencies must also develop a plan to provide notice to small governments that might be significantly or uniquely affected by any regulatory requirements. The plan must enable officials of affected small governments to have meaningful and timely input in the development of the EPA regulatory proposals with significant federal E:\FR\FM\10MRP2.SGM 10MRP2 13422 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 intergovernmental mandates and must inform, educate, and advise small governments on compliance with the regulatory requirements. This action proposes to (1) amend monitoring and calculation methodologies in subpart W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a definition in subpart A. This proposed rule 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. Thus, this proposed rule is not subject to the requirements of section 202 and 205 of the UMRA. This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. The proposed amendments would not impose any new requirements that are not currently required for 40 CFR part 98, and the rule amendments would not uniquely apply to small governments. Therefore, this action is not subject to the requirements of section 203 of the UMRA. E. Executive Order 13132: Federalism This action does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. However, for a more detailed discussion about how Part 98 relates to existing state programs, please see Section II of the preamble to the final Part 98 rule (74 FR 56266, October 30, 2009). This action proposes to (1) amend monitoring and calculation methodologies in subpart W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a definition in subpart A. Few, if any, state or local government facilities would be affected by the provisions in this proposed rule. This regulation also does not limit the power of States or localities to collect GHG data and/or regulate GHG emissions. Thus, Executive Order 13132 does not apply to this action. In the spirit of Executive Order 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 action from state and local officials. For a summary of the EPA’s consultation with state and local organizations and representatives in VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 developing Part 98, see Section VIII.E of the preamble to the final rule (74 FR 56371, October 30, 2009). F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments Subject to the Executive Order 13175 (65 FR 67249, November 9, 2000) the EPA may not issue a regulation that has tribal 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 tribal governments, or the EPA consults with tribal officials early in the process of developing the proposed regulation and develops a tribal summary impact statement. The EPA has concluded that this action may have tribal implications. This action proposes to (1) Amend monitoring and calculation methodologies in subpart W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a definition in subpart A. However, it will neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. This regulation would apply directly to petroleum and natural gas facilities that emit greenhouses gases. Although few facilities that would be subject to the rule are likely to be owned by tribal governments, the EPA has sought opportunities to provide information to tribal governments and representatives during the development of the proposed and final subpart W that was promulgated on November 30, 2010 (75 FR 74458). The EPA consulted with tribal officials early in the process of developing subpart W to permit them to have meaningful and timely input into its development. For additional information about the EPA’s interactions with tribal governments, see section IV.F of the preamble to the re-proposal of subpart W published on April 12, 2010 (75 FR 18608), and section IV.F of the preamble to the final subpart W published on November 30, 2010 (75 FR 74458). The EPA specifically solicits additional comment on this proposed action from tribal officials. G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks The EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5–501 of the Executive PO 00000 Frm 00030 Fmt 4701 Sfmt 4702 Order has the potential to influence the regulation. This action proposes to (1) Amend monitoring and calculation methodologies in subpart W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a definition in subpart A. This action is not subject to Executive Order 13045 because it does not establish an environmental standard intended to mitigate health or safety risks. H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use This action proposes to (1) amend monitoring and calculation methodologies in subpart W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a definition in subpart A. This action is not subject to Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not a significant regulatory action under Executive Order 12866. I. National Technology Transfer and Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law 104– 113 (15 U.S.C. 272 note) directs the EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards. This action proposes to (1) Amend monitoring and calculation methodologies in subpart W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a definition in subpart A. This proposed rulemaking does not involve the use of any technical standards. No changes are being proposed that affect the test methods currently in use for subpart W. Therefore, the EPA is not considering the use of any voluntary consensus standards. J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations Executive Order 12898 (59 FR 7629, (February 16, 1994)) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the United States. This action proposes to (1) amend monitoring and calculation methodologies in subpart W; (2) assign subpart W data reporting elements into CBI data categories; and (3) amend a definition in subpart A. The EPA has determined that this proposed rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it does not affect the level of protection provided to human health or the environment. Instead, this proposed rule addresses information collection and reporting procedures. List of Subjects in 40 CFR Part 98 Environmental protection, Administrative practice and procedure, Greenhouse gases, Incorporation by reference, Reporting and recordkeeping requirements. Dated: February 20, 2014. Gina McCarthy, Administrator. For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is proposed to be amended as follows: PART 98—MANDATORY GREENHOUSE GAS REPORTING 1. The authority citation for part 98 continues to read as follows: ■ Authority: 42 U.S.C. 7401–7671q. Subpart A—[AMENDED] 2. Section 98.6 is amended by revising the definition of ‘‘Well completions’’ to read as follows: ■ § 98.6 Definitions. emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * Well completions means the process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. Well completion also involves connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment, steps that do not significantly vent natural gas to the atmosphere. This process may VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 also include high-rate flowback of injected gas, water, oil, and proppant used to fracture and prop open new fractures in existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere. * * * * * Subpart W—[AMENDED] 3. Section 98.230 is amended by revising paragraph (a)(2) to read as follows: ■ § 98.230 Definition of the source category. (a) * * * (2) Onshore petroleum and natural gas production. Onshore petroleum and natural gas production means all equipment on a single well-pad or associated with a single well-pad (including but not limited to compressors, generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and processing equipment, and portable non-selfpropelled equipment, which includes well drilling and completion equipment, workover equipment, maintenance and repair equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/ or natural gas (including condensate). This equipment also includes associated storage or measurement vessels all petroleum and natural gas production equipment located on islands, artificial islands, or structures connected by a causeway to land, an island, or an artificial island. Onshore petroleum and natural gas production also means all equipment on or associated with a single enhanced oil recovery (EOR) well pad using CO2 or natural gas injection. * * * * * ■ 4. Section 98.232 is amended by: ■ a. Revising paragraph (c)(11); ■ b. Revising paragraph (d)(1); ■ c. Revising paragraph (e)(1); ■ d. Adding paragraph (e)(6); ■ e. Revising paragraph (f)(1); ■ f. Adding paragraph (f)(4); ■ g. Revising paragraph (g)(1); ■ h. Adding paragraph (g)(4); ■ i. Revising paragraph (h)(1); ■ j. Adding paragraph (h)(5); and ■ k. Revising paragraphs (i)(1) through (i)(7). The revisions and additions read as follows: § 98.232 GHGs to report. * * * * * (c) * * * (11) Reciprocating compressor venting. * * * * * PO 00000 Frm 00031 Fmt 4701 Sfmt 4702 13423 (d) * * * (1) Reciprocating compressor venting. * * * * * (e) * * * (1) Reciprocating compressor venting. * * * * * (6) Flare stack emissions. (f) * * * (1) Reciprocating compressor venting. * * * * * (4) Flare stack emissions. * * * * * (g) * * * (1) Reciprocating compressor venting. * * * * * (4) Flare stack emissions. (h) * * * (1) Reciprocating compressor venting. * * * * * (5) Flare stack emissions. (i) * * * (1) Equipment leaks from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open-ended lines at above grade transmission-distribution transfer stations. (2) Equipment leaks at below grade transmission-distribution transfer stations. (3) Equipment leaks at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations. (4) Equipment leaks at below grade metering-regulating stations. (5) Distribution main equipment leaks. (6) Distribution services equipment leaks. (7) Report under subpart W of this part the emissions of CO2, CH4, and N2O emissions from stationary fuel combustion sources following the methods in § 98.233(z). * * * * * ■ 5. Section 98.233 is amended by: ■ a. Revising paragraphs (a) introductory text, (a)(1), and (a)(2); ■ b. Adding paragraph (a)(4); ■ c. Revising paragraphs (c), (d), (e), (f), (g), (h), and (i); ■ d. Revising paragraphs (j) introductory text, (j)(1) introductory text, (j)(1)(vii) introductory text, and (j)(2); ■ e. Removing paragraphs (j)(3) and (j)(4). ■ f. Redesignating paragraph (j)(5) as paragraph (j)(3) and revising newly redesignated paragraph (j)(3); ■ g. Redesignating paragraph (j)(6) as paragraph (j)(4) and revising newly redesignated paragraph (j)(4); ■ h. Redesignating paragraph (j)(7) as paragraph (j)(5) and revising newly redesignated paragraph (j)(5); ■ i. Redesignating paragraph (j)(8) as paragraph (j)(6) and revising newly redesignated paragraph (j)(6); E:\FR\FM\10MRP2.SGM 10MRP2 13424 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules j. Redesignating paragraph (j)(9) as paragraph (j)(7) and revising newly redesignated paragraph (j)(7); ■ k. Revising paragraph (k); ■ l. Revising paragraphs (l) introductory text, (l)(2) introductory text, and (l)(2)(ii); ■ m. Revising paragraphs (l)(3) introductory text and the parameters ‘‘FR’’ and ‘‘D’’ of Equation W–17B in paragraph (l)(3); ■ n. Revising paragraphs (l)(5) and (l)(6); ■ o. Revising paragraphs (m), (n), (o), (p), (q), and (r); ■ p. Revising paragraphs (s)(2) introductory text, (s)(2)(i), (s)(3), (s)(4), and (t) introductory text. ■ q. Revising Equation W–33 of paragraph (t)(1) and adding the parameter ‘‘Za’’ to Equation W–33 in paragraph (t)(1); r. Revising Equation W–34 of paragraph (t)(2) and adding the parameter ‘‘Za’’ to Equation W–34 in paragraph (t)(2); ■ s. Revising paragraphs (u) introductory text, (u)(2)(iii), and (u)(2)(v) through (vii); ■ t. Revising paragraphs (v), (w) introductory text, (w)(1), and (w)(3) introductory text; ■ u. Revising the parameters ‘‘MassCO2’’, ‘‘N’’, and ‘‘Vv’’ to Equation W–37 in paragraph (w)(3); ■ v. Revising paragraphs (x) introductory text and (x)(1); ■ w. Revising the parameter ‘‘Shl’’ to Equation W–38 in paragraph (x)(2); ■ x. Revising paragraph (z)(1); ■ y. Revising the parameters ‘‘Va’’, ‘‘YCO2’’, ‘‘Yj’’, and ‘‘YCH4’’ to Equations W–39A and W–39B in paragraph (z)(2)(iii); ■ z. Revising Equation W–40 in paragraph (z)(2)(vi) and the parameters ‘‘MassN2O’’, ‘‘Fuel’’, and ‘‘HHV’’ to Equation W–40 in paragraph (z)(2)(vi); and ■ aa. Removing the parameter ‘‘GWP’’ of Equation W–40 in paragraph (z)(2)(vi). The revisions and additions read as follows: Where: Es,i = Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from natural gas pneumatic device vents, of types ‘‘t’’ (continuous high bleed, continuous low bleed, intermittent bleed), for GHGi. Countt = Total number of natural gas pneumatic devices of type ‘‘t’’ (continuous high bleed, continuous low bleed, intermittent bleed) as determined in paragraph (a)(1) or (a)(2) of this section. EFt = Population emission factors for natural gas pneumatic device vents (in standard cubic feet per hour per device) of each type ‘‘t’’ listed in Tables W–1A, W–3, and W–4 of this subpart for onshore petroleum and natural gas production, onshore natural gas transmission compression, and underground natural gas storage facilities, respectively. GHGi = For onshore petroleum and natural gas production facilities, onshore natural gas transmission compression facilities, and underground natural gas storage facilities, concentration of GHGi, CH4 or CO2, in produced natural gas or processed natural gas for each facility as specified in paragraphs (u)(2)(i), (iii), and (iv) of this section. Tt = Average estimated number of hours in the operating year the devices, of each type ‘‘t’’, were operational using engineering estimates based on best available data. Default is 8760 hours. two consecutive calendar years to determine ‘‘Countt’’ for Equation W–1 of this subpart for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) using engineering estimates based on best available data. * * * * * (4) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. * * * * * (c) Natural gas driven pneumatic pump venting. (1) Calculate CH4 and CO2 volumetric emissions from natural gas driven pneumatic pump venting using Equation W–2 of this section. Natural gas driven pneumatic pumps covered in paragraph (e) of this section do not have to report emissions under this paragraph (c). VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 (1) For all industry segments, determine ‘‘Countt’’ for Equation W–1 of this subpart for each type of natural gas pneumatic device (continuous high bleed, continuous low bleed, and intermittent bleed) by counting the devices, except as specified in paragraph (a)(2) of this section. The reported number of devices must represent the total number of devices for the reporting year. (2) For the onshore petroleum and natural gas production industry segment, you have the option in the first GHGi = Concentration of GHGi, CH4, or CO2, in produced natural gas as defined in paragraph (u)(2)(i) of this section. T = Average estimated number of hours in the operating year the pumps were operational using engineering estimates based on best available data. Default is 8760 hours. (2) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. PO 00000 Frm 00032 Fmt 4701 Sfmt 4702 § 98.233 Calculating GHG emissions. * * * * * (a) Natural gas pneumatic device venting. Calculate CH4 and CO2 volumetric emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices using Equation W–1 of this section. (d) Acid gas removal (AGR) vents. For AGR vents (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for CO2 only (not CH4) vented directly to the atmosphere or emitted through a flare, engine (e.g., permeate from a membrane or deadsorbed gas from a pressure swing adsorber used as fuel supplement), or sulfur recovery plant, using any of the E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.001</GPH> Where: Es,i = Annual total volumetric GHG emissions at standard conditions in standard cubic feet per year from all natural gas driven pneumatic pump venting, for GHGi. Count = Total number of natural gas driven pneumatic pumps. EF = Population emissions factors for natural gas driven pneumatic pumps (in standard cubic feet per hour per pump) listed in Table W–1A of this subpart for onshore petroleum and natural gas production. ■ EP10MR14.000</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 ■ Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13425 Method in subpart C of this part (General Stationary Fuel Combustion Sources). The calculation and reporting of CH4 and N2O emissions is not required as part of the Tier 4 requirements for AGR units. (2) Calculation Method 2. If a CEMS is not available but a vent meter is installed, use the CO2 composition and annual volume of vent gas to calculate emissions using Equation W–3 of this section. Where: Ea,CO2 = Annual volumetric CO2 emissions at actual conditions, in cubic feet per year. VS = Total annual volume of vent gas flowing out of the AGR unit in cubic feet per year at actual conditions as determined by flow meter using methods set forth in § 98.234(b). Alternatively, you may follow the manufacturer’s instructions or industry standard practice for calibration of the vent meter. use the inlet or outlet gas flow rate of the acid gas removal unit to calculate emissions for CO2 using Equations W– 4A or W–4B of this section. If inlet gas flow rate is known, use Equation W–4A. If outlet gas flow rate is known, use Equation W–4B. emcdonald on DSK67QTVN1PROD with PROPOSALS2 Where: Ea, CO2 = Annual volumetric CO2 emissions at actual conditions, in cubic feet per year. Vin = Total annual volume of natural gas flow into the AGR unit in cubic feet per year at actual conditions as determined using methods specified in paragraph (d)(5) of this section. Vout = Total annual volume of natural gas flow out of the AGR unit in cubic feet per year at actual conditions as determined using methods specified in paragraph (d)(5) of this section. VolI = Annual average volumetric fraction of CO2 content in natural gas flowing into the AGR unit as determined in paragraph (d)(7) of this section. Volo = Annual average volumetric fraction of CO2 content in natural gas flowing out of the AGR unit as determined in paragraph (d)(8) of this section. (4) Calculation Method 4. If CEMS or a vent meter is not installed, you may calculate emissions using any standard simulation software package, such as AspenTech HYSYS®, or API 4679 AMINECalc, that uses the PengRobinson equation of state and speciates CO2 emissions. A minimum of the following, determined for typical operating conditions over the calendar year by engineering estimate and VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 VolCO2 = Annual average volumetric fraction of CO2 content in vent gas flowing out of the AGR unit as determined in paragraph (d)(6) of this section. (3) Calculation Method 3. If a CEMS or a vent meter is not installed, you may process knowledge based on best available data, must be used to characterize emissions: (i) Natural gas feed temperature, pressure, and flow rate. (ii) Acid gas content of feed natural gas. (iii) Acid gas content of outlet natural gas. (iv) Unit operating hours, excluding downtime for maintenance or standby. (v) Exit temperature of natural gas. (vi) Solvent pressure, temperature, circulation rate, and weight. (5) For Calculation Method 3, determine the gas flow rate of the inlet when using Equation W–4A of this section or the gas flow rate of the outlet when using Equation W–4B of this section for the natural gas stream of an AGR unit using a meter according to methods set forth in § 98.234(b). If you do not have a continuous flow meter, either install a continuous flow meter or use an engineering calculation to determine the flow rate. (6) For Calculation Method 2, if a continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream to determine VolCO2 in Equation PO 00000 Frm 00033 Fmt 4701 Sfmt 4702 W–3 of this section according to methods set forth in § 98.234(b). (7) For Calculation Method 3, if a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream to determine VolI in Equation W–4A or W–4B of this section according to methods set forth in § 98.234(b). (8) For Calculation Method 3, determine annual average volumetric fraction of CO2 content in natural gas flowing out of the AGR unit using one of the methods specified in paragraphs (d)(8)(i) through (d)(8)(iii) of this section. (i) If a continuous gas analyzer is installed on the outlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a continuous gas analyzer. (ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet gas stream to determine VolO in Equation W–4A or W–4B of this section E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.003</GPH> requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may follow the manufacturer’s instructions or industry standard practice. If a CO2 concentration monitor and volumetric flow rate monitor are not available, you may elect to install a CO2 concentration monitor and a volumetric flow rate monitor that comply with all of the requirements specified for the Tier 4 Calculation EP10MR14.002</GPH> calculation methods described in this paragraph (d), as applicable. (1) Calculation Method 1. If you operate and maintain a continuous emissions monitoring system (CEMS) that has both a CO2 concentration monitor and volumetric flow rate monitor, you must calculate CO2 emissions under this subpart by following the Tier 4 Calculation Method and all associated calculation, quality assurance, reporting, and recordkeeping 13426 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules Count = Total number of glycol dehydrators that have an annual average of daily natural gas throughput that is less than 0.4 million standard cubic feet per day. 1000 = Conversion of EFi in thousand standard cubic feet to standard cubic feet. (3) Calculation Method 3. Dehydrators that use desiccant must calculate emissions from the amount of gas vented from the vessel when it is depressurized for the desiccant refilling process using Equation W–6 of this section. Desiccant dehydrator emissions covered in this paragraph do not have to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. Where: Es,n = Annual natural gas emissions at standard conditions in cubic feet. H = Height of the dehydrator vessel (ft). D = Inside diameter of the vessel (ft). P1 = Atmospheric pressure (psia). P2 = Pressure of the gas (psia). p = pi (3.14). %G = Percent of packed vessel volume that is gas. N = Number of dehydrator openings in the calendar year. 100 = Conversion of %G to fraction. (4) For glycol dehydrators that use the calculation method in paragraph (e)(2) of this section, calculate both CH4 and CO2 mass emissions from volumetric GHGi emissions using calculations in paragraph (v) of this section. For desiccant dehydrators that use the calculation method in paragraph (e)(3) of this section, calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (5) Determine if the dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1), (e)(2), and (e)(3) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data. (6) Calculate annual emissions from dehydrator vents to flares or regenerator fire-box/fire tubes as follows: VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00034 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.005</GPH> (viii) Use of flash tank separator (and disposition of recovered gas). (ix) Hours operated. (x) Wet natural gas temperature and pressure. (xi) Wet natural gas composition. Determine this parameter using one of the methods described in paragraphs (e)(1)(xi)(A) through (e)(1)(xi)(D) of this section. (A) Use the GHG mole fraction as defined in paragraph (u)(2)(i) or (u)(2)(ii) of this section. (B) If the GHG mole fraction cannot be determined using paragraph (u)(2)(i) or (u)(2)(ii) of this section, select a representative analysis. (C) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analyze wet natural gas composition. (D) If only composition data for dry natural gas is available, assume the wet natural gas is saturated. (2) Calculation Method 2. Calculate annual volumetric emissions from glycol dehydrators that have an annual average of daily natural gas throughput that is less than 0.4 million standard cubic feet per day using Equation W–5 of this section: EP10MR14.004</GPH> calculate CH4, CO2, and N2O annual emissions as specified in paragraph (e)(6) of this section. (1) Calculation Method 1. Calculate annual mass emissions from absorbent dehydrators that have an annual average of daily natural gas throughput that is greater than or equal to 0.4 million standard cubic feet per day by using a software program, such as AspenTech HYSYS® or GRI–GLYCalcTM, that uses the Peng-Robinson equation of state to calculate the equilibrium coefficient, speciates CH4 and CO2 emissions from dehydrators, and has provisions to include regenerator control devices, a separator flash tank, stripping gas and a gas injection pump or gas assist pump. The following parameters must be determined by engineering estimate based on best available data and must be used at a minimum to characterize emissions from dehydrators: (i) Feed natural gas flow rate. (ii) Feed natural gas water content. (iii) Outlet natural gas water content. (iv) Absorbent circulation pump type (e.g., natural gas pneumatic/air pneumatic/electric). (v) Absorbent circulation rate. (vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG)). (vii) Use of stripping gas. Where: Es,i = Annual total volumetric GHG emissions (either CO2 or CH4) at standard conditions in cubic feet. EFi = Population emission factors for glycol dehydrators in thousand standard cubic feet per dehydrator per year. Use 73.4 for CH4 and 3.21 for CO2 at 60 °F and 14.7 psia. emcdonald on DSK67QTVN1PROD with PROPOSALS2 according to methods set forth in § 98.234(b). (iii) If a continuous gas analyzer is not available or installed, you may use sales line quality specification for CO2 in natural gas. (9) Calculate annual volumetric CO2 emissions at standard conditions using calculations in paragraph (t) of this section. (10) Calculate annual mass CO2 emissions at standard conditions using calculations in paragraph (v) of this section. (11) Determine if CO2 emissions from the AGR unit are recovered and transferred outside the facility. Adjust the CO2 emissions estimated in paragraphs (d)(1) through (d)(10) of this section downward by the magnitude of CO2 emissions recovered and transferred outside the facility. (e) Dehydrator vents. For dehydrator vents, calculate annual CH4 and CO2 emissions using the applicable calculation methods described in paragraphs (e)(1) through (e)(4) of this section. If emissions from dehydrator vents are routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (e)(5) of this section. If emissions from dehydrator vents are routed to a flare or regenerator fire-box/fire tubes, you must Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13427 p = Wells 1 through h of the same tubing diameter group and pressure group combination in a sub-basin. Tp = Cumulative amount of time in hours of venting for each well, p, of the same tubing diameter group and pressure group combination in a sub-basin during the year. If the available venting data do not contain a record of the date of the venting events and data are not available to provide the venting hours for the specific time period of January 1 to December 31, you may calculate an annualized vent time, Tp, using Equation W–7B of this section. FR = Average flow rate in cubic feet per hour for all measured wells of the same tubing diameter group and pressure group combination in a sub-basin, over the duration of the liquids unloading, under actual conditions as determined in paragraph (f)(1)(i) of this section. Where: HRp = Cumulative amount of time in hours of venting for each well, p, during the monitoring period. MPp = Time period, in days, of the monitoring period for each well, p. A minimum of 300 days in a calendar year are required. The next period of data collection must start immediately following the end of data collection for the previous reporting year. Dp = Time period, in days during which the well, p, was in production (365 if the well was in production for the entire year). section for at least one well in a unique well tubing diameter group and pressure group combination in each sub-basin category. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately. (A) Calculate the average flow rate per hour of venting for each unique tubing diameter group and pressure group combination in each sub-basin category by dividing the recorded total annual flow by the recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere. (B) Apply the average hourly flow rate calculated under paragraph (f)(1)(i)(A) of this section to all wells in the same pressure group that have the same tubing diameter group, for the number of hours of venting these wells. (C) Calculate a new average flow rate every other calendar year starting with the first calendar year of data collection. For a new producing sub-basin category, calculate an average flow rate beginning in the first year of production. (ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section. (2) Calculation Method 2. Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unloading without plunger lift assist using Equation W–8 of this section. (i) Determine the well vent average flow rate (‘‘FR’’ in Equation W–7A of this section) as specified in paragraphs (f)(1)(i)(A) through (f)(1)(i)(C) of this VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00035 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.007</GPH> EP10MR14.008</GPH> atmosphere to expel liquids accumulated in the tubing, install a recording flow meter on the vent line used to vent gas from the well (e.g., on the vent line off the wellhead separator or atmospheric storage tank) according to methods set forth in § 98.234(b). Calculate the total emissions from well venting to the atmosphere for liquids unloading using Equation W–7A of this section. For any tubing diameter group and pressure group combination in a sub-basin where liquids unloading occurs both with and without plunger lifts, Equation W–7A will be used twice, once for wells with plunger lifts and once for wells without plunger lifts. EP10MR14.006</GPH> for liquids unloading using one of the calculation methods described in paragraphs (f)(1), (f)(2), or (f)(3) of this section. Calculate annual CH4 and CO2 volumetric and mass emissions using the method described in paragraph (f)(4) of this section. (1) Calculation Method 1. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately. For at least one well of each unique well tubing diameter group and pressure group combination in each sub-basin category (see § 98.238 for the definitions of tubing diameter group, pressure group, and sub-basin category), where gas wells are vented to the Where: Ea = Annual natural gas emissions for all wells of the same tubing diameter group and pressure group combination in a sub-basin at actual conditions, a, in cubic feet. Calculate emission from wells with plunger lifts and wells without plunger lifts separately. h = Total number of wells of the same tubing diameter group and pressure group combination in a sub-basin either with or without plunger lifts. emcdonald on DSK67QTVN1PROD with PROPOSALS2 (i) Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) or (e)(2) of this section for absorbent dehydrators. Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(3) and (e)(4) of this section for dehydrators that use desiccant. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent. (f) Well venting for liquids unloadings. Calculate annual volumetric natural gas emissions from well venting 13428 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules production, or casing pressure for each well with no packers, in pounds per square inch absolute (psia). If casing pressure is not available for each well, you may determine the casing pressure by multiplying the tubing pressure of each well with a ratio of casing pressure to tubing pressure from a well in the same sub-basin for which the casing pressure is known. The tubing pressure must be measured during gas flow to a flow-line. The shut-in pressure, surface pressure, or casing pressure must be determined just prior to liquids unloading when the well production is impeded by liquids loading or closed to the flow-line by surface valves. SFRp = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per hour. Use Equation W–33 of this section to calculate the average flow-line rate at standard conditions. HRp,q = Hours that each well, p, was left open to the atmosphere during each unloading event, q. 1.0 = Hours for average well to blowdown casing volume at shut-in pressure. q = Unloading event. Zp,q = If HRp,q is less than 1.0 then Zp,q is equal to 0. If HRp,q is greater than or equal to 1.0 then Zp,q is equal to 1. Where: Es = Annual natural gas emissions for each sub-basin at standard conditions, s, in cubic feet per year. W = Total number of wells with plunger lift assist and well venting for liquids unloading for each sub-basin. p = Wells 1 through W with well venting for liquids unloading for each sub-basin. Vp = Total number of unloading events in the monitoring period for each well, p. 0.37 ×10¥3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). TDp = Tubing internal diameter for each well, p, in inches. WDp = Tubing depth to plunger bumper for each well, p, in feet. SPp = Flow-line pressure for each well, p, in pounds per square inch absolute (psia), using engineering estimate based on best available data. SFRp = Average flow-line rate of gas for well, p, at standard conditions in cubic feet per hour. Use Equation W–33 of this section to calculate the average flow-line rate at standard conditions. HRp,q = Hours that each well, p, was left open to the atmosphere during each unloading event, q. 0.5 = Hours for average well to blowdown tubing volume at flow-line pressure. q = Unloading event. Zp,q = If HRp,q is less than 0.5 then Zp,q is equal to 0. If HRp,q is greater than or equal to 0.5 then Zp,q is equal to 1. flowback is routed to open pits or tanks and a subsequent period when gas content is sufficient to route the flowback to a separator or when the gas content is sufficient to allow measurement by the devices specified in paragraph (g)(1) of this section, regardless of whether a separator is actually utilized. If you elect to use Equation W–10A of this section, you must follow the procedures specified in paragraph (g)(1) of this section. Emissions must be calculated separately for completions and workovers, for each sub-basin, and for each well type combination identified in paragraph (g)(2) of this section. You must calculate CH4 and CO2 volumetric and mass emissions as specified in paragraph (g)(3) of this section. If emissions from gas well venting during completions and workovers with hydraulic fracturing are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (g)(4) of this section. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 for each sub-basin and well type combination. W = Total number of wells completed or worked over using hydraulic fracturing in a sub-basin and well type combination. PO 00000 Frm 00036 Fmt 4701 Sfmt 4702 Tp,s = Cumulative amount of time of flowback, after sufficient quantities of gas are present to enable separation, where gas is vented or flared for the completion or workover, in hours, for each well, p, in a sub-basin and well type combination during the reporting E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.010</GPH> EP10MR14.011</GPH> Where: Es,n = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during completions or workovers following hydraulic fracturing (4) Calculate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. (g) Gas well venting during completions and workovers with hydraulic fracturing. Calculate annual volumetric natural gas emissions from gas well venting during completions and workovers involving hydraulic fracturing using Equation W–10A or Equation W–10B of this section. Equation W–10A applies to well venting when the flowback rate is measured from a specified number of example completions or workovers and Equation W–10B applies when the flowback vent or flare volume is measured for each completion or workover. Completion and workover activities are separated into two periods, an initial period when (3) Calculation Method 3. Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unloading with plunger lift assist using Equation W–9 of this section. EP10MR14.009</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 Where: Es = Annual natural gas emissions for each sub-basin at standard conditions, s, in cubic feet per year. W = Total number of wells with well venting for liquids unloading for each sub-basin. p = Wells 1 through W with well venting for liquids unloading for each sub-basin. Vp = Total number of unloading events in the monitoring period per well, p. 0.37 ×10¥3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). CDp = Casing internal diameter for each well, p, in inches. WDp = Well depth from either the top of the well or the lowest packer to the bottom of the well, for each well, p, in feet. SPp = For each well, p, shut-in pressure or surface pressure for wells with tubing Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules Where: FRa = Flowback rate in actual cubic feet per hour, under actual subsonic flow conditions. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 using a recording flow meter (digital or analog) on the vent line to measure the flowback, at the beginning of the period of time when sufficient quantities of gas are present to enable separation, of the completion or workover according to methods set forth in § 98.234(b). (1) If you elect to use Equation W– 10A of this section, you must use Calculation Method 1 as specified in paragraph (g)(1)(i) of this section, or Calculation Method 2 as specified in paragraph (g)(1)(ii) of this section, to determine the value of FRMs and FRMi. These values must be based on the flow rate for flowback, once sufficient gas is present to enable separation. The number of measurements or calculations required to estimate FRMs and FRMi must be determined individually for completions and workovers per subbasin and well type as follows: complete measurements or calculations for at least one completion or workover for less than or equal to 25 completions or workovers for each well type within a sub-basin; complete measurements or calculations for at least two completions or workovers for 26 to 50 completions or workovers for each sub-basin and well type combination; complete measurements or calculations for at least three completions or workovers for 51 to 100 completions or workovers for each sub-basin and well type combination; complete measurements or calculations for at least four completions or workovers for 101 to 250 completions or workovers for each subbasin and well type combination; and complete measurements or calculations for at least five completions or workovers for greater than 250 completions or workovers for each subbasin and well type combination. (i) Calculation Method 1. You must use Equation W–12A as specified in paragraph (g)(1)(iii) of this section to determine the value of FRMs. You must use Equation W–12B as specified in paragraph (g)(1)(iv) of this section to determine the value of FRMi. The procedures specified in paragraphs (g)(1)(v) and (g)(1)(vi) also apply. When making flowback measurements for use in Equations W–12A and W–12B of this section, you must use a recording flow meter (digital or analog) installed on the vent line, ahead of a flare or vent, to measure the flowback rates in units of standard cubic feet per hour according to methods set forth in § 98.234(b). (ii) Calculation Method 2. You must use Equation W–12A as specified in paragraph (g)(1)(iii) of this section to determine the value of FRMs. You must use Equation W–12B as specified in paragraph (g)(1)(iv) of this section to determine the value of FRMi. The procedures specified in paragraphs (g)(1)(v) and (g)(1)(vi) also apply. When calculating the flowback rates for use in Equations W–12A and W–12B of this section based on well parameters, you must record the well flowing pressure immediately upstream (and immediately downstream in subsonic flow) of a well choke according to methods set forth in § 98.234(b) to calculate the well flowback. The upstream pressure must be surface pressure and reservoir pressure cannot be assumed. The downstream pressure must be measured after the choke and atmospheric pressure cannot be assumed. Calculate flowback rate using Equation W–11A of this section for subsonic flow or Equation W–11B of this section for sonic flow. You must use best engineering estimates based on best available data along with Equation W–11C of this section to determine whether the predominant flow is sonic or subsonic. If the value of R in Equation W–11C of this section is greater than or equal to 2, then flow is sonic; otherwise, flow is subsonic. Convert calculated FRa values shall be converted from actual conditions upstream of the restriction orifice to standard conditions (FRs,p and FRi,p) for use in Equations W–12A and W–12B of this section using Equation W–33 in paragraph (t) of this section. A = Cross sectional open area of the restriction orifice (m2). P1 = Pressure immediately upstream of the choke (psia). Tu = Temperature immediately upstream of the choke (degrees Kelvin). P2 = Pressure immediately downstream of the choke (psia). 3430 = Constant with units of m2/(sec2 * K). 1.27*105 = Conversion from m3/second to ft3/ hour. PO 00000 Frm 00037 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.012</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 year. This may include non-contiguous periods of venting or flaring. Tp,i = Cumulative amount of time of flowback to open tanks/pits, from when gas is first detected until sufficient quantities of gas are present to enable separation, for the completion or workover, in hours, for each well, p, in a sub-basin and well type combination during the reporting year. This may include non-contiguous periods of routing to open tanks/pits. FRMs = Ratio of average flowback, during the period when sufficient quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30-day production rate for the sub-basin and well type combination, calculated using procedures specified in paragraph (g)(1)(iii) of this section, expressed in standard cubic feet per hour. FRMi = Ratio of initial flowback rate during well completions and workovers from hydraulic fracturing to 30-day production rate for the sub-basin and well type combination, calculated using procedures specified in paragraph (g)(1)(iv) of this section, expressed in standard cubic feet per hour, for the period of flow to open tanks/pits. PRs,p = Average production flow rate during the first 30 days of production after completions of newly drilled gas wells or gas well workovers using hydraulic fracturing in standard cubic feet per hour of each well p, that was measured in the sub-basin and well type combination. EnFs,p = Volume of N2 injected gas in cubic feet at standard conditions that was injected into the reservoir during an energized fracture job for each well, p, as determined by using an appropriate meter according to methods described in § 98.234(b), or by using receipts of gas purchases that are used for the energized fracture job. Convert to standard conditions using paragraph (t) of this section. If the fracture process did not inject gas into the reservoir or if the injected gas is CO2 then EnFs,p is 0. FVs,p = Flow volume vented or flared of each well, p, in standard cubic feet measured using a recording flow meter (digital or analog) on the vent line to measure flowback during the separation period of the completion or workover according to methods set forth in § 98.234(b). FRp,i = Flow rate vented or flared of each well, p, in standard cubic feet measured 13429 13430 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules A = Cross sectional open area of the restriction orifice (m2). Tu = Temperature immediately upstream of the choke (degrees Kelvin). 187.08 = Constant with units of m2/(sec2 * K). 1.27*105 = Conversion from m3/second to ft3/ hour. Where: R = Pressure ratio. P1 = Pressure immediately upstream of the choke (psia). P2 = Pressure immediately downstream of the choke (psia). (iii) For Equation W–10A of this section, calculate FRMs using Equation W–12A of this section. Where: FRMs = Ratio of average flowback rate, during the period of time when sufficient quantities of gas are present to enable separation, of well completions and workovers from hydraulic fracturing to 30-day production rate for each subbasin and well type combination. FRs,p = Measured average flowback rate from Calculation Method 1 described in paragraph (g)(1)(i) of this section or calculated average flowback rate from Calculation Method 2 described in paragraph (g)(1)(ii) of this section, during the separation period in standard cubic feet per hour for well(s) p for each subbasin and well type combination. Convert measured and calculated FRa values shall be converted from actual conditions upstream of the restriction orifice (FRa) to standard conditions (FRs,p) for each well p using Equation W– 33 in paragraph (t) of this section. You may not use flow volume as used in Equation W–10B converted to a flow rate for this parameter. PRs,p = Average production flow rate during the first 30 days of production after completions of newly drilled gas wells or gas well workovers using hydraulic fracturing, in standard cubic feet per hour for each well, p, that was measured in the sub-basin and well type combination. N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and well type combination. Where: FRMi = Ratio of flowback gas rate while flowing to open tanks/pits during well completions and workovers from hydraulic fracturing to 30-day production rate. FRi,p = Initial measured gas flowback rate from Calculation Method 1 described in paragraph (g)(1)(i) of this section or initial calculated flow rate from Calculation Method 2 described in paragraph (g)(1)(ii) of this section in standard cubic feet per hour for well(s), p, for each sub-basin and well type combination. Measured and calculated FRi,p values must be based on flow conditions at the beginning of the separation period and must be expressed at standard conditions. PRs,p = Average production flow rate during the first 30-days of production after completions of newly drilled gas wells or gas well workovers using hydraulic fracturing, in standard cubic feet per hour of each well, p, that was measured in the sub-basin and well type combination. N = Number of measured or calculated well completions or workovers using hydraulic fracturing in a sub-basin and well type combination. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00038 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.016</GPH> respectively, in the gas producing subbasin and well type combination for the total number of hours of flowback and for the first 30 day average production rate for each of these wells. (vi) For Equation W–12A and W–12B of this section, calculate new flowback rates for horizontal and vertical gas well completions and horizontal and vertical gas well workovers in each sub-basin category once every two years starting in the first calendar year of data collection. (2) For paragraphs (g) introductory text and (g)(1) of this section, measurements and calculations are completed separately for workovers and completions per sub-basin and well type combination. A well type combination is a unique combination of the EP10MR14.014</GPH> EP10MR14.015</GPH> (v) For Equation W–10A of this section, the ratio of flowback rate during well completions and workovers from hydraulic fracturing to 30-day production rate for horizontal and vertical wells are applied to all horizontal and vertical well completions in the gas producing sub-basin and well type combination and to all horizontal and vertical well workovers, (iv) For Equation W–10A of this section, calculate FRMi using Equation W–12B of this section. EP10MR14.013</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 Where: FRa = Flowback rate in actual cubic feet per hour, under actual sonic flow conditions. Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13431 (i) Use the volumetric total natural gas emissions vented to the atmosphere during well completions and workovers as determined in paragraph (g) of this section to calculate volumetric and mass emissions using paragraphs (u) and (v) of this section. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to adjust emissions for the portion of gas flared during well completions and workovers using hydraulic fracturing. This adjustment to emissions from completions using flaring, versus completions without flaring, accounts for the conversion of CH4 to CO2 in the flare and for the formation on N2O during flaring. (h) Gas well venting during completions and workovers without hydraulic fracturing. Calculate annual volumetric natural gas emissions from each gas well venting during workovers without hydraulic fracturing using Equation W–13A of this section. Calculate annual volumetric natural gas emissions from each gas well venting during completions without hydraulic fracturing using Equation W–13B of this section. You must convert annual volumetric natural gas emissions to CH4 and CO2 volumetric and mass emissions as specified in paragraph (h)(1) of this section. If emissions from gas well venting during completions and workovers without hydraulic fracturing are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (h)(2) of this section. Where: Es,wo = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during well workovers without hydraulic fracturing. Nwo = Number of workovers per sub-basin category that do not involve hydraulic fracturing in the reporting year. EFwo = Emission factor for non-hydraulic fracture well workover venting in standard cubic feet per workover. Use 3,114 standard cubic feet natural gas per well workover without hydraulic fracturing. Es,p = Annual volumetric natural gas emissions in standard cubic feet from gas well venting during well completions without hydraulic fracturing. p = Well completions 1 through f in a subbasin. f = Total number of well completions without hydraulic fracturing in a sub-basin category. Vp = Average daily gas production rate in standard cubic feet per hour for each well, p, undergoing completion without hydraulic fracturing. This is the total annual gas production volume divided by total number of hours the wells produced to the flow-line. For completed wells that have not established a production rate, you may use the average flow rate from the first 30 days of production. In the event that the well is completed less than 30 days from the end of the calendar year, the first 30 days of the production straddling the current and following calendar years shall be used. Tp = Time that gas is vented to either the atmosphere or a flare for each well, p, undergoing completion without hydraulic fracturing, in hours during the year. (1) Calculate both CH4 and CO2 volumetric emissions from natural gas volumetric emissions using calculations in paragraph (u) of this section. Calculate both CH4 and CO2 mass emissions from volumetric emissions vented to atmosphere using calculations in paragraph (v) of this section. (2) Calculate annual emissions of CH4, CO2, and N2O from gas well venting to flares during well completions and workovers not involving hydraulic fracturing as specified in paragraphs (h)(2)(i) and (h)(2)(ii) of this section. (i) Use the gas well venting volume and gas composition during well completions and workovers that are flared as determined using the methods specified in paragraphs (h) and (h)(1) of this section. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine emissions from the flare for gas well venting to a flare during completions and workovers without hydraulic fracturing. (i) Blowdown vent stacks. Calculate CO2 and CH4 blowdown vent stack emissions from the depressurization of equipment to reduce system pressure for planned or emergency shutdowns resulting from human intervention or to take equipment out of service for maintenance as specified in either paragraph (i)(2) or (i)(3) of this section. Equipment with a unique physical volume of less than 50 cubic feet as determined in paragraph (i)(1) of this section are not subject to the requirements in paragraphs (i)(2) through (i)(4) this section. The requirements in this paragraph (i) do not apply to blowdown vent stack emissions from depressurizing to a flare, overpressure relief, operating pressure control venting, blowdown of non-GHG gases, and desiccant dehydrator blowdown venting before reloading. (1) Method for calculating unique physical volumes. You must calculate each unique physical volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, and vessels) between isolation valves, in cubic feet, by using engineering estimates based on best available data. (2) Method for determining emissions from blowdown vent stacks according to equipment type. If you elect to determine emissions according to each equipment type, using unique physical volumes as calculated in paragraph (i)(1) of this section, you must calculate emissions as specified in paragraphs (i)(2)(i) through (i)(2)(iii) of this section for each equipment type. Equipment types must be grouped into the following seven categories: station piping, pipeline venting, compressors, scrubbers/strainers, pig launchers and receivers, emergency shutdowns, and all other blowdowns greater than or equal to 50 cubic feet. (i) Calculate the total annual natural gas emissions from each unique physical volume that is blown down VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00039 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.017</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 parameters listed in paragraphs (g)(2)(i) through (g)(2)(iii) of this section. (i) Vertical or horizontal (directional drilling). (ii) With flaring or without flaring. (iii) Reduced emission completion/ workover or not reduced emission completion/workover. (3) Calculate both CH4 and CO2 volumetric and mass emissions from total natural gas volumetric emissions using calculations in paragraphs (u) and (v) of this section. (4) Calculate annual emissions from gas well venting during well completions and workovers from hydraulic fracturing where all or a portion of the gas is flared as specified in paragraphs (g)(4)(i) and (g)(4)(ii) of this section. 13432 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules using either Equation W–14A or W–14B of this section. Ps = Absolute pressure at standard conditions (14.7 psia). Pa = Absolute pressure at actual conditions in the unique physical volume (psia). Za = Compressibility factor at actual conditions for natural gas. You may use 1 if the temperature is above ¥10 degrees Fahrenheit and pressure is below 5 atmospheres, or if the compressibility factor at the actual temperature and pressure is 0.98 or greater. Where: Es,n = Annual natural gas emissions at standard conditions from each unique physical volume that is blown down, in cubic feet. p = Individual occurrence of blowdown for the same unique physical volume. N = Number of occurrences of blowdowns for each unique physical volume in the calendar year. You must retain logs documenting the number of occurrences of blowdowns for each unique physical volume in the calendar year. Vp = Unique physical volume between isolation valves, in cubic feet, for each blowdown ‘‘p.’’ Ts = Temperature at standard conditions (60 °F). Ta,p = Temperature at actual conditions in the unique physical volume (°F) for each blowdown ‘‘p’’. Ps = Absolute pressure at standard conditions (14.7 psia). Pa,b,p = Absolute pressure at actual conditions in the unique physical volume (psia) at the beginning of the blowdown ‘‘p’’. Pa,e,p = Absolute pressure at actual conditions in the unique physical volume (psia) at the end of the blowdown ‘‘p’’; 0 if blowdown volume is purged using nonGHG gases. Za = Compressibility factor at actual conditions for natural gas. You may use 1 if the temperature is above ¥10 degrees Fahrenheit and pressure is below 5 atmospheres, or if the compressibility factor at the actual temperature and pressure is 0.98 or greater. unique physical volumes associated with the equipment type. (iii) Calculate total annual CH4 and CO2 volumetric and mass emissions from each equipment type by using the annual natural gas emission value calculated in paragraph (i)(2)(ii) of this section for the equipment type and the calculation method specified in paragraph (i)(4) of this section. (3) Method for determining emissions from blowdown vent stacks using a flow meter. In lieu of determining emissions from blowdown vent stacks using unique physical volumes as specified in paragraphs (i)(1) and (i)(2) of this section, you may use a flow meter and measure blowdown vent stack emissions. If you choose to use this method, you must measure the natural gas emissions from the blowdown(s) at the facility using a flow meter according to methods in § 98.234(b), and calculate annual CH4 and CO2 volumetric and mass emissions measured by the meters according to paragraph (i)(4) of this section. (4) Method for converting from natural gas emissions to GHG volumetric and mass emissions. Calculate both CH4 and CO2 volumetric and mass emissions using the methods specified in paragraphs (u) and (v) of this section. (j) Onshore production storage tanks. Calculate CH4, CO2, and N2O (when flared) emissions from atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore petroleum and natural gas production facilities (including stationary liquid storage not owned or operated by the reporter), as specified in this paragraph (j). For wells flowing to gas-liquid separators with annual average daily throughput of oil greater than or equal to 10 barrels per day, calculate annual CH4 and CO2 using Calculation Method 1 or 2 as specified in paragraphs (j)(1) and (j)(2) of this section. For wells flowing directly to atmospheric storage tanks without passing through a wellhead separator with throughput greater than 10 barrels per day, calculate annual CH4 and CO2 emissions using Calculation Method 2 as specified in paragraph (j)(2) of this section. For wells flowing to gas-liquid separators or directly to atmospheric storage tanks with throughput less than 10 barrels per day, use Calculation Method 3 as specified in paragraphs (j)(3) of this section. You must also calculate emissions that may have occurred due to dump valves not closing properly using the method specified in paragraph (j)(6) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed to a vapor recovery system, you must adjust the emissions downward according to paragraph (j)(4) of this section. If emissions from atmospheric pressure fixed roof storage tanks are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (j)(5) of this section. (1) Calculation Method 1. Calculate annual CH4 and CO2 emissions from onshore production storage tanks using operating conditions in the last (ii) Calculate the annual natural gas emissions, in cubic feet, from each equipment type by summing Es,n, as calculated in either Equation W–14A or Equation W–14B of this subpart, for all VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00040 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.019</GPH> V = Unique physical volume between isolation valves, in cubic feet, as calculated in paragraph (i)(1) of this section. C = Purge factor is 1 if the unique physical volume is not purged, or 0 if the unique physical volume is purged using nonGHG gases. Ts = Temperature at standard conditions (60 °F). Ta = Temperature at actual conditions in the unique physical volume (°F). EP10MR14.018</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 Where: Es,n = Annual natural gas emissions at standard conditions from each unique physical volume that is blown down, in cubic feet. N = Number of occurrences of blowdowns for each unique physical volume in the calendar year. You must retain logs documenting the number of occurrences of blowdowns for each unique physical volume in the calendar year. Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13433 1,000 = Conversion from thousand standard cubic feet to standard cubic feet. (4) Determine if the storage tank receiving your separator oil has a vapor recovery system. (i) Adjust the emissions estimated in paragraphs (j)(1) through (j)(3) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data. (ii) [Reserved] (5) Determine if the storage tank receiving your separator oil is sent to flare(s). (i) Use your separator flash gas volume and gas composition as determined in this section. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine storage tank emissions from the flare. (6) Calculate emissions from occurrences of well pad gas-liquid separator liquid dump valves not closing during the calendar year by using Equation W–16 of this section. Where: Es,i,o = Annual volumetric GHG emissions at standard conditions from each storage tank in cubic feet that resulted from the dump valve on the gas-liquid separator not closing properly. En = Storage tank emissions as determined in Calculation Methods 1, 2, or 3 in paragraphs (j)(1), (j)(2), and (j)(3) of this section (with wellhead separators) in standard cubic feet per year. Tn = Total time a dump valve is not closing properly in the calendar year in hours. Estimate Tn based on maintenance, operations, or routine well pad inspections that indicate the period of time when the valve was malfunctioning in open or partially open position. CFn = Correction factor for tank emissions for time period Tn is 2.87 for crude oil production. Correction factor for tank emissions for time period Tn is 4.37 for gas condensate production. 8,760 = Conversion to hourly emissions. (k) Transmission storage tanks. For vent stacks connected to one or more transmission condensate storage tanks, either water or hydrocarbon, without vapor recovery, in onshore natural gas transmission compression, calculate CH4 and CO2 annual emissions from compressor scrubber dump valve leakage as specified in paragraphs (k)(1) through (k)(3) of this section. If emissions from compressor scrubber dump valve leakage are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (k)(4) of this section. (1) Except as specified in paragraph (k)(1)(iv) of this section, you must monitor the tank vapor vent stack annually for emissions using one of the methods specified in paragraphs (k)(1)(i) through (k)(1)(iii) of this section. (i) Use an optical gas imaging instrument according to methods set forth in § 98.234(a)(1). (ii) Measure the tank vent directly using a flow meter or high volume sampler according to methods in § 98.234(b) or (d) for a duration of 5 minutes. (iii) Measure the tank vent using a calibrated bag according to methods in § 98.234(c) for a duration of 5 minutes or until the bag is full, whichever is shorter. (iv) You may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in § 98.234(a)(5). (2) If the tank vapors from the vent stack are continuous for 5 minutes, or the acoustic leak detection device detects a leak, then you must use one of the methods in either paragraph (k)(2)(i) or (k)(2)(ii) of this section and the requirements specified in paragraphs (k)(2)(iii) and (k)(2)(iv) of this section to quantify annual emissions. (i) Use a flow meter, such as a turbine meter, calibrated bag, or high volume sampler to estimate tank vapor volumes from the vent stack according to (7) Calculate both CH4 and CO2 mass emissions from natural gas volumetric emissions using calculations in paragraph (v) of this section. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00041 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.021</GPH> storage tanks, using either of the methods in paragraphs (j)(2)(i) or (j)(2)(ii) of this section. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as described in § 98.234(b) to sample and analyze separator oil composition at separator pressure and temperature. * * * * * (3) Calculation Method 3. Calculate CH4 and CO2 emissions using Equation W–15 of this section: EP10MR14.020</GPH> minimum to characterize emissions from liquid transferred to tanks: * * * * * (vii) Separator oil composition and Reid vapor pressure. If this data is not available, determine these parameters by using one of the methods described in paragraphs (j)(1)(vii)(A) through (j)(1)(vii)(C) of this section. * * * * * (2) Calculation Method 2. Calculate annual CH4 and CO2 emissions by assuming that all of the CH4 and CO2 in solution at separator temperature and pressure is emitted from oil sent to Where: Es,i = Annual total volumetric GHG emissions (either CO2 or CH4) at standard conditions in cubic feet. EFi = Population emission factor for separators or wells in thousand standard cubic feet per separator or well per year, for crude oil use 4.2 for CH4 and 2.8 for CO2 at 60 °F and 14.7 psia, and for gas condensate use 17.6 for CH4 and 2.8 for CO2 at 60 °F and 14.7 psia. Count = Total number of separators or wells with annual average daily throughput less than 10 barrels per day. Count only separators or wells that feed oil directly to the storage tank. emcdonald on DSK67QTVN1PROD with PROPOSALS2 wellhead gas-liquid separator before liquid transfer to storage tanks. Calculate flashing emissions with a software program, such as AspenTech HYSYS® or API 4697 E&P Tank, that uses the Peng-Robinson equation of state, models flashing emissions, and speciates CH4 and CO2 emissions that will result when the oil from the separator enters an atmospheric pressure storage tank. The following parameters must be determined for typical operating conditions over the year by engineering estimate and process knowledge based on best available data, and must be used at a Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 methods set forth in § 98.234(b) through (d). If you do not have a continuous flow measurement device, you may install a flow measuring device on the tank vapor vent stack. If the vent is directly measured for five minutes under paragraph (k)(1)(ii) or (k)(1)(iii) of this section to detect continuous leakage, this serves as the measurement. (ii) Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the method set forth in § 98.234(a)(5). (iii) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section. (iv) Calculate CH4 and CO2 volumetric and mass emissions at standard conditions using calculations in paragraphs (t), (u), and (v) of this section, as applicable to the monitoring equipment used. (3) If a leaking dump valve is identified, the leak must be counted as having occurred since the beginning of the calendar year, or from the previous test that did not detect leaking in the same calendar year. If the leaking dump valve is fixed following leak detection, the leak duration will end upon being repaired. If a leaking dump valve is identified and not repaired, the leak must be counted as having occurred through the rest of the calendar year. (4) Calculate annual emissions from storage tanks to flares as specified in paragraphs (k)(4)(i) and (k)(4)(ii) of this section. (i) Use the storage tank emissions volume and gas composition as determined in paragraphs (k)(1) through (k)(3) of this section. Where: Es,n = Annual volumetric natural gas emissions, at the facility level, from associated gas venting at standard conditions, in cubic feet. GORp,q = Gas to oil ratio, for well p in subbasin q, in standard cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities. Vp,q = Volume of oil produced, for well p in sub-basin q, in barrels in the calendar year during time periods in which associated gas was vented or flared. SGp,q = Volume of associated gas sent to sales, for well p in sub-basin q, in standard cubic feet of gas in the calendar year during time periods in which associated gas was vented or flared. EREp,q = Emissions reported elsewhere, volume of associated gas for well p in VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine storage tank emissions sent to a flare. (l) Well testing venting and flaring. Calculate CH4 and CO2 annual emissions from well testing venting as specified in paragraphs (l)(1) through (l)(5) of this section. If emissions from well testing venting are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (l)(6) of this section. * * * * * (2) If GOR cannot be determined from your available data, then you must measure quantities reported in this section according to one of the procedures specified in paragraph (l)(2)(i) or (l)(2)(ii) of this section to determine GOR. * * * * * (ii) You may use an industry standard practice as described in § 98.234(b). (3) Estimate venting emissions using Equation W–17A (for oil wells) or Equation W–17B (for gas wells) of this section. * * * * * FR = Average annual flow rate in barrels of oil per day for the oil well(s) being tested. * * * * * D = Number of days during the calendar year that the well(s) is tested. * * * * * (5) Calculate both CH4 and CO2 volumetric and mass emissions from natural gas volumetric emissions using calculations in paragraphs (u) and (v) of this section. (6) Calculate emissions from well testing if emissions are routed to a flare sub-basin q, in standard cubic feet, during time periods in which associated gas was vented or flared and for which emission source types of this section calculate and report emissions from the associated gas stream prior to venting or flaring of the associated gas (i.e., § 98.233(j) for onshore production storage tanks). x = Total number of wells in sub-basin that vent or flare associated gas. y = Total number of sub-basins in a basin that contain wells that vent or flare associated gas. (4) Calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using calculations in paragraphs (u) and (v) of this section. PO 00000 Frm 00042 Fmt 4701 Sfmt 4702 as specified in paragraphs (l)(6)(i) and (l)(6)(ii) of this section. (i) Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) through (4) of this section. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine well testing emissions from the flare. (m) Associated gas venting and flaring. Calculate CH4 and CO2 annual emissions from associated gas venting not in conjunction with well testing (refer to paragraph (l): Well testing venting and flaring of this section) as specified in paragraphs (m)(1) through (m)(4) of this section. If emissions from associated gas venting are routed to a flare, you must calculate CH4, CO2, and N2O annual emissions as specified in paragraph (m)(5) of this section. (1) Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, use the GOR from a cluster of wells in the same sub-basin category. (2) If GOR cannot be determined from your available data, then you must use one of the procedures specified in paragraphs (m)(2)(i) or (m)(2)(ii) of this section to determine GOR. (i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists. (ii) You may use an industry standard practice as described in § 98.234(b). (3) Estimate venting emissions using Equation W–18 of this section. (5) Calculate emissions from associated natural gas if emissions are routed to a flare as specified in paragraphs (m)(5)(i) and (m)(5)(ii) of this section. (i) Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) through (m)(4) of this section. (ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine associated gas emissions from the flare. (n) Flare stack emissions. Calculate CO2, CH4, and N2O emissions from a flare stack as specified in paragraphs (n)(1) through (n)(9) of this section. (1) If you have a continuous flow measurement device on the flare, you E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.022</GPH> 13434 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13435 (i) For onshore natural gas production, determine the GHG mole fraction using paragraph (u)(2)(i) of this section. (ii) For onshore natural gas processing, when the stream going to flare is natural gas, use the GHG mole fraction in feed natural gas for all streams upstream of the de-methanizer or dew point control, and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities. For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole fraction in feed natural gas liquid for all streams. (iii) For any applicable industry segment, when the stream going to the flare is a hydrocarbon product stream, such as methane, ethane, propane, butane, pentane-plus and mixed light hydrocarbons, then you may use a representative composition from the source for the stream determined by engineering calculation based on process knowledge and best available data. (3) Determine flare combustion efficiency from manufacturer. If not available, assume that flare combustion efficiency is 98 percent. (4) Convert GHG volumetric emissions to standard conditions using calculations in paragraph (t) of this section. (5) Calculate GHG volumetric emissions from flaring at standard conditions using Equations W–19 and W–20 of this section. Where: Es,CH4 = Annual CH4 emissions from flare stack in cubic feet, at standard conditions. Es,CO2 = Annual CO2 emissions from flare stack in cubic feet, at standard conditions. Vs = Volume of gas sent to flare in standard cubic feet, during the year as determined in paragraph (n)(1) of this section. h = Flare combustion efficiency, expressed as fraction of gas combusted by a burning flare (default is 0.98). XCH4 = Mole fraction of CH4 in the feed gas to the flare as determined in paragraph (n)(2) of this section. XCO2 = Mole fraction of CO2 in the feed gas to the flare as determined in paragraph (n)(2) of this section. ZU = Fraction of the feed gas sent to an unlit flare determined by engineering estimate and process knowledge based on best available data and operating records. ZL = Fraction of the feed gas sent to a burning flare (equal to 1- ZU). Yj = Mole fraction of hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus) in the feed gas to the flare as determined in paragraph (n)(1) of this section. Rj = Number of carbon atoms in the hydrocarbon constituent j in the feed gas to the flare: 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus). (7) Calculate N2O emissions from flare stacks using Equation W–40 in paragraph (z) of this section. (8) If you operate and maintain a CEMS that has both a CO2 concentration monitor and volumetric flow rate monitor for the combustion gases from the flare, you must calculate only CO2 emissions for the flare. You must follow the Tier 4 Calculation Method and all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources). If a CEMS is used to calculate flare stack emissions, the requirements specified in paragraphs (n)(1) through (n)(7) are not required. (9) The flare emissions determined under paragraph (n) of this section must be corrected for flare emissions calculated and reported under other paragraphs of this section to avoid double counting of these emissions. (o) Centrifugal compressor venting. If you are required to report emissions from centrifugal compressor venting as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (o)(5) of this section; perform calculations specified in paragraphs (o)(6) through (o)(9) of this section; and calculate CH4 and CO2 mass emissions as specified in paragraph (o)(11) of this section. If emissions from a compressor source are routed to a flare, paragraphs (o)(1) through (o)(11) of this section do not apply and instead you must calculate CH4, CO2, and N2O emissions as specified in paragraph (o)(12) of this section. If emissions from a compressor source are captured for fuel use or are routed to a thermal oxidizer, paragraphs (o)(1) through (o)(12) of this section do not apply and instead you must calculate and report emissions as specified in subpart C of this part. If emissions from a compressor source are routed to vapor recovery, the calculations specified in paragraphs (o)(1) through (o)(12) of this section do not apply. If you are required to report emissions from centrifugal compressor venting at an onshore petroleum and natural gas production facility as specified in § 98.232(c)(19), you must calculate volumetric emissions as specified in paragraph (o)(10) of this section; and calculate CH4 and CO2 mass emissions as specified in paragraph (o)(11) of this section. (1) General requirements for conducting volumetric emission measurements. You must conduct volumetric emission measurements on each centrifugal compressor as specified in this paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a (6) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculation in paragraph (v) of this section. VerDate Mar<15>2010 19:36 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00043 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.023</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 must use the measured flow volumes to calculate the flare gas emissions. If all of the flare gas is not measured by the existing flow measurement device, then the flow not measured can be estimated using engineering calculations based on best available data or company records. If you do not have a continuous flow measurement device on the flare, you can use engineering calculations based on process knowledge, company records, and best available data. (2) If you have a continuous gas composition analyzer on gas to the flare, you must use these compositions in calculating emissions. If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as specified in paragraphs (n)(2)(i) through (n)(2)(iii) of this section. emcdonald on DSK67QTVN1PROD with PROPOSALS2 13436 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules measurement method specified in paragraph (o)(1)(i) or (o)(1)(ii) of this section. Manifolded compressor sources (as defined in § 98.238) must use a measurement method specified in paragraph (o)(1)(i), (o)(1)(ii), (o)(1)(iii), or (o)(1)(iv) of this section. (i) Centrifugal compressor source as found leak measurements. Measure venting from each compressor according to either paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraphs (o)(1)(i)(C) and (o)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section. (A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (o)(2)(i)(A) or (o)(2)(i)(B) of this section and, if the compressor has wet seal oil degassing vents, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section. If a compressor has a continuously operating vapor recovery system for the wet seal degassing, then measurement of wet seal degassing is not required. (B) For a compressor measured in notoperating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (o)(2)(i)(A), (o)(2)(i)(B), or (o)(2)(i)(C) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode. (C) You must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If three consecutive calendar years occur without measuring the compressor in not-operating-depressurized-mode, you must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at the next scheduled depressurized shutdown. The requirement specified in this paragraph does not apply if the compressor has blind flanges in place throughout the reporting year. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 (D) You must measure the compressor as specified in paragraph (o)(1)(i)(A) of this section at least once in any three consecutive calendar years, provided that the measurement can be taken when the compressor is in operatingmode. If three consecutive calendar years occur without measuring the compressor in operating-mode, you must measure the compressor as specified in paragraph (o)(1)(i)(A) of this section in the next calendar year that the compressor is in operating-mode for more than 2,000 hours. (ii) Centrifugal compressor source continuous monitoring. Instead of measuring the compressor source according to paragraph (o)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissions from a compressor source as specified in paragraph (o)(3) of this section. (iii) Manifolded centrifugal compressor source as found leak measurements. For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (o)(1)(i), (o)(1)(ii), or (o)(1)(iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting leak measurements at the common vent stack as specified in paragraph (o)(4) of this section. The leak measurements must be conducted at the frequency specified in paragraphs (o)(1)(iii)(A) through (o)(1)(iii)(C) of this section. (A) A minimum of three leak measurements must be taken for each manifolded group of compressor sources in a calendar year. (B) The leak measurements may be performed while the compressors are in any compressor mode. (C) The three required leak measurements must be separated by a minimum of 60 days. If more than two leak measurements are performed, the first and last measurements in a calendar year must be separated by a minimum of 120 days. (iv) Manifolded centrifugal compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (o)(1)(i), (o)(1)(ii), or (o)(1)(iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressor sources as specified in paragraph (o)(5) of this section. PO 00000 Frm 00044 Fmt 4701 Sfmt 4702 (2) Methods for performing as found leak measurements from individual centrifugal compressor sources. If conducting leak measurements for each compressor source, you must determine the volumetric emissions of leaks from blowdown valves and isolation valves as specified in paragraph (o)(2)(i) of this section, and the volumetric emissions of leaks from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section. (i) For blowdown valves on compressors in operating-mode and for isolation valves on compressors in notoperating-depressurized-mode, determine the volumetric emissions of leaks using one of the methods specified in paragraphs (o)(2)(i)(A) through (o)(2)(i)(C) of this section. (A) Measure the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. (B) Measure the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer according to methods set forth in § 98.234(b). (C) For isolation valves, you may use an acoustic leak detection device according to methods set forth in § 98.234(a) instead of measuring the isolation valve leakage through the blowdown vent as provided for in paragraphs (o)(2)(i)(A) or (o)(2)(i)(B) of this section. (ii) For wet seal oil degassing vents in operating-mode, determine vapor volumes at standard conditions, using a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b). (3) Methods for continuous leak measurement from individual centrifugal compressor sources. If you elect to conduct continuous volumetric emission measurements for an individual compressor source as specified in paragraph (o)(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (o)(3)(i) and (o)(3)(ii) of this section. (i) Continuously measure the volumetric flow for the individual compressor source at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13437 for a given mode-source combination m, use the average of all measurements. Tm = Total time the compressor is in the mode-source combination for which Es,i,m is being calculated in the reporting year, in hours. GHGi,m = Mole fraction of GHGi in the vent gas for measured compressor modesource combination m; use the appropriate gas compositions in paragraph (u)(2) of this section. m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section that was measured for the reporting year. (ii) Using Equation W–22 of this section, calculate the annual volumetric GHG emissions from each centrifugal compressor mode-source combination specified in paragraph (o)(1)(i)(A) and (o)(1)(i)(B) of this section that was not measured during the reporting year. Where: Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for unmeasured compressor mode-source combination m, at standard conditions, in cubic feet. EFm,s = Reporter emission factor for compressor mode-source combination m, in standard cubic feet per hour, as calculated in paragraph (o)(6)(iii) of this section. Tm = Total time the compressor was in the unmeasured mode-source combination m, for which Es,i,m is being calculated in the reporting year, in hours. GHGi,m = Mole fraction of GHGi in the vent gas for unmeasured compressor modesource combination m; use the appropriate gas compositions in paragraph (u)(2) of this section. m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section that was not measured in the reporting year. (iii) Using Equation W–23 of this section, develop an emission factor for each compressor mode-source combination specified in paragraph (o)(1)(i)(A) and (o)(1)(i)(B) of this section. These emission factors must be used in Equation W–22 of this section to determine volumetric emissions from a centrifugal compressor in the modesource combinations that were not measured in the reporting year. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00045 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.025</GPH> EP10MR14.026</GPH> (o)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG emissions from as found leak measurements for individual centrifugal compressor sources. For compressor sources measured according to paragraph (o)(1)(i) of this section, you must calculate annual GHG emissions from the compressor sources as specified in paragraphs (o)(6)(i) through (o)(6)(iv) of this section. (i) Using Equation W–21 of this section, calculate the annual volumetric GHG emissions for each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) and (o)(1)(i)(B) of this section that was measured during the reporting year. EP10MR14.024</GPH> (C) A high volume sampler according to methods set forth § 98.234(d). (5) Methods for continuous leak measurement from manifolded groups of centrifugal compressor sources. If you elect to conduct continuous volumetric emission measurements for a manifolded group of compressor sources as specified in paragraph (o)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (o)(5)(i) through (o)(5)(iii) of this section. (i) Measure at a single point in the manifold downstream of all compressor inputs and where emissions cannot be comingled with other non-compressor emission sources. (ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph Where: Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for measured compressor mode-source combination m, at standard conditions, in cubic feet. MTs,m = Volumetric gas emissions for measured compressor mode-source combination m, in standard cubic feet per hour, measured according to paragraph (o)(2) of this section. If multiple measurements are performed emcdonald on DSK67QTVN1PROD with PROPOSALS2 be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (4) Methods for performing as found leak measurements from manifolded groups of centrifugal compressor sources. If conducting leak measurements for a manifolded group of compressor sources, you must measure volumetric emissions of leaks as specified in paragraphs (o)(4)(i) and (o)(4)(ii) of this section. (i) Measure at a single point in the manifold downstream of all compressor inputs and where emissions cannot be comingled with other non-compressor emission sources. (ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraphs (o)(4)(ii)(A) through (o)(4)(ii)(C) of this section. (A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b). (B) Calibrated bagging according to methods set forth in § 98.234(c). Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules Where: Es,i,v = Annual volumetric GHGi (either CH4 or CO2) emissions from compressor source v, at standard conditions, in cubic feet. Qs,v = Volumetric gas emissions from compressor source v, for reporting year, in standard cubic feet. GHGi,v = Mole fraction of GHGi in the vent gas for compressor source v; use the appropriate gas compositions in paragraph (u)(2) of this section. emcdonald on DSK67QTVN1PROD with PROPOSALS2 Where: Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions for manifolded group of compressor sources g, at standard conditions, in cubic feet. MTg,avg = Average volumetric gas emissions of all measurements performed in the reporting year according to paragraph (o)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet per hour. GHGi,g = Mole fraction of GHGi in the vent gas for manifolded group of compressor sources g; use the appropriate gas Where: Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions from manifolded group of compressor sources g, at standard conditions, in cubic feet. Qs,g = Volumetric gas emissions from manifolded group of compressor sources g, for reporting year, in standard cubic feet. (iv) The reporter emission factor in Equation W–23 of this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this (8) Method for calculating volumetric GHG emissions from as found leak measurements of manifolded groups of compositions in paragraph (u)(2) of this section. (9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of centrifugal compressor sources. For a manifolded group of compressor sources measured according to paragraph (o)(1)(iv) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (o)(5) of this section and calculate annual volumetric GHG GHGi,g = Mole fraction of GHGi in the vent gas for measured manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section. (10) Method for calculating volumetric GHG emissions from wet seal oil degassing vents at an onshore Where: Es,i = Annual volumetric GHGi (either CH4 or CO2) emissions from centrifugal VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 compressor wet seals, at standard conditions, in cubic feet. Frm 00046 Fmt 4701 Sfmt 4702 option, the reporter emission factor must be applied to all reporting facilities for the owner or operator. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual centrifugal compressor sources. For compressor sources measured according to paragraph (o)(1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (o)(3) of this section and calculate annual volumetric GHG emissions associated with the compressor source using Equation W– 24A of this section. centrifugal compressor sources. For manifolded groups of compressor sources measured according to paragraph (o)(1)(iii) of this section, you must calculate annual volumetric GHG emissions using Equation W–24B of this section. emissions associated with each manifolded group of compressor sources using Equation W–24C of this section. If the centrifugal compressors included in the manifolded group of compressor sources share the manifold with reciprocating compressors, you must follow the procedures in either this paragraph (o)(9) or paragraph (p)(9) of this section to calculate emissions from the manifolded group of compressor sources. petroleum and natural gas production facility. You must calculate emissions from centrifugal compressor wet seal oil degassing vents at an onshore petroleum and natural gas production facility using Equation W–25 of this section. Count = Total number of centrifugal compressors that have wet seal oil degassing vents. E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.030</GPH> for compressor p in the current reporting year and the preceding two reporting years. Countm = Total number of compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years. m = Compressor mode-source combination specified in paragraph (o)(1)(i)(A) or (o)(1)(i)(B) of this section. EP10MR14.028</GPH> EP10MR14.029</GPH> Where: EFm,s = Reporter emission factor to be used in Equation W–22 of this section for compressor mode-source combination m, in standard cubic feet per hour. The reporter emission factor must be based on all compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years. MTm,p,s = Average volumetric gas emission measurement for compressor modesource combination m, for compressor p, in standard cubic feet per hour, calculated using all volumetric gas emission measurements (MTm in Equation W–21 of this section) for compressor mode-source combination m EP10MR14.027</GPH> 13438 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 EFi,s = Emission factor for GHGi. Use 1.2 × 107 standard cubic feet per year per compressor for CH4 and 5.30 × 105 standard cubic feet per year per compressor for CO2 at 60 °F and 14.7 psia. (11) Method for converting from volumetric to mass emissions. You must calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (12) General requirements for calculating volumetric GHG emissions from centrifugal compressors routed to flares. You must calculate and report emissions from all centrifugal compressor sources that are routed to a flare as specified in paragraphs (o)(12)(i) through (o)(12)(iii) of this section. (i) Emissions calculations under this paragraph (o) of this section are not required for compressor sources that are routed to a flare. (ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attributable to compressor sources from the flare. (iii) Report all applicable activity data for compressors with compressor sources routed to flares as specified in § 98.236(o). (p) Reciprocating compressor venting. If you are required to report emissions from reciprocating compressor venting as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (p)(5) of this section; perform calculations specified in paragraphs (p)(6) through (p)(9) of this section; and calculate CH4 and CO2 mass emissions as specified in paragraph (p)(11) of this section. If emissions from a compressor source are routed to a flare, paragraphs (p)(1) through (p)(11) of this section do not apply and instead you must calculate CH4, CO2, and N2O emissions as specified in paragraph (p)(12) of this section. If emissions from a compressor source are captured for fuel use or are routed to a thermal oxidizer, paragraphs (p)(1) through (p)(12) of this section do not apply and instead you must calculate and report emissions as specified in subpart C of this part. If emissions from a compressor source are routed to vapor recovery, the calculations specified in paragraphs (p)(1) through (p)(12) of this section do not apply. If you are required to report emissions from reciprocating VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 compressor venting at an onshore petroleum and natural gas production facility as specified in § 98.232(c)(11), you must calculate volumetric emissions as specified in paragraph (p)(10) of this section; and calculate CH4 and CO2 mass emissions as specified in paragraph (p)(11) of this section. (1) General requirements for conducting volumetric emission measurements. You must conduct volumetric emission measurements on each reciprocating compressor as specified in this paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a measurement method specified in paragraph (p)(1)(i) or (p)(1)(ii) of this section. Manifolded compressor sources (as defined in § 98.238) must use a measurement method specified in paragraph (p)(1)(i), (p)(1)(ii), (p)(1)(iii), or (p)(1)(iv) of this section. (i) Reciprocating compressor source as found leak measurements. Measure venting from each compressor according to either paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraph (p)(1)(i)(D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section. (A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) of this section. (B) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of this section. (C) For a compressor measured in notoperating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (p)(2)(i)(A), (p)(2)(i)(B), or (p)(2)(i)(C) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode. PO 00000 Frm 00047 Fmt 4701 Sfmt 4702 13439 (D) You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section either prior to or during the next compressor shutdown when the replacement of the compressor rod packing occurs. (ii) Reciprocating compressor source continuous monitoring. Instead of measuring the compressor source according to paragraph (p)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissions from a compressor source as specified in paragraph (p)(3) of this section. (iii) Manifolded reciprocating compressor source as found leak measurements. For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (p)(1)(i), (p)(1)(ii), or (p)(1)(iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting leak measurements at the common vent stack as specified in paragraph (p)(4) of this section. The leak measurements must be conducted at the frequency specified in paragraphs (p)(1)(iii)(A) through (p)(1)(iii)(C) of this section. (A) A minimum of three leak measurements must be taken for each manifolded group of compressor sources in a calendar year. (B) The leak measurements may be performed while the compressors are in any compressor mode. (C) The three required leak measurements must be separated by a minimum of 60 days. If more than three leak measurements are performed, the first and last measurements in a calendar year must be separated by a minimum of 120 days. (iv) Manifolded reciprocating compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (p)(1)(i), (p)(1)(ii), or (p)(1)(iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressors sources as specified in paragraph (p)(5) of this section. E:\FR\FM\10MRP2.SGM 10MRP2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (2) Methods for performing as found leak measurements from individual reciprocating compressor sources. If conducting leak measurements for each compressor source, you must determine the volumetric emissions of leaks from blowdown valves and isolation valves as specified in paragraph (p)(2)(i) of this section. You must determine the volumetric emissions of leaks from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (p)(2)(iii) of this section. (i) For blowdown valves on compressors in operating-mode or standby-pressurized-mode, and for isolation valves on compressors in notoperating-depressurized-mode, determine the volumetric emissions of leaks using one of the methods specified in paragraphs (p)(2)(i)(A) through (p)(2)(i)(C) of this section. (A) Measure the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. (B) Measure the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b). (C) For isolation valves, you may use an acoustic leak detection device according to methods set forth in § 98.234(a) instead of measuring the isolation valve leakage through the blowdown vent as provided for in paragraphs (p)(2)(i)(A) or (p)(2)(i)(B) of this section. (ii) For reciprocating rod packing equipped with an open-ended vent line on compressors in operating-mode, determine the volumetric emissions of leaks using one of the methods specified in paragraphs (p)(2)(ii)(A) and (p)(2)(ii)(B) of this section. (A) Measure the volumetric flow at standard conditions from the openended vent line using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively. (B) Measure the volumetric flow at standard conditions from the openended vent line using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b). (iii) For reciprocating rod packing not equipped with an open-ended vent line on compressors in operating-mode, you must determine the volumetric emissions of leaks using the method specified in paragraphs (p)(2)(iii)(A) and (p)(2)(iii)(B) of this section. (A) You must use the methods described in § 98.234(a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or from the compressor crank case breather cap or other vent with a closed distance piece. (B) You must measure emissions found in paragraph (p)(2)(iii)(A) of this section using an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in § 98.234(b), (c), and (d), respectively. (3) Methods for continuous leak measurement from individual reciprocating compressor sources. If you elect to conduct continuous volumetric emission measurements for an individual compressor source as specified in paragraph (p)(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (p)(3)(i) and (p)(3)(ii) of this section. (i) Continuously measure the volumetric flow for the individual compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (4) Methods for performing as found leak measurements from manifolded groups of reciprocating compressor sources. If conducting leak measurements for a manifolded group of compressor sources, you must measure volumetric emissions of leaks as specified in paragraphs (p)(4)(i) and (p)(4)(ii) of this section. (i) Measure at a single point in the manifold downstream of all compressor inputs and where emissions cannot be comingled with other non-compressor emission sources. (ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified Where: Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for measured VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 compressor mode-source combination m, at standard conditions, in cubic feet. Frm 00048 Fmt 4701 Sfmt 4702 in paragraph (p)(4)(ii)(A) through (p)(4)(ii)(C). (A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b). (B) Calibrated bagging according to methods set forth in § 98.234(c). (C) A high volume sampler according to methods set forth § 98.234(d). (5) Methods for continuous leak measurement from manifolded groups of reciprocating compressor sources. If you elect to conduct continuous volumetric emission measurements for a manifolded group of compressor sources as specified in paragraph (p)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (p)(5)(i) through (p)(5)(iii) of this section. (i) Measure at a single point in the manifold downstream of all compressor inputs and where emissions cannot be comingled with other non-compressor emission sources. (ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b). (iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks. (6) Method for calculating volumetric GHG emissions from as found leak measurements for individual reciprocating compressor sources. For compressor sources measured according to paragraph (p)(1)(i) of this section, you must calculate GHG emissions from the compressor sources as specified in paragraphs (p)(6)(i) through (p)(6)(iv) of this section. (i) Using Equation W–26 of this section, calculate the annual volumetric GHG emissions for each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (p)(1)(i)(C) of this section that was measured during the reporting year. MTs,m = Volumetric gas emissions for measured compressor mode-source combination m, in standard cubic feet E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.031</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 13440 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13441 m, for which Es,i,m is being calculated in the reporting year, in hours. GHGi,m = Mole fraction of GHGi in the vent gas for unmeasured compressor modesource combination m; use the appropriate gas compositions in paragraph (u)(2) of this section. m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was not measured in the reporting year. (iii) Using Equation W–28 of this section, develop an emission factor for each compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section. These emission factors must be used in Equation W–27 of this section to determine volumetric emissions from a reciprocating compressor in the mode-source combinations that were not measured in the reporting year. Where: EFm,s = Reporter emission factor to be used in Equation W–27 of this section for compressor mode-source combination m, in standard cubic feet per hour. The reporter emission factor must be based on all compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years. MTm,p,s = Average volumetric gas emission measurement for compressor modesource combination m, for compressor p, in standard cubic feet per hour, calculated using all volumetric gas emission measurements (MTm in Equation W–26 of this section) for compressor mode-source combination m for compressor p in the current reporting year and the preceding two reporting years. Countm = Total number of compressors measured in compressor mode-source combination m in the current reporting year and the preceding two reporting years. m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section. from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator. (7) Method for calculating volumetric GHG emissions from continuous monitoring of individual reciprocating compressor sources. For compressor sources measured according to paragraph (p)(1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (p)(3) of this section and calculate annual volumetric GHG emissions associated with the compressor source using Equation W– 29A of this section. Where: Es,i,v = Annual volumetric GHGi (either CH4 or CO2) emissions from compressor source v, at standard conditions, in cubic feet. Qs,v = Volumetric gas emissions from compressor source v, for reporting year, in standard cubic feet. GHGi,v = Mole fraction of GHGi in the vent gas for compressor source v; use the appropriate gas compositions in paragraph (u)(2) of this section. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 (A) Emission factors must be calculated annually for each compressor mode-source combination specified in paragraph ((p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section. (B) You must combine emissions for blowndown vents, measured in the operating and standby-pressurized modes. (iv) The reporter emission factor in Equation W–28 of this section may be calculated by using all measurements (8) Method for calculating volumetric GHG emissions from as found leak measurements of manifolded groups of PO 00000 Frm 00049 Fmt 4701 Sfmt 4702 reciprocating compressor sources. For manifolded groups of compressor sources measured according to paragraph (p)(1)(iii) of this section, you must calculate annual GHG emissions using Equation W–29B of this section. E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.033</GPH> EP10MR14.034</GPH> (ii) Using Equation W–27 of this section, calculate the annual volumetric GHG emissions from each reciprocating compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section that was not measured during the reporting year. EP10MR14.032</GPH> GHGi,m = Mole fraction of GHGi in the vent gas for measured compressor modesource combination m; use the appropriate gas compositions in paragraph (u)(2) of this section. m = Compressor mode-source combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was measured for the reporting year. Where: Es,i,m = Annual volumetric GHGi (either CH4 or CO2) emissions for unmeasured compressor mode-source combination m, at standard conditions, in cubic feet. EFm,s = Reporter emission factor for compressor mode-source combination m, in standard cubic feet per hour, as calculated in paragraph (p)(6)(iii) of this section. Tm = Total time the compressor was in the unmeasured mode-source combination emcdonald on DSK67QTVN1PROD with PROPOSALS2 per hour, measured according to paragraph (p)(2) of this section. If multiple measurements are performed for a given mode-source combination m, use the average of all measurements. Tm = Total time the compressor is in the mode-source combination m, for which Es,i,m is being calculated in the reporting year, in hours. Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 Where: Es,i = Annual volumetric GHGi (either CH4 or CO2) emissions from reciprocating compressors, at standard conditions, in cubic feet. Count = Total number of reciprocating compressors. EFi,s = Emission factor for GHGi. Use 9.48 × 103 standard cubic feet per year per compressor for CH4 and 5.27 × 102 standard cubic feet per year per compressor for CO2 at 60 °F and 14.7 psia. (11) Method for converting from volumetric to mass emissions. You must calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (12) General requirements for calculating volumetric GHG emissions from reciprocating compressors routed to flares. You must calculate and report emissions from all reciprocating compressor sources that are routed to a Where: VerDate Mar<15>2010 (9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of reciprocating compressor sources. For a manifolded group of compressor sources measured according to paragraph (p)(1)(iv) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (p)(5) of this section and calculate annual volumetric GHG GHGi,g = Mole fraction of GHGi in the vent gas for measured manifolded group of compressor sources g; use the appropriate gas compositions in paragraph (u)(2) of this section. (10) Method for calculating volumetric GHG emissions from reciprocating compressor venting at an flare as specified in paragraphs (p)(12)(i) through (p)(12)(iii) of this section. (i) Emissions calculations under this paragraph (p) of this section are not required for compressor sources that are routed to a flare. (ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attributable to compressor sources from the flare. (iii) Report all applicable activity data for compressors with compressor sources routed to flares as specified in § 98.236(p). (q) Equipment leak surveys. You must use the methods described in § 98.234(a) to conduct leak detection(s) of equipment leaks from all component types listed in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1). This paragraph (q) applies to component Es,p,i = Annual total volumetric emissions of GHGi from specific component type ‘‘p’’ 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00050 Fmt 4701 Sfmt 4702 emissions associated with each manifolded group of compressor sources using Equation W–29C of this section. If the reciprocating compressors included in the manifolded group of compressor sources share the manifold with centrifugal compressors, you must follow the procedures in either this paragraph (p)(9) or paragraph (o)(9) of this section to calculate emissions from the manifolded group of compressor sources. onshore petroleum and natural gas production facility. You must calculate emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility using Equation W–29D of this section. types in streams with gas content greater than 10 percent CH4 plus CO2 by weight. Component types in streams with gas content less than or equal to 10 percent CH4 plus CO2 by weight are exempt from the requirements of this paragraph (q) and do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of this paragraph (q) and do not need to be reported. For industry segments listed in § 98.230(a)(3) through (a)(8), if equipment leaks are detected for component types listed in this paragraph (q), then you must calculate equipment leak emissions per component type per reporting facility using Equations W–30 of this section. For the industry segment listed in § 98.230(a)(8), the results from Equation W–30 are used to calculate population emission factors on a meter/regulator run basis using Equation W–31 of this section. (listed in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1)) in standard (‘‘s’’) E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.038</GPH> Where: Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions from manifolded group of compressor sources g, at standard conditions, in cubic feet. Qs,g = Volumetric gas emissions from manifolded group of compressor sources g, for reporting year, in standard cubic feet. compositions in paragraph (u)(2) of this section. EP10MR14.036</GPH> EP10MR14.037</GPH> Where: Es,i,g = Annual volumetric GHGi (either CH4 or CO2) emissions for manifolded group of compressor sources g, at standard conditions, in cubic feet. MTg,avg = Average volumetric gas emissions of all measurements performed in the reporting year according to paragraph (p)(4) of this section for the manifolded group of compressor sources g, in standard cubic feet per hour. GHGi,g = Mole fraction of GHGi in the vent gas for manifolded group of compressor sources g; use the appropriate gas EP10MR14.035</GPH> 13442 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules cubic feet, as specified in paragraphs (q)(1) through (q)(8) of this section. xp = Total number of specific component type ‘‘p’’ detected as leaking during annual leak surveys. EFs,p = Leaker emission factor for specific component types listed in Table W–2 through Table W–7 of this subpart. GHGi = For onshore natural gas processing facilities, concentration of GHGi, CH4 or CO2, in the total hydrocarbon of the feed natural gas; for onshore natural gas transmission compression and underground natural gas storage, GHGi equals 0.975 for CH4 and 1.1 × 10¥2 for CO2 ; for LNG storage and LNG import and export equipment, GHGi equals 1 for CH4 and 0 for CO2 ; and for natural gas distribution, GHGi equals 1 for CH4 and 1.1 × 10¥2 CO2. Tp,z = The total time the surveyed component ‘‘z’’, component type ‘‘p’’, was found leaking and operational, in hours. If one leak detection survey is conducted in the calendar year, assume the component was leaking for the entire calendar year, accounting for time the component was not operational (i.e. not operating under pressure) using engineering estimate based on best available data. If multiple leak detection surveys are conducted in the calendar year, assume that the component found to be leaking has been leaking since the previous survey (if not found leaking in the previous survey) or the beginning of the calendar year (if it was found leaking in the previous survey), accounting for time the component was not operational using engineering estimate based on best available data. For the last leak detection survey in the calendar year, assume that all leaking components continue to leak until the end of the calendar year, accounting for time the component was not operational using engineering estimate based on best available data. 13443 surveys conducted at above grade transmission-distribution transfer stations. Natural gas distribution facilities are required to perform equipment leak surveys only at above grade stations that qualify as transmission-distribution transfer stations. Below grade transmissiondistribution transfer stations and all metering-regulating stations that do not meet the definition of transmissiondistribution transfer stations are not required to perform equipment leak surveys under this section. (i) Natural gas distribution facilities may choose to conduct equipment leak surveys at all above grade transmissiondistribution transfer stations over multiple years, not exceeding a five year period to cover all above grade transmission-distribution transfer stations. If the facility chooses to use the multiple year option, then the number of transmission-distribution transfer stations that are monitored in each year should be approximately equal across all years in the cycle. (ii) Use Equation W–31 to determine the meter/regulator run population emission factors for each GHGi. The meter/regulator run population emission factors calculated using Equation W–31 must be used in Equation W–32B of this section to estimate emissions from above grade metering-regulating stations that are not transmission-distribution transfer stations. As additional survey data become available, you must recalculate the meter/regulator run population emission factors for each GHGi annually according to paragraph (q)(8)(iii) of this section. Where: EFs,MR,i = Meter/regulator run population emission factor for GHGi based on all surveyed above grade transmissiondistribution transfer stations over ‘‘n’’ years, in standard cubic feet of GHGi per operational hour of all meter/regulator runs. Es,p,i,y = Annual total volumetric emissions at standard conditions of GHGi from component type ‘‘p’’ during year ‘‘y’’ in standard (‘‘s’’) cubic feet, as calculated using Equation W–30 of this section. p = Seven component types listed in Table W–7 of this subpart for transmissiondistribution transfer stations. Tw,y = The total time the surveyed meter/ regulator run ‘‘w’’ was operational, in hours during survey year ‘‘y’’ using engineering estimate based on best available data. CountMR,y = Count of meter/regulator runs surveyed at above grade transmissiondistribution transfer stations in year ‘‘y’’. y = Year of data included in emission factor ‘‘EFs,MR,i’’ according to paragraph (q)(8)(iii) of this section. n = Number of years of data used to calculate emission factor ‘‘EFs,MR,i’’ according to paragraph (q)(8)(iii) of this section. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 PO 00000 Frm 00051 Fmt 4701 Sfmt 4702 (iii) The emission factor ‘‘EFs,MR,i’’, based on annual equipment leak surveys at above grade transmission-distribution transfer stations, must be calculated annually. If the facility has submitted a smaller number of annual reports than the duration of the selected cycle period (up to 5 years), then all available data from the current year and previous years must be used in the emission E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.039</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 (1) You must conduct either one leak detection survey in a calendar year or multiple complete leak detection surveys in a calendar year. The leak detection surveys selected must be conducted during the calendar year. (2) Calculate both CO2 and CH4 mass emissions using calculations in paragraph (v) of this section. (3) Onshore natural gas processing facilities must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and noncompressor components in gas service listed in Table W–2 of this subpart. (4) Onshore natural gas transmission compression facilities must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and noncompressor components in gas service listed in Table W–3 of this subpart. (5) Underground natural gas storage facilities must use the appropriate default total hydrocarbon leaker emission factors for storage stations in gas service listed in Table W–4 of this subpart. (6) LNG storage facilities must use the appropriate default methane leaker emission factors for LNG storage components in gas service listed in Table W–5 of this subpart. (7) LNG import and export facilities must use the appropriate default methane leaker emission factors for LNG terminals components in LNG service listed in Table W–6 of this subpart. (8) Natural gas distribution facilities must use Equation W–30 of this section and the default methane leaker emission factors for transmission-distribution transfer station components in gas service listed in Table W–7 of this subpart to calculate component emissions from annual equipment leak 13444 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules gas content greater than 10 percent CH4 plus CO2 by weight. Emissions sources in streams with gas content less than or equal to 10 percent CH4 plus CO2 by weight are exempt from the requirements of this paragraph (q) do not need to be reported. Tubing systems equal to or less than one half inch diameter are exempt from the requirements of paragraph (r) of this section and do not need to be reported. You must calculate emissions from all emission sources listed in this paragraph using Equation W–32A of this section, except for natural gas distribution facility emission sources listed in § 98.232(i)(3). Natural gas distribution facility emission sources listed in § 98.232(i)(3) must calculate emissions using Equation W–32B and according to paragraph (r)(6) of this section. Where: Es,e,i = Annual volumetric emissions of GHGi from the emission source type in standard cubic feet. The emission source type may be a component (e.g. connector, open-ended line, etc.), below grade metering-regulating station, below grade transmission-distribution transfer station, distribution main, or distribution service. Es,MR,i = Annual volumetric emissions of GHGi from all meter/regulator runs at above grade metering regulating stations that are not above grade transmission distribution transfer stations, in standard cubic feet. Counte = Total number of the emission source type at the facility. For onshore petroleum and natural gas production facilities, average component counts are provided by major equipment piece in Tables W–1B and Table W–1C of this subpart. Use average component counts as appropriate for operations in Eastern and Western U.S., according to Table W– 1D of this subpart. Underground natural gas storage facilities must count each component listed in Table W–4 of this subpart. LNG storage facilities must count the number of vapor recovery compressors. LNG import and export facilities must count the number of vapor recovery compressors. Natural gas distribution facilities must count: (1) The number of distribution services by material type; (2) miles of distribution mains by material type; and (3) number of below grade metering-regulating stations, by pressure type; as listed in Table W–7 of this subpart. CountMR = Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations. EFs,e = Population emission factor for the specific emission source type, as listed in Tables W–1A and W–4 through W–7 of this subpart. Use appropriate population emission factor for operations in Eastern and Western U.S., according to Table W–1D of this subpart. EFs,MR,i = Meter/regulator run population emission factor for GHGi based on all surveyed above grade transmission- distribution transfer stations over ‘‘n’’ years, in standard cubic feet of GHGi per operational hour of all meter/regulator runs., as determined in Equation W–31. GHGi = For onshore petroleum and natural gas production facilities, concentration of GHGi, CH4, or CO2, in produced natural gas as defined in paragraph (u)(2) of this section; for onshore natural gas transmission compression and underground natural gas storage, GHGi equals 0.975 for CH4 and 1.1 × 10¥2 for CO2; for LNG storage and LNG import and export equipment, GHGi equals 1 for CH4 and 0 for CO2; and for natural gas distribution, GHGi equals 1 for CH4 and 1.1 × 10¥2CO2. Te = Average estimated time that each emission source type associated with the equipment leak emission was operational in the calendar year, in hours, using engineering estimate based on best available data. Tw,avg = Average estimated time that each meter/regulator run was operational in the calendar year, in hours per meter/ regulator run, using engineering estimate based on best available data. streams of gases, including recycle CO2 stream. The component count can be determined using either of the calculation methods described in this paragraph (r)(2). The same calculation method must be used for the entire calendar year. (i) Component Count Method 1. For all onshore petroleum and natural gas production operations in the facility perform the following activities: (A) Count all major equipment listed in Table W–1B and Table W–1C of this subpart. For meters/piping, use one meters/piping per well-pad. (B) Multiply major equipment counts by the average component counts listed in Table W–1B and W–1C of this subpart for onshore natural gas production and onshore oil production, respectively. Use the appropriate factor in Table W–1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W– 1D of this subpart. (ii) Component Count Method 2. Count each component individually for the facility. Use the appropriate factor in Table W–1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W– 1D of this subpart. (3) Underground natural gas storage facilities must use the appropriate default total hydrocarbon population emission factors for storage wellheads in gas service listed in Table W–4 of this subpart. (4) LNG storage facilities must use the appropriate default methane population emission factor for LNG storage compressors in gas service listed in Table W–5 of this subpart. (5) LNG import and export facilities must use the appropriate default methane population emission factor for LNG terminal compressors in gas service listed in Table W–6 of this subpart. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 (1) Calculate both CH4 and CO2 mass emissions from volumetric emissions using calculations in paragraph (v) of this section. (2) Onshore petroleum and natural gas production facilities must use the appropriate default whole gas population emission factors listed in Table W–1A of this subpart. Major equipment and components associated with gas wells are considered gas service components in reference to Table W–1A of this subpart and major natural gas equipment in reference to Table W–1B of this subpart. Major equipment and components associated with crude oil wells are considered crude service components in reference to Table W–1A of this subpart and major crude oil equipment in reference to Table W–1C of this subpart. Where facilities conduct EOR operations the emissions factor listed in Table W–1A of this subpart shall be used to estimate all PO 00000 Frm 00052 Fmt 4701 Sfmt 4702 E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.040</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 calculation. After the first cycle is completed, the survey will continue on a rolling basis by including the measurements from the current calendar year and as many of the previous calendar years as are needed to complete the survey cycle. (r) Equipment leaks by population count. This paragraph applies to emissions sources listed in § 98.232 (c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams with Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules * * * 1 if the temperature is above -10 degrees Fahrenheit and pressure is below 5 atmospheres, or if the compressibility * Za = Compressibility factor at actual conditions for natural gas. You may use * * * * * Za = Compressibility factor at actual conditions for GHG i. You may use 1 if the compressibility factor at the actual temperature and pressure is 0.98 or greater. emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * (u) GHG volumetric emissions at standard conditions. Calculate GHG volumetric emissions at standard conditions as specified in paragraphs (u)(1) and (2) of this section. (2) * * * (iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for the onshore natural gas transmission compression industry segment. You may use either a default 95 percent methane VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data. * * * * * (v) GHG mole fraction in natural gas stored in the LNG storage industry segment. You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data. (vi) GHG mole fraction in natural gas stored in the LNG import and export industry segment. For export facilities that receive gas from transmission pipelines, you may use either a default 95 percent methane and 1 percent PO 00000 Frm 00053 Fmt 4701 Sfmt 4725 required in paragraph (s)(1)(i) of this section. (4) For either first or subsequent year reporting, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle must use the most recent BOEMRE data collection and emissions estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report emissions. (t) GHG volumetric emissions using actual conditions. If equation parameters in § 98.233 are already at standard conditions, which results in volumetric emissions at standard conditions, then this paragraph does not apply. Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) of this section, with actual pressure and temperature determined by engineering estimates based on best available data unless otherwise specified. (1) * * * factor at the actual temperature and pressure is 0.98 or greater. (2) * * * carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data. (vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities. You may use a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data. (v) GHG mass emissions. Calculate GHG mass emissions in metric tons by converting the GHG volumetric emissions at standard conditions into mass emissions using Equation W–36 of this section. E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.042</GPH> EP10MR14.043</GPH> * (2) Offshore production facilities that are not under BOEMRE jurisdiction must use the most recent monitoring methods and calculation methods published by BOEMRE referenced in 30 CFR 250.302 through 304 to calculate and report annual emissions (GOADS). (i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, you may report the most recently reported emissions data submitted to demonstrate compliance with this subpart of part 98, with emissions adjusted based on the operating time for the facility relative to operating time in the previous reporting period. * * * * * (3) If BOEMRE discontinues or delays their data collection effort by more than 4 years, then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection and emissions estimation methods to estimate emissions. These emission estimates would be used to report emissions from the facility sources as EP10MR14.041</GPH> (6) Natural gas distribution facilities must use the appropriate methane emission factors as described in paragraph (r)(6) of this section. (i) Below grade metering-regulating stations, distribution mains, and distribution services must use the appropriate default methane population emission factors listed in Table W–7 of this subpart. Below grade transmissiondistribution transfer stations must use the emission factor for below grade metering-regulating stations. (ii) Above grade metering-regulating stations (that are not above grade transmission-distribution transfer stations) must use the meter/regulator run population emission factor calculated in Equation W–31. Natural gas distribution facilities that do not have above grade transmissiondistribution transfer stations are not required to calculate emissions for above grade metering-regulating stations. (s) * * * 13445 13446 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (w) EOR injection pump blowdown. Calculate CO2 pump blowdown emissions from each EOR injection pump system as follows: (1) Calculate the total injection pump system volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves. * * * * * (3) Calculate the total annual CO2 emissions from each EOR injection pump system using Equation W–37 of this section: * * * * * MassCO2 = Annual EOR injection pump system emissions in metric tons from blowdowns. N = Number of blowdowns for the EOR injection pump system in the calendar year. Vv = Total volume in cubic feet of EOR injection pump system chambers (including pipelines, manifolds and vessels) between isolation valves. * * * * * (x) EOR hydrocarbon liquids dissolved CO2. Calculate CO2 emissions downstream of the storage tank from dissolved CO2 in hydrocarbon liquids produced through EOR operations as follows: (1) Determine the amount of CO2 retained in hydrocarbon liquids after emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * MassN2O = Annual N2O emissions from the combustion of a particular type of fuel (metric tons). Fuel = Annual mass or volume of the fuel combusted (mass or volume per year, choose appropriately to be consistent with the units of HHV). HHV = Higher heating value of fuel, mmBtu/ unit of fuel (in units consistent with the fuel quantity combusted). For the higher heating value for field gas or process vent gas, use 1.235 × 10¥3 mmBtu/scf for HHV. 6. Section 98.234 is amended by: a. Revising paragraphs (a) introductory text and (d)(1); ■ b. Removing and reserving paragraph (f); and ■ c. Adding paragraph (h). The revisions read as follows: ■ ■ VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 flashing in tankage at STP conditions. Annual samples of hydrocarbon liquids downstream of the storage tank must be taken according to methods set forth in § 98.234(b) to determine retention of CO2 in hydrocarbon liquids immediately downstream of the storage tank. Use the annual analysis for the calendar year. (2) * * * * * * * * Shl = Amount of CO2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel, under standard conditions. * * * * * (z) * * * (1) If a fuel combusted in the stationary or portable equipment is listed in Table C–1 of subpart C of this part, or is a blend containing one or more fuels listed in Table C–1, calculate emissions according to paragraph (z)(1)(i) of this section. If the fuel combusted is natural gas and is of pipeline quality specification and has a minimum high heat value of 950 Btu per standard cubic foot, use the calculation method described in paragraph (z)(1)(i) of this section and you may use the emission factor provided for natural gas as listed in Table C–1. If the fuel is natural gas, and is not pipeline quality or has a high heat value of less than 950 Btu per standard cubic feet, calculate emissions according to paragraph (z)(2) of this section. If the fuel is field gas, process vent gas, or a blend containing field gas or process vent gas, calculate emissions according to paragraph (z)(2) of this section. § 98.234 Monitoring and QA/QC requirements. * * * * * (a) You must use any of the methods described as follows in this paragraph to conduct leak detection(s) of equipment leaks and through-valve leakage from all source types listed in § 98.233(k), (o), (p) and (q) that occur during a calendar year. (d) * * * (1) A technician following manufacturer instructions shall conduct measurements, including equipment manufacturer operating procedures and measurement methods relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the source. * * * * * PO 00000 Frm 00054 Fmt 4701 Sfmt 4702 (i) For fuels listed in Table C–1 or a blend containing one or more fuels listed in Table C–1, calculate CO2, CH4, and N2O emissions according to any Tier listed in subpart C of this part. You must follow all applicable calculation requirements for that tier listed in § 98.33, any monitoring or QA/QC requirements listed for that tier in § 98.34, any missing data procedures specified in § 98.35, and any recordkeeping requirements specified in § 98.37. (ii) Emissions from fuel combusted in stationary or portable equipment at onshore natural gas and petroleum production facilities and at natural gas distribution facilities will be reported according to the requirements specified in § 98.236(c)(19) and not according to the reporting requirements specified in subpart C of this part. (2) * * * (iii) * * * * * * * * Va = Volume of gas sent to combustion unit in actual cubic feet, during the year. YCO2 = Mole fraction of CO2 constituent in gas sent to combustion unit. * * * * * Yj = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes plus) in gas sent to combustion unit. * * * * * YCH4 = Mole fraction of methane constituent in gas sent to combustion unit. * * * (vi) * * * * * (h) For well venting for liquids unloading, if a monitoring period other than the full calendar year is used to determine the cumulative amount of time in hours of venting for each well (the term ‘‘Tp’’ in Equation W–7A and W–7B of § 98.233) or the number of unloading events per well (the term ‘‘Vp’’ in Equations W–8 and W–9 of § 98.233), then the monitoring period must begin before February 1 of the reporting year and must not end before December 1 of the reporting year. The end of one monitoring period must immediately precede the start of the next monitoring period for the next reporting year. All production days must be monitored and all venting accounted for. ■ 7. Section 98.235 is revised to read as follows: E:\FR\FM\10MRP2.SGM 10MRP2 EP10MR14.044</GPH> Where: Massi = GHGi (either CH4, CO2, or N2O) mass emissions in metric tons. Es,i = GHGi (either CH4, CO2, or N2O) volumetric emissions at standard conditions, in cubic feet. Pi = Density of GHGi. Use 0.0526 kg/ft3 for CO2 and N2O, and 0.0192 kg/ft3 for CH4 at 60 °F and 14.7 psia. Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 § 98.235 Procedures for estimating missing data. Except as specified in § 98.233, whenever a value of a parameter is unavailable for a GHG emission calculation required by this subpart (including, but not limited to, if a measuring device malfunctions during unit operation, a required gas sample is not taken, or activity data are not collected), you must follow the procedures specified in paragraphs (a) through (h) of this section, as applicable. (a) If you choose to take quarterly gas samples as allowed in § 98.233(d) in lieu of using a continuous gas analyzer, and there is a missing sample, you must substitute the average value of the last four samples for which data are available. (b) If you did not conduct monitoring as specified in § 98.233(k) for a transmission storage tank(s), you must assume the vent stack(s) connected to the transmission storage tank(s) was leaking for the entire calendar year. (c) For stationary and portable combustion sources that use the calculation methods of subpart C of this part, you must use the missing data procedures in subpart C of this part. (d) For each missing value of a parameter that should have been measured using a continuous flow meter, composition analyzer, thermocouple, or pressure gauge, you must substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the ‘‘after’’ value is not obtained by the end of the reporting year, you may use the ‘‘before’’ value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, you must use the first quality-assured value obtained after the missing data period as the substitute data value. A value is quality-assured according to the procedures specified in § 98.234. (e) For the first six months of required data collection, facilities that become newly subject to this subpart W may use best engineering estimates for any data that cannot reasonably be measured or obtained according to the requirements of this subpart. (f) For the first six months of required data collection, facilities that are currently subject to this subpart W and that acquire new wells that were not previously subject to this subpart W may use best engineering estimates for any data related to those newly acquired wells that cannot reasonably be VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 measured or obtained according to the requirements of this subpart. (g) For each missing value of any activity data not described in this section, you must substitute data value(s) using the best available estimate(s) of the parameter(s), based on all available process data (including, but not limited to, processing rates, operating hours). (h) You must report information for all measured and substitute values of a parameter, and the procedures used to substitute an unavailable value of a parameter per the requirements in § 98.236(bb). ■ 8. Section 98.236 is revised to read as follows: § 98.236 Data reporting requirements. In addition to the information required by § 98.3(c), each annual report must contain reported emissions and related information as specified in this section. (a) The annual report must include the information specified in paragraphs (a)(1) through (8) of this section for each applicable industry segment. The annual report must also include annual emissions totals, in metric tons of CO2e of each GHG, for each applicable industry segment listed in paragraphs (a)(1) through (a)(8) of this section, and each applicable emission source listed in paragraphs (b) through (z) of this section. (1) Onshore petroleum and natural gas production. For the equipment/ activities specified in paragraphs (a)(1)(i) through (a)(1)(xvii) of this section, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section. (ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this section. (iii) Acid gas removal units. Report the information specified in paragraph (d) of this section. (iv) Dehydrators. Report the information specified in paragraph (e) of this section. (v) Liquids unloading. Report the information specified in paragraph (f) of this section. (vi) Completions and workovers with hydraulic fracturing. Report the information specified in paragraph (g) of this section. (vii) Completions and workovers without hydraulic fracturing. Report the information specified in paragraph (h) of this section. (viii) Onshore production storage tanks. Report the information specified in paragraph (j) of this section. PO 00000 Frm 00055 Fmt 4701 Sfmt 4702 13447 (ix) Well testing. Report the information specified in paragraph (l) of this section. (x) Associated natural gas. Report the information specified in paragraph (m) of this section. (xi) Flare stacks. Report the information specified in paragraph (n) of this section. (xii) Centrifugal compressors. Report the information specified in paragraph (o) of this section. (xiii) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (xiv) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (xv) EOR injection pumps. Report the information specified in paragraph (w) of this section. (xvi) EOR hydrocarbon liquids. Report the information specified in paragraph (x) of this section. (xvii) Combustion equipment. Report the information specified in paragraph (z) of this section. (2) Offshore petroleum and natural gas production. Report the information specified in paragraph (s) of this section. (3) Onshore natural gas processing. For the equipment/activities specified in paragraphs (a)(3)(i) through (a)(3)(vii) of this section, report the information specified in the applicable paragraphs of this section. (i) Acid gas removal units. Report the information specified in paragraph (d) of this section. (ii) Dehydrators. Report the information specified in paragraph (e) of this section. (iii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section. (iv) Flare stacks. Report the information specified in paragraph (n) of this section. (v) Centrifugal compressors. Report the information specified in paragraph (o) of this section. (vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (vii) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (4) Onshore natural gas transmission compression. For the equipment/ activities specified in paragraphs (a)(4)(i) through (a)(4)(vii) of this section, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section. (ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section. E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 13448 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (iii) Transmission storage tanks. Report the information specified in paragraph (k) of this section. (iv) Flare stacks. Report the information specified in paragraph (n) of this section. (v) Centrifugal compressors. Report the information specified in paragraph (o) of this section. (vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (vii) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (5) Underground natural gas storage. For the equipment/activities specified in paragraphs (a)(5)(i) through (a)(5)(vi) of this section, report the information specified in the applicable paragraphs of this section. (i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section. (ii) Flare stacks. Report the information specified in paragraph (n) of this section. (iii) Centrifugal compressors. Report the information specified in paragraph (o) of this section. (iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (v) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (6) LNG storage. For the equipment/ activities specified in paragraphs (a)(6)(i) through (a)(6)(v) of this section, report the information specified in the applicable paragraphs of this section. (i) Flare stacks. Report the information specified in paragraph (n) of this section. (ii) Centrifugal compressors. Report the information specified in paragraph (o) of this section. (iii) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (iv) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (v) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (7) LNG import and export equipment. For the equipment/activities specified in paragraphs (a)(7)(i) through (a)(7)(vi) of this section, report the information specified in the applicable paragraphs of this section. (i) Blowdown vent stacks. Report the information specified in paragraph (i) of this section. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 (ii) Flare stacks. Report the information specified in paragraph (n) of this section. (iii) Centrifugal compressors. Report the information specified in paragraph (o) of this section. (iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section. (v) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (8) Natural gas distribution. For the equipment/activities specified in paragraphs (a)(8)(i) through (a)(8)(iii) of this section, report the information specified in the applicable paragraphs of this section. (i) Combustion equipment. Report the information specified in paragraph (z) of this section. (ii) Equipment leak surveys. Report the information specified in paragraph (q) of this section. (iii) Equipment leaks by population count. Report the information specified in paragraph (r) of this section. (b) Natural gas pneumatic devices. You must indicate whether the facility contains the following types of equipment: continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermittent bleed natural gas pneumatic devices, then you must report the information specified in paragraphs (b)(1) through (b)(4) of this section. (1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and (b)(1)(ii) of this section. (i) The total number of devices, determined according to § 98.233(a)(1) and (a)(2). (ii) If the reported value in paragraph (b)(1)(i) of this section is an estimated value determined according to § 98.233(a)(2), then you must report the information specified in paragraphs (b)(1)(ii)(A) through (b)(1)(ii)(C) of this section. (A) The number of devices reported in paragraph (b)(1)(i) of this section that are counted. (B) The number of devices reported in paragraph (b)(1)(i) of this section that are estimated (not counted). (C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting. PO 00000 Frm 00056 Fmt 4701 Sfmt 4702 (2) Estimated average number of hours in the calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of this section were operating in the calendar year (‘‘Tt’’ in Equation W–1 of this subpart). (3) Annual CO2 emissions, in metric tons CO2, for the natural gas pneumatic devices combined, calculated using Equation W–1 of this subpart and § 98.233(a)(4), and reported in paragraph (b)(1)(i) of this section. (4) Annual CH4 emissions, in metric tons CH4, for the natural gas pneumatic devices combined, calculated using Equation W–1 of this subpart and § 98.233(a)(4), and reported in paragraph (b)(1)(i) of this section. (c) Natural gas driven pneumatic pumps. You must indicate whether the facility has any natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must report the information specified in paragraphs (c)(1) through (c)(4) of this section. (1) Count of natural gas driven pneumatic pumps. (2) Average estimated number of hours in the calendar year the pumps were operational (‘‘T’’ in Equation W–2 of this subpart). (3) Annual CO2 emissions, in metric tons CO2, for all natural gas driven pneumatic pumps combined, calculated according to § 98.233(c)(1) and (c)(2). (4) Annual CH4 emissions, in metric tons CH4, for all natural gas driven pneumatic pumps combined, calculated according to § 98.233(c)(1) and (c)(2). (d) Acid gas removal units. You must indicate whether your facility has any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant. If your facility contains any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant, then you must report the information specified in paragraphs (d)(1) and (d)(2) of this section. (1) You must report the information specified in paragraphs (d)(1)(i) through (d)(1)(vi) of this section for each acid gas removal unit. (i) A unique name or ID number for the acid gas removal unit. For the onshore petroleum and natural gas production industry segment, a different name or ID may be used for a single acid gas removal unit for each location it operates at in a given year. (ii) Total feed rate entering the acid gas removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million cubic feet per year. E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (iii) The calculation method used to calculate CO2 emissions from the acid gas removal unit, as specified in § 98.233(d). (iv) Whether any CO2 emissions from the acid gas removal unit are recovered and transferred outside the facility, as specified in § 98.233(d)(11). If any CO2 emissions from the acid gas removal unit were recovered and transferred outside the facility, then you must report the annual quantity of CO2, in metric tons CO2, that was recovered and transferred outside the facility. (v) Annual CO2 emissions, in metric tons CO2, from the acid gas removal unit, calculated using any one of the calculation methods specified in § 98.233(d) and as specified in § 98.233(d)(10) and (11). (vi) Sub-basin ID (for the onshore petroleum and natural gas production industry segment only). (2) You must report information specified in paragraphs (d)(2)(i) through (d)(2)(iii) of this section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for each acid gas removal unit. (i) If you used Calculation Method 1 or Calculation Method 2 as specified in § 98.233(d) to calculate CO2 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(i)(A) and (d)(2)(i)(B) of this section. (A) Annual average volumetric fraction of CO2 in the vent gas exiting the acid gas removal unit. (B) Annual volume of gas vented from the acid gas removal unit, in cubic feet. (ii) If you used Calculation Method 3 as specified in § 98.233(d) to calculate CO2 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(D) of this section. (A) Which equation was used; Equation W–4A or W–4B. (B) Annual average volumetric fraction of CO2 in the natural gas flowing out of the acid gas removal unit, as specified in Equation W–4A or Equation W–4B of this subpart. (C) Annual average volumetric fraction of CO2 content in natural gas flowing into the acid gas removal unit, as specified in Equation W–4A or Equation W–4B of this subpart. (D) The natural gas flow rate used, as specified in Equation W–4A of this subpart, reported as either total annual volume of natural gas flow into the acid gas removal unit in cubic feet at actual conditions; or total annual volume of natural gas flow out of the acid gas removal unit, as specified in Equation VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 W–4B of this subpart, in cubic feet at actual conditions,. (iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO2 emissions from the acid gas removal unit, then you must report the information specified in paragraphs (d)(2)(iii)(A) through (d)(2)(iii)(L) of this section, as applicable to the simulation software package used. (A) The name of the simulation software package used. (B) Natural gas feed temperature, in degrees Fahrenheit. (C) Natural gas feed pressure, in pounds per square inch. (D) Natural gas flow rate, in standard cubic feet per minute. (E) Acid gas content of the feed natural gas, in mole percent. (F) Acid gas content of the outlet natural gas, in mole percent. (G) Unit operating hours, excluding downtime for maintenance or standby, in hours per year. (H) Exit temperature of the natural gas, in degrees Fahrenheit. (I) Solvent pressure, in pounds per square inch. (J) Solvent temperature, in degrees Fahrenheit. (K) Solvent circulation rate, in gallons per minute. (L) Solvent weight, in pounds per gallon. (e) Dehydrators. You must indicate whether your facility contains any of the following equipment: absorbent dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day, glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day, and dehydrators that use desiccant. If your facility contains any of the equipment listed in this paragraph (e), then you must report the applicable information in paragraphs (e)(1) through (e)(3). (1) For each absorbent dehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day (as specified in § 98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) through (e)(1)(xviii) of this section for the dehydrator. (i) A unique name or ID number for the dehydrator. For the onshore petroleum and natural gas production industry segment, a different name or ID may be used for a single dehydrator for each location it operates at in a given year. (ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, determined by engineering estimate based on best available data. PO 00000 Frm 00057 Fmt 4701 Sfmt 4702 13449 (iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet. (iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet. (v) Dehydrator absorbent circulation pump type (e.g., natural gas pneumatic, air pneumatic, or electric). (vi) Dehydrator absorbent circulation rate, in gallons per minute. (vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene glycol (DEG), or ethylene glycol (EG)). (viii) Whether stripper gas is used in dehydrator. (ix) Whether a flash tank separator is used in dehydrator. (x) Total time the dehydrator is operating, in hours. (xi) Temperature of the wet natural gas, in degrees Fahrenheit. (xii) Pressure of the wet natural gas, in pounds per square inch gauge. (xiii) Mole fraction of CH4 in wet natural gas. (xiv) Mole fraction of CO2 in wet natural gas. (xv) Whether any dehydrator emissions are vented to a vapor recovery device. (xvi) Whether any dehydrator emissions are vented to a flare or regenerator firebox/fire tubes. If any emissions are vented to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(1)(xvi)(A) through (e)(1)(xvi)(C) of this section for these emissions from the dehydrator. (A) Annual CO2 emissions, in metric tons CO2, for the dehydrator, calculated according to § 98.233(e)(6). (B) Annual CH4 emissions, in metric tons CH4, for the dehydrator, calculated according to § 98.233(e)(6). (C) Annual N2O emissions, in metric tons N2O, for the dehydrator, calculated according to § 98.233(e)(6). (xvii) Whether any dehydrator emissions are vented to the atmosphere without being routed to a flare or regenerator firebox/fire tubes. If any emissions are not routed to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(1)(xvii)(A) and (e)(1)(xvii)(B) of this section for those emissions from the dehydrator. (A) Annual CO2 emissions, in metric tons CO2, for the dehydrator when not venting to a flare or regenerator firebox/ fire tubes, calculated according to § 98.233(e)(1) and (e)(5). (B) Annual CH4 emissions, in metric tons CH4, for the dehydrator when not venting to a flare or regenerator firebox/ fire tubes, calculated according to § 98.233(e)(1) and (e)(5). E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 13450 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (xviii) Sub-basin ID (for the onshore petroleum and natural gas production industry segment only). (2) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day (as specified in § 98.233(e)(2)), you must report the information specified in paragraphs (e)(2)(i) through (e)(2)(v) of this section for the entire facility. (i) The total number of dehydrators at the facility. (ii) Whether any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a vapor recovery device. If any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a vapor recovery device, then you must report the total number of dehydrators at the facility that vented to a vapor recovery device. (iii) Whether any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. If any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes, then you must specify the type of control device and the number of dehydrators at the facility that were vented to each type of control device. (iv) Whether any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a flare or regenerator firebox/fire tubes. If any dehydrators reported in paragraph (e)(2)(i) of this section were vented to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(2)(iv)(A) through (e)(2)(iv)(D) of this section. (A) The total number of dehydrators venting to a flare or regenerator firebox/ fire tubes. (B) Annual CO2 emissions, in metric tons CO2, for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(6). (C) Annual CH4 emissions, in metric tons CH4, for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(6). (D) Annual N2O emissions, in metric tons N2O, for the dehydrators reported in paragraph (e)(2)(iv)(A) of this section, calculated according to § 98.233(e)(6). (v) For dehydrators reported in paragraph (e)(2)(i) of this section that were not vented to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(2)(v)(A) and (e)(2)(v)(B) of this section. (A) Annual CO2 emissions in metric tons CO2, for emissions from all VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 dehydrators reported in paragraph (e)(2)(i) of this section that were not vented to a flare or regenerator firebox/ fire tubes, calculated according to § 98.233(e)(2), (e)(4), and (e)(5), where emissions are added together for all such dehydrators. (B) Annual CH4 emissions in metric tons CO2, for emissions from all dehydrators reported in paragraph (e)(2)(i) of this section that were not vented to a flare or regenerator firebox/ fire tubes, calculated according to § 98.233(e)(2), (e)(4), and (e)(5), where emissions are added together for all such dehydrators. (3) For dehydrators that use desiccant (as specified in § 98.233(e)(3)), you must report the information specified in paragraphs (e)(3)(i) through (e)(3)(iii) of this section for the entire facility. (i) The same information specified in paragraphs (e)(2)(i) through (e)(2)(iv) of this section for glycol dehydrators, and report the information under this paragraph for dehydrators that use desiccant. (ii) Annual CO2 emissions, in metric tons CO2, for emissions from all desiccant dehydrators reported under paragraph (e)(3)(i) of this section that are not venting to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(3), (e)(4), and (e)(5), and summing for all such dehydrators. (iii) Annual CH4 emissions, in metric tons CH4, for emissions from all desiccant dehydrators reported in paragraph (e)(3)(i) of this section that are not venting to a flare or regenerator firebox/fire tubes, calculated according to § 98.233(e)(3), (e)(4), and (e)(5), and summing for all such dehydrators. (f) Liquids unloading. You must indicate whether well venting for liquids unloading occurs at your facility, and if so, which methods (as specified in § 98.233(f)) were used to calculate emissions. If your facility performs well venting for liquids unloading and uses Calculation Method 1, then you must report the information specified in paragraph (f)(1) of this section. If the facility performs liquids unloading and uses Calculation Method 2 or 3, then you must report the information specified in paragraph (f)(2) of this section. (1) For each sub-basin and well tubing diameter and pressure grouping for which you used Calculation Method 1 to calculate natural gas emissions from well venting for liquids unloading, report the information specified in paragraphs (f)(1)(i) through (f)(1)(xii) of this section. Report information separately for wells with plunger lifts and wells without plunger lifts. (i) Sub-basin ID. PO 00000 Frm 00058 Fmt 4701 Sfmt 4702 (ii) Well tubing diameter and pressure group ID. (iii) Plunger lift indicator. (iv) Count of wells vented to the atmosphere for the sub-basin/well tubing diameter and pressure grouping. (v) Percentage of wells for which the monitoring period used to determine the cumulative amount of time venting was not the full calendar year. (vi) Cumulative amount of time wells were vented (sum of ‘‘Tp’’ from Equation W–7A or W–7B of this subpart), in hours. (vii) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells in the sub-basin/well tubing diameter and pressure grouping. (viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(1). (ix) Annual CO2 emissions, in metric tons CO2, from well venting for liquids unloading, calculated according to § 98.233(f)(1) and § 98.233(f)(4). (x) Annual CH4 emissions, in metric tons CH4, from well venting for liquids unloading, calculated according to § 98.233(f)(1) and § 98.233(f)(4). (xi) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xi)(A) through (f)(1)(xi)(E) of this section for each individual well not using a plunger lift that was tested during the year. (A) API number of tested well. (B) Casing pressure, in pounds per square inch absolute. (C) Internal casing diameter, in inches. (D) Measured depth of the well, in feet. (E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour. (xii) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xii)(A) through (f)(1)(xii)(E) of this section for each individual well using a plunger lift that was tested during the year. (A) The API well number. (B) The tubing pressure, in pounds per square inch absolute. (C) The internal tubing diameter, in inches. (D) Measured depth of the well, in feet. (E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour. (2) For each sub-basin for which you used Calculation Method 2 or 3 (as E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules specified in § 93.233(f)) to calculate natural gas emissions from well venting for liquids unloading, you must report the information in (f)(2)(i) through (f)(2)(x) of this section. Report information separately for each calculation method. (i) Sub-basin ID. (ii) Calculation method. (iii) Plunger lift indicator. (iv) Number of wells vented to the atmosphere. (v) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells. (vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(2) or § 98.233(f)(3), as applicable. (vii) Annual CO2 emissions, in metric tons CO2, from well venting for liquids unloading, calculated according to § 98.233(f)(2) or § 98.233(f)(3), as applicable, and § 98.233(f)(4). (viii) Annual CH4 emissions, in metric tons CH4, from well venting for liquids unloading, calculated according to § 98.233(f) (2) or § 98.233(f)(3), as applicable, and § 98.233(f)(4). (ix) For wells without plunger lifts, the average internal casing diameter, in inches. (x) For wells with plunger lifts, the average internal tubing diameter, in inches. (g) Completions and workovers with hydraulic fracturing. You must indicate whether your facility had any gas well completions or workovers with hydraulic fracturing during the calendar year. If your facility had gas well completions or workovers with hydraulic fracturing during the calendar year, then you must report information specified in paragraphs (g)(1) through (g)(10) of this section, for each sub-basin and well type combination. Report information separately for completions and workovers. (1) Sub-basin ID. (2) Well type. (3) Number of completions or workovers in the category. (4) Calculation method used. (5) If you used Equation W–10A to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(5)(i) and (g)(5)(ii) of this section. (i) Cumulative backflow time, in hours, for each sub-basin (‘‘Tp’’ in Equation W–10A). (ii) Measured flowback rate, in standard cubic feet per hour, for each sub-basin (‘‘FRs,p’’ in Equation W–12A). (6) If you used Equation W–10B to calculate annual volumetric total gas emissions for completions that vent gas VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 to the atmosphere, then you must report the vented natural gas volume, in standard cubic feet, for each well in the sub-basin (‘‘FVs,p’’ in Equation W–10B). (7) Annual gas emissions, in standard cubic feet (‘‘Es,n’’ in Equation W–10A or W–10B). (8) Annual CO2 emissions, in metric tons CO2. (9) Annual CH4 emissions, in metric tons CH4. (10) If the well emissions were vented to a flare, then you must report the total N2O emissions, in metric tons N2O. (h) Completions and workovers without hydraulic fracturing. You must indicate whether the facility had any gas well completions without hydraulic fracturing or any gas well workovers without hydraulic fracturing, and if the activities occurred with or without flaring. If the facility had gas well completions or workovers without hydraulic fracturing, then you must report the information specified in paragraphs (h)(1) through (h)(4) of this section, as applicable. (1) For each sub-basin with gas well completions without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(1)(i) through (h)(1)(vi) of this section. (i) Sub-basin ID. (ii) Number of well completions that vented gas directly to the atmosphere without flaring. (iii) Total number of hours that gas vented directly to the atmosphere during backflow for all completions in the sub-basin category (the sum of all ‘‘Tp’’ for completions that vented to the atmosphere as used in Equation W– 13B). (iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin without flaring, in standard cubic feet per hour (average of all ‘‘Vp’’ used in Equation W–13B). (v) Annual CO2 emissions, in metric tons CO2, that resulted from completions venting gas directly to the atmosphere (‘‘Es,p’’ from Equation W– 13B for completions that vented directly to the atmosphere, converted to mass emissions according to § 98.233(h)(1)). (vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions venting gas directly to the atmosphere (Es,p from Equation W–13B for completions that vented directly to the atmosphere, converted to mass emissions according to § 98.233(h)(1)). (2) For each sub-basin with gas well completions without hydraulic fracturing and with flaring, report the information specified in paragraphs PO 00000 Frm 00059 Fmt 4701 Sfmt 4702 13451 (h)(2)(i) through (h)(2)(vii) of this section. (i) Sub-basin ID. (ii) Number of well completions that flared gas. (iii) Total number of hours that gas vented to a flare during backflow for all completions in the sub-basin category (the sum of all ‘‘Tp’’ for completions that vented to a flare from Equation W–13B). (iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin with flaring, in standard cubic feet per hour (the average of all ‘‘Vp’’ from Equation W– 13B). (v) Annual CO2 emissions, in metric tons CO2, that resulted from completions that flared gas calculated according to § 98.233(h)(2). (vi) Annual CH4 emissions, in metric tons CH4, that resulted from completions that flared gas calculated according to § 98.233(h)(2). (vii) Annual N2O emissions, in metric tons N2O, that resulted from completions that flared gas calculated according to § 98.233(h)(2). (3) For each sub-basin with gas well workovers without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(3)(i) through (h)(3)(iv) of this section. (i) Sub-basin ID. (ii) Number of workovers that vented gas to the atmosphere without flaring. (iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from workovers venting gas directly to the atmosphere (‘‘Es,wo’’ in Equation W–13A for workovers that vented directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)). (iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from workovers venting gas directly to the atmosphere (‘‘Es,wo’’ in Equation W–13A for workovers that vented directly to the atmosphere, converted to mass emissions as specified in § 98.233(h)(1)). (4) For each sub-basin with gas well workovers without hydraulic fracturing and with flaring, report the information specified in paragraphs (h)(4)(i) through (h)(4)(v) of this section. (i) Sub-basin ID. (ii) Number of workovers that flared gas. (iii) Annual CO2 emissions, in metric tons CO2 per year, that resulted from workovers that flared gas calculated as specified in § 98.233(h)(2). (iv) Annual CH4 emissions, in metric tons CH4 per year, that resulted from workovers that flared gas, calculated as specified in § 98.233(h)(2). (v) Annual N2O emissions, in metric tons N2O per year, that resulted from E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 13452 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules workovers that flared gas calculated as specified in § 98.233(h)(2). (i) Blowdown vent stacks. You must indicate whether your facility has blowdown vent stacks. If your facility has blowdown vent stacks, then you must report whether emissions were calculated by equipment type or by using flow meters. If you calculated emissions by equipment type, then you must report the information specified in paragraph (i)(1) of this section. If you calculated emissions using flow meters, then you must report the information specified in paragraph (i)(2) of this section. (1) Report by equipment type. If you calculated emissions from blowdown vent stacks by equipment type, then you must report the equipment types and the information specified in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for each equipment type. If a blowdown event resulted in emissions from multiple equipment types, then you must report the information in paragraphs (i)(1)(i) through (i)(1)(iii) of this section for the equipment type that represented the largest portion of the emissions for the blowdown event. (i) Total number of blowdowns in the calendar year for the equipment type (the sum of equation variable ‘‘N’’ from Equation W–14A or Equation W–14B of this subpart, for all unique physical volumes for the equipment type). (ii) Annual CO2 emissions for the equipment type, in metric tons CO2, calculated according to § 98.233(i)(2)(iii). (iii) Annual CH4 emissions for the equipment type, in metric tons CH4, calculated according to § 98.233(i)(2)(iii). (2) Report by flow meter. If you elect to calculate emissions from blowdown vent stacks by using a flow meter according to § 98.233(i)(3), then you must report the information specified in paragraphs (i)(2)(i) and (i)(2)(ii) of this section for the facility. (i) Annual CO2 emissions from all blowdown vent stacks at the facility, in metric tons CO2 (the sum of all CO2 mass emission values calculated according to § 98.233(i)(3), for all flow meters). (ii) Annual CH4 emissions from all blowdown vent stacks at the facility, in metric tons CH4, (the sum of all CH4 mass emission values calculated according to § 98.233(i)(3), for all flow meters). (j) Onshore production storage tanks. You must indicate whether your facility sends produced oil to atmospheric tanks. If your facility sends produced oil to atmospheric tanks, then you must indicate which Calculation Method(s) VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 you used to calculate GHG emissions, and you must report the information specified in paragraphs (j)(1) and (j)(2) of this section as applicable. If any atmospheric tanks were observed to have malfunctioning dump valves during the calendar year, then you must indicate that dump valves were malfunctioning and you must report the information specified in paragraph (j)(3) of this section. (1) If you used Calculation Method 1 or Calculation Method 2 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(1)(i) through (j)(1)(xiv) of this section for each sub-basin and by calculation method. (i) Sub-basin ID. (ii) Calculation method used, and name of the software package used if using Calculation Method 1. (iii) The total annual gas-liquid separator oil volume that is sent to applicable onshore production storage tanks, in barrels. (iv) The average gas-liquid separator temperature, in degrees. (v) The average gas-liquid separator pressure, in pounds per square inch gauge. (vi) The average sales oil or stabilized oil API gravity, in degrees. (vii) The minimum and maximum concentration (mole fraction) of CO2 in flash gas from onshore production storage tanks. (viii) The minimum and maximum concentration (mole fraction) of CH4 in flash gas from onshore production storage tanks. (ix) The number of wells sending oil to gas-liquid separators or directly to atmospheric tanks. (x) The number of atmospheric tanks. (xi) An estimate of the number of atmospheric tanks, not on well-pads, receiving your oil. (xii) If any emissions from the atmospheric tanks at your facility were controlled with vapor recovery systems, then you must report the information specified in paragraphs (j)(1)(xii)(A) through (j)(1)(xii)(E) of this section. (A) The number of atmospheric tanks that control emissions with vapor recovery systems. (B) Total CO2 mass, in metric tons CO2, that was recovered during the calendar year using a vapor recovery system. (C) Total CH4 mass, in metric tons CH4, that was recovered during the calendar year using a vapor recovery system. (D) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks equipped with vapor recovery systems. PO 00000 Frm 00060 Fmt 4701 Sfmt 4702 (E) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks equipped with vapor recovery systems. (xiii) If any atmospheric tanks at your facility vented gas directly to the atmosphere without using a vapor recovery system or without flaring, then you must report the information specified in paragraphs (j)(1)(xiii)(A) through (j)(1)(xiii)(C) of this section. (A) The number of atmospheric tanks that vented gas directly to the atmosphere without using a vapor recovery system or without flaring. (B) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to the atmosphere. (C) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to the atmosphere. (xiv) If you controlled emissions from any atmospheric tanks at your facility with one or more flares, then you must report the information specified in paragraphs (j)(1)(xiv)(A) through (j)(1)(xiv)(D) of this section. (A) The number of atmospheric tanks that controlled emissions with flares. (B) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled emissions with one or more flares. (C) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled emissions with one or more flares. (D) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled emissions with one or more flares. (2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraph (j)(2)(i) through (j)(2)(iii) of this paragraph. (i) Report the information specified in paragraphs (j)(2)(i)(A) through (j)(2)(i)(F) of this section, at the basin level, for atmospheric tanks where emissions were calculated using Calculation Method 3. (A) The total annual oil throughput that is sent to all atmospheric tanks in the basin, in barrels. (B) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) sent to atmospheric tanks in the basin that controlled emissions with flares. (C) An estimate of the fraction of oil throughput reported in paragraph (j)(2)(i)(A) sent to atmospheric tanks in the basin that controlled emissions with vapor recovery systems. (D) The number of atmospheric tanks in the basin. (E) The number of wells with gasliquid separators (‘‘Count’’ from Equation W–15 of this subpart) in the basin. E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (F) The number of wells without gasliquid separators (‘‘Count’’ from Equation W–15 of this subpart) in the basin. (ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (j)(2)(ii)(D) of this section for each subbasin with atmospheric tanks whose emissions were calculated using Calculation Method 3 and that did not control emissions with flares. (A) Sub-basin ID. (B) The number of atmospheric tanks in the sub-basin that did not control emissions with flares. (C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks in the sub-basin that did not control emissions with flares, calculated using Equation W–15 of this subpart. (D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks in the sub-basin that vented gas directly to the atmosphere, calculated using Equation W–15 of this subpart. (iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (j)(2)(iii)(E) of this section for each subbasin with atmospheric tanks whose emissions were calculated using Calculation Method 3 and that controlled emissions with flares. (A) Sub-basin ID. (B) The number of atmospheric tanks in the sub-basin that controlled emissions with flares. (C) Annual CO2 emissions, in metric tons CO2, from atmospheric tanks that controlled emissions with flares. (D) Annual CH4 emissions, in metric tons CH4, from atmospheric tanks that controlled emissions with flares. (E) Annual N2O emissions, in metric tons N2O, from atmospheric tanks that controlled emissions with flares. (3) If any gas-liquid separator liquid dump values did not close properly during the calendar year, then you must report the information specified in paragraphs (j)(3)(i) through (j)(3)(iv) of this section. (i) The total number of gas-liquid separators whose liquid dump valves did not close properly during the calendar year. (ii) The total time the dump valves on gas-liquid separators did not close properly in the calendar year, in hours (‘‘Tn’’ in Equation W–16 of this subpart). (iii) Annual CO2 emissions, in metric tons CO2, that resulted from dump valves on gas-liquid separators not closing properly during the calendar year, calculated using Equation W–16 of this subpart. (iv) Annual CH4 emissions, in metric tons CH4, that resulted from the dump valves on gas-liquid separators not closing properly during the calendar VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 year, calculated using Equation W–16 of this subpart. (k) Transmission storage tanks. You must indicate whether your facility contains any transmission storage tanks. If your facility contains at least one transmission storage tank, then you must report the information specified in paragraphs (k)(1) through (k)(3) of this section for each transmission storage tank vent stack. (1) For each transmission storage tank vent stack, report the information specified in (k)(1)(i) through (k)(1)(iv) of this section. (i) The unique name or ID number for the transmission storage tank vent stack. (ii) Method used to determine if dump valve leakage occurred. (iii) Indicator whether scrubber dump valve leakage occurred for the transmission storage tank vent. (iv) Indicator if there is a flare attached to the transmission storage tank vent stack. (2) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii), and the vent stack vented directly to the atmosphere during the calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (k)(2)(v) of this section for each transmission storage vent stack where scrubber dump valve leakage occurred. (i) Method used to measure the leak rate. (ii) Measured leak rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour. (iii) Duration of time that venting occurred, in hours (may use best available data if a continuous flow measurement device was used). (iv) Annual CO2 emissions, in metric tons CO2, that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(k)(1) through (k)(3). (v) Annual CH4 emissions, in metric tons CH4, that resulted from venting gas directly to the atmosphere, calculated according to § 98.233(k)(1) through (k)(3). (3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii), and the vent stack vented to a flare during the calendar year, then you must report the information specified in paragraphs (k)(3)(i) through (k)(3)(vi) of this section. (i) Method used to measure the leak rate. (ii) Measured leakage rate (average leak rate from a continuous flow PO 00000 Frm 00061 Fmt 4701 Sfmt 4702 13453 measurement device) in standard cubic feet per hour. (iii) Duration of time that flaring occurred in hours (may use best available data if a continuous flow measurement device was used). (iv) Annual CO2 emissions, in metric tons CO2, that resulted from flaring gas, calculated according to § 98.233(k)(4). (v) Annual CH4 emissions, in metric tons CH4, that resulted from flaring gas, calculated according to § 98.233(k)(4). (vi) Annual N2O emissions, in metric tons N2O, that resulted from flaring gas, calculated according to § 98.233(k)(4). (l) Well testing. You must indicate whether you performed gas well or oil well testing, and if the testing of gas wells or oil wells resulted in vented or flared emissions during the calendar year. If you performed well testing that resulted in vented or flared emissions during the calendar year, then you must report the information specified in paragraphs (l)(1) through (l)(4) of this section, as applicable. (1) If you used Equation W–17A to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are not vented to a flare, then you must report the information specified in paragraphs (l)(1)(i) through (l)(1)(vi) of this section. (i) Number of wells tested in the calendar year. (ii) Average number of well testing days in the calendar year. (iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil. (iv) Average flow rate for well(s) tested, in barrels of oil per day. (v) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l). (vi) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l). (2) If you used Equation W–17A to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are vented to a flare, then you must report the information specified in paragraphs (l)(2)(i) through (l)(2)(vii) of this section. (i) Number of wells tested in the calendar year. (ii) Average number of well testing days in the calendar year. (iii) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil. (iv) Average flow rate for well(s) tested, in barrels of oil per day. (v) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l). (vi) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l). E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 13454 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (vii) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(l). (3) If you used Equation W–17B to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were not vented to a flare, then you must report the information specified in paragraphs (l)(3)(i) through (l)(3)(v) of this section. (i) Number of wells tested in the calendar year. (ii) Average number of well testing days in the calendar year. (iii) Average annual production rate for well(s) tested, in actual cubic feet per day. (iv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l). (v) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l). (4) If you used Equation W–17B to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were vented to a flare, then you must report the information specified in paragraphs (l)(4)(i) through (l)(4)(vi) of this section. (i) Number of wells tested in calendar year. (ii) Average number of well testing days in the calendar year. (iii) Average annual production rate for well(s) tested, in actual cubic feet per day. (iv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(l). (v) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(l). (vi) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(l). (m) Associated natural gas. You must indicate whether any associated gas was vented or flared during the calendar year. If associated gas was vented or flared during the calendar year, then you must report the information specified in paragraphs (m)(1) through (m)(9) of this section for each sub-basin. (1) Sub-basin ID. (2) Indicator whether any associated gas was vented directly to the atmosphere without flaring. (3) Indicator whether any associated gas was flared. (4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average of the ‘‘GOR’’ values used in Equation W–18 of this subpart). (5) Volume of oil produced, in barrels, in the calendar year during the time periods in which associated gas was vented or flared (the sum of ‘‘Vp,q’’ used in Equation W–18 of this subpart). VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 (6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year during time periods in which associated gas was vented or flared (the sum of ‘‘SG’’ values used in Equation W–18 of this subpart). (7) Total volume of emissions reported elsewhere, in standard cubic feet, during time periods in which associated gas was vented or flared and which are calculated and reported under other paragraphs of this section, in standard cubic feet (the sum of ‘‘EREp,q’’ values used in Equation W–18 of this subpart). (8) If you had associated gas emissions directly to the atmosphere without flaring, then you must report the information specified in paragraphs (m)(8)(i) through (m)(8)(iii) of this section for each sub-basin. (i) Total number of wells for which associated gas was vented directly to the atmosphere without flaring. (ii) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(m)(3) and (m)(4). (iii) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(m)(3) and (m)(4). (9) If you had associated gas emissions that were flared, then you must report the information specified in paragraphs (m)(9)(i) through (m)(9)(iv) of this section for each sub-basin. (i) Total number of wells for which associated gas was flared. (ii) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(m)(5). (iii) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(m)(5). (iv) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(m)(5). (n) Flare stacks. You must indicate if your facility contains any flare stacks. You must report the information specified in paragraphs (n)(1) through (n)(12) of this section for each flare stack at your facility, and for each industry segment applicable to your facility. (1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production industry segment, a different name or ID may be used for a single flare stack for each location where it operates at in a given calendar year. (2) Indicate whether the flare stack has a continuous flow measurement device. (3) Indicate whether the flare stack has a continuous gas composition analyzer on feed gas to the flare. (4) Volume of gas sent to the flare, in standard cubic feet (‘‘Va’’ in Equation W–19 of this subpart). PO 00000 Frm 00062 Fmt 4701 Sfmt 4702 (5) Fraction of the feed gas sent to an un-lit flare (‘‘Zu’’ in Equation W–19 of this subpart). (6) Flare combustion efficiency, expressed as the fraction of gas combusted by a burning flare. (7) Mole fraction of CH4 in the feed gas to the flare (‘‘XCH4’’ in Equation W– 19 of this subpart). (8) Mole fraction of CO2 in the feed gas to the flare (‘‘XCO2’’ in Equation W– 20 of this subpart). (9) Annual CO2 emissions, in metric tons CO2 (refer to Equation W–20 of this subpart). (10) Annual CH4 emissions, in metric tons CH4 (refer to Equation W–19 of this subpart). (11) Annual N2O emissions, in metric tons N2O (refer to Equation W–40 of this subpart). (12) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used to measure emissions from the flare, then you are not required to report N2O and CH4 emissions for the flare stack. (o) Centrifugal compressors. You must indicate whether your facility has centrifugal compressors. You must report the information specified in paragraphs (o)(1) and (o)(2) of this section for all centrifugal compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(o)(2) or (o)(4), you must report the information specified in paragraph (o)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(o)(3) or (o)(5), you must report the information specified in paragraph (o)(4) of this section. Centrifugal compressors in onshore petroleum and natural gas production are not required to report information in paragraphs (o)(1) through (o)(4) of this section and instead must report the information specified in paragraph (o)(5) of this section. (1) Compressor activity data. Report the information specified in paragraphs (o)(1)(i) through (o)(1)(xvi) of this section for each compressor located at your facility. (i) Unique name or ID for the centrifugal compressor. (ii) Hours in operating-mode. (iii) Hours in not-operatingdepressurized-mode. (iv) Indicate whether the compressor was measured in operating-mode. (v) Indicate whether the compressor was measured in not-operatingdepressurized-mode. E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (vi) Indicate whether any compressor sources are part of a manifolded group of compressor sources. (vii) Indicate whether any compressor sources are routed to a flare. (viii) Indicate whether any compressor sources have vapor recovery. (ix) Indicate whether emissions from any compressor sources are captured for fuel use or are routed to a thermal oxidizer. (x) Indicate whether the compressor has blind flanges installed. (xi) Indicate whether the compressor has wet or dry seals. (xii) If the compressor has wet seals, the number of wet seals. (xiii) Compressor power rating (hp). (xiv) Year compressor was installed. (xv) Compressor model name and description. (xvi) Date of last maintenance shutdown that compressor was depressurized. (2) Compressor source emission vent. For each compressor source at each compressor, report the information specified in paragraphs (o)(2)(i) through (o)(2)(viii) of this section. (i) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) of this section. (ii) Centrifugal compressor source (wet seal, isolation valve, or blowdown valve). (iii) Unique name or ID for the emission vent. If the emission vent is connected to a manifolded group of compressor sources, use the same emission vent ID for each compressor source. (iv) Emission vent type. Indicate whether the emission vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the emission vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery. (v) Indicate whether an as found leak measurement(s) as identified in § 98.233(o)(2) or (o)(4) was conducted on the emission vent. (vi) Indicate whether continuous leak measurements as identified in § 98.233(o)(3) or (o)(5) were conducted on the emission vent. (vii) Report emissions as specified in paragraphs (o)(2)(vii)(A) and (o)(2)(vii)(B) of this section for the emission vent. For emission vents associated with individual compressor sources that use an as found leak measurement(s), calculate emissions by summing all emissions from all compressor mode-source combinations for the emission vent. (A) Annual CO2 emissions, in metric tons CO2. VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 (B) Annual CH4 emissions, in metric tons CH4. (viii) If the emission vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational. (3) As found leak measurement sample data. If the measurement methods specified in paragraphs § 98.233(o)(2) or (o)(4) are conducted, report the information specified in paragraph (o)(3)(i) of this section. If the measurement method specified in paragraph § 98.233(o)(2) is performed, report the information specified in paragraph (o)(3)(ii) of this section. (i) For each as found leak measurement performed on an emission vent, report the information specified in paragraphs (o)(3)(i)(A) through (o)(3)(i)(E) of this section. (A) Name or ID of emission vent. Use same emission vent ID as in paragraph (o)(2)(iii) of this section. (B) Sample date. (C) Leak measurement method. (D) Measured flow rate, in standard cubic feet per hour. (E) For each compressor attached to the emission vent, report the mode of operation the compressor was in when the sample was taken. (ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W–24 was used to calculate emissions in Equation W–23, report the information specified in paragraphs (o)(3)(ii)(A) through (o)(3)(ii)(D) of this section (A) The compressor mode-source combination. (B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EFm,s in Equation W–24). (C) The total number of compressors measured in the compressor modesource combination in the current reporting year and the preceding two reporting years (Countm in Equation W– 24). (D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or corporate. (4) Continuous leak measurement data. If the measurement methods specified in paragraphs § 98.233(o)(3) or (o)(5) are conducted, report the information specified in paragraphs (o)(4)(i) and (o)(4)(ii) of this section for each continuous measurement conducted on each emission vent associated with each compressor source or manifolded group of compressor sources. (i) Name or ID of emission vent. Use same emission vent ID as in paragraph (o)(2)(iii) of this section. PO 00000 Frm 00063 Fmt 4701 Sfmt 4702 13455 (ii) Measured volume of flow during the reporting year, in million standard cubic feet. (5) Centrifugal compressors with wet seal degassing vents in onshore petroleum and natural gas production must report the information specified in paragraphs (o)(5)(i) through (o)(5)(iii) of this section. (i) Number of centrifugal compressors that have wet seal oil degassing vents. (ii) Annual CO2 emissions, in metric tons CO2, from centrifugal compressors with wet seal oil degassing vents. (iii) Annual CH4 emissions, in metric tons CH4, from centrifugal compressors with wet seal oil degassing vents. (p) Reciprocating compressors. You must indicate whether your facility has reciprocating compressors. You must report the information specified in paragraphs (p)(1) and (p)(2) of this section for all reciprocating compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(p)(2) or (p)(4), you must report the information specified in paragraph (p)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(p)(3) or (p)(5), you must report the information specified in paragraph (p)(4) of this section. Reciprocating compressors in onshore petroleum and natural gas production are not required to report information in paragraphs (p)(1) through (p)(4) of this section and instead must report the information specified in paragraph (p)(5) of this section. (1) Compressor activity data. Report the information specified in paragraphs (p)(1)(i) through (p)(1)(xvi) of this section for each compressor located at your facility. (i) Unique name or ID for the reciprocating compressor. (ii) Hours in operating-mode. (iii) Hours in standby-depressurizedmode. (iv) Hours in not-operatingdepressurized-mode. (v) Indicate whether the compressor was measured in operating-mode. (vi) Indicate whether the compressor was measured in standbydepressurized-mode. (vii) Indicate whether the compressor was measured in not-operatingdepressurized-mode. (viii) Indicate whether any compressor sources are part of a manifolded group of compressor sources. (ix) Indicate whether any compressor sources are routed to a flare. E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 13456 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (x) Indicate whether any compressor sources have vapor recovery. (xi) Indicate whether emissions from any compressor sources are captured for fuel use or are routed to a thermal oxidizer. (xii) Indicate whether the compressor has blind flanges installed. (xiii) Compressor power rating (hp). (xiv) Year compressor was installed. (xv) Compressor model name and description. (xvi) Date of last maintenance shutdown for rod packing replacement. (2) Compressor source emission vent. For each compressor source at each compressor, report the information specified in paragraphs (p)(2)(i) through (p)(2)(viii) of this section. (i) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section. (ii) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing). (iii) Unique name or ID for the emission vent. If the emission vent is connected to a manifolded group of compressor sources, use the same emission vent ID for each compressor source. (iv) Emission vent type. Indicate whether the emission vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the emission vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery. (v) Indicate whether an as found leak measurement(s) as identified in § 98.233(p)(2) or (p)(4) was conducted on the emission vent. (vi) Indicate whether continuous leak measurements as identified in § 98.233(p)(3) or (p)(5) were conducted on the emission vent. (vii) Report emissions as specified in paragraphs (p)(2)(vii)(A) and (p)(2)(vii)(B) of this section for the emission vent. For emission vents associated with individual compressor sources that use an as found leak measurement(s), calculate emissions by summing all emissions from all compressor mode-source combinations for the emission vent. (A) Annual CO2 emissions, in metric tons CO2. (B) Annual CH4 emissions, in metric tons CH4. (viii) If the emission vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational. (3) As found leak measurement sample data. If the measurement methods specified in paragraphs § 98.233(p)(2) or (p)(4) are conducted, VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 report the information specified in paragraph (p)(3)(i) of this section. If the measurement method specified in paragraph § 98.233(p)(2) is performed, report the information specified in paragraph (p)(3)(ii) of this section. (i) For each as found leak measurement performed on an emission vent, report the information specified in paragraphs (p)(3)(i)(A) through (p)(3)(i)(E) of this section. (A) Name or ID of emission vent. Use same emission vent ID as in paragraph (p)(2)(iii) of this section. (B) Sample date. (C) Leak measurement method. (D) Measured flow rate, in standard cubic feet per hour. (E) For each compressor attached to the emission vent, report the mode of operation the compressor was in when the sample was taken. (ii) For each compressor mode-source combination where a reporter emission factor as calculated in equation W–28 was used to calculate emissions in Equation W–27, report the information specified in paragraphs (p)(3)(ii)(A) through (p)(3)(ii)(D) of this section (A) The compressor mode-source combination. (B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EFm,s in Equation W–28). (C) The total number of compressors measured in the compressor modesource combination in the current reporting year and the preceding two reporting years (Countm in Equation W– 28). (D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or corporate. (4) Continuous leak measurement data. If the measurement methods specified in paragraphs § 98.233(p)(3) or (p)(5) are conducted, report the information specified in paragraphs (p)(4)(i) and (p)(4)(ii) of this section for each continuous measurement conducted on each emission vent associated with each compressor source or manifolded group of compressor sources. (i) Name or ID of emission vent. Use same emission vent ID as in paragraph (p)(2)(iii) of this section. (ii) Measured volume of flow during the reporting year, in million standard cubic feet. (5) Reciprocating compressors in onshore petroleum and natural gas production must report the information specified in paragraphs (p)(5)(i) through (p)(5)(iii) of this section. (i) Number of reciprocating compressors. PO 00000 Frm 00064 Fmt 4701 Sfmt 4702 (ii) Annual CO2 emissions, in metric tons CO2, from reciprocating compressors. (iii) Annual CH4 emissions, in metric tons CH4, from reciprocating compressors. (q) Equipment leak surveys. If your facility is subject to the requirements of § 98.233(q), then you must report the information specified in paragraphs (q)(1) and (q)(2) of this section. Natural gas distribution facilities must also report the information specified in paragraph (q)(3) of this section. (1) You must report the information specified in paragraphs (q)(1)(i) and (ii) of this section. (i) The number of complete equipment leak surveys performed during the calendar year. (ii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak survey cycle must report the number of years in the leak survey cycle. (2) You must indicate whether your facility contains any of the component types listed in § 98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), or (i)(1), for your facility’s industry segment. For each component type that is located at your facility, you must report the information specified in paragraphs (q)(2)(i) through (q)(2)(v) of this section. If a component type is located at your facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (q)(2)(v) of this section but report a zero (‘‘0’’) for the information required according to paragraphs (q)(2)(iii), (q)(2)(iv), and (q)(2)(v) of this section. (i) Component type. (ii) Total number of the surveyed component type that were identified as leaking in the calendar year (‘‘xp’’ in Equation W–30 of this subpart for the component type). (iii) Average time the surveyed components were found leaking and operational, in hours (average of ‘‘Tp,z’’ from Equation W–30 of this subpart for the component type). (iv) Annual CO2 emissions, in metric tons CO2, for the component type. (v) Annual CH4 emissions, in metric tons CH4, for the component type. (3) Natural gas distribution facilities must report the information specified in paragraphs (q)(3)(i) through (q)(3)(viii) of this section. (i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year. (ii) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in the calendar year (‘‘CountMR,y’’ from E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules Equation W–31 of this subpart, for the current calendar year). (iii) Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of ‘‘Tw,y’’ from Equation W–31 of this subpart, for the current calendar year). (iv) Number of above grade transmission-distribution transfer stations surveyed in the current leak survey cycle. (v) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in current leak survey cycle (sum of ‘‘CountMR,y’’ from Equation W–31 of this subpart, for all calendar years in the current leak survey cycle). (vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours (average of ‘‘Tw,y’’ from Equation W–31 of this subpart, for all years included in the leak survey cycle). (vii) Meter/regulator run CO2 emission factor based on all surveyed transmission-distribution transfer stations in the current leak survey cycle, in standard cubic feet of CO2 per meter/ regulator run operating hour (‘‘EFs,MR,i’’ for CO2 calculated using Equation W–31 of this subpart). (viii) Meter/regulator run CH4 emission factor based on all surveyed transmission-distribution transfer stations in the current leak survey cycle, in standard cubic feet of CH4 per meter/ regulator run operating hour (‘‘EFs,MR,i’’ for CH4 calculated using Equation W–31 of this subpart). (r) Equipment leaks by population count. If your facility is subject to the requirements of § 98.233(r), then you must report the information specified in paragraph (r)(1) of this section. Natural gas distribution facilities must also report the information specified in paragraph (r)(2) of this section. Onshore petroleum and natural gas production facilities must also report the information specified in paragraph (r)(3) of this section. (1) You must indicate whether your facility contains any of the emission source types covered by § 98.233(r), for the applicable industry segment. You must report the information specified in paragraphs (r)(1)(i) through (r)(1)(v) of this section separately for each emission source type that is located at your facility. Onshore petroleum and natural gas production facilities must report the information specified in paragraphs (r)(1)(i) through (r)(1)(v) of this section separately by component type, service type, and geographic location (i.e., Eastern U.S or Western U.S.). (i) Emission source type. Onshore petroleum and natural gas production VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 facilities must report the component type, service type and geographic location. (ii) Total number of the emission source type at the facility (‘‘Counte’’ in Equation W–32A of this subpart). (iii) Average estimated time that the emission source type was operational in the calendar year, in hours (‘‘Te’’ in Equation W–32A of this subpart). (iv) Annual CO2 emissions, in metric tons CO2, for the emission source type. (v) Annual CH4 emissions, in metric tons CH4, for the emission source type. (2) Natural gas distribution facilities must also report the information specified in paragraphs (q)(2)(i) through (q)(2)(viii) of this of this section. (i) Number of above grade transmission-distribution transfer stations at the facility. (ii) Number of above grade meteringregulating stations that are not transmission-distribution transfer stations at the facility. (iii) Number of below grade transmission-distribution transfer stations at the facility. (iv) Number of below grade meteringregulating stations that are not transmission-distribution transfer stations at the facility. (v) Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations (‘‘CountMR’’ in Equation W–32B of this subpart). (vi) Average estimated time that each meter/regulator run was operational in the calendar year, in hours per meter/ regulator run (‘‘Tw,avg’’ in Equation W– 32B of this subpart). (vii) Annual CO2 emissions, in metric tons CO2, from above grade metering regulating stations that are not above grade transmission-distribution transfer stations. (viii) Annual CH4 emissions, in metric tons CH4, from above grade metering regulating stations that are not above grade transmission-distribution transfer stations. (3) Onshore petroleum and natural gas production facilities must also report the information specified in paragraphs (r)(3)(i) and (r)(3)(ii) of this section. (i) Calculation method used. (ii) Onshore petroleum and natural gas production facilities must report the information specified in paragraphs (r)(3)(ii)(A) and (r)(3)(ii)(B) of this section, for each major equipment type, production type (i.e., natural gas or crude oil), and geographic location combination in Tables W–1B and W–1C of this subpart. (A) An indication of whether the facility contains the major equipment type. PO 00000 Frm 00065 Fmt 4701 Sfmt 4702 13457 (B) If the facility does contain the equipment type, the count of the major equipment type. (s) Offshore petroleum and natural gas production. You must report the information specified in paragraphs (s)(1) through (s)(3) of this section for each emission source type listed in the most recent BOEMRE study. (1) Annual CO2 emissions, in metric tons CO2. (2) Annual CH4 emissions, in metric tons CH4. (3) Annual N2O emissions, in metric tons N2O. (t) [Reserved] (u) [Reserved] (v) [Reserved] (w) EOR injection pumps. You must indicate whether CO2 EOR injection was used at your facility during the calendar year and if any EOR injection pump blowdowns occurred during the year. If any EOR injection pump blowdowns occurred during the calendar year, then you must report the information specified in paragraphs (w)(1) through (w)(8) of this section for each EOR injection pump system. (1) Sub-basin ID. (2) EOR injection pump system identifier. (3) Pump capacity, in barrels per day. (4) Total volume of EOR injection pump system equipment chambers, in cubic feet (‘‘Vv’’ in Equation W–37 of this subpart). (5) Number of blowdowns for the EOR injection pump system in the calendar year. (6) Density of critical phase EOR injection gas, in kilograms per cubic foot (‘‘Rc’’ in Equation W–37 of this subpart). (7) Mass fraction of CO2 in critical phase EOR injection gas (‘‘GHGCO2’’ in Equation W–37 of this subpart). (8) Annual CO2 emissions, in metric tons CO2, from EOR injection pump system blowdowns. (x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon liquids were produced through EOR operations. If hydrocarbon liquids were produced through EOR operations, you must report the information specified in paragraphs (x)(1) through (x)(4) of this section for each sub-basin category with EOR operations. (1) Sub-basin ID. (2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in barrels (‘‘Vhl’’ in Equation W–38 of this subpart). (3) Average CO2 retained in hydrocarbon liquids downstream of the storage tank, in metric tons per barrel under standard conditions (‘‘Shl’’ in Equation W–38 of this subpart). E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 13458 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules (4) Annual CO2 emissions, in metric tons CO2, from CO2 retained in hydrocarbon liquids produced through EOR operations downstream of the storage tank (‘‘MassCO2’’ in Equation W– 38 of this subpart). (y) [Reserved] (z) Combustion equipment at onshore petroleum and natural gas production facilities and natural gas distribution facilities. If your facility is required by § 98.232(c)(22) or (i)(7) to report emissions from combustion equipment, then you must indicate whether your facility has any combustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section. If your facility contains any combustion units subject to reporting according to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section, then you must report the information specified in paragraphs (z)(1) and (z)(2) of this section, as applicable. (1) Indicate whether the combustion units include: external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), then you must report the information specified in paragraphs (z)(1)(i) and (z)(1)(ii) of this section for each unit type. (i) The type of combustion unit. (ii) The total number of combustion units. (2) Indicate whether the combustion units include: external fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or, internal fuel combustion units of any heat capacity that are compressor-drivers. If your facility contains: external fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers, then you must report the information specified in VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 paragraphs (z)(2)(i) through (z)(2)(vi) for each combustion unit type and fuel type combination. (i) The type of combustion unit. (ii) The type of fuel combusted. (iii) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or tons. (iv) Annual CO2 emissions, in metric tons CO2, calculated according to § 98.233(z)(1) and (z)(2). (v) Annual CH4 emissions, in metric tons CH4, calculated according to § 98.233(z)(1) and (z)(2). (vi) Annual N2O emissions, in metric tons N2O, calculated according to § 98.233(z)(1) and (z)(2). (aa) Each facility must report the information specified in paragraphs (aa)(1) through (aa)(9) of this section, for each applicable industry segment, by using best available data. If a quantity required to be reported is zero, you must report zero as the value. (1) For onshore petroleum and natural gas production, report the data specified in paragraphs (aa)(1)(i) and (aa)(1)(ii) of this section. (i) Report the information specified in paragraphs (aa)(1)(i)(A) through (aa)(1)(i)(D) of this section for the basin as a whole. (A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production. (B) The quantity of gas produced in the calendar year for sales, in thousand standard cubic feet. (C) The quantity of crude oil produced in the calendar year for sales, not including lease condensates, in barrels. (D) The quantity of lease condensate produced in the calendar year for sales, in barrels. (ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (aa)(1)(ii)(M) of this section for each unique sub-basin category. (A) State. (B) County. (C) Formation type. (D) The number of producing wells at the end of the calendar year. (E) The number of producing wells acquired during the calendar year. (F) The number of producing wells divested during the calendar year. (G) The number of wells completed during the calendar year. (H) The number of wells taken out of production during the calendar year. (I) Average mole fraction of CH4 in produced gas. PO 00000 Frm 00066 Fmt 4701 Sfmt 4702 (J) Average mole fraction of CO2 in produced gas. (K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per barrel. (L) If an oil sub-basin, report the average API gravity of all wells. (M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch gauge. (2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) through (aa)(2)(iii) of this section. (i) The quantity of gas produced from the offshore platform in the calendar year for sales, in thousand standard cubic feet. (ii) The quantity of oil produced from the offshore platform in the calendar year for sales, in barrels. (iii) The quantity of condensate produced from the offshore platform in the calendar year for sales, in barrels. (3) For natural gas processing, report the quantities specified in paragraphs (aa)(3)(i) through (aa)(3)(vii) of this section. (i) The quantity of produced gas received at the gas processing plant in the calendar year, in thousand standard cubic feet. (ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, in thousand standard cubic feet. (iii) The quantity of NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels. (iv) The quantity of NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels. (v) Average mole fraction of CH4 in produced gas received. (vi) Average mole fraction of CO2 in produced gas received. (vii) Indicate whether the facility fractionates NGLs. (4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) through (aa)(4)(v) of this section. (i) The quantity of gas transported through the compressor station in the calendar year, in thousand standard cubic feet. (ii) Number of compressors. (iii) Total compressor power rating of all compressors combined, in horsepower. (iv) Average upstream pipeline pressure, in pounds per square inch gauge. (v) Average downstream pipeline pressure, in pounds per square inch gauge. (5) For underground natural gas storage, report the quantities specified E:\FR\FM\10MRP2.SGM 10MRP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules in paragraphs (aa)(5)(i) through (aa)(5)(iii) of this section. (i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet. (ii) The quantity of gas withdrawn from storage in the calendar year, in thousand standard cubic feet. (iii) Total storage capacity, in thousand standard cubic feet. (6) For LNG import equipment, report the quantity of LNG imported in the calendar year, in thousand standard cubic feet. (7) For LNG export equipment, report the quantity of LNG exported in the calendar year, in thousand standard cubic feet. (8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (aa)(8)(iii) of this section. (i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet. (ii) The quantity of LNG withdrawn from storage in the calendar year, in thousand standard cubic feet. (iii) Total storage capacity, in thousand standard cubic feet. (9) For natural gas distribution, report the quantities specified in paragraphs (aa)(9)(i) through (aa)(9)(vii) of this section. (i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report. (ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in thousand standard cubic feet. (iii) The quantity of natural gas added to in-system storage in the calendar year, in thousand standard cubic feet. (iv) The quantity of natural gas delivered to end users, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for. (v) The quantity of natural gas transferred to third parties such as other LDCs or pipelines, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for. (vi) The quantity of natural gas consumed by the LDC for operational purposes, in thousand standard cubic feet. (vii) The estimated quantity of gas stolen in the calendar year, in thousand standard cubic feet. (bb) For any missing data procedures used, report the information in paragraphs (bb)(1) through (bb)(5) in VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 this section for each individual missing data value used in a calculation. Aggregation of missing data values within a component, well, sub-basin, or basin is not acceptable. If missing data is substituted for the same parameter in non-consecutive periods during the calendar year, the information in paragraphs (bb)(1) through (bb)(5) in this section should be reported for each period separately. (1) The date(s) the missing data is used. (2) The equation(s) in which the missing data is used. (3) The description of the unique or unusual circumstance that led to missing data use, including information on any equipment or components involved and any procedures that were not followed. (4) The description of the procedures used to substitute an unavailable value of a parameter. (5) The description of how the owner or operator will avoid the use of missing data in the future, such as mitigation strategies or changes to standard operating procedures. ■ 9. Section 98.238 is amended by: ■ a. Adding a definition for ‘‘Associated gas venting or flaring’’ in alphabetical order; ■ b. Removing the definition for ‘‘Component’’; ■ c. Adding definitions for ‘‘Compressor mode’’ and ‘‘Compressor source’’ in alphabetical order; ■ d. Removing the definitions for ‘‘Equipment leak’’ and ‘‘Equipment leak detection’’; ■ e. Adding definitions for ‘‘Manifolded compressor source’’ and ‘‘Manifolded group of compressor sources’’ in alphabetical order; ■ f. Revising the definition for ‘‘Meter/ regulator run’’; ■ g. Adding definitions for ‘‘Reduced emissions completion’’ and ‘‘Reduced emissions workover’’ in alphabetical order; and ■ h. Revising the definition for ‘‘Subbasin category, for onshore natural gas production’’. The revisions and additions read as follows: § 98.238 Definitions. * * * * * Associated gas venting or flaring means the venting or flaring of natural gas which 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. This does not include venting or flaring resulting from activities that are reported elsewhere, including tank PO 00000 Frm 00067 Fmt 4701 Sfmt 4702 13459 venting, well completions, and well workovers. * * * * * Compressor mode means the operational and pressurized status of a compressor. For a centrifugal compressor, ‘‘mode’’ refers to either operating -mode or not-operatingdepressurized -mode. For a reciprocating compressor, ‘‘mode’’ refers to either: operating -mode, standbypressurized -mode, or not-operatingdepressurized -mode. Compressor source means any type of vent or valve (i.e., wet seal, blowdown valve, isolation valve, or rod packing) on a centrifugal or reciprocating compressor. * * * * * Manifolded compressor source means a compressor source (as defined in this section) that is manifolded to a common vent that routes gas from multiple compressors. Manifolded group of compressor sources means a collection of any combination of manifolded compressor sources (as defined in this section) that are manifolded to a common vent. Meter/regulator run means a series of components used in regulating pressure or metering natural gas flow or both. At least one meter, at least on regulator, or any combination of both on a single run of piping is considered one meter/ regulator run. * * * * * Reduced emissions completion means a well completion following hydraulic fracturing where gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere. Reduced emissions workover means a well workover with hydraulic fracturing (i.e., refracturing) where gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere. * * * * * Sub-basin category, for onshore natural gas production, means a subdivision of a basin into the unique combination of wells with the surface coordinates within the boundaries of an individual county and subsurface completion in one or more of each of the following five formation types: Oil, high E:\FR\FM\10MRP2.SGM 10MRP2 13460 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 permeability gas, shale gas, coal seam, or other tight gas reservoir rock. The distinction between high permeability gas and tight gas reservoirs shall be designated as follows: High permeability gas reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs with ≤0.1 millidarcy permeability. Permeability for a reservoir type shall be determined by engineering estimate. Wells that produce only from high permeability VerDate Mar<15>2010 18:44 Mar 07, 2014 Jkt 232001 gas, shale gas, coal seam, or other tight gas reservoir rock are considered gas wells; gas wells producing from more than one of these formation types shall be classified into only one type based on the formation with the most contribution to production as determined by engineering knowledge. All wells that produce hydrocarbon liquids (with or without gas) and do not meet the definition of a gas well in this sub-basin category definition are PO 00000 Frm 00068 Fmt 4701 Sfmt 9990 considered to be in the oil formation. All emission sources that handle condensate from gas wells in high permeability gas, shale gas, or tight gas reservoir rock formations are considered to be in the formation that the gas well belongs to and not in the oil formation. * * * * * [FR Doc. 2014–04408 Filed 3–7–14; 8:45 am] BILLING CODE 6560–50–P E:\FR\FM\10MRP2.SGM 10MRP2

Agencies

ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 79, Number 46 (Monday, March 10, 2014)]
[Proposed Rules]
[Pages 13393-13460]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-04408]



[[Page 13393]]

Vol. 79

Monday,

No. 46

March 10, 2014

Part II





Environmental Protection Agency





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40 CFR Part 98





Greenhouse Gas Reporting Rule: Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems; Proposed Rule

Federal Register / Vol. 79 , No. 46 / Monday, March 10, 2014 / 
Proposed Rules

[[Page 13394]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2011-0512; FRL-9906-85-OAR]
RIN 2060-AR96


Greenhouse Gas Reporting Rule: Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The EPA is proposing revisions and confidentiality 
determinations for the petroleum and natural gas systems source 
category and the general provisions of the Greenhouse Gas Reporting 
Rule. In particular, the EPA is proposing to revise certain calculation 
methods, amend certain monitoring and data reporting requirements, 
clarify certain terms and definitions, and correct certain technical 
and editorial errors that have been identified during the course of 
implementation. This action also proposes confidentiality 
determinations for new or substantially revised data elements contained 
in these proposed amendments, as well as proposes a revised 
confidentiality determination for one existing data element.

DATES: Comments. Comments must be received on or before April 24, 2014.
    Public Hearing. The EPA does not plan to conduct a public hearing 
unless requested. To request a hearing, please contact the person 
listed in the following FOR FURTHER INFORMATION CONTACT section by 
March 17, 2014. If requested, the hearing will be conducted on March 
25, 2014, in the Washington, DC area. The EPA will provide further 
information about the hearing on the Greenhouse Gas Reporting Rule Web 
site, https://www.epa.gov/ghgreporting/ if a hearing is 
requested.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2011-0512 by any of the following methods:
     Federal eRulemaking Portal: https://www.regulations.gov. 
Follow the online instructions for submitting comments.
     Email: GHG_Reporting_Rule_Oil_And_Natural_Gas@epa.gov. Include Docket ID No. EPA-HQ-OAR-2011-0512 or RIN No. 
2060-AR96 in the subject line of the message.
     Fax: (202) 566-9744.
     Mail: Environmental Protection Agency, EPA Docket Center 
(EPA/DC), Mailcode 28221T, Attention Docket ID No. OAR-2011-0512, 1200 
Pennsylvania Avenue NW., Washington, DC 20460.
     Hand/Courier Delivery: EPA Docket Center, Public Reading 
Room, William Jefferson Clinton (WJC) West Building, Room 3334, 1301 
Constitution Avenue NW., Washington, DC 20004. Such deliveries are 
accepted only during the normal hours of operation of the Docket 
Center, and special arrangements should be made for deliveries of boxed 
information.
    Additional Information on Submitting Comments: To expedite review 
of your comments by agency staff, you are encouraged to send a separate 
copy of your comments, in addition to the copy you submit to the 
official docket, to Carole Cook, U.S. EPA, Office of Atmospheric 
Programs, Climate Change Division, Mail Code 6207-J, 1200 Pennsylvania 
Avenue NW., Washington, DC 20460, telephone (202) 343-9263, email 
address: GHGReportingRule@epa.gov.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2011-0512, Greenhouse Gas Reporting Rule: Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems; Proposed Rule. 
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 confidential 
business information (CBI) or other information whose disclosure is 
restricted by statute.
    Should you choose to submit information that you claim to be CBI, 
clearly mark the part or all of the information that you claim to be 
CBI. For information that you claim to be CBI in a disk or CD-ROM that 
you mail to the EPA, mark the outside of the disk or CD-ROM as CBI and 
then identify electronically within the disk or CD-ROM the specific 
information that is claimed as CBI. In addition to one complete version 
of the comment that includes information claimed as CBI, a copy of the 
comment that does not contain the information claimed as CBI must be 
submitted for inclusion in the public docket. 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 to only 
the mail or hand/courier delivery address listed above, attention: 
Docket ID No. EPA-HQ-OAR-2011-0512. If you have any questions about CBI 
or the procedures for claiming CBI, please consult the person 
identified in the FOR FURTHER INFORMATION CONTACT section.
    Do not submit information that you consider to be CBI or otherwise 
protected through https://www.regulations.gov or email. The https://www.regulations.gov Web site is an ``anonymous access'' system, 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 disk or 
CD-ROM 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 avoid the use 
of special characters, any form of encryption, and be free of any 
defects or viruses.
    Docket: All documents in the docket are listed in the https://www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in https://www.regulations.gov or in hard copy at the Air Docket, EPA/
DC, WJC West Building, Room 3334, 1301 Constitution Ave. NW., 
Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30 
p.m., Monday through Friday, excluding legal holidays. The telephone 
number for the Public Reading Room is (202) 566-1744, and the telephone 
number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division, 
Office of Atmospheric Programs (MC-6207J), Environmental Protection 
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone 
number: (202) 343-9263; fax number: (202) 343-2342; email address: 
GHGReportingRule@epa.gov. For technical information, please go to the 
Greenhouse Gas Reporting Rule Web site, https://www.epa.gov/
ghgreporting/

[[Page 13395]]

index.html. To submit a question, select Help Center, followed by 
``Contact Us.''
    Worldwide Web (WWW). In addition to being available in the docket, 
an electronic copy of today's proposal will also be available through 
the WWW. Following the Administrator's signature, a copy of this action 
will be posted on EPA's Greenhouse Gas Reporting Rule Web site at 
https://www.epa.gov/ghgreporting/.

SUPPLEMENTARY INFORMATION: 
    Regulated Entities. The Administrator determined that this action 
is subject to the provisions of Clean Air Act (CAA) section 307(d). See 
CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to 
``such other actions as the Administrator may determine''). These are 
proposed amendments to existing regulations. If finalized, these 
amended regulations would affect owners or operators of petroleum and 
natural gas systems that directly emit greenhouse gases (GHGs). 
Regulated categories and entities include those listed in Table 1 of 
this preamble:

           Table 1--Examples of Affected Entities by Category
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                                                   Examples of affected
            Category                  NAICS             facilities
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Petroleum and Natural Gas                486210  Pipeline transportation
 Systems.                                         of natural gas.
                                         221210  Natural gas
                                                  distribution.
                                         211111  Crude petroleum and
                                                  natural gas
                                                  extraction.
                                         211112  Natural gas liquid
                                                  extraction.
------------------------------------------------------------------------

    Table 1 of this preamble is not intended to be exhaustive, but 
rather provides a guide for readers regarding facilities likely to be 
affected by this action. Other types of facilities than those listed in 
the table could also be subject to reporting requirements. To determine 
whether you are affected by this action, you should carefully examine 
the applicability criteria found in 40 CFR part 98, subpart A and 40 
CFR part 98, subpart W. If you have questions regarding the 
applicability of this action to a particular facility, consult the 
person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

BAMM best available monitoring methods
CAA Clean Air Act
CBI confidential business information
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e carbon dioxide equivalent
EIA Energy Information Administration
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FERC Federal Energy Regulatory Commission
FR Federal Register
GHG greenhouse gas
GOR gas to oil ratio
GWP global warming potential
LNG liquefied natural gas
MMscf million standard cubic feet per day
N2O nitrous oxide
NAICS North American Industry Classification System
NGL natural gas liquids
NTTAA National Technology Transfer and Advancement Act
OMB Office of Management and Budget
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
scf standard cubic feet
TSD Technical Support Document
UIC underground injection control
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995

Organization of This Document. The following outline is provided to aid 
in locating information in this preamble.

I. Background
    A. Organization of This Preamble
    B. Background on the Proposed Action
    C. Legal Authority
    D. How would these amendments apply to 2014 and 2015 reports?
II. Revisions and Other Amendments
    A. Proposed Revisions To Provide Consistency Throughout Subpart 
W
    B. Proposed Changes to Calculation Methods and Reporting 
Requirements
    C. Proposed Revisions to Missing Data Provisions
    D. Proposed Amendments to Best Available Monitoring Methods
III. Proposed Confidentiality Determinations
    A. Overview and Background
    B. Approach to Proposed CBI Determinations for New or Revised 
Subpart W Data Elements
    C. Proposed Confidentiality Determinations for Data Elements 
Assigned to the ``Unit/Process `Static' Characteristics That Are Not 
Inputs to Emission Equations'' and ``Unit/Process Operating 
Characteristics That Are Not Inputs to Emission Equations'' Data 
Categories
    D. Other Proposed or Re-Proposed Case-by-Case Confidentiality 
Determinations for Subpart W
    E. Request for Comments on Proposed Confidentiality 
Determinations
IV. Impacts of the Proposed Amendments to Subpart W
V. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    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 That Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

I. Background

A. Organization of This Preamble

    The first section of this preamble provides background information 
regarding the origin of the proposed amendments. This section also 
discusses the EPA's legal authority under the CAA to promulgate and 
amend 40 CFR part 98 of the Greenhouse Gas Reporting Rule (hereinafter 
referred to as ``Part 98'') as well as the legal authority for making 
confidentiality determinations for the data to be reported. Section II 
of this preamble contains information on the proposed revisions to 40 
CFR part 98, subpart W (hereafter referred to as ``subpart W''). 
Section III of this preamble discusses proposed confidentiality 
determinations for new or substantially revised (i.e., requiring 
additional or different data to be reported) data reporting elements, 
as well as a proposed revised confidentiality determination for one 
existing data element. Section IV of this preamble discusses the 
impacts of the proposed amendments to subpart W. Finally, Section V of 
this preamble describes the statutory and executive order requirements 
applicable to this action.

B. Background on the Proposed Action

    On October 30, 2009, the EPA published Part 98 for collecting 
information regarding greenhouse gases (GHGs) from a broad range of 
industry sectors (74 FR 56260). The 2009 rule,

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which finalized reporting requirements for 29 source categories, did 
not include the petroleum and natural gas systems source category. A 
subsequent rule was published on November 20, 2010 finalizing the 
requirements for the petroleum and natural gas systems source category 
at 40 CFR part 98, subpart W (75 FR 74458) (hereafter referred to as 
``the final subpart W rule''). Following promulgation, the EPA 
finalized actions revising subpart W (76 FR 22825, April 25, 2011; 76 
FR 59533, September 27, 2011; 76 FR 80554, December 23, 2011; 77 FR 
51477, August 24, 2012; 78 FR 25392, May 1, 2013; 78 FR 71904, Nov. 29, 
2013).
    In this action, the EPA is proposing to make certain revisions to 
the petroleum and natural gas systems source category GHG reporting 
requirements (Part 98, subpart W) and one clarifying edit to a 
definition in the general provisions source category (Part 98, subpart 
A). The proposed changes revise certain calculation methods, amend 
certain monitoring and data reporting requirements, clarify certain 
terms and definitions, and correct certain technical and editorial 
errors identified during the course of implementation. The proposed 
revisions were identified from the verification of annual reports, 
review of Best Available Monitoring Method (BAMM) request submittals, 
and questions raised by reporting entities. In conjunction with this 
action, we are proposing confidentiality determinations for the new and 
substantially revised (i.e., requiring additional or different data to 
be reported) data elements contained in these proposed amendments, as 
well as proposing a revised confidentiality determination for one 
existing data element.

C. Legal Authority

    The EPA is proposing these rule amendments under its existing CAA 
authority provided in CAA section 114. As stated in the preamble to the 
2009 final GHG reporting rule (74 FR 56260, October 30, 2009), CAA 
section 114(a)(1) provides the EPA broad authority to require the 
information proposed to be gathered by this rule because such data 
would inform and are relevant to the EPA's carrying out a wide variety 
of CAA provisions. See the preambles to the proposed (74 FR 16448, 
April 10, 2009) and final GHG reporting rule (74 FR 56260, October 30, 
2009) for further information.
    In addition, the EPA is proposing confidentiality determinations 
for proposed new or substantially revised data elements in subpart W, 
as well as proposing a revised confidentiality determination for one 
existing data element, under its authorities provided in sections 114, 
301, and 307 of the CAA. Section 114(c) requires that the EPA make 
information obtained under section 114 available to the public, except 
where information qualifies for confidential treatment. The 
Administrator has determined that this action is subject to the 
provisions of section 307(d) of the CAA.

D. How would these amendments apply to 2014 and 2015 reports?

    The EPA is planning to address the comments we receive on these 
proposed changes and publish the final amendments before the end of 
2014. If finalized, these amendments would become effective on January 
1, 2015. Facilities would therefore be required to follow the revised 
methods in subpart W, as amended, to calculate emissions beginning 
January 1, 2015 (i.e., beginning with the 2015 reporting year). The 
first annual reports of emissions calculated using the amended 
requirements would be those submitted by March 31, 2016, which would 
cover the 2015 reporting year. For the 2014 reporting year, reporters 
would continue to calculate emissions and other relevant data for the 
reports that are submitted according to the requirements of 40 CFR part 
98 that are applicable to the 2014 reporting year (i.e. those currently 
in effect).

II. Revisions and Other Amendments

    The amendments to subpart W that the EPA is proposing include the 
following types of changes:
     Changes to clarify or simplify calculation methods for 
certain sources at a facility, and reduce some of the burden associated 
with data collection and reporting.
     Revisions to units of measure, terms, and definitions in 
certain equations to provide consistency throughout the rule, provide 
clarity, or better reflect facility operations.
     Revisions to reporting requirements to clarify and align 
more closely with the calculation methods and to clearly identify the 
data that must be reported for each source type.
     Other amendments and revisions identified as a result of 
working with the affected sources during rule implementation and 
outreach.
    In addition to the specific revisions or amendments discussed in 
this section of the preamble, the EPA is proposing several minor 
technical revisions to subpart W to improve readability, to create 
consistency in terminology, and/or to correct typographical or other 
errors. These proposed revisions contained in the proposed regulatory 
text are further explained in the memorandum, ``Proposed Minor 
Technical Corrections to Subpart W, Petroleum and Natural Gas Systems, 
in the Greenhouse Gas Reporting Program'' in Docket ID No. EPA-HQ-OAR-
2011-0512. The EPA invites public comment on the revisions identified 
in this memorandum, as well as those outlined in this preamble.

A. Proposed Revisions To Provide Consistency Throughout Subpart W

1. Consistency in Units of Measure for Emissions Reporting
    Currently, subpart W requires that reported GHG emissions be 
expressed in metric tons of CO2 equivalent 
(CO2e). The EPA is proposing to amend 40 CFR 98.236 to 
revise the reporting of GHG emissions from units of metric tons of 
CO2e of each reported GHG to metric tons of each reported 
GHG. These proposed changes would increase consistency between the 
reporting requirements for subpart W and the rest of Part 98, because 
other subparts of Part 98 generally require the reporting of metric 
tons of individual GHGs instead of metric tons of CO2e. 
Reporters would use the global warming potentials (GWPs) in Table A-1 
of 40 CFR Part 98, subpart A, as required in 40 CFR 98.2(b)(4), to 
calculate annual emissions aggregated for all GHGs from all applicable 
source categories in metric tons of CO2e for their annual 
reports.
    Specifically, we are proposing to revise the units of emissions 
reported in 40 CFR 98.236 to require reporting in metric tons of 
methane (CH4), carbon dioxide (CO2), and nitrous 
oxide (N2O), as applicable, instead of reporting each gas in metric 
tons of CO2e. We are also proposing to revise certain 
calculation methods that require the calculation of emissions in 
CO2e. For example, subpart W total GHG emissions are 
calculated using equations that reference GWPs (Equations W-36 and W-
40). We are proposing to amend each equation referencing GWPs 
separately to remove the conversion factors and GWPs that are built 
into the equations, and allow for calculation of individual GHG 
emissions in metric tons.
    The proposed revisions reduce the likelihood of errors and 
inconsistencies, because it reduces the number of calculations that 
need to be completed by reporters and removes some variability in how 
different reporters may complete these calculations (e.g., a reporter 
could inadvertently use the wrong GWP). The proposed changes would also 
simplify analysis of emissions on a GHG-specific basis,

[[Page 13397]]

which would facilitate the verification of reported data. In addition, 
this proposed change would align subpart W with the manner of reporting 
for most other subparts of Part 98.
2. Onshore Production Source Category Definition
    We are proposing to revise the source category definition of 
onshore petroleum and natural gas production at 40 CFR 98.230(a)(2) to 
clarify the emission sources covered for purposes of GHG reporting. The 
proposed amendments clarify the types of emission sources in the 
onshore petroleum and natural gas production source category to which 
the reporting requirements of subpart W apply. Specifically, we are 
proposing to add references to engines, boilers, heaters, flares, 
separation and processing equipment, and maintenance and repair 
equipment and to remove references to gravity separation equipment and 
auxiliary non-transportation-related equipment. Thus, the first 
sentence of 40 CFR 98.230(a)(2) is proposed to read as follows: 
``Onshore petroleum and natural gas production means all equipment on a 
single well-pad or associated with a single well-pad (including but not 
limited to compressors, generators, dehydrators, storage vessels, 
engines, boilers, heaters, flares, separation and processing equipment, 
and portable non-self-propelled equipment which includes well drilling 
and completion equipment, workover equipment, maintenance and repair 
equipment, and leased, rented or contracted equipment) used in the 
production, extraction, recovery, lifting, stabilization, separation or 
treating of petroleum and/or natural gas (including condensate).'' The 
references to gravity separation equipment and auxiliary non-
transportation-related equipment in the current rule are redundant with 
other sources specified in the definition. The proposed amendments do 
not subject new emission sources to the reporting requirements and do 
not remove sources currently covered from the reporting requirements, 
but rather provide a more accurate description of the industry segment 
for purposes of GHG reporting.
3. Definition of Sub-Basin Category
    The EPA is proposing to revise the definition of sub-basin category 
at 40 CFR 98.238 to clarify coverage for purposes of GHG reporting due 
to issues identified during implementation. Specifically, we are 
proposing to define sub-basin category as ``a subdivision of a basin 
into the unique combination of wells with the surface coordinates 
within the boundaries of an individual county and subsurface completion 
in one or more of each of the following five formation types: Oil, high 
permeability gas, shale gas, coal seam, or other tight gas reservoir 
rock. The distinction between high permeability gas and tight gas 
reservoirs shall be designated as follows: High permeability gas 
reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs 
with <=0.1 millidarcy permeability. Permeability for a reservoir type 
shall be determined by engineering estimate. Wells that produce only 
from high permeability gas, shale gas, coal seam, or other tight gas 
reservoir rock are considered gas wells; gas wells producing from more 
than one of these formation types shall be classified into only one 
type based on the formation with the most contribution to production as 
determined by engineering knowledge. All wells that produce hydrocarbon 
liquids (with or without gas) and do not meet the definition of a gas 
well in this sub-basin category definition are considered to be in the 
oil formation. All emission sources that handle condensate from gas 
wells in high permeability gas, shale gas, or tight gas reservoir rock 
formations are considered to be in the formation that the gas well 
belongs to and not in the oil formation.'' The EPA is proposing these 
edits to clarify that ``tight gas reservoir rock'' generally refers to 
tight reservoir rock formations that produce gas, and not tight 
reservoir rock formations that produce only oil, and that wells that 
produce liquids in a sub-basin from formations other than high 
permeability gas, shale gas, coal seam, or other tight gas reservoir 
rock are considered oil wells.

B. Proposed Changes to Calculation Methods and Reporting Requirements

    This section describes proposed changes or corrections to 
calculation methods and reporting requirements. In general, the 
proposed revisions to calculation methods would provide greater 
flexibility and potentially reduce burden to facilities (e.g., by 
increasing options for calculating emissions from compressors), and 
increase clarity and congruency of calculation and reporting 
requirements (e.g., by clarifying which reporting requirements apply to 
which calculation methods). The EPA is also proposing minor technical 
revisions to the calculation methods of subpart W, such as making 
equation variables and definitions consistent across multiple equations 
that identify the same parameters, or clarifying requirements that have 
caused confusion. Please see the memo, ``Proposed Minor Technical 
Corrections to Subpart W, Petroleum and Natural Gas Systems, in the 
Greenhouse Gas Reporting Program'' in Docket ID No. EPA-HQ-OAR-2011-
0512, for more information on the minor technical revisions included in 
this proposal.
    We are also proposing revisions to the reporting requirements in 40 
CFR 98.236. The proposed revisions would restructure the reporting 
requirements, make reporting requirements consistent with the 
calculation methods, clarify the data elements to be reported, and 
improve data utility. In the current subpart W rule, slight 
inconsistencies between the calculation and the reporting sections have 
caused confusion among some reporters. In order to improve the quality 
of the data reported, we are proposing to revise reporting requirements 
that more clearly align with the calculation methods for each source 
type.
    We are proposing to reorganize the reporting section by source type 
(e.g., natural gas pneumatic device venting, acid gas removal vents, 
etc.) and, for each industry segment, list which source types must be 
reported. These proposed changes would clarify the reporting 
requirements for each industry segment and streamline verification by 
reducing the amount of correspondence with facilities during 
verification regarding required data elements that were not reported. 
Although the proposed reporting requirements appear lengthier, the 
revisions separate the requirements into discrete reporting elements in 
order to facilitate reporting and improve data collection. The proposed 
revisions to the reporting requirements in 40 CFR 98.236 will clarify 
which data elements are required to be reported for which facilities. 
For example, in reviewing the current subpart W reporting forms, if a 
reporter left certain fields blank in the reporting form (e.g., 
emissions from flaring), the EPA has been unable to discern whether the 
field was left blank intentionally. Because the proposed 40 CFR 98.236 
would clearly define each data element for each emission source in each 
industry segment that must be reported, it would clarify which fields 
in the subpart W reporting form should be populated. In some cases, we 
are also proposing to add additional data elements to improve the 
quality of the data reported. The reporting of these proposed data 
elements would improve verification of reported emissions and reduce 
the amount of correspondence with reporters that is associated with 
follow-up and revision of annual reports. In nearly all cases, the new 
data elements are based on data that are

[[Page 13398]]

already collected by the reporter or are readily available to the 
reporter, and would not require additional monitoring or data 
collection. For additional information on the proposed changes to the 
reporting section, see the memo, ``Proposed Revisions to the Subpart W 
Reporting Requirements'' in Docket Id. No. EPA-HQ-OAR-2011-0512.
1. Natural Gas Pneumatic Device Venting
    The EPA is proposing to revise the calculation method for natural 
gas pneumatic device venting to expand the use of site-specific data on 
gas compositions, if available, for facilities in the onshore natural 
gas transmission compression and underground natural gas storage 
industry segments. The final subpart W rule provides default natural 
gas compositions of 95 percent CH4 and 1 percent 
CO2 for onshore natural gas transmission compression and 
underground natural gas storage, when calculating CH4 and 
CO2 volumetric emissions from transmission storage tanks 
(transmission compression), blowdown vent stacks (transmission 
compression), and compressor venting (40 CFR 98.233(u)(2)(iii) and 
(iv)). The provisions of 40 CFR 98.233(u)(2) only allow default gas 
compositions to be used, unless otherwise specified in 40 CFR 
98.233(u)(2) (i.e., for onshore production and natural gas processing).
    We are proposing to allow either the use of site-specific 
composition data for natural gas transmission compression and 
underground natural gas storage facilities or the use of a default gas 
composition (95 percent CH4 and 1 percent CO2). 
Specifically, we are proposing to revise the parameter ``GHGi'' in 
Equation W-1 to remove the default gas composition for CH4 
and CO2 and to direct reporters to use the concentrations 
determined as specified in 40 CFR 98.233(u)(2)(i), (iii), and (iv). 
This amendment addresses reporter concerns and improves data quality 
for those using site-specific data. The proposed changes are consistent 
with provisions for other applicable emission sources at natural gas 
transmission compression and underground storage facilities and would 
allow a consistent gas composition to be used for all sources at a 
facility. The calculation still must be conducted in much the same way 
that is currently required; however, we are proposing that reporters be 
allowed to use site-specific data if they are available. Therefore, the 
EPA does not anticipate that this proposed change will significantly 
affect the reporting burden. The EPA requests comment on whether the 
use of site-specific composition data for calculating emissions should 
be required or optional. The EPA also requests comment and specific 
details on when, if ever, a facility would not have site-specific gas 
composition data available.
    We are also proposing to revise the natural gas pneumatic device 
venting calculations (40 CFR 98.233(a)(1), (a)(2), and (a)(3)) to 
simplify how ``Countt'' of Equation W-1 (total number of 
natural gas pneumatic devices) must be calculated each year as new 
devices are added. The revisions clarify that for all industry 
segments, the reported number of devices must represent the total 
number of devices for the reporting year. For the onshore petroleum and 
natural gas production industry segment, reporters would continue to 
have the option in the first two reporting years to estimate 
``Countt'' using engineering estimates.
2. Acid Gas Removal Vents
    For acid gas removal vents, we are proposing minor clarifying edits 
to 40 CFR 98.233(d) to clearly label each calculation method and to 
clarify provisions by providing references to equations where 
appropriate. We are also proposing to revise the parameters 
``VolCO2'' in Equation W-3 and parameters 
``VolI'' and ``VolO'' in Equation W-4A and W-4B 
to clarify that the volumetric fraction used should be the annual 
average. We are also proposing to specify in 40 CFR 98.233(d)(8) that 
reporters may use sales line quality specifications for CO2 
in natural gas only if a continuous gas analyzer is not available.
3. Dehydrators
    We are proposing to revise the dehydrator vents source by 
renumbering and revising the dehydrator calculation method for 
desiccant dehydrators in order to clarify the adjustment of emissions 
to account for venting to a vapor recovery system or to a flare (40 CFR 
98.233(e)). The proposed amendments provide for the adjustment of 
emissions vented to a vapor recovery system or flare (40 CFR 
98.233(e)(5) and (e)(6)) for desiccant dehydrators because in the final 
subpart W rule, it was not clear how such an adjustment would be made. 
As such, we are clarifying the calculation methods for desiccant 
dehydrators that vent to a flare or vapor recovery device.
4. Well Venting for Liquids Unloading
    The EPA is proposing to revise the calculation and reporting 
requirements for well venting from liquids unloading to allow for 
annualizing venting data for facilities that calculate emissions using 
a recording flow meter (Calculation Method 1). This proposed amendment 
would address reporter concerns and simplify reporting. Some reporters 
have expressed difficulty in collecting well venting data using a 
recording flow meter for the exact period of January 1 to December 31, 
because they contend that it would require them to be physically 
present at each recording flow meter on December 31. The EPA is 
proposing to revise Calculation Method 1 (40 CFR 98.233(f)(1)) such 
that reporters may use an annualized value to determine the cumulative 
amount of time of venting (``Tp'' in Equation W-7A and W-7B) 
if data are not available for the specific time period January 1 to 
December 31. We are specifying that if an annualized value is used, the 
monitoring period must begin before February 1 and must not end before 
December 1 of the reporting year, and that a minimum of 300 consecutive 
days must be used by reporters to determine the annualized vent time. 
The EPA is also proposing that the date of the end of one monitoring 
period must be the start of the next monitoring period for the next 
reporting year, and that all days must be monitored and all venting 
accounted for. We are proposing that if a reporter uses a monitoring 
period other than a full calendar year for any well, they must report 
the percentage of wells for which a monitoring period other than a full 
calendar year is used. Although the proposed change increases 
flexibility, the calculation still must be conducted in much the same 
way that is currently required. Therefore, the EPA does not anticipate 
that this proposed change will significantly affect reporting burden.
    We are proposing to change Calculation Method 1 at 40 CFR 
98.233(f)(1) to separate the calculation and reporting of emissions 
from wells that have plunger lifts and wells that do not have plunger 
lifts. This separation would allow the EPA and the public to more 
easily disaggregate emission data and activity data for wells that have 
plunger lifts and wells that do not have plunger lifts. We are 
proposing a clarification to Calculation Method 2 in 40 CFR 
98.233(f)(2) to clarify that this method is used for wells without 
plunger lifts.
    In a harmonizing change, the EPA is proposing to revise the 
reporting requirement for reporters using Calculation Method 1, under 
40 CFR 98.236 such that reporters would be required to report the 
cumulative amount of time of venting for each group of wells during the 
year. Calculation Method 1 uses the cumulative amount of time of 
venting and not the number of venting events,

[[Page 13399]]

to calculate emissions; therefore, this revision would align the 
reporting requirement with the calculation method. We are proposing 
harmonizing changes to 40 CFR 98.236 to separate the reporting of 
emissions from wells with and without plunger lifts when Calculation 
Method 1 is used.
    We are also proposing to amend the definition of the term ``SPp'' 
in Equation W-8 (40 CFR 98.233(f)(2)) to clarify that if casing 
pressure is not available for each well, reporters may determine the 
casing pressure using a ratio of the casing pressure to tubing pressure 
from a well in the same sub-basin where the casing pressure is known. 
This amendment would improve the consistency of the calculation method 
used to determine casing pressure across reporters.
    We are also proposing to revise 40 CFR 98.236 to require that 
facilities using Calculation Methods 1, 2, and 3 report a separate 
count of wells with plunger lifts and wells without plunger lifts, and 
to report annual emissions separately from each of those sources, 
respectively. We are also proposing to amend 40 CFR 98.236 to require 
the reporting of the cumulative number of unloadings from wells with 
plunger lifts and unloadings from wells without plunger lifts, the 
average flow rate of the measured well venting for wells with and 
without plunger lifts, and the internal casing or tubing diameters and 
pressures for wells with and without plunger lifts, as applicable. 
These proposed revisions break out the existing count and emissions 
reporting requirements to more clearly specify the sources of emissions 
at facilities. For further information on well venting for liquids 
unloading, see the Technical Support Document (TSD) ``Greenhouse Gas 
Reporting Rule: Technical Support for Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems; Proposed Rule'' 
in Docket ID No. EPA-HQ-OAR-2011-0512.
5. Gas Well Completions And Workovers
    The EPA is proposing to amend 40 CFR 98.238 to add definitions for 
``reduced emissions completion'' and ``reduced emissions workover''. 
Currently, reduced emissions completions and reduced emission workovers 
are mentioned in the relevant calculation method as equipment that 
separates natural gas from the backflow and sends this natural gas to a 
flow-line. However, there are currently no defined terms for reduced 
emissions completions and reduced emissions workovers. The EPA notes 
that since the time that subpart W was promulgated, the EPA promulgated 
new source performance standards for the oil and natural gas sector 
under 40 CFR Part 60, subpart OOOO, that requires the use of a reduced 
emissions completion in specified circumstances. The EPA proposes to 
add a definition for ``reduced emissions completion'' to subpart W that 
would be consistent with the description of that term in the new source 
performance standard rulemaking (see 76 FR 52757-8). Specifically, the 
EPA is proposing to amend 40 CFR 98.238 to define a ``reduced emissions 
completion'' as a well completion following fracturing where gas 
flowback that is otherwise vented is captured, cleaned, and routed to 
the flow line or collection system, re-injected into the well or 
another well, used as an on-site fuel source, or used for other useful 
purpose that a purchased fuel or raw material would serve, with no 
direct release to the atmosphere. We are proposing to amend 40 CFR 
98.238 to define a ``reduced emissions workover'' as a well workover 
with hydraulic fracturing (i.e., refracturing) where gas flowback that 
is otherwise vented is captured, cleaned, and routed to the flow line 
or collection system, re-injected into the well or another well, used 
as an on-site fuel source, or used for other useful purpose that a 
purchased fuel or raw material would serve, with no direct release to 
the atmosphere. The EPA does not anticipate these definitional changes 
would impact current reporters under Part 98 because these changes are 
clarifying in nature and do not change any requirements of subpart W.
    The EPA is also proposing to amend the definition of ``well 
completions'' in 40 CFR 98.6 to delete the term ``re-fracture'' as this 
term applies to an already producing well and is considered a well 
workover, not a well completion, for the purposes of part 98. This 
amendment is intended to avoid potential confusion concerning whether a 
re-fracture is a completion or workover in the context of subpart W. 
This change will also better align the existing definition of ``well 
completions'' with the new proposed definition of a ``reduced emissions 
completion'' by clarifying that a reduced emission completion only 
applies to new fractures and that re-fractures are potentially covered 
under the new definition of ``reduced emission workover''. The 
definition of ``well workover'' in 40 CFR 98.6 already refers to re-
fractures, so no clarifying change is needed for that definition.
    We are also proposing to revise reporting requirements for 
completions and workovers to differentiate between completions and 
workovers with different well type combinations in each sub-basin 
category. A well type combination is a unique combination of the 
following factors: Vertical or horizontal, with flaring or without 
flaring, and reduced emission completion/workover or not reduced 
emission completion/workover. Specifically, for well completions and 
workovers with hydraulic fracturing, we are proposing to require 
separate counts and separate reporting of emissions for the different 
well type combinations. These revisions would improve data quality for 
emissions from wells with hydraulic fracturing. Because the EPA is 
proposing to expand the well type definition for completions and 
workovers with hydraulic fracturing to include whether the well 
completions/workovers are flared or not, and whether it is a reduced or 
not reduced emission completion/workover, it is possible that reporters 
will have more than one reporting category (i.e., different well types 
in each sub-basin) for completions and workovers with hydraulic 
fracturing. Therefore, some reporters will be required to further 
categorize their calculated emissions from completions and workovers 
with hydraulic fracturing, which they did not have to do before. We 
anticipate that these proposed changes will increase burden to some 
reporters somewhat. Reporters will be required to separate and report 
their calculated emissions from completions and workovers without 
hydraulic fracturing by whether the emissions are related to 
completions or workovers, which they do not have to do under the 
current version of the rule. We anticipate that those proposed changes 
would only slightly increase burden to reporters.
    We are also proposing revisions to Equation W-10A that would add 
clarity and increase the accuracy of emissions calculations for gas 
well completions and workovers with hydraulic fracturing. In the final 
subpart W rule, the measurement or calculation for determining the 
ratio of flowback during well completions and workovers to 30-day 
production rate in Equation W-10A (40 CFR 98.233(g)) begins immediately 
upon initiating flowback of a well. Some reporters have asserted that 
the flowback characteristics of a well following hydraulic fracturing 
do not enable measurement or calculation to begin immediately upon 
initiating flowback due to a lack of sufficient gas being present, and 
the calculation needs to be revised to account for this fact. 
Therefore, the EPA is proposing to

[[Page 13400]]

modify the calculation to require the measurement of flow rate only 
when sufficient gas is present to enable flow rate measurement. In 
addition, some reporters have asserted that the accuracy of emissions 
calculations could be affected by the combined use of sales gas volume 
and approximations on flow rates for non-measured wells. To resolve 
this apparent issue, the time variable ``Tp'' in Equation W-
10A and W-10B is being modified. Time that the gas is routed to 
production would no longer be included, so it would no longer be 
necessary to subtract the volume of gas being sent to sales. This 
amendment would not significantly change the reporting burden. The 
proposed equations are similar in complexity as the previous equations 
and use measurements that are of similar complexity. This proposed 
revision would improve data quality and provide flexibility by 
providing an estimation method for data that could not likely be 
measured accurately.
    We are also proposing changes to the calculation section at 40 CFR 
98.233(g) and (h) to support the separate calculation of emissions from 
completions and workovers that are vented, flared, or use equipment 
that separates natural gas from the backflow and sends this natural gas 
to a flow-line (e.g., reduced emissions completions or reduced 
emissions workovers). Reporters currently calculate emissions from all 
completion and workover activities, but the equations do not facilitate 
the classification of the activity needed for separate reporting. We 
are proposing to revise Equation W-13 in 40 CFR 98.233(h) to separate 
the calculation of emissions from workovers from the calculation of 
completions into two equations. This amendment will improve data 
quality. We are also proposing to clarify that reporters must calculate 
the annual volumetric natural gas emissions from each gas well venting 
during workovers without hydraulic fracturing using Equation W-13A and 
from each gas well venting from completions without hydraulic 
fracturing using new Equation W-13B. We do not anticipate that this 
proposed change would significantly increase the reporting burden, 
because the proposed calculations are the same as the current 
calculation; we only propose to break it into two steps. The proposed 
methodology also requires the addition of parameter ``Es,p'' 
for Equation W-13B to specify the annual volumetric natural gas 
emissions in standard cubic feet from well completions. We are also 
proposing to revise 40 CFR 98.233(g)(1) to clarify the number of 
measurements or calculations that must be taken to estimate the average 
ratio of flowback rate (FRM).
    We are proposing to revise 40 CFR 98.233(g)(2) to clarify that 
measurements from the well flowing pressure upstream of a well choke to 
calculate well backflow must be collected for each sub-basin and well 
type combination. We are also proposing to revise parameter 
``PRs,p'' in Equations W-10A and W-10B and Equation W-12 to 
clarify that the first 30 day average production flow rate is the 
average taken after completions of newly drilled gas wells or 
workovers.
    For further information on gas well venting during completions and 
workovers, see the TSD ``Greenhouse Gas Reporting Rule: Technical 
Support for Revisions and Confidentiality Determinations for Petroleum 
and Natural Gas Systems; Proposed Rule'' in Docket ID No. EPA-HQ-OAR-
2011-0512.
6. Blowdown Vents
    Based on questions received during implementation of the final 
subpart W rule and reporter concerns, the EPA is proposing to revise 
Equations W-14A and W-14B to include a compressibility term. 
Specifically, some reporters requested that the EPA allow the use of a 
factor to adjust for compressibility when calculating emissions from 
blowdown vents. The calculation method for blowdown vents included in 
the existing subpart W rule assumes natural gas is an ideal gas with a 
compressibility factor of 1, and does not include an adjustment for 
compressibility in the calculation. Although the EPA had previously 
considered including the compressibility term (76 FR 56010, September 
9, 2011), the EPA ultimately did not propose including the factor, 
because we then concluded that including a compressibility adjustment 
could create a degree of uncertainty between reporters on how their 
reported blowdown values compared (on a volume basis). We noted at that 
time that although the compressibility of pure light hydrocarbon 
substances is well known, the compressibility of hydrocarbon mixtures 
is less well known and the composition of natural gas throughout the 
segments covered by subpart W can be variable. At that time, we 
determined that ideal gas law calculations were adequate for reporting 
purposes under Part 98.
    The EPA notes that the circumstances surrounding this issue are now 
different because, as discussed in Section III.B.1 of this preamble, 
the EPA is proposing to require the use of site-specific data on gas 
compositions, if available. In addition, we have determined that at 
high pressures and low temperatures, the accuracy of the emission 
estimate would be improved if a compressibility factor were included in 
the calculation. The compressibility of methane at standard conditions 
is close to one. However, the compressibility of methane at low 
temperatures and high pressures is lower than one, which may affect the 
accuracy of the emission calculation if not included in that 
calculation. Therefore, the EPA proposes to revise Equations W-14A and 
W-14B in 40 CFR 98.233(i) to include the compressibility term 
``Za''. A default compressibility term of 1 may be used at 
conditions where the pressure is below 5 atmospheres, and the 
temperature is above -10 degrees Fahrenheit, or if the compressibility 
factor at the actual temperature and pressure is 0.98 or greater. We 
are proposing harmonizing changes to Equations W-33 and W-34 in 40 CFR 
98.233(t) to include the compressibility term ``Za'' for 
conversion of volumetric emissions at actual conditions to standard 
conditions. Because it is likely that most facilities handle gas within 
the proposed compressibility factor default ranges, it is unlikely that 
adding this compressibility factor term into the blowdown vent stack 
calculations will significantly increase the reporting burden.
    The EPA is also proposing to simplify the reporting for blowdowns. 
In the final subpart W rule, reporters must calculate and record 
emissions for each blowdown event that is greater than or equal to 50 
cubic feet of actual volume. Currently, for each piece of equipment 
(unique physical volume) that is blown down more than one time in a 
calendar year, reports are submitted for the total number of blowdowns, 
the emissions for each unique physical volume, and the name or ID 
number for the unique physical volume. For all equipment that is blown 
down only once during the calendar year, reports are submitted as an 
aggregate for all such equipment at each facility. Reports include the 
total number of blowdowns and the emissions from all equipment with 
unique physical volumes that are blown down only once. The volume of 
gas vented is calculated for each blowdown event using the conditions 
specific to the event. However, the reporting of each ``unique physical 
volume'' blown down more than once in a year may be an extensive list 
of unique equipment.
    A similar reporting approach was adopted by the EPA in the November 
2010 version of subpart W (75 FR 74458). There, the reporting

[[Page 13401]]

requirement specified that emissions be reported collectively per 
equipment type. This approach caused some confusion because a list of 
equipment types was not provided. Therefore we are proposing to revise 
the current reporting requirements in 40 CFR 98.236(c)(7) to simplify 
the reporting structure to report blowdown emissions aggregated by 
seven categories: station piping, pipeline venting, compressors, 
scrubbers/strainers, pig launchers and receivers, emergency shutdowns, 
and all other blowdowns greater than or equal to 50 cubic feet. 
Although facilities are no longer required to report blowdown vent 
stack emissions by each unique physical volume, facilities still have 
to calculate blowdown vent stack emissions from each unique physical 
volume and categorize the emissions by equipment. Therefore, the EPA 
has determined that this proposed change would not significantly impact 
burden to reporters.
    The EPA is also proposing an optional calculation method for 
blowdown emissions for situations where a flow meter is in place to 
measure the emissions directly. If a blowdown vent is equipped with a 
flow meter, there would not be an advantage to calculating the 
emissions using the unique volume, temperature, and pressure conditions 
of the equipment instead of the directly measured flow rate. We are 
proposing this alternative calculation method in 40 CFR 98.233(i), 
along with associated reporting requirements in 40 CFR 98.236. We are 
also proposing additional clarifying edits for both the blowdown 
calculation and reporting sections of the rule. If a flow meter is in 
place to measure emissions, the emissions would be reported on a 
facility basis, and would not be aggregated by emission type per 40 CFR 
98.236(i)(2). For further information on blowdown vents, see the TSD 
``Greenhouse Gas Reporting Rule: Technical Support for Revisions and 
Confidentiality Determinations for Petroleum and Natural Gas Systems; 
Proposed Rule'' in Docket ID No. EPA-HQ-OAR-2011-0512.
7. Onshore Production Storage Tanks
    We are proposing to revise the method for estimating emissions from 
occurrences of well pad gas-liquid separator liquid dump valves that 
are not properly operating for onshore production storage tanks. The 
EPA initiated this revision to address reporter concerns and to improve 
data quality. Specifically, reporters expressed concern with the burden 
associated with quantifying and recording information for all properly 
functioning dump valves. The proposed revisions would require the 
detection of an anomaly and only then require quantification. Hence 
only those dump valves found to not be closing properly (i.e., stuck 
dump valves) would have to be quantified. Specifically, the EPA is 
proposing to simplify Equation W-16 to calculate emissions for only 
periods when the dump valve is not closing properly.
    The EPA is also proposing to revise the reporting section to make 
it clear that facilities are to separately report the emissions from 
onshore production storage tanks attributable to periods when dump 
valves are not closing properly, as opposed to emissions that occur 
when dump valves are closing properly. In the final subpart W rule, 40 
CFR 98.236(c)(8)(iv) requires that facilities report annual total 
volumetric GHG emissions that resulted from dump valves that are not 
closing properly. However, Equation W-16 in the final subpart W rule 
sums the total emissions for periods when the dump valve is closing 
properly and periods when the dump valve is not closing properly. The 
EPA is clarifying 40 CFR 98.236 to specify that facilities that use 
Equation W-16 should report only emissions that result from dump valves 
that are not closing properly. Note that emissions from atmospheric 
tanks that are not a result of dump valves not closing properly would 
continue to be reported in this proposed revision outside of Equation 
W-16. There is no significant additional burden to facilities, because 
reporters already use these data elements in Equation W-16: separate 
tank and dump valve emissions already need to be calculated separately, 
but would now also be reported separately. This revision would 
eliminate potential confusion for reporters, clarify recordkeeping 
requirements, and improve the ability to quantify emissions from stuck 
dump valves. For further information on emissions from improperly 
functioning dump valves, see the TSD ``Greenhouse Gas Reporting Rule: 
Technical Support for Revisions and Confidentiality Determinations for 
Petroleum and Natural Gas Systems; Proposed Rule'' in Docket ID No. 
EPA-HQ-OAR-2011-0512. These proposed revisions would improve the 
quality of data collected.
8. Associated Gas Venting and Flaring
    The EPA is proposing to add a term to Equation W-18 (40 CFR 
98.233(m)(3)) to account for situations where part of the associated 
gas from a well goes to a sales line while another part of the gas is 
flared or vented. These amendments improve data quality by eliminating 
duplicate reporting. Emissions are currently calculated based on the 
gas-to-oil ratio (GOR) and volume of oil produced during the flaring 
period. The GOR is based on total gas from the well, which means all 
the gas would currently be reported as flared even though a portion of 
the gas goes to a sales line. The proposed revision to Equation W-18 
subtracts the volume of associated gas sent to sales from the annual 
volumetric natural gas emissions from associated gas venting. The EPA 
has also included in the equation a term (EREp,q) for 
emissions reported under other sources included in this subpart (i.e., 
tank venting) to avoid double counting of these emissions. The EPA also 
proposes updating the definition of the term GORp,q and the 
emission result Ea,n in Equation W-18 to specify that the 
gas to oil ratio and the result of the calculation are calculated at 
standard conditions rather than actual conditions. Because the GOR is 
measured in standard cubic feet, this change would harmonize the 
equation terms and the result of the emission calculation equation 
would be at standard conditions. Although the proposed calculation 
method modifies the current equation to include two new terms, these 
terms are already being calculated elsewhere and/or can be estimated. 
Therefore, the EPA does not anticipate that this proposed change will 
significantly affect the reporting burden.
    The EPA is also proposing to add a definition for the term 
``Associated gas venting or flaring'' to clarify what is included in 
this source. The EPA is proposing to define ``Associated gas venting or 
flaring'' as ``the venting or flaring of natural gas which 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. This definition does not include 
venting or flaring resulting from activities that are reported 
elsewhere, including tank venting, well completions, and well 
workovers.'' The proposed definition allows for greater consistency 
with the changes made to the calculation method. This is a clarifying 
proposed change that improves data quality and should not significantly 
affect the burden to current reporters. For further information on 
emissions from associated gas, see the TSD ``Greenhouse Gas Reporting 
Rule: Technical Support for Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems;

[[Page 13402]]

Proposed Rule'' in Docket ID No. EPA-HQ-OAR-2011-0512.
9. Flare Stack Emissions
    The EPA is proposing to amend the calculation method for emissions 
from a flare stack to simplify the calculation to standard conditions 
and to account for gas that is sent to an unlit flare. Specifically, we 
are proposing to revise Equation W-19 and combine Equations W-20, and 
W-21. The EPA also proposes to revise the equations such that the 
emissions of CH4 and CO2 are calculated in 
standard conditions. We propose to remove paragraph 40 CFR 
98.233(n)(11), which specifies estimating emissions for the volume of 
gas flared under actual conditions. We also propose to add the terms 
``ZU'' and ``ZL'' to Equation W-19 and the terms 
``ZU'' and ``ZL'' to Equation W-20 to account for 
the fraction of gas sent to an unlit flare and the fraction of gas sent 
to a burning flare. The fraction of feed gas sent to an unlit flare 
would be determined by using engineering estimates and process 
knowledge. The proposed changes simplify and clarify the calculation 
requirements and would improve the accuracy of the collected data by 
accounting for the fraction of emissions that are not combusted when 
sent to an unlit flare.
    The EPA is also proposing a revision to the onshore natural gas 
transmission compression, underground natural gas storage, liquefied 
natural gas (LNG) storage, LNG import and export equipment industry 
segments to clarify that emissions from any flares in these segments 
must be reported using the calculation method for emissions from a 
flare stack. This clarifying revision is consistent with the treatment 
of flares in other parts of subpart W and is necessary to calculate 
emissions for compressors routed to flares under the proposed 
compressor calculation requirement modifications. We anticipate that 
this proposed change may slightly increase burden for select reporters 
and will not significantly affect burden for most reporters; however, 
this clarifying revision is consistent with the treatment of flares in 
other parts of subpart W and is necessary to calculate emissions for 
compressors routed to flares under the proposed compressor calculation 
requirement modifications.
10. Centrifugal and Reciprocating Compressors
    Some reporters have contended that the current monitoring 
requirements for compressor venting are overly burdensome and present 
safety and operational process concerns. These reporters asserted that 
it is not practical to require a measurement from each individual 
compressor for groups of compressors that are routed to a common vent 
manifold (or flare header), because this would require the entire group 
of compressors that are connected to the common manifold (or flare 
header) to be shutdown, blown down, and purged in order to safely 
install meters (or ports for temporary meters) and enable individual 
measurements. The reporters stated that it is extremely rare that 
entire groups of compressors are shutdown at the same time. In the 
November 2010 response to public comments on the subpart W final rule 
(Docket ID No. EPA-HQ-OAR-2009-0923), the EPA noted that commenters 
requested that the EPA allow direct measurements of common manifolded 
vent lines on compressors. At least one commenter stated that if 
continuous measurement of manifolded vent lines and aggregate annual 
emissions reporting were allowed as an option for measuring 
compressors, they would be able to safely collect and report to the EPA 
continuously measured data. The EPA did not include this option in the 
2010 final subpart W rule because it was not clear whether measurements 
at a common vent outlet could be used to correctly characterize annual 
emissions from individual compressors.
    In today's action, we are proposing changes to the centrifugal and 
reciprocating compressor calculation sections (see 40 CFR 98.233(o) and 
(p)) in order to address reporter concerns related to measuring 
centrifugal and reciprocating compressor emissions that are routed to a 
common vent manifold (or flare header). For those compressors, the EPA 
is proposing an option where reporters would take at least three 
measurements per year and report the average of the measurements. These 
measurements would need to be taken before emissions are comingled with 
other non-compressor emission sources. This option would address 
reporter's safety concerns for facilities that need to shut down 
equipment to install individual meters and maintain accurate 
characterization of annual emissions from compressors at the facility. 
Annual volumetric emissions would be determined for each manifolded 
group of compressors combined for all operating conditions (mode-source 
combinations). Reporters would still be required to report activity 
data for any individually measured sources (i.e., non-manifolded 
sources) at the compressor level. Activity data reported would include 
information about the individual compressors included in the manifolded 
vent. This proposed measurement option would allow the EPA to correctly 
characterize and analyze GHG emissions from all compressors at 
individual facilities in the petroleum and natural gas systems source 
category while potentially reducing burden to the industry. Although 
reporting elements include new activity data, reporters would no longer 
be required to sample manifolded compressor sources individually, thus 
decreasing overall burden and providing flexibility. For example, if a 
reporter operates seven compressors that have their blowdown vent 
stacks manifolded, the reporter would no longer have to conduct seven 
measurements every year (one for each blowdown vent stack) as required 
by the current rule. Instead, for this example, the reporter would be 
required to only conduct a measurement three times per year on the 
common vent stack that is associated with the manifolded group of seven 
compressor sources, which would decrease burden for the reporter 
compared to the seven measurements currently required.
    The EPA considered requiring only one or two measurements per year 
for these manifolded sources (as opposed to the EPA proposal above for 
the average of three measurements). The EPA concluded that the annual 
process variability for these sources was high enough to warrant more 
than one or two measurements per year. Please see the TSD ``Greenhouse 
Gas Reporting Rule: Technical Support for Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems; Proposed Rule'' 
in Docket ID No. EPA-HQ-OAR-2011-0512, for more background and 
information on the options considered. In addition to seeking comment 
on our proposed option, the EPA is specifically seeking comment on the 
two other options that were considered and other derivations of these 
options (i.e., four measurements per year instead of three). Comments 
should include justification why the specific option receiving comment 
does not negatively impact safety, is technical and economically 
feasible, does not impose undue burden on reporters, and how the option 
is sufficiently accurate given the annual process variability for these 
sources.
    We are also proposing to include four definitions in 40 CFR 98.238 
to support the addition of the calculation method for manifolded vents. 
We are proposing a definition for ``compressor'' to mean ``any type of 
vent or valve (i.e., wet seal, blowdown valve, isolation valve, or rod 
packing) on a centrifugal or reciprocating compressor.'' We are 
proposing a definition for ``compressor

[[Page 13403]]

mode'' to mean ``means the operational and pressurized status of a 
compressor. For a centrifugal compressor, ``mode'' refers to either 
operating-mode or not-operating-depressurized-mode. For a reciprocating 
compressor, ``mode'' refers to either: Operating-mode, standby-
pressurized-mode, or not-operating-depressurized-mode.'' We are 
proposing a definition for ``manifolded compressor source'' to mean ``a 
compressor source that is manifolded to a common vent that routes gas 
from multiple compressors.'' We are also proposing a definition of 
``manifolded group of compressor sources'' to mean ``a collection of 
any combination of compressor sources that are manifolded to a common 
vent.''
    In addition, for compressors that are routed to an operational 
flare, we are proposing to allow operators to calculate and report 
emissions with other flare emissions (in lieu of estimating compressor 
emissions based on knowledge of the total flare emissions and the 
portion of those flare emissions that can be attributed to 
compressors). This proposed change addresses reporter concerns, 
provides flexibility, and potentially decreases burden without 
affecting data quality. Although operators would still be required to 
report certain compressor-related activity data for each compressor 
that is routed to an operational flare (as provided for in 40 CFR 
98.236(o)(1) and (p)(1)), reporting emissions from compressors (that 
are routed to an operational flare) with other flare emissions would 
reduce burden, because reporters would not be required to sample 
compressors individually or be required to portion flare emissions 
attributed to compressors.
    It was brought to the EPA's attention that the 3-year cycle 
requirement for measuring compressors in the not-operating-
depressurized-mode could present a compliance challenge for some 
facilities, because not every facility schedules routine shutdowns for 
maintenance within 3 years. The EPA did not intend for reporters to 
perform an unscheduled shutdown of a facility for the sole purpose of 
taking a measurement of the compressor in the not-operating-
depressurized-mode. Therefore, we are proposing to revise the 
requirement to measure each compressor in the not-operating-
depressurized-mode at least once in any 3 consecutive calendar years, 
provided the measurement can be taken during a scheduled shutdown. If 
there is no scheduled shutdown within three consecutive calendar years, 
the EPA proposes that a measurement must be made at the next scheduled 
depressurized compressor shutdown (for reciprocating compressors, this 
measurement can be taken during the next scheduled shutdown when the 
compressor rod packing is replaced). By allowing the measurement to be 
taken at these specified scheduled shutdowns, operators would not have 
to plan a shutdown of their equipment to take a measurement of their 
compressor in the not-operating-depressurized-mode. This proposed 
amendment addresses reporters' concerns and potentially decreases 
burden without affecting data quality. Even though the ``not-operating-
depressurized-mode'' is measured only at scheduled shutdowns (which 
might be every 3 years or greater), the reporter is still required to 
conduct an annual measurement in whatever mode the compressor is found. 
Therefore, the frequency in measurements is unchanged. The EPA also 
considered modifying the existing requirement to measure each 
compressor in the not-operating-depressurized-mode at least once every 
3 years to correspond to a longer term, such as every 5 years. However, 
such an extension might not resolve the issue for all reporters. The 
EPA is specifically seeking comment on our proposed option as well as 
the additional option that was considered.
    The EPA is also clarifying that for reporters that elect to conduct 
as found leak measurements for individual compressor sources, all 
measurements from a single owner or operator may be used when 
developing an emission factor (using Equation W-24 or W-28 of 40 CFR 
98.233) for each compressor mode-source combination. If the reporter 
elects to use this option, the reporter emission factor must be applied 
to all reporting facilities for the owner or operator. Although this 
option may make it easier for some reporters to keep track of their 
calculated reporter emission factors, all reporters are still required 
to calculate reporter emission factors if they use the as found leak 
measurement option. Therefore, the EPA does not anticipate that this 
clarifying edit will significantly affect the reporting burden.
    We are also proposing to restructure and revise the centrifugal and 
reciprocating compressor sections (see 40 CFR 98.233(o) and 40 CFR 
98.233(p)) in order to improve clarity for reporters. Because the 
restructuring was extensive, entirely new text appears for 40 CFR 
98.233(o) and 40 CFR 98.233(p). Although the proposed restructuring 
changes would not significantly change any of the requirements or 
burden, the proposed restructuring and revisions would clarify current 
requirements that are vague or confusing. For example, we are proposing 
to retain the current equations for determining emissions from each 
compressor's measured mode-source combination and unmeasured mode-
source combination; however, we are proposing language that would 
explain when to use the equation(s). We are also proposing revisions to 
improve consistency between the centrifugal and reciprocating 
compressor sections (see 40 CFR 98.233(o) and 40 CFR 98.233(p)). For 
example, we are proposing to revise the equation variables to bring 
consistency between the two sections. It is our view that the 
restructuring and clarification revisions that we are proposing in this 
action for the centrifugal and reciprocating compressor sections would 
improve readability and usability for both industry and government 
regulators. For further information on measuring emissions from 
compressors, see the TSD ``Greenhouse Gas Reporting Rule: Technical 
Support for Revisions and Confidentiality Determinations for Petroleum 
and Natural Gas Systems; Proposed Rule'' in Docket ID No. EPA-HQ-OAR-
2011-0512.
11. Natural Gas Distribution: Leak Detection Equipment and Emissions 
From Components
    For natural gas distribution, the final subpart W rule requires 
reporters to calculate a facility emission factor for a meter/regulator 
run per component type at above grade metering-regulating (M-R) 
stations. The calculation of the emission factor using Equation W-32 in 
40 CFR 98.233(r) based on the results of equipment leak surveys that 
are required under 40 CFR 98.233(q) at above grade transmission-
distribution (T-D) stations and the subsequent annual emissions 
calculated for those stations using Equations W-30B. Reporters have 
pointed out that the nomenclature and inter-related calculations 
between 40 CFR 98.233(q) and (r) has caused confusion. Therefore, the 
EPA is proposing to revise the calculation requirements for natural gas 
distribution facilities and associated terminology in 40 CFR 98.233(q) 
and (r). Specifically, the EPA is proposing to place the facility 
meter/regulator run emission factor calculation in 40 CFR 98.233(q) 
instead of 40 CFR 98.233(r) and clarify that the emission factor is 
calculated separately for CO2 and CH4 and is on a 
meter/regulator run operational hour basis, instead of on a meter/
regulator run component basis. Facilities calculate annual emissions 
from above grade transmission-distribution transfer stations using 
Equation W-30 of 40 CFR 98.233(q).

[[Page 13404]]

The emissions are calculated in Equation W-30 on a per component basis 
based on equipment leak survey results and leaker emission factors for 
transmission-distribution transfer station components listed in Table 
W-7. The results of the component level annual emissions calculations 
using Equation W-30 are then summed for all component types in Equation 
W-31 to develop the annual facility meter/regulator run emission 
factors for CO2 and CH4. Those facility emission 
factors must be recalculated annually as additional equipment leak 
survey data becomes available from above grade transmission-
distribution transfer stations. To calculate annual emissions from 
above grade metering-regulating stations that are not above grade 
transmission-distribution transfer stations, facilities must use the 
emission factors (calculated in Equation W-31) in the annual emissions 
calculation of Equation W-32B in 40 CFR 98.233(r). Emissions from below 
grade metering-regulating stations, below grade transmission-
distribution transfer stations, distribution mains, and distribution 
services are calculated using Equation W-32A of 40 CFR 98.233(r) using 
population emission factors listed in Table W-7. These proposed 
revisions will alleviate the current confusion with the calculation and 
reporting requirements for natural gas distribution facilities while 
capturing the same emissions sources from this industry segment and 
maintaining the same level of data accuracy. Data are generally 
reported at a less detailed level, but there is no change in emissions 
coverage.
12. Onshore Petroleum and Natural Gas Production and Natural Gas 
Distribution Combustion Emissions
    The EPA is proposing to clarify that emissions and volume of fuel 
combusted must be reported for all compressor driven internal 
combustion units in 40 CFR 98.236. The EPA is proposing to revise this 
reporting requirement to be consistent with the emission estimation 
methods in 40 CFR 98.233(z)(4) that specify the exemption from 
reporting emissions for internal combustion units with a rated heat 
input capacity less than or equal to 1 MMBtu/hr (130 horsepower) does 
not apply to internal fuel combustion sources that are compressor 
drivers.

C. Proposed Revisions to Missing Data Provisions

    We are proposing to revise 40 CFR 98.235 to clarify the procedures 
for estimating missing data. We are proposing to increase the 
specificity regarding how to use, treat, and report missing data for 
each calculation specified in 40 CFR 98.233.These proposed revisions 
would increase clarity for reporters and improve the accuracy of the 
data reported by ensuring that the data substituted for missing values 
is limited in use, and, where necessary, well-documented and quality-
assured or based on the best available estimates. To address newly 
acquired wells, the EPA is also proposing missing data procedures 
specific to facilities that are newly subject to subpart W and to 
existing onshore petroleum and natural gas production facilities that 
acquire wells that were not subject to subpart W prior to the 
acquisition. In these specific cases, the EPA is proposing to allow 
best engineering estimates for any parameter that cannot be reasonably 
measured or obtained according to the requirements in subpart W for up 
to six months from the first date of subpart W applicability. Where 
facilities acquired additional wells, only data and calculations 
associated with those newly acquired wells would fall within this 
proposed provision. This proposed revision provides flexibility for 
newly acquired facilities or wells. Missing data procedures were 
previously not allowed for many areas of subpart W; however, with the 
proposed removal of BAMM, the missing data procedures provide clarity 
for reporters who may have unintentionally missed required data.

D. Proposed Amendments to Best Available Monitoring Methods

    In order to provide facilities with time to adjust to the 
requirements of the rule, subpart W has provisions allowing the 
optional use of best available monitoring methods (BAMM) for unique or 
unusual circumstances. Where a facility uses BAMM, it is required to 
follow emission calculations specified by the EPA, but is allowed to 
use alternative methods for determining inputs to calculate emissions. 
Inputs are the values used by facilities to calculate equation outputs. 
Examples of BAMM include: Monitoring methods used by the facility that 
do not meet the specifications of subpart W, supplier data, engineering 
calculations, and other company records. Facilities are required to 
receive approval from the EPA prior to using BAMM and these facilities 
are required to specify in their GHG annual reports when BAMM is used 
for an emission source. The EPA has previously noted that the Agency 
intended to ``approve the use of BAMM beyond 2011 only in cases that 
are unique or unusual'' (76 FR 59538). Furthermore, the EPA limited the 
approvals of BAMM to one reporting year in keeping with the intent to 
allow use of BAMM as a transitional provision until facilities come 
into compliance with the final rule. While the EPA occasionally uses 
BAMM for targeted, short-term monitoring flexibilities (i.e., provision 
for reporters who become subject to Part 98 from the recent GWP changes 
to subpart A to have automatic BAMM for the first three months of 
reporting), no industry-specific subpart within Part 98 continues to 
use the BAMM flexibility except subpart W.
    In this action, the EPA is proposing to remove all provisions in 40 
CFR 98.234(f) for BAMM. We are also proposing to remove and reserve 40 
CFR 98.234(g), which is a provision specific to the 2011 and 2012 
reporting years. The removal of BAMM will improve data quality by 
requiring consistent reporting for each segment in subpart W. We are 
proposing these amendments because we expect facilities would be able 
to comply with the monitoring and QA/QC methods required under subpart 
W after this proposed rule is finalized and effective. Reporters with 
issues that were unidentified at the time of the final rule will, by 
January 1, 2015, have had adequate time to resolve these issues. It has 
been the EPA's intent throughout implementation of subpart W that BAMM 
be available as a limited, transitional program to serve as a bridge to 
full compliance with the rule for cases where reporters faced 
reasonable impediments to compliance. The EPA never intended to extend 
BAMM requirements indefinitely. The proposed amendments are therefore 
in keeping with the EPA's stated intent to transition to reporting 
without BAMM. We also believe, based on several years of experience 
with the industry and these reporting requirements, that facilities 
have successfully transitioned so that they either no longer need to 
use BAMM or will not need to use BAMM if these proposed revisions are 
finalized.
    In a review of BAMM request submittals for the 2014 reporting year, 
the EPA found that the sources with the most frequent BAMM requests 
included centrifugal compressors, reciprocating compressors, blowdown 
vent stacks, and combustion emissions, which are addressed in this 
rulemaking. The proposed revisions would also resolve the need for BAMM 
for certain facilities for which the final subpart W monitoring 
requirements were technically infeasible. For example, the most common 
concerns raised in BAMM requests associated with technical 
infeasibility included concerns related to having to shut down a 
facility to install access ports to

[[Page 13405]]

conduct compressor measurements. As discussed in Section II.B.10 of 
this preamble, we are making revisions that allow the testing of a 
common vent and that clarify that operators do not have to shut a 
facility down for the sole purpose to test a compressor in its non-
operating mode, but that the measurement must be made at the next 
scheduled shutdown.
    In light of the extended time period in which the EPA has granted 
BAMM to allow facilities to come into compliance with subpart W 
requirements, the revisions that the EPA is proposing to make to the 
final rule, and the fact that all other industry-specific subparts in 
Part 98 no longer have continual BAMM, we expect that facilities would 
be in compliance with the monitoring and QA/QC methods required under 
subpart W for the 2015 calendar year.
    The EPA requests comment and strong technical evidence for site-
specific unique or unusual circumstances that would require the use of 
BAMM after January 1, 2015. These comments should include the details 
of how and why the special circumstances exist, why the data collection 
methods in subpart W (including those in this proposal) are not 
feasible, the data that could not be monitored in order to comply with 
subpart W, and how specifically the data could otherwise be collected. 
For further information on BAMM, see the TSD ``Greenhouse Gas Reporting 
Rule: Technical Support for Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems; Proposed Rule'' 
in Docket ID No. EPA-HQ-OAR-2011-0512.

III. Proposed Confidentiality Determinations

A. Overview and Background

    In this proposed rule we are proposing confidentiality 
determinations for new and subtantially revised reporting data elements 
in the proposed amendments, with certain exceptions as discussed in 
more detail below. These new and substantially revised data elements 
would result from the proposed corrections, clarifying, and other 
amendments that are described in Section II of this preamble, which 
would also result in substantial changes to the data elements that are 
reported. We are also proposing to revise the confidentiality 
determination for one existing data element that is not being amended, 
as discussed in Section III.B of this preamble. The final 
confidentiality determinations the EPA has previously made for the 
remainder of the subpart W data elements are unaffected by the proposed 
amendments and continue to apply. For information on confidentiality 
determinations for the GHGRP and subpart W data elements, see: 75 FR 
39094, July 7, 2010; 76 FR 30782, May 26, 2011; 77 FR 48072, August 13, 
2012; and 78 FR 55994, September 11, 2013. These proposed 
confidentiality determinations would be finalized after considering 
public comment. The EPA plans to finalize these determinations at the 
same time the proposed rule amendments described in this action are 
finalized.

B. Approach to Proposed CBI Determinations for New or Revised Subpart W 
Data Elements

    For the proposed new and substantially revised data elements, 
except for the specific data elements separately addressed below, we 
are applying the same approach as previously used for making 
confidentiality determinations for data elements reported under the 
GHGRP. In the ``Confidentiality Determinations for Data Required Under 
the Mandatory Greenhouse Gas Reporting Rule and Amendments to Special 
Rules Governing Certain Information Obtained Under the Clean Air Act'' 
(hereinafter referred to as ``2011 Final CBI Rule'') (76 FR 30782, May 
26, 2011), the EPA grouped Part 98 data elements into 22 data 
categories (11 direct emitter data categories and 11 supplier data 
categories) with each of the 22 data categories containing data 
elements that are similar in type or characteristics. The EPA then made 
categorical confidentiality determinations for eight direct emitter 
data categories and eight supplier data categories and applied the 
categorical confidentiality determination to all data elements assigned 
to the category. Of these data categories with categorical 
determinations, the EPA determined that four direct emitter data 
categories are comprised of those data elements that meet the 
definition of ``emissions data,'' as defined at 40 CFR 2.301(a), and 
that, therefore, are not entitled to confidential treatment under 
section 114(c) of the CAA.\1\ The EPA determined that the other four 
direct emitter data categories and the eight supplier data categories 
do not meet the definition of ``emission data.'' For these data 
categories that are determined not to be emission data, the EPA 
determined categorically that data in three direct emitter data 
categories and five supplier data categories are eligible for 
confidential treatment as CBI, and that the data in one direct emitter 
data category and three supplier data categories are ineligible for 
confidential treatment as CBI. For two direct emitter data categories, 
``Unit/Process `Static' Characteristics that Are Not Inputs to Emission 
Equations'' and ``Unit/Process Operating Characteristics that Are Not 
Inputs to Emission Equations,'' and three supplier data categories, 
``GHGs Reported,'' ``Production/Throughput Quantities and 
Composition,'' and ``Unit/Process Operating Characteristics,'' the EPA 
determined in the 2011 Final CBI Rule that the data elements assigned 
to those categories are not emission data, but the EPA did not make 
categorical CBI determinations for them. Rather, the EPA made CBI 
determinations for each individual data element included in those 
categories on a case-by-case basis taking into consideration the 
criteria in 40 CFR 2.208. No final confidentiality determination was 
made for the inputs to emission equation data category (a direct 
emitter data category).
---------------------------------------------------------------------------

    \1\ Direct emitter data categories that meet the definition of 
``emission data'' in 40 CFR 2.301(a) are Facility and Unit 
Identifier Information, Emissions, Calculation Methodology and 
Methodological Tier, Data Elements Reported for Periods of Missing 
Data that are not Inputs to Emission Equations, and Inputs to 
Emission Equations.
---------------------------------------------------------------------------

    For this rulemaking, we are proposing to assign 243 new or revised 
data elements to the appropriate direct emitter data categories created 
in the 2011 Final CBI Rule based on the type and characteristics of 
each data element. Note that subpart W is a direct emitter source 
category, thus, no data are assigned to any supplier data categories.
    For data elements the EPA has assigned in this proposed action to a 
direct emitter category with a categorical determination, the EPA is 
proposing that the categorical determination for the category be 
applied to the proposed new or revised data element. For the proposed 
categorical assignment of the data elements in these eight categories 
with categorical determinations, see Memorandum Data Category 
Assignments and Confidentiality Determinations for all Data Elements 
(excluding inputs to emission equations) in the Proposed ``Technical 
Revisions and Confidentiality Determinations for Petroleum and Natural 
Gas Systems'' in Docket ID No. EPA-HQ-OAR-2011-0512.
    For data elements assigned to the ``Unit/Process `Static' 
Characteristics that Are Not Inputs to Emission Equations'' and ``Unit/
Process Operating Characteristics that Are Not Inputs to Emission 
Equations,'' we are proposing confidentiality determinations on a case-
by-case basis taking into

[[Page 13406]]

consideration the criteria in 40 CFR 2.208, consistent with the 
approach used for data elements previously assigned to these two data 
categories. For the proposed categorical assignment of these data 
elements, see Memorandum Data Category Assignments and Confidentiality 
Determinations for all Data Elements (excluding inputs to emission 
equations) in the Proposed ``Technical Revisions and Confidentiality 
Determinations for Petroleum and Natural Gas Systems'' in Docket ID No. 
EPA-HQ-OAR-2011-0512. For the results of our case-by-case evaluation of 
these data elements, see Sections III.C and III.D of this preamble.
    For the reasons stated below, we are proposing individual 
confidentiality deteminations for 11 new or substantially revised data 
elements without making a data category assignment. In the 2011 Final 
CBI rule, although the EPA grouped similar data into categories and 
made categorical confidentiality determinations for a number of data 
categories, the EPA also recognized that similar data elements may not 
always have the same confidentiality status, in which case the EPA made 
individual instead of categorical determinations for the data elements 
within such data categories.\2\ Similarly, while the 11 proposed new or 
substantially revised data elements are similar in type or certain 
characteristics to data elements previously assigned to the 
``Production/Throughput Data Not Used as Input'' and ``Raw Materials 
Consumed that are Not Inputs to Emission Equations'' data categories, 
we do not believe that they share the same confidentiality status as 
the non-subpart W data elements already assigned to those two data 
categories, which the EPA has determined categorically to be CBI based 
on the data elements assigned to those categories at the time of the 
2011 Final CBI Rule. As discussed in more detail below, our review 
showed that these 11 subpart W production and throughput-related data 
elements fail to qualify for confidential treatment. Therefore, we do 
not believe that the categorical determinations for the ``Production/
Throughput Data Not Used as Input'' and ``Raw Materials Consumed that 
are Not Inputs to Emission Equations'' data categories are appropriate 
for these 11 data elements; accordingly, these data elements should not 
be assigned to these data categories. Not assigning these 11 data 
elements to these two data categories would also leave unaffected the 
existing categorical determinations for these data categories, which 
remain valid and applicable to the data elements assigned to those data 
categories. For the reasons stated above, we are proposing individual 
confidentiality determinations for these 11 data elements without 
making categorical assignment.
---------------------------------------------------------------------------

    \2\ In the 2011 Final CBI rule, several data categories include 
both CBI and non-CBI data elements. See 76 FR 30786.
---------------------------------------------------------------------------

    Our proposed individual determinations follow the same two-step 
evaluation process as set forth in the 2011 Final CBI Rule and 
subsequent confidentiality determinations for Part 98 data. 
Specifically, we first determined whether the data element meets the 
definition of emission data in 40 CFR 2.301(a). Data elements that meet 
the definition of emission data are required to be released under 
section 114 of the Clean Air Act. For data elements found to not meet 
the definition of emission data, we evaluated whether a data element 
meets the criteria in 40 CFR 2.208 for confidential treatment. In 
particular, we focus on: (1) Whether the data are already public; and 
(2) whether ``. . . disclosure of the information is likely to cause 
substantial harm to the business's competitive position.'' For the 
results of our case-by-case evaluation of these proposed new subpart W 
data elements, see Section III.D of this preamble.
    We are also proposing to revise the confidentiality determinations 
for one existing subpart W data element. Our review of the 11 proposed 
data elements discussed above led us to re-examine our previous 
determination for this data element, which is similar in type or 
characteristics to the 11 proposed data elements for which the EPA is 
choosing to make case-by-case determinations. This one data element is 
the only subpart W data element currently assigned to ``Production/
Throughput Data Not Used as Input'' data category. As discussed in more 
detail in Section III.D of this preamble, our review showed that this 
data element fails to qualify for confidential treatment. For the same 
reasons set forth above for not proposing categorical assignments for 
the 11 data elements, we are proposing to remove this data element's 
current category assignment, as well as the application of the 
categorical CBI determination to this data element. Instead, we are re-
proposing a confidentiality determination based on the two-step process 
discussed above for the proposed 11 new data elements. For the results 
of our case-by-case evaluation of the proposed subpart W data elements, 
see Section III.D of this preamble.
    We are proposing to assign 40 new or substantially revised data 
elements used to calculate GHG emissions in subpart W to the ``Input to 
Emission Equation'' data category. To date, the EPA has not made 
confidentiality determinations for any data element, including any 
subpart W data element, assigned to the ``Inputs to Emission Equation'' 
data category. We are therefore not proposing confidentiality 
determinations for the 40 proposed new or substantially revised inputs 
to emission equations data elements. However, due to concerns expressed 
by reporters with the potential release of inputs to emission 
equations, we previously established a process for evaluating ``inputs 
to emission equation'' data elements to identify potential disclosure 
concerns and actions to address such concerns if appropriate.\3\ The 
EPA has used this process to evaluate inputs to emission equations, 
including the subpart W data elements that are already assigned to the 
inputs to emission equations data category.\4\ We performed a similar 
evaluation for the 40 proposed new and substantially revised subpart W 
inputs to emission equations and did not identify any potential 
disclosure concerns. Accordingly, the proposal would require reporting 
of these data elements by March 31, 2016, which is the reporting 
deadline for the 2015 reporting year. For the list of new and revised 
subpart W inputs to emission equations and the results of our 
evaluation, see memorandum titled ``Review of Public Availability and 
Harm Evaluation for Proposed New Inputs to Emission Equations in the 
Proposed `Revisions and Confidentiality Determinations for Petroleum 
and Natural Gas Systems' '' in Docket ID No. EPA-HQ-OAR-2011-0512.
---------------------------------------------------------------------------

    \3\ See the ``Change to the Reporting Date for Certain Data 
Elements Required Under the Mandatory Reporting of Greenhouse Gases 
Rule'' (hereinafter referred to as the ``Final Deferral Notice'') 
(76 FR 53057, August 25, 2011) and the accompanying memorandum 
entitled ``Process for Evaluating and Potentially Amending Part 98 
Inputs to Emission Equations'' (Docket ID EPA-HQ-OAR-2010-0929).
    \4\ See the memoranda titled ``Summary of Data Collected to 
Support Determination of Public Availability of Inputs to Emission 
Equations for which Reporting was Deferred to March 31, 2015'' and 
``Evaluation of Competitive Harm from Disclosure of Inputs to 
Equations Data Elements Deferred to March 31, 2015.'' (Docket ID 
EPA-HQ-OAR-2010-0929).
---------------------------------------------------------------------------

    The proposed amendments include revisions a number of subpart W 
data reporting elements for which confidentiality determinations were 
previously finalized in the August 13, 2012 ``Final Confidentiality 
Determinations for Regulations Under the Mandatory Reporting of 
Greenhouse Gases Rule'' (77 FR 48072). The proposed revisions relative 
to some of

[[Page 13407]]

these data reporting elements would not require different or additional 
data to be reported under these data elements. The proposed revisions 
include a reorganization of the reporting requirements so that the data 
elements more close align with the calculation methodologies. This 
reorganization of the reporting section would result in changes to many 
of the rule citations for data elements. In addition to re-structuring 
the reporting section, the EPA has proposed other minor revisions 
designed to clarify the existing reporting requirements. For example, 
some of the proposed changes would clarify the source type (e.g., 
natural gas pneumatic device venting, acid gas removal vents, etc.) and 
industry segment that is required to report the data element. The 
proposed revisions also include corrections of typographical and other 
clerical errors. These corrections would not change the data to be 
reported. Although the proposed revisions would separate the 
requirements into a larger number of discrete reporting elements and 
would clarify and correct typographical errors, they would not change 
the underlying data elements to be reported for many data elements. 
Therefore, the confidentiality determinations finalized in the August 
13, 2012 rule continue to apply. We are therefore not proposing 
revisions to the existing confidentially determinations for the data 
reporting elements that either would not require different or 
additional data to be reported under the proposed revisions or the 
proposed revisions would not change the underlying data elements to be 
reported. For a summary of the proposed reporting requirements for 
subpart W that incorporate these changes to data organization and 
descriptions, see the memo, ``Proposed Revisions to the Subpart W 
Reporting Requirements'' in Docket ID No. EPA-HQ-OAR-2011-0512.

C. Proposed Confidentiality Determinations for Data Elements Assigned 
to the ``Unit/Process `Static' Characteristics That Are Not Inputs to 
Emission Equations'' and ``Unit/Process Operating Characteristics That 
Are Not Inputs to Emission Equations'' Data Categories

    The EPA is proposing to assign 101 proposed new or substantially 
revised data elements for subpart W to the ``Unit/Process `Operating' 
Characteristics That Are Not Inputs to Emission Equations'' data 
category or the ``Unit/Process `Static' Characteristics That Are Not 
Inputs to Emission Equations'' data category, because the proposed new 
or substantially revised data elements share the same characteristics 
as the other data elements previously assigned to the category. We are 
proposing confidentiality determinations for these proposed new or 
substantially revised data elements based on the approach set forth in 
the 2011 Final CBI Rule for data elements assigned to these two data 
categories. In that rule, the EPA determined categorically that data 
elements assigned to these two data categories do not meet the 
definition of emission data in 40 CFR 2.301(a); the EPA then made 
individual, instead of categorical, confidentiality determinations for 
these data elements.
    As with all other data elements assigned to these two categories, 
the proposed new or substantially revised data elements do not meet the 
definition of emissions data in 40 CFR 2.301(a). The EPA then 
considered the confidentiality criteria at 40 CFR 2.208 in making our 
proposed confidentiality determinations. Specifically, we focused on 
whether the data are already publicly available from other sources and, 
if not, whether disclosure of the data is likely to cause substantial 
harm to the business' competitive position. Table 2 of this preamble 
lists the data elements the EPA proposes to assign to the ``Unit/
Process `Operating' Characteristics That Are Not Inputs to Emission 
Equations'' and ``Unit/Process `Static' Characteristics That Are Not 
Inputs to Emission Equations'' data categories, the proposed 
confidentiality determination for each data element, and our rationale 
for each determination.

   Table 2--Proposed New Data Elements Assigned to the ``Unit/Process
 `Operating' Characteristics That Are Not Inputs to Emission Equations''
   and ``Unit/Process `Static' Characteristics That Are Not Inputs to
                  Emission Equations'' Data Categories
------------------------------------------------------------------------
                                                          Proposed
                                                      confidentiality
           Citation                Data element      determination and
                                                         rationale
------------------------------------------------------------------------
    ``Unit/Process `Operating' Characteristics That Are Not Inputs to
                   Emission Equations'' Data Category
------------------------------------------------------------------------
98.236(d)(1)(iv)..............  Whether any CO2    This proposed data
                                 emissions are      element would be
                                 recovered and      reported by onshore
                                 transferred        petroleum and
                                 outside the        natural gas
                                 facility.          production
                                                    facilities and by
                                                    onshore natural gas
                                                    processing plants.
                                                    This data element
                                                    indicates that a
                                                    facility is
                                                    operating an acid
                                                    gas removal unit and
                                                    indicates how the
                                                    facility handles the
                                                    CO2 emissions it
                                                    generates. Acid gas
                                                    removal units are
                                                    used to remove
                                                    carbon dioxide and
                                                    hydrogen sulfide
                                                    from raw natural gas
                                                    streams and are
                                                    commonly found at
                                                    gas processing
                                                    facilities. These
                                                    units are listed in
                                                    a facility's
                                                    construction and
                                                    operating permits,
                                                    which are publicly
                                                    available. Because
                                                    this information is
                                                    routinely available
                                                    through required
                                                    permits, we propose
                                                    these data elements
                                                    be designated as
                                                    ``not CBI.''

[[Page 13408]]

 
98.236(e)(1)(xvii)............  For each           These proposed data
                                 absorbent          elements would be
                                 dehydrator,        reported by onshore
                                 whether any        petroleum and
98.236(e)(2)(i)...............   dehydrator         natural gas
                                 emissions are      production
                                 vented to the      facilities and by
                                 atmosphere         onshore natural gas
98.236(e)(2)(ii)..............   without being      processing plants.
                                 routed to a        These data elements
                                 flare or           indicate that a
                                 regenerator        facility is equipped
98.236(e)(2)(iii).............   firebox.           with dehydration
                                For glycol          units, the number of
                                 dehydrators with   dehydrators used,
                                 an annual          the design of
                                 average daily      dehydrator used
                                 natural gas        (glycol or
                                 throughput less    desiccant), and how
                                 than 0.4 MMscfd,   emissions from
                                 the total number   dehydration units
                                 of dehydrators     are handled by the
                                 at the facility..  facility.
                                For glycol          Dehydration units
                                 dehydrators with   are used to remove
                                 an annual          water from natural
                                 average daily      gas streams. Most
                                 natural gas        natural gas
                                 throughput less    processing
                                 than 0.4 MMscfd,   facilities are
                                 the total number   equipped with these
                                 of dehydrators     units and because
                                 venting to a       they are a source of
                                 vapor recovery     hazardous air
                                 device..           pollutants, these
                                For glycol          units are subject to
                                 dehydrators with   rigorous emissions
                                 an annual          control requirements
                                 average daily      (e.g., 40 CFR part
                                 natural gas        63, subpart HH).
                                 throughput less    Dehydration units
                                 than 0.4 MMscfd,   and their associated
                                 the number of      control devices are
                                 dehydrators        listed in a
                                 venting to a       facility's
                                 control device     construction and
                                 other than a       operating permits,
                                 vapor recovery     which are publicly
                                 device or a        available. For this
                                 flare or           reason, we propose
                                 regenerator        these data elements
                                 firebox/fire       be designated as
                                 tubes..            ``not CBI'' for both
                                                    onshore production
                                                    and natural gas
                                                    processing plants.
98.236(e)(2)(iv)..............  For glycol
                                 dehydrators with
                                 an annual
                                 average daily
                                 natural gas
                                 throughput less
                                 than 0.4 MMscfd,
                                 whether any
                                 glycol
                                 dehydrator
                                 emissions are
                                 vented to a
                                 flare or
                                 regenerator
                                 firebox/fire
                                 tubes.
98.236(e)(2)(iv)(A)...........  For glycol
                                 dehydrators with
                                 an annual
                                 average daily
                                 natural gas
                                 throughput less
                                 than 0.4 MMscfd
                                 and vented to a
                                 flare or
                                 regenerator
                                 firebox, the
                                 total number of
                                 dehydrators.
98.236(e)(3)(i)...............  For dehydrators
                                 that use
                                 desiccant, the
                                 total number of
                                 dehydrators at
                                 the facility.
98.236(e)(3)(i)...............  For dehydrators
                                 that use
                                 desiccant,
                                 whether any
                                 dehydrator
                                 emissions are
                                 vented to a
                                 vapor recovery
                                 device.
98.236(e)(3)(i)...............  For dehydrators
                                 that use
                                 desiccant, the
                                 total number of
                                 dehydrators
                                 venting to a
                                 vapor recovery
                                 device.
98.236(e)(3)(i)...............  For dehydrators
                                 that use
                                 desiccant,
                                 whether any
                                 dehydrator
                                 emissions are
                                 vented to a
                                 control device
                                 other than a
                                 vapor recovery
                                 device or a
                                 flare or
                                 regenerator
                                 firebox/fire
                                 tubes, and the
                                 control device
                                 type.
98.236(e)(3)(i)...............  For dehydrators
                                 that use
                                 desiccant,
                                 whether any
                                 dehydrator
                                 emissions are
                                 vented to a
                                 control device
                                 other than a
                                 vapor recovery
                                 device or a
                                 flare or
                                 regenerator
                                 firebox/fire
                                 tubes.
98.236(e)(3)(i)...............  For dehydrators
                                 that use
                                 desiccant, the
                                 number of
                                 dehydrators
                                 venting to a
                                 control device
                                 other than a
                                 vapor recovery
                                 device or a
                                 flare or
                                 regenerator
                                 firebox/fire
                                 tubes.
98.236(e)(3)(i)...............  For dehydrators
                                 that use
                                 desiccant,
                                 whether any
                                 glycol
                                 dehydrator
                                 emissions are
                                 vented to a
                                 flare or
                                 regenerator
                                 firebox/fire
                                 tubes.
98.236(e)(3)(i)...............  For dehydrators
                                 that use
                                 desiccant and
                                 vent to a flare
                                 or regenerator
                                 firebox, the
                                 total number of
                                 dehydrators.

[[Page 13409]]

 
98.236(f).....................  Liquids            These proposed data
                                 unloading. You     element would be
                                 must indicate      reported by onshore
98.236(f)(1)(iv)..............   whether well       petroleum and
                                 venting for        natural gas
                                 liquids            production
                                 unloading occurs   facilities. Liquid
                                 at your facility.  unloading is
                                For each Sub-       conducted in mature
                                 basin and well     gas wells that have
                                 tubing diameter    an accumulation of
                                 and pressure       liquids which impede
                                 group for which    the steady flow of
                                 you used           natural gas. This is
                                 Calculation        a common occurrence
                                 Method 1           in reservoirs where
                                 (reported          the pressure is
                                 separately for     depleted and liquids
                                 wells with         enter the well bore.
                                 plunger lifts      The fact that
                                 and wells          liquids unloading
                                 without plunger    occurs and the
                                 lifts), the        number of unloading
                                 count of wells     wells with and
                                 vented to the      without plungers
                                 atmosphere for     vented to the
                                 this grouping..    atmosphere indicate
                                                    that the wells in a
                                                    basin are older and
                                                    may indicate changes
                                                    in production rates.
                                                    However, the age and
                                                    production rates for
                                                    wells are
                                                    information that can
                                                    be derived from or
                                                    are already
                                                    available to the
                                                    public through state
                                                    oil and gas
                                                    commissions. Hence,
                                                    this information is
                                                    routinely publicly
                                                    available, so we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(g).....................  Whether the        These proposed data
                                 facility had any   elements would be
                                 gas well           reported by onshore
98.236(g)(3)..................   completions or     petroleum and
                                 workovers with     natural gas
                                 hydraulic          production
                                 fracturing in      facilities and
                                 the calendar       provide information
                                 year.              on whether the
                                For each            facility conducted
                                 completion or      any well completions
                                 workover and       or workovers during
                                 well type          the reporting year,
                                 combination, the   and for those
                                 total number of    facilities that had
                                 completions or     well completions and/
                                 workovers..        or workovers, the
                                                    number of
                                                    completions and
                                                    workovers that were
                                                    completed.
                                                    Information on the
                                                    number of
                                                    completions and
                                                    workovers performed
                                                    by an oil and gas
                                                    operator in a given
                                                    year and the age and
                                                    production rates for
                                                    wells can be derived
                                                    from or is available
                                                    publicly on state
                                                    oil and gas
                                                    commission Web
                                                    sites. Because
                                                    disclosure of these
                                                    data elements would
                                                    not be likely to
                                                    cause substantial
                                                    competitive harm, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(h)(1)..................  You must indicate  This proposed data
                                 whether the        element would be
                                 facility had any   reported by onshore
                                 gas well           petroleum and
                                 completions        natural gas
                                 without            production
                                 hydraulic          facilities and
                                 fracturing or      provides information
                                 any gas well       on whether the
                                 workovers          facility conducted
                                 without            any well completions
                                 hydraulic          or workovers during
                                 fracturing, and    the reporting year
                                 if the             and whether the
                                 activities         emissions were
                                 occurred with or   flared. Information
                                 without flaring.   on completions and
                                                    workovers performed
                                                    in a given year and
                                                    the age and
                                                    production rates for
                                                    wells can be derived
                                                    from or is available
                                                    publicly on state
                                                    oil and gas
                                                    commission Web sites
                                                    and from the Energy
                                                    Information
                                                    Administration
                                                    (EIA). Whether the
                                                    emissions from well
                                                    completions and
                                                    workovers are sent
                                                    to a flare provides
                                                    only information
                                                    about how the
                                                    emissions are
                                                    handled by the
                                                    facility, which is
                                                    not considered to be
                                                    sensitive
                                                    information by the
                                                    industry. Because
                                                    disclosure of these
                                                    data elements would
                                                    not be likely to
                                                    cause substantial
                                                    competitive harm, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(h)(1)(ii)..............  For each sub-      These proposed data
                                 basin with gas     elements would be
                                 well completions   reported by onshore
                                 without            petroleum and
98.236(h)(2)(ii)..............   hydraulic          natural gas
                                 fracturing and     production
                                 without flaring,   facilities and
                                 the number of      provide information
                                 completions that   on the number of
                                 vented gas to      completions where
                                 the atmosphere.    gas is vented to the
                                For each sub-       atmosphere and the
                                 basin with gas     number of
                                 well completions   completions where
                                 without            the gas is vented to
                                 hydraulic          a flare. The number
                                 fracturing with    of completions that
                                 flaring, the       vent gas directly to
                                 number of well     the atmosphere and
                                 completions that   the number of
                                 flared gas..       completions that
                                                    send the gas to a
                                                    flare provides only
                                                    information about
                                                    the number of well
                                                    completions that
                                                    were performed in a
                                                    sub-basin during a
                                                    reporting year and
                                                    how the emissions
                                                    are handled by the
                                                    facility. The number
                                                    of completions
                                                    performed each year
                                                    is available
                                                    publicly on state
                                                    oil and gas
                                                    commission Web sites
                                                    and from the EIA.
                                                    Thus, disclosure of
                                                    these data elements
                                                    would not be likely
                                                    to cause substantial
                                                    competitive harm and
                                                    we propose these
                                                    data elements be
                                                    designated as ``not
                                                    CBI.''

[[Page 13410]]

 
98.236(h)(1)(iv)..............  Average daily gas  This proposed data
                                 production rate    element would be
                                 for all            reported by onshore
                                 completions        petroleum and
                                 without            natural gas
                                 hydraulic          production
                                 fracturing in      facilities. This
                                 the sub-basin      data element
                                 without flaring,   potentially provides
                                 in standard        information about
                                 cubic feet per     the productivity of
                                 hour (average of   wells where
                                 all ``Vp'' as      hydraulic fracturing
                                 used in Equation   is not conducted and
                                 W-13B).            the emissions are
                                                    not flared. Because
                                                    production data for
                                                    individual
                                                    production wells are
                                                    publicly available,
                                                    the average daily
                                                    production for all
                                                    wells in a basin
                                                    presents no
                                                    information that is
                                                    not already publicly
                                                    available. Because
                                                    disclosure of this
                                                    data element would
                                                    not be likely to
                                                    cause substantial
                                                    competitive harm, we
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI.''
98.236(h)(2)(iii).............  Total number of    This proposed data
                                 hours that gas     element would be
                                 vented to a        reported by onshore
                                 flare during       petroleum and
                                 backflow for all   natural gas
                                 completions in     production
                                 the sub-basin      facilities and
                                 category (sum of   potentially provides
                                 all ``Tp'' for     information on the
                                 completions that   time spent on well
                                 vented to a        completions.
                                 flare as used in   Information specific
                                 Equation W-13B).   to exploratory wells
                                                    is generally
                                                    considered
                                                    proprietary
                                                    information by the
                                                    industry. However,
                                                    by reporting this
                                                    data as the total
                                                    for all completed
                                                    wells in a sub-basin
                                                    category, data for
                                                    individual wells
                                                    would not be
                                                    disclosed because of
                                                    the large number of
                                                    wells per sub-basin
                                                    category. Because
                                                    disclosure of this
                                                    data element would
                                                    not be likely to
                                                    cause substantial
                                                    competitive harm, we
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI.''
98.236(h)(2)(iv)..............  Average daily gas  This proposed data
                                 production rate    element would be
                                 for all            reported by onshore
                                 completions        petroleum and
                                 without            natural gas
                                 hydraulic          production
                                 fracturing in      facilities. This
                                 the sub-basin      data element
                                 with flaring, in   potentially provides
                                 standard cubic     information about
                                 feet per hour      the productivity of
                                 (the average of    wells where
                                 all ``Vp'' from    hydraulic fracturing
                                 Equation W-13B).   is not conducted and
                                                    the emissions are
                                                    flared. Because
                                                    production data for
                                                    individual
                                                    production wells are
                                                    publicly available,
                                                    the average daily
                                                    production for all
                                                    wells in a basin
                                                    presents no
                                                    information that is
                                                    not already publicly
                                                    available. Because
                                                    disclosure of this
                                                    data element would
                                                    not be likely to
                                                    cause substantial
                                                    competitive harm, we
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI.''
98.236(i)(1)(i)...............  Total number of    This proposed data
                                 blowdowns in the   element would be
                                 calendar year      reported by the
                                 for the            onshore petroleum
                                 equipment type     and natural gas
                                 (sum equation      production, onshore
                                 variable ``N''     natural gas
                                 from Equation W-   processing, onshore
                                 14A or Equation    natural gas
                                 W-14B of this      transmission
                                 subpart for all    compression, and LNG
                                 unique physical    import and export
                                 volumes for the    facilities.
                                 equipment type).   Blowdowns occur when
                                                    equipment is taken
                                                    out of service,
                                                    either to be placed
                                                    on standby or for
                                                    maintenance
                                                    purposes, and the
                                                    natural gas in the
                                                    equipment is
                                                    typically released
                                                    to the atmosphere.
                                                    This practice may
                                                    occur as part of a
                                                    routine scheduled
                                                    maintenance or as
                                                    the result of an un-
                                                    planned event (e.g.,
                                                    equipment
                                                    breakdown). Although
                                                    blowdown events may
                                                    be associated with
                                                    periods of reduced
                                                    production or
                                                    throughput, natural
                                                    gas processing
                                                    plants and LNG
                                                    import/export
                                                    facilities typically
                                                    have backup units
                                                    that can be used to
                                                    avoid production
                                                    shutdowns. Hence,
                                                    the number of
                                                    blowdown events that
                                                    occur during a
                                                    reporting year does
                                                    not indicate a plant
                                                    was shut down and
                                                    would not provide
                                                    any potentially
                                                    sensitive
                                                    information on the
                                                    impact of such
                                                    events on a
                                                    facility's
                                                    production or
                                                    throughput. Hence,
                                                    the disclosure of
                                                    the number of
                                                    blowdowns occurring
                                                    during a reporting
                                                    year is not likely
                                                    to cause substantial
                                                    competitive harm.
                                                    For this reason, we
                                                    propose that this
                                                    data element be
                                                    designated ``not
                                                    CBI'' when reported
                                                    by onshore natural
                                                    gas processing
                                                    plants and LNG
                                                    import/export
                                                    facilities.

[[Page 13411]]

 
                                                   These proposed data
                                                    elements would also
                                                    be reported by the
                                                    natural gas
                                                    transmission
                                                    compression sector.
                                                    Companies operating
                                                    in this sector are
                                                    subject to
                                                    regulatory oversight
                                                    by the Federal
                                                    Energy Regulatory
                                                    Commission (FERC),
                                                    state utility
                                                    commissions, and
                                                    other federal
                                                    agencies because
                                                    they operate in an
                                                    industry that is
                                                    inherently
                                                    uncompetitive. FERC
                                                    controls pricing,
                                                    sets rules for
                                                    business practices,
                                                    has the power to
                                                    impose conditions on
                                                    mergers and
                                                    acquisitions, and
                                                    has the sole
                                                    responsibility for
                                                    authorizing the
                                                    location,
                                                    construction and
                                                    operations of
                                                    companies operating
                                                    in this sector. The
                                                    rate charged for
                                                    transporting gas is
                                                    regulated. Hence the
                                                    tightly regulated
                                                    natural gas
                                                    transmission sector
                                                    is inherently less
                                                    competitive than
                                                    other industries.
                                                    Because disclosure
                                                    of the number of
                                                    blowdowns occurring
                                                    during a reporting
                                                    year would not be
                                                    likely to cause
                                                    substantive
                                                    competitive harm, we
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI'' when reported
                                                    by the natural gas
                                                    transmission sector.
98.236(j).....................  You must indicate  This proposed data
                                 whether your       element would be
                                 facility sends     reported by onshore
                                 produced oil to    petroleum and
                                 atmospheric        natural gas
                                 tanks.             production
                                                    facilities and
                                                    indicates only that
                                                    a facility is
                                                    equipped with
                                                    atmospheric storage
                                                    tanks. Atmospheric
                                                    storage tanks are
                                                    used to store
                                                    hydrocarbon liquids
                                                    from separators or
                                                    production wells.
                                                    Atmospheric tanks
                                                    are a typical part
                                                    of onshore
                                                    production
                                                    facilities and are
                                                    listed in each
                                                    facility's
                                                    construction and
                                                    operating permits,
                                                    which have to be
                                                    reissued when
                                                    modifications are
                                                    made to the
                                                    facility. Hence,
                                                    disclosure of this
                                                    data element would
                                                    not be likely to
                                                    cause substantial
                                                    competitive harm and
                                                    we propose that this
                                                    data element be
                                                    designated as ``not
                                                    CBI.''
98.236(j).....................  If any of the      These proposed data
                                 atmospheric        elements would be
                                 tanks are          reported by onshore
98.236(j)(3)(ii)..............   observed to have   petroleum and
                                 malfunctioning     natural gas
                                 dump valves,       production
                                 indicate that      facilities and
                                 dump valves were   provide information
                                 malfunctioning.    on malfunctioning of
                                If any of the gas-  dump valves on gas-
                                 liquid separator   liquid separators.
                                 liquid dump        Separators are used
                                 valves did not     to separate
                                 close properly     hydrocarbons into
                                 during the         liquid and gas
                                 reporting year,    phases and are
                                 the total time,    typically connected
                                 in hours, the      to atmospheric
                                 dump valves on     storage tanks where
                                 gas-liquid         the hydrocarbon
                                 separators did     liquids are stored.
                                 not close          Dump valves on
                                 properly (``Tn''   separators
                                 in equation W-     periodically release
                                 16)..              liquids from the
                                                    separator. The time
                                                    period during which
                                                    a dump valve is
                                                    malfunctioning
                                                    provides little
                                                    insight into
                                                    maintenance
                                                    practices or the
                                                    nature or cost of
                                                    repairs that are
                                                    needed. Therefore,
                                                    this information
                                                    would not be likely
                                                    to cause substantial
                                                    competitive harm to
                                                    reporters. For this
                                                    reason, we are
                                                    proposing these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(k)(1)(iii).............  For each           These proposed data
                                 transmission       elements would be
                                 storage tank       reported by the
                                 vent stack,        onshore natural gas
98.236(k)(1)(iv)..............   indicate whether   transmission
                                 scrubber dump      compression sector.
                                 valve leakage is   Companies operating
                                 occurring for      in this sector are
                                 the underground    subject to
                                 storage vent.      regulatory oversight
                                For each            by FERC, state
                                 transmission       utility commissions,
                                 storage tank       and other federal
                                 vent stack,        agencies because
                                 indicate if        they operate in an
                                 there is a flare   industry that is
                                 attached to the    inherently
                                 vent stack..       uncompetitive. FERC
                                                    controls pricing,
                                                    sets rules for
                                                    business practices,
                                                    has the power to
                                                    impose conditions on
                                                    mergers and
                                                    acquisitions, and
                                                    has the sole
                                                    responsibility for
                                                    authorizing the
                                                    location,
                                                    construction and
                                                    operations of
                                                    companies operating
                                                    in this sector. The
                                                    rate charged for
                                                    transporting gas is
                                                    regulated. Hence the
                                                    natural gas
                                                    transmission sector
                                                    is inherently less
                                                    competitive than
                                                    other industries and
                                                    there is little
                                                    incentive to build
                                                    additional pipelines
                                                    and compressor
                                                    stations within the
                                                    same corridors as
                                                    existing
                                                    transmission lines.
                                                    Because disclosure
                                                    of these data
                                                    elements would not
                                                    be likely to cause
                                                    substantive
                                                    competitive harm, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''

[[Page 13412]]

 
98.236(l)(1)(iv)..............  If oil well        This proposed data
                                 testing is         element would be
                                 performed where    reported by onshore
                                 emissions are      petroleum and
98.236(l)(2)(iv)..............   not vented to a    natural gas
                                 flare, the         production
                                 average flow       facilities. These
                                 rate in barrels    data elements
98.236(l)(3)(iii).............   of oil per day     provide information
                                 for well(s)        on the oil flow and
                                 tested.            gas production rates
                                If oil well         of wells. Oil and
                                 testing is         gas production data
                                 performed where    for individual wells
                                 emissions are      are publicly
                                 vented to a        available. Because
                                 flare, the         production data for
                                 average flow       individual
                                 rate in barrels    production wells are
                                 of oil per day     publicly available,
                                 for well(s)        the average of all
                                 tested..           wells tested
                                If gas well         presents no
                                 testing is         information that is
                                 performed where    not already publicly
                                 emissions are      available. Because
                                 not vented to a    disclosure of these
                                 flare, the         data elements would
                                 average annual     not be likely to
                                 production rate    cause substantial
                                 in actual cubic    competitive harm, we
                                 feet per day for   propose these data
                                 well(s) tested..   elements be
                                                    designated as ``not
                                                    CBI.''
98.236(l)(4)(iii).............  If gas well
                                 testing is
                                 performed where
                                 emissions are
                                 vented to a
                                 flare, the
                                 average annual
                                 production rate
                                 in actual cubic
                                 feet per day for
                                 well(s) tested.
98.236(m).....................  You must indicate  These proposed data
                                 whether any        elements would be
                                 associated gas     reported by onshore
98.236(m)(2)..................   was vented or      petroleum and
                                 flared during      natural gas
98.236(m)(3)..................   the reporting      production
                                 year.              facilities and
                                For each sub-       indicate whether
                                 basin, indicate    associated gas is
                                 whether any        flared or vented
                                 associated gas     directly to the
                                 was vented         atmosphere.
                                 without flaring..  Information on how
                                For each sub-       emissions are
                                 basin, indicate    handled does not
                                 whether any        provide any insight
                                 associated gas     into the operation
                                 was flared..       of the emission
                                                    source. Therefore,
                                                    disclosure of these
                                                    data elements would
                                                    be unlikely to cause
                                                    competitive harm.
                                                    For this reason, we
                                                    are proposing these
                                                    data elements be
                                                    designated as ``not
                                                    CBI.''
98.236(m)(5)..................  For each sub-      These proposed data
                                 basin, the         elements would be
                                 volume of oil      reported by onshore
98.236(m)(6)..................   produced during    petroleum and
                                 time periods in    natural gas
                                 which associated   production
                                 gas was vented     facilities and
                                 or flared          provide production
                                 (barrels).         related information
                                For each sub-       during periods when
                                 basin, the total   associated gas is
                                 volume of          vented or flared.
                                 associated gas     Associated gas is
                                 sent to sales      vented or flared
                                 during time        when it is not being
                                 periods in which   captured for sales.
                                 associated gas     Oil and gas
                                 was vented or      production data for
                                 flared (scf)..     individual
                                                    production wells are
                                                    publicly available,
                                                    By reporting this
                                                    data as total for
                                                    all production wells
                                                    in a sub-basin
                                                    category, no data
                                                    for individual wells
                                                    is disclosed that is
                                                    not already publicly
                                                    available. Because
                                                    disclosure of these
                                                    data elements would
                                                    not be likely to
                                                    cause substantial
                                                    competitive harm, we
                                                    propose they be
                                                    designated as ``not
                                                    CBI.''
98.236(o)(1)(xvi).............  Date of last       These proposed data
                                 maintenance        elements would be
98.236(o)(2)(viii)............   shutdown that      reported by onshore
                                 the compressor     petroleum and
                                 was                natural gas
                                 depressurized.     production
                                If the emission     facilities, onshore
                                 vent is routed     natural gas
                                 to flare,          processing plants,
                                 combustion, or     LNG import/export
                                 vapor recovery,    terminals, natural
                                 report the         gas transmission
                                 percentage of      compression,
                                 time that the      underground natural
                                 respective         gas storage
                                 device was         facilities, and LNG
                                 operational..      storage facilities.
                                                    These data elements
                                                    provide information
                                                    about the operation
                                                    and maintenance of
                                                    centrifugal
                                                    compressors.
                                                    Centrifugal
                                                    compressors are used
                                                    to move gas at high
                                                    pressure through
                                                    pipelines and are
                                                    standard equipment
                                                    found at all types
                                                    of natural gas
                                                    facilities.
                                                    Facilities typically
                                                    have backup
                                                    compressors to allow
                                                    operations to
                                                    continue without
                                                    interruption during
                                                    periods of
                                                    maintenance and
                                                    repair. Hence, the
                                                    percentage of time a
                                                    compressor was
                                                    operational and the
                                                    date of last
                                                    maintenance shutdown
                                                    would be not likely
                                                    to cause substantial
                                                    competitive harm to
                                                    any type of natural
                                                    gas facility. For
                                                    these reasons, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''

[[Page 13413]]

 
98.236(p)(1)(xvi).............  Date of last       These proposed data
                                 maintenance        elements would be
98.236(p)(2)(viii)............   shutdown for rod   reported by onshore
                                 packing            petroleum and
                                 replacement.       natural gas
                                If the emission     production
                                 vent is routed     facilities, onshore
                                 to flare,          natural gas
                                 combustion, or     processing plants,
                                 vapor recovery,    LNG import/export
                                 report the         terminals, natural
                                 percentage of      gas transmission
                                 time that the      compression,
                                 respective         underground natural
                                 device was         gas storage
                                 operational..      facilities, and LNG
                                                    storage facilities.
                                                    These data elements
                                                    provide information
                                                    about the operation
                                                    and maintenance of
                                                    reciprocating
                                                    compressors.
                                                    Reciprocating
                                                    compressors are used
                                                    to move gas at high
                                                    pressure through
                                                    pipelines and are
                                                    standard equipment
                                                    found at all types
                                                    of natural gas
                                                    facilities.
                                                    Facilities typically
                                                    have backup
                                                    compressors to allow
                                                    operations to
                                                    continue without
                                                    interruption during
                                                    periods of
                                                    compressor
                                                    maintenance and
                                                    repair. Hence, the
                                                    percentage of time a
                                                    compressor is
                                                    operational and date
                                                    of last maintenance
                                                    shutdown would be
                                                    not likely to cause
                                                    substantial
                                                    competitive harm to
                                                    any type of natural
                                                    gas facility. For
                                                    these reasons, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(q)(2)(iii).............  Average time the   This proposed data
                                 surveyed           element would
                                 components were    provide information
                                 found leaking      on the amount of
                                 and operational,   time operational
                                 in hours           components were
                                 (average of Tp,z   found to be leaking.
                                 in Equation W-30   This information
                                 of this subpart).  would provide little
                                                    insight into
                                                    maintenance
                                                    practices at a
                                                    facility because it
                                                    would not identify
                                                    the cause of the
                                                    leaks or the nature
                                                    and cost of repairs.
                                                    Therefore, this
                                                    information would
                                                    not be likely to
                                                    cause substantial
                                                    competitive harm to
                                                    reporters. For this
                                                    reason, we are
                                                    proposing the
                                                    average time
                                                    operational
                                                    components were
                                                    found leaking be
                                                    designated as ``not
                                                    CBI.''
98.236(q)(3)(ii)..............  Number of meter/   These proposed data
                                 regulator runs     elements would be
                                 at above grade     reported by natural
98.236(q)(3)(iii).............   transmission-      gas distribution
                                 distribution       facilities. Natural
                                 transfer           gas distribution
                                 stations           companies are
                                 surveyed in the    subject to
98.236(q)(3)(v)...............   calendar year.     regulatory oversight
                                Average time that   by state utility
                                 meter/regulator    commissions because
98.236(q)(3)(vi)..............   runs surveyed in   they operate in an
                                 the calendar       industry that is
                                 year were          inherently not
                                 operational, in    competitive. The
                                 hours (average     state utility
                                 of Tw,y in         commission controls
                                 Equation W-31 of   pricing, sets rules
                                 this subpart,      for business
                                 for the current    practices, has the
                                 calendar year)..   power to impose
                                Number of meter/    conditions on
                                 regulator runs     mergers and
                                 at above grade     acquisitions, and
                                 transmission-      has the sole
                                 distribution       responsibility for
                                 transfer           authorizing the
                                 stations           location,
                                 surveyed in        construction and
                                 current leak       operations of
                                 survey cycle..     companies operating
                                Average time that   in this sector.
                                 meter/regulator    Because disclosure
                                 runs surveyed in   of these data
                                 the current leak   elements would not
                                 survey cycle       be likely to cause
                                 were               substantive
                                 operational, in    competitive harm, we
                                 hours..            propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI'' when reported
                                                    by natural gas
                                                    distributors.
98.236(w).....................  Whether CO2        This proposed data
                                 enhanced oil       element would be
                                 recovery (EOR)     reported by onshore
                                 injection was      petroleum and
                                 used at the        natural gas
                                 facility.          production
                                                    facilities. This
                                                    data element
                                                    indicates whether
                                                    EOR is performed.
                                                    However, underground
                                                    injection of CO2 is
                                                    regulated under 40
                                                    CFR parts 124, 144
                                                    and 146. Facilities
                                                    that inject CO2
                                                    underground are
                                                    required to have an
                                                    Underground
                                                    Injection Control
                                                    (UIC) permit, which
                                                    is a public document
                                                    issued by the EPA or
                                                    by states that have
                                                    primary enforcement
                                                    authority for
                                                    permitting injection
                                                    wells. Since this
                                                    information is
                                                    already available
                                                    through other public
                                                    documents, we
                                                    propose this data be
                                                    designated as ``not
                                                    CBI.''
98.236(w).....................  You must indicate  This proposed data
                                 whether any EOR    element would be
                                 injection pump     reported by the
                                 blowdowns          onshore petroleum
                                 occurred during    and natural gas
                                 the year.          production
                                                    facilities using
                                                    EOR. Blowdowns are a
                                                    typical operation
                                                    undertaken by EOR
                                                    operators and occur
                                                    when equipment is
                                                    taken out of service
                                                    either to be placed
                                                    on standby or for
                                                    maintenance
                                                    purposes. This
                                                    practice may occur
                                                    as part of a routine
                                                    scheduled
                                                    maintenance or be
                                                    the result of an un-
                                                    planned event (e.g.,
                                                    equipment
                                                    breakdown). Although
                                                    blowdown events may
                                                    be associated with
                                                    periods of reduced
                                                    production,
                                                    facilities typically
                                                    have backup pumps
                                                    that can be used to
                                                    avoid production
                                                    shutdowns. Hence,
                                                    the disclosure of
                                                    the number of
                                                    blowdowns occurring
                                                    during a reporting
                                                    year is not likely
                                                    to cause substantial
                                                    competitive harm.
                                                    For this reason, we
                                                    propose that this
                                                    data element be
                                                    designated ``not
                                                    CBI.''

[[Page 13414]]

 
98.236(x).....................  Whether            This proposed data
                                 hydrocarbon        element would be
                                 liquids were       reported by onshore
                                 produced through   petroleum and
                                 EOR operations.    natural gas
                                                    production
                                                    facilities using EOR
                                                    and provides
                                                    production related
                                                    information about
                                                    EOR operations.
                                                    However, production
                                                    data for wells is
                                                    available to the
                                                    public through state
                                                    oil and gas
                                                    commissions. Since
                                                    this information is
                                                    already available
                                                    through other public
                                                    documents, we
                                                    propose this data be
                                                    designated as ``not
                                                    CBI.''
98.236(z)(2)(i)...............  The type of        This data element
                                 combustion unit.   would be reported by
                                                    onshore petroleum
                                                    and gas production
                                                    facilities and
                                                    natural gas
                                                    distribution. This
                                                    data element would
                                                    provide information
                                                    on the types of
                                                    combustion units.
                                                    Information on the
                                                    types of combustion
                                                    units located at a
                                                    facility is often
                                                    available in a
                                                    facility's
                                                    construction and
                                                    operating permits.
                                                    For these reasons,
                                                    we consider
                                                    information on the
                                                    types of combustion
                                                    units in production
                                                    and distribution
                                                    facilities would not
                                                    be likely to cause
                                                    substantive
                                                    competitive harm and
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI'' for both
                                                    industry sectors.
98.236(z)(2)(ii)..............  Type of fuel       This data element
                                 combusted.         would be reported by
                                                    onshore petroleum
                                                    and gas production
                                                    facilities and
                                                    natural gas
                                                    distribution. This
                                                    data element would
                                                    provide information
                                                    on the types of fuel
                                                    burned. However,
                                                    facilities in both
                                                    these sectors
                                                    generally burn fuels
                                                    that are readily
                                                    available to them as
                                                    part of their
                                                    operations.
                                                    Information on the
                                                    types of fuels
                                                    burned by a facility
                                                    is often available
                                                    in a facility's
                                                    construction and
                                                    operating permits.
                                                    For these reasons,
                                                    we consider
                                                    information on the
                                                    types of fuels
                                                    burned by production
                                                    and distribution
                                                    facilities would not
                                                    be likely to cause
                                                    substantive
                                                    competitive harm and
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI'' for both
                                                    industry sectors.
98.236(aa)(1)(ii)(I)..........  For each sub-      This proposed data
                                 basin category,    element would be
98.236(aa)(1)(ii)(J)..........   the average mole   reported by onshore
                                 fraction CH4 in    petroleum and
                                 produced gas.      natural gas
                                For each sub-       production
                                 basin category,    facilities. The
                                 the average mole   typical composition
                                 fraction CO2 in    of produced gas is
                                 produced gas..     available through
                                                    the Gas Technology
                                                    Institute and the
                                                    Department of
                                                    Energy, Gas
                                                    Information System
                                                    (GASIS) Database.\5\
                                                    Both of these
                                                    sources are made
                                                    available to the
                                                    public. Since these
                                                    data are publicly
                                                    available we are
                                                    proposing these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(4)(i)..............  The quantity of    These proposed data
                                 gas transported    elements would be
                                 through the        reported by the
98.236(aa)(4)(iv).............   compressor         onshore natural gas
                                 station in the     transmission
98.236(aa)(4)(v)..............   calendar year,     compression sector.
                                 in thousand        Companies operating
                                 standard cubic     in this sector are
                                 feet.              subject to
                                The average         regulatory oversight
                                 upstream           by FERC, state
                                 pipeline           utility commissions,
                                 pressure in        and other federal
                                 pounds per         agencies because
                                 square inch        they operate in an
                                 gauge..            industry that is
                                The average         inherently
                                 downstream         uncompetitive. FERC
                                 pipeline           controls pricing,
                                 pressure in        sets rules for
                                 pounds per         business practices,
                                 square inch        has the power to
                                 gauge..            impose conditions on
                                                    mergers and
                                                    acquisitions, and
                                                    has the sole
                                                    responsibility for
                                                    authorizing the
                                                    location,
                                                    construction and
                                                    operations of
                                                    companies operating
                                                    in this sector. The
                                                    rate charged for
                                                    transporting gas is
                                                    regulated. Hence the
                                                    natural gas
                                                    transmission sector
                                                    is inherently less
                                                    competitive than
                                                    other industries and
                                                    there is little
                                                    incentive to build
                                                    additional pipelines
                                                    and compressor
                                                    stations within the
                                                    same corridors as
                                                    existing
                                                    transmission lines.
                                                    Because disclosure
                                                    of pipeline
                                                    pressures and the
                                                    quantity of gas
                                                    transported through
                                                    the compressor would
                                                    not be likely to
                                                    cause substantive
                                                    competitive harm, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''

[[Page 13415]]

 
98.236(aa)(5)(i)..............  The quantity of    These proposed data
                                 gas injected       elements would be
                                 into storage in    reported by
98.236(aa)(5)(ii).............   the calendar       underground natural
                                 year, in           gas storage
                                 thousand           facilities.
                                 standard cubic     Underground storage
                                 feet.              facilities are
                                The quantity of     closely associated
                                 gas withdrawn      with and are part of
                                 from storage in    the utilities'
                                 the calendar       integrated
                                 year, in           distribution
                                 thousand           systems. Some are
                                 standard cubic     owned by natural gas
                                 feet..             distribution
                                                    companies.
                                                    Distribution
                                                    companies are
                                                    regulated by state
                                                    commissions, because
                                                    they operate in an
                                                    industry that is
                                                    inherently not
                                                    competitive.
                                                    Underground storage
                                                    facilities are
                                                    constrained by
                                                    geographical and
                                                    geological
                                                    requirements. These
                                                    facilities must be
                                                    located in areas
                                                    where appropriate
                                                    geologic conditions
                                                    exist for gas
                                                    storage, while also
                                                    located near regions
                                                    of the country where
                                                    gas usage fluctuates
                                                    during the year.
                                                    Typically, gas is
                                                    injected into
                                                    underground storage
                                                    during the summer
                                                    months, when
                                                    consumer demand is
                                                    low, and withdrawn
                                                    during the winter
                                                    months, when demand
                                                    peaks. These factors
                                                    provide significant
                                                    barriers to new
                                                    companies moving
                                                    into the underground
                                                    storage sector or
                                                    existing companies
                                                    increasing their
                                                    market share.
                                                    Because disclosure
                                                    of these proposed
                                                    new data elements
                                                    would not be likely
                                                    to cause substantive
                                                    competitive harm to
                                                    underground storage
                                                    facilities, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(6).................  For LNG import     Quantities of LNG
                                 equipment, the     imported to the U.S.
                                 quantity of LNG    together with the
                                 imported in the    name of the importer
                                 calendar year,     are published by EIA
                                 in thousand        in quarterly
                                 standard cubic     reports. Because
                                 feet.              disclosure of this
                                                    proposed new data
                                                    element would not be
                                                    likely to cause
                                                    substantive
                                                    competitive harm, we
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(7).................  For LNG export     Quantities of natural
                                 equipment, the     gas exported from
                                 quantity of LNG    the U.S. are
                                 exported in the    published by EIA in
                                 calendar year,     quarterly reports.
                                 in thousand        Because disclosure
                                 standard cubic     of this proposed new
                                 feet.              data element would
                                                    not be likely to
                                                    cause substantive
                                                    competitive harm, we
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(8)(i)..............  The quantity of    These proposed data
                                 LNG added into     elements would be
                                 storage in the     reported by LNG
98.236(aa)(8)(ii).............   calendar year,     storage facilities.
                                 in thousand        Most LNG storage
                                 standard cubic     facilities are owned
                                 feet.              by distributors
                                The quantity of     whose operations are
                                 LNG withdrawn      regulated by FERC
                                 from storage in    and state
                                 the calendar       commissions, because
                                 year, in           they operate in an
                                 thousand           industry that is
                                 standard cubic     inherently not
                                 feet..             competitive. FERC
                                                    controls pricing,
                                                    sets rules for
                                                    business practices,
                                                    has the power to
                                                    impose conditions on
                                                    mergers and
                                                    acquisitions, and
                                                    has the sole
                                                    responsibility for
                                                    authorizing the
                                                    location,
                                                    construction and
                                                    operations of
                                                    companies operating
                                                    in this sector.
                                                    Because disclosure
                                                    of these proposed
                                                    new data elements
                                                    would not be likely
                                                    to cause substantive
                                                    competitive harm, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(9)(i)..............  The quantity of    Natural gas
                                 natural gas        distribution
                                 received at all    companies are
98.236(aa)(9)(ii).............   custody transfer   subject to
                                 stations in the    regulatory oversight
                                 calendar year in   by state utility
98.236(aa)(9)(iii)............   thousand           commissions, because
                                 standard cubic     they operate in an
                                 feet.              industry that is
98.236(aa)(9)(iv).............  The quantity of     inherently not
                                 natural gas        competitive. Many of
                                 withdrawn from     these data elements
                                 in-system          are also reported to
                                 storage in the     EIA on a monthly
                                 calendar year in   basis (e.g., natural
                                 thousand cubic     gas withdrawn from
                                 feet..             storage, natural gas
                                The quantity of     stored, gas received
                                 natural gas        at city gate). EIA
                                 added to in-       publishes the data
                                 system storage     on their Web site on
                                 in the calendar    an annual basis.
                                 year in thousand   Because disclosure
                                 cubic feet..       of these proposed
                                The quantity of     new data elements
                                 natural gas        would not be likely
                                 delivered to end   to cause substantive
                                 users in           competitive harm, we
                                 thousand cubic     propose these data
                                 feet. This value   elements be
                                 does not include   designated as ``not
                                 stolen gas, or     CBI.''
                                 gas that is
                                 otherwise
                                 unaccounted for.
98.236(aa)(9)(v)..............  The quantity of    .....................
                                 natural gas
                                 transferred to
                                 third parties
                                 such as other
                                 LDCs or
                                 pipelines in
                                 thousand cubic
                                 feet. This value
                                 does not include
                                 stolen gas, or
                                 gas that is
                                 otherwise
                                 unaccounted for.
98.236(aa)(9)(vi).............  The quantity of    .....................
                                 natural gas
                                 consumed by the
                                 LDC for
                                 operational
                                 purposes in
                                 thousand cubic
                                 feet.
98.236(aa)(9)(vii)............  The estimated      .....................
                                 quantity of gas
                                 stolen in the
                                 calendar year in
                                 thousand cubic
                                 feet.
------------------------------------------------------------------------

[[Page 13416]]

 
 ``Unit/Process `Static' Characteristics That Are Not Inputs to Emission
                        Equations'' Data Category
------------------------------------------------------------------------
98.236(o)(1)(iv) operating      For non-           These proposed data
 mode (v) not operating mode.    manifolded         elements would be
                                 compressors,       reported by onshore
                                 whether the        petroleum and
98.236(o)(1)(vii).............   compressor was     natural gas
                                 measured in the    production
98.236(o)(1)(viii)............   operating-mode     facilities, onshore
                                 or the not-        natural gas
98.236(o)(1)(ix)..............   operating-         processing plants,
                                 depressurized-mo   LNG import/export
                                 de.                terminals, natural
98.236(o)(1)(x)...............  Indicate whether    gas transmission
                                 any compressor     compression,
98.236(o)(1)(xi)..............   sources are        underground natural
                                 routed to a        gas storage
98.236(o)(1)(xiii)............   flare..            facilities, and LNG
98.236(o)(1)(xiv).............  Indicate whether    storage facilities.
98.236(o)(1)(xv)..............   any compressor     These data elements
                                 sources have       indicate whether a
                                 vapor recovery..   facility has
                                Indicate whether    centrifugal
                                 emissions from     compressors, how
                                 any compressor     emissions from each
                                 sources are        unit are handled,
                                 captured for       and specific
                                 fuel use or are    information about
                                 routed to a        the design and age
                                 thermal            of each centrifugal
                                 oxidizer..         compressor.
                                Indicate whether    Centrifugal
                                 the compressor     compressors are used
                                 has blind          to move gas at high
                                 flanges            pressure through
                                 installed..        pipelines and are
                                Indicate whether    standard equipment
                                 the compressor     found at all types
                                 has wet or dry     of natural gas
                                 seals..            facilities.
                                Compressor power    Centrifugal
                                 rating (hp)..      compressors are also
                                Year compressor     listed in each
                                 was installed..    facility's
                                Compressor model    construction and
                                 name and           operating permits,
                                 description..      which must be
                                                    updated and reissued
                                                    when modifications
                                                    are made. Hence, the
                                                    fact that a facility
                                                    has a centrifugal
                                                    compressor, its age
                                                    and design, and
                                                    emissions handling
                                                    reveals no sensitive
                                                    information that
                                                    would be likely to
                                                    cause substantial
                                                    competitive harm to
                                                    any type of natural
                                                    gas facility. For
                                                    these reasons, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(p)(1)(viii)............  Indicate whether   These proposed data
                                 any compressor     elements would be
                                 sources are part   reported by onshore
98.236(p)(1)(ix)..............   of a manifolded    petroleum and
                                 group of           natural gas
98.236(p)(1)(x)...............   compressor         production
                                 sources.           facilities, onshore
98.236(p)(1)(xi)..............  Indicate whether    natural gas
                                 any compressor     processing plants,
                                 sources are        LNG import/export
98.236(p)(1)(xii).............   routed to a        terminals, natural
                                 flare..            gas transmission
98.236(p)(1)(xiii)............  Indicate whether    compression,
98.236(p)(1)(xiv).............   any compressor     underground natural
98.236(p)(1)(xv)..............   sources have       gas storage
                                 vapor recovery..   facilities, and LNG
                                Indicate whether    storage facilities.
                                 emissions from     These data elements
                                 any compressor     indicate whether a
                                 sources are        facility has
                                 captured for       reciprocating
                                 fuel use or are    compressors, how
                                 routed to a        emissions from each
                                 thermal            unit are handled,
                                 oxidizer..         and specific
                                Indicate whether    information about
                                 the compressor     the design and age
                                 has blind          of each
                                 flanges            reciprocating
                                 installed..        compressor.
                                Compressor power    Reciprocating
                                 rating (hp)..      compressors are used
                                Year compressor     to move gas at high
                                 was installed..    pressure through
                                Compressor model    pipelines and are
                                 name and           standard equipment
                                 description..      found at all types
                                                    of natural gas
                                                    facilities.
                                                    Reciprocating
                                                    compressors are also
                                                    listed in each
                                                    facility's
                                                    construction and
                                                    operating permit,
                                                    which must be
                                                    updated and reissued
                                                    when modifications
                                                    are made. Because
                                                    disclosure of these
                                                    data elements would
                                                    be not likely to
                                                    cause substantial
                                                    competitive harm to
                                                    any type of natural
                                                    gas facility, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(z)(1)(ii)..............  The total number   This data element
                                 of combustion      would be reported by
                                 units.             onshore petroleum
                                                    and gas production
                                                    facilities and
                                                    natural gas
                                                    distribution.
                                                   This data element
                                                    provides information
                                                    on the number of
                                                    internal and
                                                    external combustion
                                                    units located at
                                                    onshore petroleum
                                                    and natural gas
                                                    production
                                                    facilities. However,
                                                    this information
                                                    would not be likely
                                                    to cause substantial
                                                    competitive harm if
                                                    released to the
                                                    public, since
                                                    internal and
                                                    external combustion
                                                    units are typical
                                                    parts of an onshore
                                                    petroleum and
                                                    natural gas
                                                    production facility
                                                    and the total number
                                                    of such units is not
                                                    considered to be
                                                    competitively
                                                    sensitive
                                                    information by this
                                                    industry sector.
                                                    Because disclosure
                                                    of the number of
                                                    combustion units
                                                    would not be likely
                                                    to cause substantive
                                                    competitive harm to
                                                    this sector, we
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI'' when reported
                                                    by onshore petroleum
                                                    and natural gas
                                                    production
                                                    facilities.
                                                   Natural gas
                                                    distribution
                                                    companies are
                                                    subject to
                                                    regulatory oversight
                                                    by state utility
                                                    commissions, because
                                                    they operate in an
                                                    industry that is
                                                    inherently not
                                                    competitive. Because
                                                    disclosure of the
                                                    number combustion
                                                    units would not be
                                                    likely to cause
                                                    substantive
                                                    competitive harm, we
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI'' when reported
                                                    by natural gas
                                                    distributors.

[[Page 13417]]

 
98.236(aa)(1)(ii)(C)..........  For each sub-      The formation type
                                 basin category,    refers to the
                                 the formation      following types of
                                 type.              formations: Oil,
                                                    high permeability
                                                    gas, shale gas, coal
                                                    seam, or other tight
                                                    gas reservoir rock.
                                                    The location of
                                                    these formations is
                                                    general information
                                                    that is publicly
                                                    available from EIA.
                                                    Because disclosure
                                                    of the formation
                                                    would not be likely
                                                    to cause substantive
                                                    competitive harm, we
                                                    propose this data
                                                    element be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(1)(ii)(D)..........  For each sub-      We are proposing that
                                 basin category,    each of these
                                 the number of      proposed new data
98.236(aa)(1)(ii)(E)..........   producing wells    elements be assigned
                                 at the end of      to the Unit/Process
                                 the calendar       Static
98.236(aa)(1)(ii)(F)..........   year.              Characteristics That
                                For each sub-       Are Not Inputs to
                                 basin category,    Emission Equations''
98.236(aa)(1)(ii)(G)..........   the number of      because each data
                                 producing wells    element provides
98.236(aa)(1)(ii)(H)..........   acquired during    descriptive
                                 the calendar       information about
                                 year..             units at the
                                For each sub-       facility and does
                                 basin category,    not meet the
                                 the number of      definition of
                                 producing wells    emission data. We
                                 divested during    propose that each
                                 the calendar       new data element be
                                 year..             designated as ``not
                                For each sub-       CBI'' because
                                 basin category,    detailed information
                                 the number of      regarding wells is
                                 wells completed    available from state
                                 during the         databases and
                                 calendar year..    permits. Because
                                For each sub-       disclosure of the
                                 basin category,    formation would not
                                 the number of      be likely to cause
                                 wells taken out    substantive
                                 of production      competitive harm, we
                                 during the         propose this data
                                 calendar year..    element be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(3)(vii)............  Whether the        Whether a natural gas
                                 onshore natural    processing facility
                                 gas processing     fractionates NGLs is
                                 facility           information that is
                                 fractionates       readily available
                                 natural gas        from other public
                                 liquids (NGLs).    sources, such as the
                                                    LPG Almanac (updated
                                                    annually) and other
                                                    trade journals. For
                                                    this reason,
                                                    disclosure of this
                                                    information would
                                                    not be likely to
                                                    cause substantial
                                                    competitive harm and
                                                    we propose that this
                                                    data element be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(4)(ii).............  Number of          These data elements
98.236(aa)(4)(iii)............   compressors.       would be reported by
                                The total           the onshore natural
                                 compressor power   gas transmission
                                 rating for all     compression sector.
                                 compressors        Companies operating
                                 combined, in       in this sector are
                                 horsepower..       subject to
                                                    regulatory oversight
                                                    by FERC, state
                                                    utility commissions,
                                                    and other federal
                                                    agencies because
                                                    they operate in an
                                                    industry that is
                                                    inherently
                                                    uncompetitive. FERC
                                                    controls pricing,
                                                    sets rules for
                                                    business practices,
                                                    has the power to
                                                    impose conditions on
                                                    mergers and
                                                    acquisitions, and
                                                    has the sole
                                                    responsibility for
                                                    authorizing the
                                                    location,
                                                    construction and
                                                    operations of
                                                    companies operating
                                                    in this sector.
                                                    Because disclosure
                                                    of the number and
                                                    power rating for
                                                    compressors would
                                                    not be likely to
                                                    cause substantive
                                                    competitive harm, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(5)(iii)............  The total storage  Companies operating
                                 capacity for       underground gas
                                 underground        storage facilities
                                 natural gas        are required to
                                 storage            report their storage
                                 facilities.        capacity to the EIA
                                                    by company on a
                                                    monthly basis. EIA
                                                    publishes the data
                                                    on their Web site on
                                                    an annual basis.
                                                    Because disclosure
                                                    of underground
                                                    storage capacity
                                                    would not be likely
                                                    to cause substantial
                                                    competitive harm, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
98.236(aa)(8)(iii)............  The total LNG      Most LNG storage
                                 storage capacity   facilities are
                                 in the calendar    regulated by FERC
                                 year, in           and state
                                 thousand           commissions, because
                                 standard cubic     they operate in an
                                 feet.              industry that is
                                                    inherently not
                                                    competitive. FERC
                                                    controls pricing,
                                                    sets rules for
                                                    business practices,
                                                    has the power to
                                                    impose conditions on
                                                    mergers and
                                                    acquisitions, and
                                                    has the sole
                                                    responsibility for
                                                    authorizing the
                                                    location,
                                                    construction and
                                                    operations of
                                                    companies operating
                                                    in this sector.
                                                    Because disclosure
                                                    of LNG storage
                                                    capacity would not
                                                    be likely to cause
                                                    substantial
                                                    competitive harm, we
                                                    propose these data
                                                    elements be
                                                    designated as ``not
                                                    CBI.''
------------------------------------------------------------------------

D. Other Proposed or Re-Proposed Case-by-Case Confidentiality 
Determinations for Subpart W

    The proposed revision includes 11 new or substantially revised data 
elements relative to production and/or throughput data from subpart W 
facilities from the onshore petroleum and natural gas production, 
offshore petroleum and natural gas production, and onshore natural gas 
processing industry sectors. Although these data elements are similar 
in certain types or characteristics to the data elements in 
``Production/Throughput Data that are Not Inputs to Emissions 
Equations'' or ``Raw Materials Consumed that are Not Inputs to 
Emissions Equations'' data categories, for the reasons provided above 
in Section III.B of this preamble, we are not proposing to assign these

[[Page 13418]]

data elements to a data category. Instead, we are proceeding to make 
individual confidentiality determinations for these data elements. As 
further explained in Section III.B of this preamble, we are also 
proposing to remove one existing data element, 40 CFR 
98.236(j)(2)(i)(A), from ``Production/Throughput Data Not Used as 
Input,'' thereby removing the application of the categorical 
confidentiality determination for this data category to this data 
element. We are re-proposing the confidentiality determination for this 
data element. Table 3 of this preamble lists the 11 new or 
substantially revised data elements and one existing data element and 
provides the rationale and proposed confidentiality determination for 
each data element.
    As described above in Section III.B of this preamble, our proposed 
determinations for these data elements were based on a two-step process 
in which we first evaluated whether the data element met the definition 
of emission data. This first step in the evaluation is important 
because emission data are not eligible for confidential treatment 
pursuant to section 114(c) of the CAA, which precludes emissions data 
from being considered confidential and requires that such data be made 
available to the public. The term ``emission data'' is defined in 40 
CFR 2.301(a).
    We propose to determine that none of these 12 data elements are 
emission data under 40 CFR 2.301(a)(2)(i), because they do not provide 
any information characterizing actual GHG emissions or descriptive 
information about the location or nature of the emissions source. 
However, we note that this determination is made strictly in the 
context of the GHGRP and may not apply to other regulatory programs.
    In the second step, we evaluate whether the data element is 
entitled to confidentiality treatment, based on the criteria for 
confidential treatment specified in 40 CFR 2.208. In particular, the 
EPA focused on the following two factors: (1) Whether the data was 
already publicly available; and (2) whether `` . . . disclosure of the 
information is likely to cause significant harm to the business' 
competitive position.'' See 40 CFR 2.208(e)(1). For each of these 12 
data elements, we determined whether the information is already 
available in the public domain.
    For those data elements for which no published data could be found, 
we evaluated whether the publication would be likely to cause 
competitive harm. Many of the new data elements proposed to be reported 
by the onshore oil and gas production sector would be reported at an 
aggregated-level (i.e., sub-basin level) that would mask any underlying 
information for individual production wells. These data elements 
involve reporting aggregated data covering all individual wells, 
exploratory wells, and production equipment in a sub-basin, rather than 
information specific to an individual well or other production unit. 
Reporting at a sub-basin level is at a large enough scale that 
disclosure of the collected data would not reveal any proprietary 
information, such as the sensitive operational information or the cost 
to do business. Because the proposed new data elements would also be 
collected at a sub-basin level, they would not disclose production data 
for individual wells, reveal information about individual exploratory 
wells, or provide insight into production costs. Therefore, we propose 
that the new production data proposed to be reported by the onshore oil 
and gas production sector be designated as non-CBI because its 
disclosure would not be likely to cause competitive harm.
    For offshore oil and gas production, the EPA is proposing that the 
quantity of gas produced for sales, quantity of oil produced for sales, 
and quantity of condensate produced for sales be reported. These data 
elements do not provide any competitively sensitive information on the 
costs of doing business. We note that similar data on throughputs for 
individual platforms are published annually by the Bureau of Ocean 
Energy Management. Therefore, we propose that these new production data 
proposed to be reported by offshore oil and gas platforms be designated 
as non-CBI because its disclosure would not be likely to cause 
competitive harm.
    For natural gas processing, the EPA is proposing that the total 
quantity of NGLs (bulk and fractionated) received at and leaving the 
processing plant be reported on an annual basis. Because the reported 
value would be the annual sum of bulk and fractionated NGLs received 
and the annual sum of bulk and fractionated NGLs leaving the plant, the 
data collected would provide very limited information on facility 
operations and would not disclose any detailed information about the 
facility's day-to-day operations, such as the amount, contents, and 
price of each shipment of bulk material received, the amount, contents, 
and price of each shipment of NGL product received, the amount of bulk 
materials fractionated and costs of fractionation, or the type and 
amounts of each individual NGL product produced. Because these data are 
to be reported at an aggregated level, these proposed two new data 
elements would not provide insight on operating costs, or other highly 
sensitive aspects of operation the disclosure of which would be likely 
to cause competitive harm. Therefore, we propose that the total 
quantity of NGLs (bulk and fractionated) received at and leaving the 
natural gas processing plant be designated as not CBI. In addition, 
many facilities in this sector already voluntarily report these data to 
the Worldwide Gas Processing survey and the data at the plant level are 
published annually in the Oil and Gas Journal. Similar data are also 
mandatorily reported monthly to the EIA. Although the EIA aggregates 
the data before publishing data, the EIA also acknowledges that some 
statistics may be based on data from fewer than three respondents, or 
that are dominated by data from one or two large respondents, and in 
these cases, it may be possible for a the information reported by a 
specific respondent to be accurately estimated.

[[Page 13419]]



Table 3--Proposed Individual Confidentiality Determination for 13 New or
  Substantially Revised Data Elements and Re-Proposal for One Existing
                              Data Elements
------------------------------------------------------------------------
                                                          Proposed
                                                      confidentiality
           Citation                Data element      determination and
                                                         rationale
------------------------------------------------------------------------
              Onshore petroleum and natural gas production
------------------------------------------------------------------------
98.236(aa)(1)(i)(A)...........  The quantity of    We propose that each
                                 gas produced in    of these data
                                 the calendar       elements be
                                 year from wells,   designated as ``not
                                 in thousand        CBI.'' The onshore
                                 standard cubic     petroleum production
                                 feet. This         sector is a
98.236(aa)(1)(i)(B)...........   includes gas       regionally
                                 that is routed     concentrated sector,
                                 to a pipeline,     with wells located
98.236(aa)(1)(i)(C)...........   vented or          in fixed geological
                                 flared, or used    formations and a
                                 in field           large number of
98.236(aa)(1)(i)(D)...........   operations. This   operators within
                                 does not include   each formation.
                                 gas injected       Information that is
98.236(j)(2)(i)(A)............   back into          typically considered
                                 reservoirs or      sensitive to this
                                 shrinkage          industry includes
                                 resulting from     data related to
                                 lease condensate   production costs for
                                 production.        developed fields and
                                The quantity of     information on
                                 gas produced in    individual
                                 the calendar       exploratory wells.
                                 year for sales     Information on
                                 in thousand        exploratory wells is
                                 standard cubic     sensitive during the
                                 feet..             time period when a
                                For each basin,     new formation is
                                 the quantity of    being developed
                                 crude oil          because lease prices
                                 produced in the    are not stabilized
                                 calendar year      until wells have
                                 for sales, not     proven production
                                 including lease    records. Once the
                                 condensates, in    formation has been
                                 barrels..          developed and
                                For each basin,     several wells have
                                 the quantity of    been drilled in a
                                 lease condensate   basin, production
                                 produced in the    decisions are based
                                 calendar year      on market prices and
                                 for sales (in      the ability to
                                 barrels)..         control flow from
                                The total annual    the well. The
                                 oil throughput     production data that
                                 that is sent to    will be reported at
                                 all atmospheric    the basin or sub-
                                 tanks in the       basin level are
                                 basin, in          already publicly
                                 barrels..          available through
                                                    the Department of
                                                    Energy. Reporting at
                                                    the basin or sub-
                                                    basin level includes
                                                    data aggregated to a
                                                    scale large enough
                                                    that it does not
                                                    disclose production
                                                    data for individual
                                                    wells, reveal
                                                    sensitive
                                                    information about
                                                    individual
                                                    exploratory wells,
                                                    or provide insight
                                                    into production
                                                    costs.
------------------------------------------------------------------------
              Offshore petroleum and natural gas production
------------------------------------------------------------------------
98.236(aa)(2)(i)..............  The quantity of    We propose that each
                                 gas produced for   of these new data
                                 sales from the     elements be
98.236(aa)(2)(ii).............   offshore           designated as ``not
                                 platform in the    CBI'' because the
                                 calendar year      production
                                 for sales, in      throughput data are
                                 thousand           published annually
                                 standard cubic     on the Bureau of
                                 feet.              Ocean Energy
                                The quantity of     Management's Web
                                 oil produced for   site.
                                 sales from the
                                 offshore
                                 platform in the
                                 calendar year
                                 for sales (in
                                 barrels)..
98.236(aa)(2)(iii)............  The quantity of
                                 condensate
                                 produced for
                                 sales from the
                                 offshore
                                 platform in the
                                 calendar year
                                 for sales (in
                                 barrels).
------------------------------------------------------------------------
                     Onshore natural gas processing
------------------------------------------------------------------------
98.236(aa)(3)(i)..............  The quantity of    We propose that each
                                 produced gas       of these new data
                                 received at the    elements be
98.236(aa)(3)(ii).............   gas processing     designated as ``not
                                 plant in           CBI'' because the
                                 thousand           average annual flow
                                 standard cubic     and plant
                                 feet.              utilization rates
                                The quantity of     are published
                                 processed          quarterly on EIA's
                                 (residue) gas      Web site and are
                                 leaving the gas    already in the
                                 processing plant   public domain.
                                 in thousand
                                 standard cubic
                                 feet..
98.236(aa)(3)(iii)............  The quantity of    We propose that each
                                 NGLs (bulk and     of these new data
                                 fractionated)      elements be
98.236(aa)(3)(iv).............   received at the    designated as ``not
                                 gas processing     CBI'' because they
                                 plant in the       are already publicly
                                 calendar year,     available. Many
                                 in barrels.        facilities in this
                                The quantity of     sector already
                                 NGLs (bulk and     voluntarily report
                                 fractionated)      these data to the
                                 leaving the gas    Worldwide Gas
                                 processing plant   Processing survey
                                 in the calendar    and the data at the
                                 year, in           plant level are
                                 barrels..          published annually
                                                    in the Oil and Gas
                                                    Journal. Similar
                                                    data are also
                                                    mandatorily reported
                                                    monthly to the EIA.
                                                    Although the EIA
                                                    aggregates the data
                                                    before publishing
                                                    data, the EIA also
                                                    acknowledges that,
                                                    ``Disclosure
                                                    limitation
                                                    procedures are not
                                                    applied to the
                                                    statistical data
                                                    published from this
                                                    survey's
                                                    information. Thus,
                                                    there may be some
                                                    statistics that are
                                                    based on data from
                                                    fewer than three
                                                    respondents, or that
                                                    are dominated by
                                                    data from one or two
                                                    large respondents.
                                                    In these cases, it
                                                    may be possible for
                                                    a knowledgeable
                                                    person to estimate
                                                    the information
                                                    reported by a
                                                    specific
                                                    respondent.'' \6\
------------------------------------------------------------------------

    The list of data elements, their data category assignments, and 
proposed confidentiality determinations can be found in the memorandum 
titled ``Data Category Assignments and Confidentiality Determinations 
for all Data Elements (excluding inputs to emission equations) in the 
Proposed `Technical Revisions and Confidentiality Determinations for 
Petroleum and Natural Gas Systems''' in Docket ID No. EPA-HQ-OAR-2011-
0512.

E. Request for Comments on Proposed Confidentiality Determinations

    For the CBI component of this rulemaking, we are specifically 
soliciting comment on the following issues. First, we specifically seek 
comment on the proposed data category

[[Page 13420]]

assignments, and application of the established categorical 
confidentiality determinations to data elements assigned to categories 
with such determinations. If a commenter believes that the EPA has 
improperly assigned certain new or substantially revised data elements 
to any of the data categories established in the 2011 Final CBI Rule, 
please provide specific comments identifying which of these data 
elements may be mis-assigned along with a detailed explanation of why 
you believe them to be incorrectly assigned and in which data category 
you believe they belong. In addition, if you believe that a data 
element should be assigned to one of the two direct emitter data 
categories that do not have a categorical confidentiality 
determination, please also provide specific comment along with detailed 
rationale and supporting information on whether such data element does 
or does not qualify as CBI.
    We also seek comment on the proposed individual confidentiality 
determinations for the following data elements: 72 new or substantially 
revised data elements assigned to the ``Unit/Process `Operating' 
Characteristics That Are Not Inputs to Emission Equations'' data 
category; 29 new or substantially revised data elements assigned to the 
``Unit/Process `Static' Characteristics That Are Not Inputs to Emission 
Equations'' category; 11 new data elements for which no data category 
assignment was proposed; and one existing data element for which we are 
proposing to remove the data category assignment and make a new 
confidentiality determination.
    By proposing confidentiality determinations prior to data reporting 
through this proposal and rulemaking process, we provide reporters an 
opportunity to submit comments, in particular comments identifying data 
they consider sensitive and their rationales and supporting 
documentation; this opportunity is the same opportunity that is 
afforded to submitters of information in case-by-case confidentiality 
determinations made in response to individual claims for confidential 
treatment not made through rulemaking. It provides an opportunity to 
rebut the Agency's proposed determinations prior to finalization. We 
will evaluate the comments on our proposed determinations, including 
claims of confidentiality and information substantiating such claims, 
before finalizing the confidentiality determinations. Please note that 
this will be a reporter's only opportunity to substantiate a 
confidentiality claim for these proposed new data elements. Upon 
finalizing the confidentiality determinations of the data elements 
identified in this rule, the EPA will release or withhold these data in 
accordance with 40 CFR 2.301, which contains special provisions 
governing the treatment of Part 98 data for which confidentiality 
determinations have been made through rulemaking.
    When submitting comments regarding the confidentiality 
determinations we are proposing in this action, please identify each 
individual data element you do or do not consider to be CBI or emission 
data in your comments. Please explain specifically how the public 
release of that particular data element would or would not cause a 
competitive disadvantage to a facility. Discuss how this data element 
may be different from or similar to data that are already publicly 
available. Please submit information identifying any publicly available 
sources of information containing the specific data elements in 
question. Data that are already available through other sources would 
likely be found not to qualify for CBI protection. In your comments, 
please identify the manner and location in which each specific data 
element you identify is publicly available, including a citation. If 
the data are physically published, such as in a book, industry trade 
publication, or federal agency publication, provide the title, volume 
number (if applicable), author(s), publisher, publication date, and 
International Standard Book Number (ISBN) or other identifier. For data 
published on a Web site, provide the address of the Web site and the 
date you last visited the Web site and identify the Web site publisher 
and content author.
    If your concern is that competitors could use a particular data 
element to discern sensitive information, specifically describe the 
pathway by which this could occur and explain how the discerned 
information would negatively affect your competitive position. Describe 
any unique process or aspect of your facility that would be revealed if 
the particular data element you consider sensitive were made publicly 
available. If the data element you identify would cause harm only when 
used in combination with other publicly available data, then describe 
the other data, identify the public source(s) of these data, and 
explain how the combination of data could be used to cause competitive 
harm. Describe the measures currently taken to keep the data 
confidential. Avoid conclusory and unsubstantiated statements, or 
general assertions regarding potential harm. Please be as specific as 
possible in your comments and include all information necessary for the 
EPA to evaluate your comments.

IV. Impacts of the Proposed Amendments to Subpart W

    The proposed amendments to subpart W are based on identified 
improvements in the regulatory language and revisions to calculation 
methods that do not significantly increase the burden of data 
collection and reporting, improve the accuracy of the data reported, 
and provide clarity. The proposed amendments do not impart significant 
additional burden to reporters and many reduce burden to reporters and 
regulators in some cases.
    As discussed in Section II of this preamble, the EPA is proposing 
to revise the reporting elements that must be reported. Any elements 
that were not previously required to be reported identify the equipment 
to be reported for the industry segment or are inputs to an emission 
equation. These data elements are typically already collected by 
reporters. These proposed revisions would remove ambiguity for the 
reporter and would not increase burden significantly, since the 
reporting elements are already available.
    As discussed in Section II.D of this preamble, the EPA is proposing 
to remove the best available monitoring method (BAMM) provisions in 40 
CFR 98.234(f). Removing these provisions would not add to previous 
burden estimates for subpart W reporters; previous burden estimates 
were prepared based on all reporters complying with the monitoring 
methods in 40 CFR 98.234 without BAMM.
    The additional proposed amendments to subpart W are not expected to 
significantly increase burden. See the memorandum, ``Assessment of 
Impacts of the 2014 Proposed Revisions to Subpart W'' in Docket Id. No. 
EPA-HQ-OAR-2011-0512 for additional information.

V. Statutory and Executive Order Reviews

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

    This action is not a ``significant regulatory action'' under the 
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is 
therefore not subject to review under Executive Orders 12866 and 13563 
(76 FR 3821, January 21, 2011).
    In addition, the EPA prepared an analysis of the potential costs 
and benefits associated with the proposed amendments to subpart W. This 
analysis

[[Page 13421]]

is contained in ``Assessment of Impacts of the 2014 Proposed Revisions 
to Subpart W.'' A copy of the analysis is available in the docket for 
this action (see Docket Id. No. EPA-HQ-OAR-2011-0512) and the analysis 
is briefly summarized in Section IV of this preamble.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
Information Collection Request (ICR) document prepared by the EPA has 
been assigned EPA ICR number 2300.15.
    This action proposes to simplify the existing reporting methods in 
subpart W and clarify monitoring methods and data reporting 
requirements, and proposes confidentiality determinations for reported 
data elements. The EPA is proposing to restructure the reporting 
requirements for clarity and align them with the calculation 
requirements. OMB has previously approved the information collection 
requirements for 40 CFR part 98 under the provisions of the Paperwork 
Reduction Act, 44 U.S.C. 3501 et seq., and has assigned OMB control 
number 2060-0629. The OMB control numbers for the EPA's regulations in 
40 CFR are listed in 40 CFR part 9. Burden is defined at 5 CFR 
1320.3(b).
    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.
    The estimated total projected cost and hour burden associated with 
reporting for subpart W are $21,964,000 and 244,000 hours, 
respectively. For the hour burden, the estimated average burden hours 
per response is 54 hours, the proposed frequency of response is once 
annually, and the estimated number of likely respondents is 2,885. For 
the cost burden to respondents or record keepers resulting from the 
collection of information, the estimated total capital and start-up 
cost component annualized over its expected useful life is $796,000 per 
year, the total operation and maintenance component is $1,690,000 per 
year, and the total labor cost is $19,478,000 per year for all of 
subpart W.
    To comment on the Agency's need for this information, the accuracy 
of the provided burden estimates, and any suggested methods for 
minimizing respondent burden, the EPA has established a public docket 
for this rule, which includes this ICR, under Docket ID number EPA-HQ-
OAR-2011-0512. Submit any comments related to the ICR to the EPA and 
OMB. See ADDRESSES section at the beginning of this proposed rule for 
where to submit comments to the EPA. Send comments to OMB at the Office 
of Information and Regulatory Affairs, Office of Management and Budget, 
725 17th Street NW., Washington, DC 20503, Attention: Desk Office for 
the EPA. Since OMB is required to make a decision concerning the ICR 
between 30 and 60 days after March 10, 2014, a comment to OMB is best 
assured of having its full effect if OMB receives it by April 9, 2014. 
The final rule will respond to any OMB or public comments on the 
information collection requirements contained in this proposal. We 
continue to be interested in the potential impacts of this proposed 
action on the burden associated with the proposed amendments and 
welcome comments on issues related to such impacts.

C. Regulatory Flexibility Act (RFA)

    The Regulatory Flexibility Act (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 today's proposed rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's regulations at 13 CFR 
121.201; (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.
    This action proposes to (1) amend monitoring and calculation 
methodologies in subpart W; (2) assign subpart W data reporting 
elements into CBI data categories; and (3) amend a definition in 
subpart A. After considering the economic impacts of these proposed 
rule amendments on small entities, I certify that this action would not 
have a significant economic impact on a substantial number of small 
entities.
    The small entities directly regulated by this proposed rule include 
small businesses in the petroleum and gas industry, small governmental 
jurisdictions and small non-profits. The EPA has determined that some 
small businesses would be affected because their production processes 
emit GHGs exceeding the reporting threshold.
    This action includes proposed amendments that do not result in a 
significant burden increase on subpart W reporters. In some cases, the 
EPA is proposing to increase flexibility in the selection of methods 
used for calculating GHGs, and is also proposing to revise certain 
methods that may result in greater conformance to current industry 
practices. In addition, the EPA is proposing to revise specific 
provisions to provide clarity on what information is being reported. 
These proposed revisions would not significantly increase the burden on 
reporters while maintaining the data quality of the information being 
reported to the EPA.
    As part of the process of finalization of the final subpart W rule, 
the EPA took several steps to evaluate the effect of the rule on small 
entities. For example, the EPA determined appropriate thresholds that 
reduced the number of small businesses reporting. In addition, the EPA 
conducted several meetings with industry associations to discuss 
regulatory options and the corresponding burden on industry, such as 
recordkeeping and reporting. Finally, the EPA continues to conduct 
significant outreach on the GHG reporting rule and maintains an ``open 
door'' policy for stakeholders to help inform the EPA's understanding 
of key issues for the industries.
    The EPA continues to be interested in the potential impacts of the 
proposed rule amendments on small entities and welcomes comments on 
issues related to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 
U.S.C. 1531-1538, requires federal agencies, unless otherwise 
prohibited by law, to assess the effects of their regulatory actions on 
state, local, and tribal governments and the private sector. Federal 
agencies must also develop a plan to provide notice to small 
governments that might be significantly or uniquely affected by any 
regulatory requirements. The plan must enable officials of affected 
small governments to have meaningful and timely input in the 
development of the EPA regulatory proposals with significant federal

[[Page 13422]]

intergovernmental mandates and must inform, educate, and advise small 
governments on compliance with the regulatory requirements.
    This action proposes to (1) amend monitoring and calculation 
methodologies in subpart W; (2) assign subpart W data reporting 
elements into CBI data categories; and (3) amend a definition in 
subpart A. This proposed rule 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. Thus, this proposed rule is not subject to the requirements 
of section 202 and 205 of the UMRA. This rule is also not subject to 
the requirements of section 203 of UMRA because it contains no 
regulatory requirements that might significantly or uniquely affect 
small governments. The proposed amendments would not impose any new 
requirements that are not currently required for 40 CFR part 98, and 
the rule amendments would not uniquely apply to small governments. 
Therefore, this action is not subject to the requirements of section 
203 of the UMRA.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the States, on the relationship between 
the national government and the States, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. However, for a more detailed 
discussion about how Part 98 relates to existing state programs, please 
see Section II of the preamble to the final Part 98 rule (74 FR 56266, 
October 30, 2009).
    This action proposes to (1) amend monitoring and calculation 
methodologies in subpart W; (2) assign subpart W data reporting 
elements into CBI data categories; and (3) amend a definition in 
subpart A. Few, if any, state or local government facilities would be 
affected by the provisions in this proposed rule. This regulation also 
does not limit the power of States or localities to collect GHG data 
and/or regulate GHG emissions. Thus, Executive Order 13132 does not 
apply to this action.
    In the spirit of Executive Order 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 
action from state and local officials. For a summary of the EPA's 
consultation with state and local organizations and representatives in 
developing Part 98, see Section VIII.E of the preamble to the final 
rule (74 FR 56371, October 30, 2009).

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

    Subject to the Executive Order 13175 (65 FR 67249, November 9, 
2000) the EPA may not issue a regulation that has tribal 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 tribal 
governments, or the EPA consults with tribal officials early in the 
process of developing the proposed regulation and develops a tribal 
summary impact statement.
    The EPA has concluded that this action may have tribal 
implications. This action proposes to (1) Amend monitoring and 
calculation methodologies in subpart W; (2) assign subpart W data 
reporting elements into CBI data categories; and (3) amend a definition 
in subpart A. However, it will neither impose substantial direct 
compliance costs on tribal governments, nor preempt Tribal law. This 
regulation would apply directly to petroleum and natural gas facilities 
that emit greenhouses gases. Although few facilities that would be 
subject to the rule are likely to be owned by tribal governments, the 
EPA has sought opportunities to provide information to tribal 
governments and representatives during the development of the proposed 
and final subpart W that was promulgated on November 30, 2010 (75 FR 
74458). The EPA consulted with tribal officials early in the process of 
developing subpart W to permit them to have meaningful and timely input 
into its development.
    For additional information about the EPA's interactions with tribal 
governments, see section IV.F of the preamble to the re-proposal of 
subpart W published on April 12, 2010 (75 FR 18608), and section IV.F 
of the preamble to the final subpart W published on November 30, 2010 
(75 FR 74458).
    The EPA specifically solicits additional comment on this proposed 
action from tribal officials.

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

    The EPA interprets Executive Order 13045 (62 FR 19885, April 23, 
1997) as applying only to those regulatory actions that concern health 
or safety risks, such that the analysis required under section 5-501 of 
the Executive Order has the potential to influence the regulation. This 
action proposes to (1) Amend monitoring and calculation methodologies 
in subpart W; (2) assign subpart W data reporting elements into CBI 
data categories; and (3) amend a definition in subpart A. This action 
is not subject to Executive Order 13045 because it does not establish 
an environmental standard intended to mitigate health or safety risks.

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

    This action proposes to (1) amend monitoring and calculation 
methodologies in subpart W; (2) assign subpart W data reporting 
elements into CBI data categories; and (3) amend a definition in 
subpart A. This action is not subject to Executive Order 13211 (66 FR 
28355 (May 22, 2001)), because it is not a significant regulatory 
action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs 
the EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.
    This action proposes to (1) Amend monitoring and calculation 
methodologies in subpart W; (2) assign subpart W data reporting 
elements into CBI data categories; and (3) amend a definition in 
subpart A. This proposed rulemaking does not involve the use of any 
technical standards. No changes are being proposed that affect the test 
methods currently in use for subpart W. Therefore, the EPA is not 
considering the use of any voluntary consensus standards.

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

    Executive Order 12898 (59 FR 7629, (February 16, 1994)) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent

[[Page 13423]]

practicable and permitted by law, to make environmental justice part of 
their mission by identifying and addressing, as appropriate, 
disproportionately high and adverse human health or environmental 
effects of their programs, policies, and activities on minority 
populations and low-income populations in the United States.
    This action proposes to (1) amend monitoring and calculation 
methodologies in subpart W; (2) assign subpart W data reporting 
elements into CBI data categories; and (3) amend a definition in 
subpart A. The EPA has determined that this proposed rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment. Instead, this proposed rule addresses information 
collection and reporting procedures.

List of Subjects in 40 CFR Part 98

    Environmental protection, Administrative practice and procedure, 
Greenhouse gases, Incorporation by reference, Reporting and 
recordkeeping requirements.

    Dated: February 20, 2014.
Gina McCarthy,
Administrator.

    For the reasons stated in the preamble, title 40, chapter I, of the 
Code of Federal Regulations is proposed to be amended as follows:

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
1. The authority citation for part 98 continues to read as follows:

    Authority: 42 U.S.C. 7401-7671q.

Subpart A--[AMENDED]

0
2. Section 98.6 is amended by revising the definition of ``Well 
completions'' to read as follows:


Sec.  98.6  Definitions.

* * * * *
    Well completions means the process that allows for the flow of 
petroleum or natural gas from newly drilled wells to expel drilling and 
reservoir fluids and test the reservoir flow characteristics, steps 
which may vent produced gas to the atmosphere via an open pit or tank. 
Well completion also involves connecting the well bore to the 
reservoir, which may include treating the formation or installing 
tubing, packer(s), or lifting equipment, steps that do not 
significantly vent natural gas to the atmosphere. This process may also 
include high-rate flowback of injected gas, water, oil, and proppant 
used to fracture and prop open new fractures in existing lower 
permeability gas reservoirs, steps that may vent large quantities of 
produced gas to the atmosphere.
* * * * *

Subpart W--[AMENDED]

0
3. Section 98.230 is amended by revising paragraph (a)(2) to read as 
follows:


Sec.  98.230  Definition of the source category.

    (a) * * *
    (2) Onshore petroleum and natural gas production. Onshore petroleum 
and natural gas production means all equipment on a single well-pad or 
associated with a single well-pad (including but not limited to 
compressors, generators, dehydrators, storage vessels, engines, 
boilers, heaters, flares, separation and processing equipment, and 
portable non-self-propelled equipment, which includes well drilling and 
completion equipment, workover equipment, maintenance and repair 
equipment, and leased, rented or contracted equipment) used in the 
production, extraction, recovery, lifting, stabilization, separation or 
treating of petroleum and/or natural gas (including condensate). This 
equipment also includes associated storage or measurement vessels all 
petroleum and natural gas production equipment located on islands, 
artificial islands, or structures connected by a causeway to land, an 
island, or an artificial island. Onshore petroleum and natural gas 
production also means all equipment on or associated with a single 
enhanced oil recovery (EOR) well pad using CO2 or natural 
gas injection.
* * * * *
0
4. Section 98.232 is amended by:
0
a. Revising paragraph (c)(11);
0
b. Revising paragraph (d)(1);
0
c. Revising paragraph (e)(1);
0
d. Adding paragraph (e)(6);
0
e. Revising paragraph (f)(1);
0
f. Adding paragraph (f)(4);
0
g. Revising paragraph (g)(1);
0
h. Adding paragraph (g)(4);
0
i. Revising paragraph (h)(1);
0
j. Adding paragraph (h)(5); and
0
k. Revising paragraphs (i)(1) through (i)(7).
    The revisions and additions read as follows:


Sec.  98.232  GHGs to report.

* * * * *
    (c) * * *
    (11) Reciprocating compressor venting.
* * * * *
    (d) * * *
    (1) Reciprocating compressor venting.
* * * * *
    (e) * * *
    (1) Reciprocating compressor venting.
* * * * *
    (6) Flare stack emissions.
    (f) * * *
    (1) Reciprocating compressor venting.
* * * * *
    (4) Flare stack emissions.
* * * * *
    (g) * * *
    (1) Reciprocating compressor venting.
* * * * *
    (4) Flare stack emissions.
    (h) * * *
    (1) Reciprocating compressor venting.
* * * * *
    (5) Flare stack emissions.
    (i) * * *
    (1) Equipment leaks from connectors, block valves, control valves, 
pressure relief valves, orifice meters, regulators, and open-ended 
lines at above grade transmission-distribution transfer stations.
    (2) Equipment leaks at below grade transmission-distribution 
transfer stations.
    (3) Equipment leaks at above grade metering-regulating stations 
that are not above grade transmission-distribution transfer stations.
    (4) Equipment leaks at below grade metering-regulating stations.
    (5) Distribution main equipment leaks.
    (6) Distribution services equipment leaks.
    (7) Report under subpart W of this part the emissions of 
CO2, CH4, and N2O emissions from 
stationary fuel combustion sources following the methods in Sec.  
98.233(z).
* * * * *
0
5. Section 98.233 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(1), and (a)(2);
0
b. Adding paragraph (a)(4);
0
c. Revising paragraphs (c), (d), (e), (f), (g), (h), and (i);
0
d. Revising paragraphs (j) introductory text, (j)(1) introductory text, 
(j)(1)(vii) introductory text, and (j)(2);
0
e. Removing paragraphs (j)(3) and (j)(4).
0
f. Redesignating paragraph (j)(5) as paragraph (j)(3) and revising 
newly redesignated paragraph (j)(3);
0
g. Redesignating paragraph (j)(6) as paragraph (j)(4) and revising 
newly redesignated paragraph (j)(4);
0
h. Redesignating paragraph (j)(7) as paragraph (j)(5) and revising 
newly redesignated paragraph (j)(5);
0
i. Redesignating paragraph (j)(8) as paragraph (j)(6) and revising 
newly redesignated paragraph (j)(6);

[[Page 13424]]

0
j. Redesignating paragraph (j)(9) as paragraph (j)(7) and revising 
newly redesignated paragraph (j)(7);
0
k. Revising paragraph (k);
0
l. Revising paragraphs (l) introductory text, (l)(2) introductory text, 
and (l)(2)(ii);
0
m. Revising paragraphs (l)(3) introductory text and the parameters 
``FR'' and ``D'' of Equation W-17B in paragraph (l)(3);
0
n. Revising paragraphs (l)(5) and (l)(6);
0
o. Revising paragraphs (m), (n), (o), (p), (q), and (r);
0
p. Revising paragraphs (s)(2) introductory text, (s)(2)(i), (s)(3), 
(s)(4), and (t) introductory text.
0
q. Revising Equation W-33 of paragraph (t)(1) and adding the parameter 
``Za'' to Equation W-33 in paragraph (t)(1);
0
r. Revising Equation W-34 of paragraph (t)(2) and adding the parameter 
``Za'' to Equation W-34 in paragraph (t)(2);
0
s. Revising paragraphs (u) introductory text, (u)(2)(iii), and 
(u)(2)(v) through (vii);
0
t. Revising paragraphs (v), (w) introductory text, (w)(1), and (w)(3) 
introductory text;
0
u. Revising the parameters ``MassCO2'', ``N'', and 
``Vv'' to Equation W-37 in paragraph (w)(3);
0
v. Revising paragraphs (x) introductory text and (x)(1);
0
w. Revising the parameter ``Shl'' to Equation W-38 in 
paragraph (x)(2);
0
x. Revising paragraph (z)(1);
0
y. Revising the parameters ``Va'', ``YCO2'', 
``Yj'', and ``YCH4'' to Equations W-39A and W-39B 
in paragraph (z)(2)(iii);
0
z. Revising Equation W-40 in paragraph (z)(2)(vi) and the parameters 
``MassN2O'', ``Fuel'', and ``HHV'' to Equation W-40 in 
paragraph (z)(2)(vi); and
0
aa. Removing the parameter ``GWP'' of Equation W-40 in paragraph 
(z)(2)(vi).
    The revisions and additions read as follows:


Sec.  98.233  Calculating GHG emissions.

* * * * *
    (a) Natural gas pneumatic device venting. Calculate CH4 
and CO2 volumetric emissions from continuous high bleed, 
continuous low bleed, and intermittent bleed natural gas pneumatic 
devices using Equation W-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.000

Where:

Es,i = Annual total volumetric GHG emissions at standard 
conditions in standard cubic feet per year from natural gas 
pneumatic device vents, of types ``t'' (continuous high bleed, 
continuous low bleed, intermittent bleed), for GHGi.
Countt = Total number of natural gas pneumatic devices of 
type ``t'' (continuous high bleed, continuous low bleed, 
intermittent bleed) as determined in paragraph (a)(1) or (a)(2) of 
this section.
EFt = Population emission factors for natural gas 
pneumatic device vents (in standard cubic feet per hour per device) 
of each type ``t'' listed in Tables W-1A, W-3, and W-4 of this 
subpart for onshore petroleum and natural gas production, onshore 
natural gas transmission compression, and underground natural gas 
storage facilities, respectively.
GHGi = For onshore petroleum and natural gas production 
facilities, onshore natural gas transmission compression facilities, 
and underground natural gas storage facilities, concentration of 
GHGi, CH4 or CO2, in produced 
natural gas or processed natural gas for each facility as specified 
in paragraphs (u)(2)(i), (iii), and (iv) of this section.
Tt = Average estimated number of hours in the operating 
year the devices, of each type ``t'', were operational using 
engineering estimates based on best available data. Default is 8760 
hours.

    (1) For all industry segments, determine ``Countt'' for 
Equation W-1 of this subpart for each type of natural gas pneumatic 
device (continuous high bleed, continuous low bleed, and intermittent 
bleed) by counting the devices, except as specified in paragraph (a)(2) 
of this section. The reported number of devices must represent the 
total number of devices for the reporting year.
    (2) For the onshore petroleum and natural gas production industry 
segment, you have the option in the first two consecutive calendar 
years to determine ``Countt'' for Equation W-1 of this 
subpart for each type of natural gas pneumatic device (continuous high 
bleed, continuous low bleed, and intermittent bleed) using engineering 
estimates based on best available data.
* * * * *
    (4) Calculate both CH4 and CO2 mass emissions from volumetric 
emissions using calculations in paragraph (v) of this section.
* * * * *
    (c) Natural gas driven pneumatic pump venting. (1) Calculate 
CH4 and CO2 volumetric emissions from natural gas 
driven pneumatic pump venting using Equation W-2 of this section. 
Natural gas driven pneumatic pumps covered in paragraph (e) of this 
section do not have to report emissions under this paragraph (c).
[GRAPHIC] [TIFF OMITTED] TP10MR14.001

Where:

Es,i = Annual total volumetric GHG emissions at standard 
conditions in standard cubic feet per year from all natural gas 
driven pneumatic pump venting, for GHGi.
Count = Total number of natural gas driven pneumatic pumps.
EF = Population emissions factors for natural gas driven pneumatic 
pumps (in standard cubic feet per hour per pump) listed in Table W-
1A of this subpart for onshore petroleum and natural gas production.
GHGi = Concentration of GHGi, CH4, 
or CO2, in produced natural gas as defined in paragraph 
(u)(2)(i) of this section.
T = Average estimated number of hours in the operating year the 
pumps were operational using engineering estimates based on best 
available data. Default is 8760 hours.

    (2) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (d) Acid gas removal (AGR) vents. For AGR vents (including 
processes such as amine, membrane, molecular sieve or other absorbents 
and adsorbents), calculate emissions for CO2 only (not 
CH4) vented directly to the atmosphere or emitted through a 
flare, engine (e.g., permeate from a membrane or de-adsorbed gas from a 
pressure swing adsorber used as fuel supplement), or sulfur recovery 
plant, using any of the

[[Page 13425]]

calculation methods described in this paragraph (d), as applicable.
    (1) Calculation Method 1. If you operate and maintain a continuous 
emissions monitoring system (CEMS) that has both a CO2 
concentration monitor and volumetric flow rate monitor, you must 
calculate CO2 emissions under this subpart by following the 
Tier 4 Calculation Method and all associated calculation, quality 
assurance, reporting, and recordkeeping requirements for Tier 4 in 
subpart C of this part (General Stationary Fuel Combustion Sources). 
Alternatively, you may follow the manufacturer's instructions or 
industry standard practice. If a CO2 concentration monitor 
and volumetric flow rate monitor are not available, you may elect to 
install a CO2 concentration monitor and a volumetric flow 
rate monitor that comply with all of the requirements specified for the 
Tier 4 Calculation Method in subpart C of this part (General Stationary 
Fuel Combustion Sources). The calculation and reporting of 
CH4 and N2O emissions is not required as part of 
the Tier 4 requirements for AGR units.
    (2) Calculation Method 2. If a CEMS is not available but a vent 
meter is installed, use the CO2 composition and annual volume of vent 
gas to calculate emissions using Equation W-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.002

Where:

Ea,CO2 = Annual volumetric CO2 emissions at 
actual conditions, in cubic feet per year.
VS = Total annual volume of vent gas flowing out of the 
AGR unit in cubic feet per year at actual conditions as determined 
by flow meter using methods set forth in Sec.  98.234(b). 
Alternatively, you may follow the manufacturer's instructions or 
industry standard practice for calibration of the vent meter.

VolCO2 = Annual average volumetric fraction of CO2 
content in vent gas flowing out of the AGR unit as determined in 
paragraph (d)(6) of this section.

    (3) Calculation Method 3. If a CEMS or a vent meter is not 
installed, you may use the inlet or outlet gas flow rate of the acid 
gas removal unit to calculate emissions for CO2 using 
Equations W-4A or W-4B of this section. If inlet gas flow rate is 
known, use Equation W-4A. If outlet gas flow rate is known, use 
Equation W-4B.
[GRAPHIC] [TIFF OMITTED] TP10MR14.003

Where:

Ea, CO2 = Annual volumetric CO2 emissions at 
actual conditions, in cubic feet per year.
Vin = Total annual volume of natural gas flow into the 
AGR unit in cubic feet per year at actual conditions as determined 
using methods specified in paragraph (d)(5) of this section.
Vout = Total annual volume of natural gas flow out of the 
AGR unit in cubic feet per year at actual conditions as determined 
using methods specified in paragraph (d)(5) of this section.
VolI = Annual average volumetric fraction of 
CO2 content in natural gas flowing into the AGR unit as 
determined in paragraph (d)(7) of this section.
Volo = Annual average volumetric fraction of CO2 content 
in natural gas flowing out of the AGR unit as determined in 
paragraph (d)(8) of this section.

    (4) Calculation Method 4. If CEMS or a vent meter is not installed, 
you may calculate emissions using any standard simulation software 
package, such as AspenTech HYSYS[supreg], or API 4679 AMINECalc, that 
uses the Peng-Robinson equation of state and speciates CO2 
emissions. A minimum of the following, determined for typical operating 
conditions over the calendar year by engineering estimate and process 
knowledge based on best available data, must be used to characterize 
emissions:
    (i) Natural gas feed temperature, pressure, and flow rate.
    (ii) Acid gas content of feed natural gas.
    (iii) Acid gas content of outlet natural gas.
    (iv) Unit operating hours, excluding downtime for maintenance or 
standby.
    (v) Exit temperature of natural gas.
    (vi) Solvent pressure, temperature, circulation rate, and weight.
    (5) For Calculation Method 3, determine the gas flow rate of the 
inlet when using Equation W-4A of this section or the gas flow rate of 
the outlet when using Equation W-4B of this section for the natural gas 
stream of an AGR unit using a meter according to methods set forth in 
Sec.  98.234(b). If you do not have a continuous flow meter, either 
install a continuous flow meter or use an engineering calculation to 
determine the flow rate.
    (6) For Calculation Method 2, if a continuous gas analyzer is not 
available on the vent stack, either install a continuous gas analyzer 
or take quarterly gas samples from the vent gas stream to determine 
VolCO2 in Equation W-3 of this section according to methods 
set forth in Sec.  98.234(b).
    (7) For Calculation Method 3, if a continuous gas analyzer is 
installed on the inlet gas stream, then the continuous gas analyzer 
results must be used. If a continuous gas analyzer is not available, 
either install a continuous gas analyzer or take quarterly gas samples 
from the inlet gas stream to determine VolI in Equation W-4A 
or W-4B of this section according to methods set forth in Sec.  
98.234(b).
    (8) For Calculation Method 3, determine annual average volumetric 
fraction of CO2 content in natural gas flowing out of the 
AGR unit using one of the methods specified in paragraphs (d)(8)(i) 
through (d)(8)(iii) of this section.
    (i) If a continuous gas analyzer is installed on the outlet gas 
stream, then the continuous gas analyzer results must be used. If a 
continuous gas analyzer is not available, you may install a continuous 
gas analyzer.
    (ii) If a continuous gas analyzer is not available or installed, 
quarterly gas samples may be taken from the outlet gas stream to 
determine VolO in Equation W-4A or W-4B of this section

[[Page 13426]]

according to methods set forth in Sec.  98.234(b).
    (iii) If a continuous gas analyzer is not available or installed, 
you may use sales line quality specification for CO2 in 
natural gas.
    (9) Calculate annual volumetric CO2 emissions at 
standard conditions using calculations in paragraph (t) of this 
section.
    (10) Calculate annual mass CO2 emissions at standard 
conditions using calculations in paragraph (v) of this section.
    (11) Determine if CO2 emissions from the AGR unit are 
recovered and transferred outside the facility. Adjust the 
CO2 emissions estimated in paragraphs (d)(1) through (d)(10) 
of this section downward by the magnitude of CO2 emissions 
recovered and transferred outside the facility.
    (e) Dehydrator vents. For dehydrator vents, calculate annual 
CH4 and CO2 emissions using the applicable 
calculation methods described in paragraphs (e)(1) through (e)(4) of 
this section. If emissions from dehydrator vents are routed to a vapor 
recovery system, you must adjust the emissions downward according to 
paragraph (e)(5) of this section. If emissions from dehydrator vents 
are routed to a flare or regenerator fire-box/fire tubes, you must 
calculate CH4, CO2, and N2O annual 
emissions as specified in paragraph (e)(6) of this section.
    (1) Calculation Method 1. Calculate annual mass emissions from 
absorbent dehydrators that have an annual average of daily natural gas 
throughput that is greater than or equal to 0.4 million standard cubic 
feet per day by using a software program, such as AspenTech 
HYSYS[supreg] or GRI-GLYCalc^TM, that uses the Peng-Robinson 
equation of state to calculate the equilibrium coefficient, speciates 
CH4 and CO2 emissions from dehydrators, and has 
provisions to include regenerator control devices, a separator flash 
tank, stripping gas and a gas injection pump or gas assist pump. The 
following parameters must be determined by engineering estimate based 
on best available data and must be used at a minimum to characterize 
emissions from dehydrators:
    (i) Feed natural gas flow rate.
    (ii) Feed natural gas water content.
    (iii) Outlet natural gas water content.
    (iv) Absorbent circulation pump type (e.g., natural gas pneumatic/
air pneumatic/electric).
    (v) Absorbent circulation rate.
    (vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene 
glycol (DEG) or ethylene glycol (EG)).
    (vii) Use of stripping gas.
    (viii) Use of flash tank separator (and disposition of recovered 
gas).
    (ix) Hours operated.
    (x) Wet natural gas temperature and pressure.
    (xi) Wet natural gas composition. Determine this parameter using 
one of the methods described in paragraphs (e)(1)(xi)(A) through 
(e)(1)(xi)(D) of this section.
    (A) Use the GHG mole fraction as defined in paragraph (u)(2)(i) or 
(u)(2)(ii) of this section.
    (B) If the GHG mole fraction cannot be determined using paragraph 
(u)(2)(i) or (u)(2)(ii) of this section, select a representative 
analysis.
    (C) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists or you 
may use an industry standard practice as specified in Sec.  98.234(b) 
to sample and analyze wet natural gas composition.
    (D) If only composition data for dry natural gas is available, 
assume the wet natural gas is saturated.
    (2) Calculation Method 2. Calculate annual volumetric emissions 
from glycol dehydrators that have an annual average of daily natural 
gas throughput that is less than 0.4 million standard cubic feet per 
day using Equation W-5 of this section:
[GRAPHIC] [TIFF OMITTED] TP10MR14.004

Where:

Es,i = Annual total volumetric GHG emissions (either 
CO2 or CH4) at standard conditions in cubic 
feet.
EFi = Population emission factors for glycol dehydrators 
in thousand standard cubic feet per dehydrator per year. Use 73.4 
for CH4 and 3.21 for CO2 at 60 [deg]F and 14.7 
psia.
Count = Total number of glycol dehydrators that have an annual 
average of daily natural gas throughput that is less than 0.4 
million standard cubic feet per day.
1000 = Conversion of EFi in thousand standard cubic feet 
to standard cubic feet.

    (3) Calculation Method 3. Dehydrators that use desiccant must 
calculate emissions from the amount of gas vented from the vessel when 
it is depressurized for the desiccant refilling process using Equation 
W-6 of this section. Desiccant dehydrator emissions covered in this 
paragraph do not have to be calculated separately using the method 
specified in paragraph (i) of this section for blowdown vent stacks.
[GRAPHIC] [TIFF OMITTED] TP10MR14.005

Where:

Es,n = Annual natural gas emissions at standard 
conditions in cubic feet.
H = Height of the dehydrator vessel (ft).
D = Inside diameter of the vessel (ft).
P1 = Atmospheric pressure (psia).
P2 = Pressure of the gas (psia).
p = pi (3.14).
%G = Percent of packed vessel volume that is gas.
N = Number of dehydrator openings in the calendar year.
100 = Conversion of %G to fraction.

    (4) For glycol dehydrators that use the calculation method in 
paragraph (e)(2) of this section, calculate both CH4 and 
CO2 mass emissions from volumetric GHGi emissions using 
calculations in paragraph (v) of this section. For desiccant 
dehydrators that use the calculation method in paragraph (e)(3) of this 
section, calculate both CH4 and CO2 volumetric 
and mass emissions from volumetric natural gas emissions using 
calculations in paragraphs (u) and (v) of this section.
    (5) Determine if the dehydrator unit has vapor recovery. Adjust the 
emissions estimated in paragraphs (e)(1), (e)(2), and (e)(3) of this 
section downward by the magnitude of emissions recovered using a vapor 
recovery system as determined by engineering estimate based on best 
available data.
    (6) Calculate annual emissions from dehydrator vents to flares or 
regenerator fire-box/fire tubes as follows:

[[Page 13427]]

    (i) Use the dehydrator vent volume and gas composition as 
determined in paragraphs (e)(1) or (e)(2) of this section for absorbent 
dehydrators. Use the dehydrator vent volume and gas composition as 
determined in paragraphs (e)(3) and (e)(4) of this section for 
dehydrators that use desiccant.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine dehydrator vent emissions from the flare or 
regenerator combustion gas vent.
    (f) Well venting for liquids unloadings. Calculate annual 
volumetric natural gas emissions from well venting for liquids 
unloading using one of the calculation methods described in paragraphs 
(f)(1), (f)(2), or (f)(3) of this section. Calculate annual 
CH4 and CO2 volumetric and mass emissions using 
the method described in paragraph (f)(4) of this section.
    (1) Calculation Method 1. Calculate emissions from wells with 
plunger lifts and wells without plunger lifts separately. For at least 
one well of each unique well tubing diameter group and pressure group 
combination in each sub-basin category (see Sec.  98.238 for the 
definitions of tubing diameter group, pressure group, and sub-basin 
category), where gas wells are vented to the atmosphere to expel 
liquids accumulated in the tubing, install a recording flow meter on 
the vent line used to vent gas from the well (e.g., on the vent line 
off the wellhead separator or atmospheric storage tank) according to 
methods set forth in Sec.  98.234(b). Calculate the total emissions 
from well venting to the atmosphere for liquids unloading using 
Equation W-7A of this section. For any tubing diameter group and 
pressure group combination in a sub-basin where liquids unloading 
occurs both with and without plunger lifts, Equation W-7A will be used 
twice, once for wells with plunger lifts and once for wells without 
plunger lifts.
[GRAPHIC] [TIFF OMITTED] TP10MR14.006

Where:

Ea = Annual natural gas emissions for all wells of the 
same tubing diameter group and pressure group combination in a sub-
basin at actual conditions, a, in cubic feet. Calculate emission 
from wells with plunger lifts and wells without plunger lifts 
separately.
h = Total number of wells of the same tubing diameter group and 
pressure group combination in a sub-basin either with or without 
plunger lifts.
p = Wells 1 through h of the same tubing diameter group and pressure 
group combination in a sub-basin.
Tp = Cumulative amount of time in hours of venting for 
each well, p, of the same tubing diameter group and pressure group 
combination in a sub-basin during the year. If the available venting 
data do not contain a record of the date of the venting events and 
data are not available to provide the venting hours for the specific 
time period of January 1 to December 31, you may calculate an 
annualized vent time, Tp, using Equation W-7B of this 
section.
FR = Average flow rate in cubic feet per hour for all measured wells 
of the same tubing diameter group and pressure group combination in 
a sub-basin, over the duration of the liquids unloading, under 
actual conditions as determined in paragraph (f)(1)(i) of this 
section.

[GRAPHIC] [TIFF OMITTED] TP10MR14.007

Where:

HRp = Cumulative amount of time in hours of venting for 
each well, p, during the monitoring period.
MPp = Time period, in days, of the monitoring period for 
each well, p. A minimum of 300 days in a calendar year are required. 
The next period of data collection must start immediately following 
the end of data collection for the previous reporting year.
Dp = Time period, in days during which the well, p, was 
in production (365 if the well was in production for the entire 
year).

    (i) Determine the well vent average flow rate (``FR'' in Equation 
W-7A of this section) as specified in paragraphs (f)(1)(i)(A) through 
(f)(1)(i)(C) of this section for at least one well in a unique well 
tubing diameter group and pressure group combination in each sub-basin 
category. Calculate emissions from wells with plunger lifts and wells 
without plunger lifts separately.
    (A) Calculate the average flow rate per hour of venting for each 
unique tubing diameter group and pressure group combination in each 
sub-basin category by dividing the recorded total annual flow by the 
recorded time (in hours) for all measured liquid unloading events with 
venting to the atmosphere.
    (B) Apply the average hourly flow rate calculated under paragraph 
(f)(1)(i)(A) of this section to all wells in the same pressure group 
that have the same tubing diameter group, for the number of hours of 
venting these wells.
    (C) Calculate a new average flow rate every other calendar year 
starting with the first calendar year of data collection. For a new 
producing sub-basin category, calculate an average flow rate beginning 
in the first year of production.
    (ii) Calculate natural gas volumetric emissions at standard 
conditions using calculations in paragraph (t) of this section.
    (2) Calculation Method 2. Calculate the total emissions for each 
sub-basin from well venting to the atmosphere for liquids unloading 
without plunger lift assist using Equation W-8 of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.008


[[Page 13428]]


Where:

Es = Annual natural gas emissions for each sub-basin at 
standard conditions, s, in cubic feet per year.
W = Total number of wells with well venting for liquids unloading 
for each sub-basin.
p = Wells 1 through W with well venting for liquids unloading for 
each sub-basin.
Vp = Total number of unloading events in the monitoring 
period per well, p.
0.37 x10^-3 = {3.14 (pi)/4{time} /{14.7*144{time}  (psia 
converted to pounds per square feet).
CDp = Casing internal diameter for each well, p, in 
inches.
WDp = Well depth from either the top of the well or the 
lowest packer to the bottom of the well, for each well, p, in feet.
SPp = For each well, p, shut-in pressure or surface 
pressure for wells with tubing production, or casing pressure for 
each well with no packers, in pounds per square inch absolute 
(psia). If casing pressure is not available for each well, you may 
determine the casing pressure by multiplying the tubing pressure of 
each well with a ratio of casing pressure to tubing pressure from a 
well in the same sub-basin for which the casing pressure is known. 
The tubing pressure must be measured during gas flow to a flow-line. 
The shut-in pressure, surface pressure, or casing pressure must be 
determined just prior to liquids unloading when the well production 
is impeded by liquids loading or closed to the flow-line by surface 
valves.
SFRp = Average flow-line rate of gas for well, p, at 
standard conditions in cubic feet per hour. Use Equation W-33 of 
this section to calculate the average flow-line rate at standard 
conditions.
HRp,q = Hours that each well, p, was left open to the 
atmosphere during each unloading event, q.
1.0 = Hours for average well to blowdown casing volume at shut-in 
pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 1.0 then 
Zp,q is equal to 0. If HRp,q is greater than 
or equal to 1.0 then Zp,q is equal to 1.

    (3) Calculation Method 3. Calculate the total emissions for each 
sub-basin from well venting to the atmosphere for liquids unloading 
with plunger lift assist using Equation W-9 of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.009

Where:

Es = Annual natural gas emissions for each sub-basin at 
standard conditions, s, in cubic feet per year.
W = Total number of wells with plunger lift assist and well venting 
for liquids unloading for each sub-basin.
p = Wells 1 through W with well venting for liquids unloading for 
each sub-basin.
Vp = Total number of unloading events in the monitoring 
period for each well, p.
0.37 x10^-3 = {3.14 (pi)/4{time} /{14.7*144{time}  (psia 
converted to pounds per square feet).
TDp = Tubing internal diameter for each well, p, in 
inches.
WDp = Tubing depth to plunger bumper for each well, p, in 
feet.
SPp = Flow-line pressure for each well, p, in pounds per 
square inch absolute (psia), using engineering estimate based on 
best available data.
SFRp = Average flow-line rate of gas for well, p, at 
standard conditions in cubic feet per hour. Use Equation W-33 of 
this section to calculate the average flow-line rate at standard 
conditions.
HRp,q = Hours that each well, p, was left open to the 
atmosphere during each unloading event, q.
0.5 = Hours for average well to blowdown tubing volume at flow-line 
pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 0.5 then 
Zp,q is equal to 0. If HRp,q is greater than 
or equal to 0.5 then Zp,q is equal to 1.

    (4) Calculate CH4 and CO2 volumetric and mass 
emissions from volumetric natural gas emissions using calculations in 
paragraphs (u) and (v) of this section.
    (g) Gas well venting during completions and workovers with 
hydraulic fracturing. Calculate annual volumetric natural gas emissions 
from gas well venting during completions and workovers involving 
hydraulic fracturing using Equation W-10A or Equation W-10B of this 
section. Equation W-10A applies to well venting when the flowback rate 
is measured from a specified number of example completions or workovers 
and Equation W-10B applies when the flowback vent or flare volume is 
measured for each completion or workover. Completion and workover 
activities are separated into two periods, an initial period when 
flowback is routed to open pits or tanks and a subsequent period when 
gas content is sufficient to route the flowback to a separator or when 
the gas content is sufficient to allow measurement by the devices 
specified in paragraph (g)(1) of this section, regardless of whether a 
separator is actually utilized. If you elect to use Equation W-10A of 
this section, you must follow the procedures specified in paragraph 
(g)(1) of this section. Emissions must be calculated separately for 
completions and workovers, for each sub-basin, and for each well type 
combination identified in paragraph (g)(2) of this section. You must 
calculate CH4 and CO2 volumetric and mass 
emissions as specified in paragraph (g)(3) of this section. If 
emissions from gas well venting during completions and workovers with 
hydraulic fracturing are routed to a flare, you must calculate 
CH4, CO2, and N2O annual emissions as 
specified in paragraph (g)(4) of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.010

[GRAPHIC] [TIFF OMITTED] TP10MR14.011

Where:

Es,n = Annual volumetric natural gas emissions in 
standard cubic feet from gas well venting during completions or 
workovers following hydraulic fracturing for each sub-basin and well 
type combination.
W = Total number of wells completed or worked over using hydraulic 
fracturing in a sub-basin and well type combination.
Tp,s = Cumulative amount of time of flowback, after 
sufficient quantities of gas are present to enable separation, where 
gas is vented or flared for the completion or workover, in hours, 
for each well, p, in a sub-basin and well type combination during 
the reporting

[[Page 13429]]

year. This may include non-contiguous periods of venting or flaring.
Tp,i = Cumulative amount of time of flowback to open 
tanks/pits, from when gas is first detected until sufficient 
quantities of gas are present to enable separation, for the 
completion or workover, in hours, for each well, p, in a sub-basin 
and well type combination during the reporting year. This may 
include non-contiguous periods of routing to open tanks/pits.
FRMs = Ratio of average flowback, during the period when 
sufficient quantities of gas are present to enable separation, of 
well completions and workovers from hydraulic fracturing to 30-day 
production rate for the sub-basin and well type combination, 
calculated using procedures specified in paragraph (g)(1)(iii) of 
this section, expressed in standard cubic feet per hour.
FRMi = Ratio of initial flowback rate during well 
completions and workovers from hydraulic fracturing to 30-day 
production rate for the sub-basin and well type combination, 
calculated using procedures specified in paragraph (g)(1)(iv) of 
this section, expressed in standard cubic feet per hour, for the 
period of flow to open tanks/pits.
PRs,p = Average production flow rate during the first 30 
days of production after completions of newly drilled gas wells or 
gas well workovers using hydraulic fracturing in standard cubic feet 
per hour of each well p, that was measured in the sub-basin and well 
type combination.
EnFs,p = Volume of N2 injected gas in cubic 
feet at standard conditions that was injected into the reservoir 
during an energized fracture job for each well, p, as determined by 
using an appropriate meter according to methods described in Sec.  
98.234(b), or by using receipts of gas purchases that are used for 
the energized fracture job. Convert to standard conditions using 
paragraph (t) of this section. If the fracture process did not 
inject gas into the reservoir or if the injected gas is 
CO2 then EnFs,p is 0.
FVs,p = Flow volume vented or flared of each well, p, in 
standard cubic feet measured using a recording flow meter (digital 
or analog) on the vent line to measure flowback during the 
separation period of the completion or workover according to methods 
set forth in Sec.  98.234(b).
FRp,i = Flow rate vented or flared of each well, p, in 
standard cubic feet measured using a recording flow meter (digital 
or analog) on the vent line to measure the flowback, at the 
beginning of the period of time when sufficient quantities of gas 
are present to enable separation, of the completion or workover 
according to methods set forth in Sec.  98.234(b).

    (1) If you elect to use Equation W-10A of this section, you must 
use Calculation Method 1 as specified in paragraph (g)(1)(i) of this 
section, or Calculation Method 2 as specified in paragraph (g)(1)(ii) 
of this section, to determine the value of FRMs and 
FRMi. These values must be based on the flow rate for 
flowback, once sufficient gas is present to enable separation. The 
number of measurements or calculations required to estimate 
FRMs and FRMi must be determined individually for 
completions and workovers per sub-basin and well type as follows: 
complete measurements or calculations for at least one completion or 
workover for less than or equal to 25 completions or workovers for each 
well type within a sub-basin; complete measurements or calculations for 
at least two completions or workovers for 26 to 50 completions or 
workovers for each sub-basin and well type combination; complete 
measurements or calculations for at least three completions or 
workovers for 51 to 100 completions or workovers for each sub-basin and 
well type combination; complete measurements or calculations for at 
least four completions or workovers for 101 to 250 completions or 
workovers for each sub-basin and well type combination; and complete 
measurements or calculations for at least five completions or workovers 
for greater than 250 completions or workovers for each sub-basin and 
well type combination.
    (i) Calculation Method 1. You must use Equation W-12A as specified 
in paragraph (g)(1)(iii) of this section to determine the value of 
FRMs. You must use Equation W-12B as specified in paragraph 
(g)(1)(iv) of this section to determine the value of FRMi. 
The procedures specified in paragraphs (g)(1)(v) and (g)(1)(vi) also 
apply. When making flowback measurements for use in Equations W-12A and 
W-12B of this section, you must use a recording flow meter (digital or 
analog) installed on the vent line, ahead of a flare or vent, to 
measure the flowback rates in units of standard cubic feet per hour 
according to methods set forth in Sec.  98.234(b).
    (ii) Calculation Method 2. You must use Equation W-12A as specified 
in paragraph (g)(1)(iii) of this section to determine the value of 
FRMs. You must use Equation W-12B as specified in paragraph 
(g)(1)(iv) of this section to determine the value of FRMi. 
The procedures specified in paragraphs (g)(1)(v) and (g)(1)(vi) also 
apply. When calculating the flowback rates for use in Equations W-12A 
and W-12B of this section based on well parameters, you must record the 
well flowing pressure immediately upstream (and immediately downstream 
in subsonic flow) of a well choke according to methods set forth in 
Sec.  98.234(b) to calculate the well flowback. The upstream pressure 
must be surface pressure and reservoir pressure cannot be assumed. The 
downstream pressure must be measured after the choke and atmospheric 
pressure cannot be assumed. Calculate flowback rate using Equation W-
11A of this section for subsonic flow or Equation W-11B of this section 
for sonic flow. You must use best engineering estimates based on best 
available data along with Equation W-11C of this section to determine 
whether the predominant flow is sonic or subsonic. If the value of R in 
Equation W-11C of this section is greater than or equal to 2, then flow 
is sonic; otherwise, flow is subsonic. Convert calculated 
FRa values shall be converted from actual conditions 
upstream of the restriction orifice to standard conditions 
(FRs,p and FRi,p) for use in Equations W-12A and 
W-12B of this section using Equation W-33 in paragraph (t) of this 
section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.012

Where:

FRa = Flowback rate in actual cubic feet per hour, under 
actual subsonic flow conditions.
A = Cross sectional open area of the restriction orifice 
(m²).
P1 = Pressure immediately upstream of the choke (psia).
Tu = Temperature immediately upstream of the choke 
(degrees Kelvin).
P2 = Pressure immediately downstream of the choke (psia).
3430 = Constant with units of m²/(sec² * K).
1.27*10⁵ = Conversion from m³/second to 
ft³/hour.

[[Page 13430]]

[GRAPHIC] [TIFF OMITTED] TP10MR14.013

Where:

FRa = Flowback rate in actual cubic feet per hour, under 
actual sonic flow conditions.
A = Cross sectional open area of the restriction orifice 
(m²).
Tu = Temperature immediately upstream of the choke 
(degrees Kelvin).
187.08 = Constant with units of m²/(sec² * K).
1.27*10⁵ = Conversion from m³/second to 
ft³/hour.
[GRAPHIC] [TIFF OMITTED] TP10MR14.014

Where:

R = Pressure ratio.
P1 = Pressure immediately upstream of the choke (psia).
P2 = Pressure immediately downstream of the choke (psia).

    (iii) For Equation W-10A of this section, calculate FRMs 
using Equation W-12A of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.015

Where:

FRMs = Ratio of average flowback rate, during the period 
of time when sufficient quantities of gas are present to enable 
separation, of well completions and workovers from hydraulic 
fracturing to 30-day production rate for each sub-basin and well 
type combination.
FRs,p = Measured average flowback rate from Calculation 
Method 1 described in paragraph (g)(1)(i) of this section or 
calculated average flowback rate from Calculation Method 2 described 
in paragraph (g)(1)(ii) of this section, during the separation 
period in standard cubic feet per hour for well(s) p for each sub-
basin and well type combination. Convert measured and calculated 
FRa values shall be converted from actual conditions 
upstream of the restriction orifice (FRa) to standard 
conditions (FRs,p) for each well p using Equation W-33 in 
paragraph (t) of this section. You may not use flow volume as used 
in Equation W-10B converted to a flow rate for this parameter.
PRs,p = Average production flow rate during the first 30 
days of production after completions of newly drilled gas wells or 
gas well workovers using hydraulic fracturing, in standard cubic 
feet per hour for each well, p, that was measured in the sub-basin 
and well type combination.
N = Number of measured or calculated well completions or workovers 
using hydraulic fracturing in a sub-basin and well type combination.

    (iv) For Equation W-10A of this section, calculate FRMi 
using Equation W-12B of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.016

Where:

FRMi = Ratio of flowback gas rate while flowing to open 
tanks/pits during well completions and workovers from hydraulic 
fracturing to 30-day production rate.
FRi,p = Initial measured gas flowback rate from 
Calculation Method 1 described in paragraph (g)(1)(i) of this 
section or initial calculated flow rate from Calculation Method 2 
described in paragraph (g)(1)(ii) of this section in standard cubic 
feet per hour for well(s), p, for each sub-basin and well type 
combination. Measured and calculated FRi,p values must be 
based on flow conditions at the beginning of the separation period 
and must be expressed at standard conditions.
PRs,p = Average production flow rate during the first 30-
days of production after completions of newly drilled gas wells or 
gas well workovers using hydraulic fracturing, in standard cubic 
feet per hour of each well, p, that was measured in the sub-basin 
and well type combination.
N = Number of measured or calculated well completions or workovers 
using hydraulic fracturing in a sub-basin and well type combination.

    (v) For Equation W-10A of this section, the ratio of flowback rate 
during well completions and workovers from hydraulic fracturing to 30-
day production rate for horizontal and vertical wells are applied to 
all horizontal and vertical well completions in the gas producing sub-
basin and well type combination and to all horizontal and vertical well 
workovers, respectively, in the gas producing sub-basin and well type 
combination for the total number of hours of flowback and for the first 
30 day average production rate for each of these wells.
    (vi) For Equation W-12A and W-12B of this section, calculate new 
flowback rates for horizontal and vertical gas well completions and 
horizontal and vertical gas well workovers in each sub-basin category 
once every two years starting in the first calendar year of data 
collection.
    (2) For paragraphs (g) introductory text and (g)(1) of this 
section, measurements and calculations are completed separately for 
workovers and completions per sub-basin and well type combination. A 
well type combination is a unique combination of the

[[Page 13431]]

parameters listed in paragraphs (g)(2)(i) through (g)(2)(iii) of this 
section.
    (i) Vertical or horizontal (directional drilling).
    (ii) With flaring or without flaring.
    (iii) Reduced emission completion/workover or not reduced emission 
completion/workover.
    (3) Calculate both CH4 and CO2 volumetric and 
mass emissions from total natural gas volumetric emissions using 
calculations in paragraphs (u) and (v) of this section.
    (4) Calculate annual emissions from gas well venting during well 
completions and workovers from hydraulic fracturing where all or a 
portion of the gas is flared as specified in paragraphs (g)(4)(i) and 
(g)(4)(ii) of this section.
    (i) Use the volumetric total natural gas emissions vented to the 
atmosphere during well completions and workovers as determined in 
paragraph (g) of this section to calculate volumetric and mass 
emissions using paragraphs (u) and (v) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to adjust emissions for the portion of gas flared during 
well completions and workovers using hydraulic fracturing. This 
adjustment to emissions from completions using flaring, versus 
completions without flaring, accounts for the conversion of 
CH4 to CO2 in the flare and for the formation on 
N2O during flaring.
    (h) Gas well venting during completions and workovers without 
hydraulic fracturing. Calculate annual volumetric natural gas emissions 
from each gas well venting during workovers without hydraulic 
fracturing using Equation W-13A of this section. Calculate annual 
volumetric natural gas emissions from each gas well venting during 
completions without hydraulic fracturing using Equation W-13B of this 
section. You must convert annual volumetric natural gas emissions to 
CH4 and CO2 volumetric and mass emissions as 
specified in paragraph (h)(1) of this section. If emissions from gas 
well venting during completions and workovers without hydraulic 
fracturing are routed to a flare, you must calculate CH4, 
CO2, and N2O annual emissions as specified in 
paragraph (h)(2) of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.017

Where:

Es,wo = Annual volumetric natural gas emissions in 
standard cubic feet from gas well venting during well workovers 
without hydraulic fracturing.
Nwo = Number of workovers per sub-basin category that do 
not involve hydraulic fracturing in the reporting year.
EFwo = Emission factor for non-hydraulic fracture well 
workover venting in standard cubic feet per workover. Use 3,114 
standard cubic feet natural gas per well workover without hydraulic 
fracturing.
Es,p = Annual volumetric natural gas emissions in 
standard cubic feet from gas well venting during well completions 
without hydraulic fracturing.
p = Well completions 1 through f in a sub-basin.
f = Total number of well completions without hydraulic fracturing in 
a sub-basin category.
Vp = Average daily gas production rate in standard cubic 
feet per hour for each well, p, undergoing completion without 
hydraulic fracturing. This is the total annual gas production volume 
divided by total number of hours the wells produced to the flow-
line. For completed wells that have not established a production 
rate, you may use the average flow rate from the first 30 days of 
production. In the event that the well is completed less than 30 
days from the end of the calendar year, the first 30 days of the 
production straddling the current and following calendar years shall 
be used.
Tp = Time that gas is vented to either the atmosphere or 
a flare for each well, p, undergoing completion without hydraulic 
fracturing, in hours during the year.

    (1) Calculate both CH4 and CO2 volumetric 
emissions from natural gas volumetric emissions using calculations in 
paragraph (u) of this section. Calculate both CH4 and 
CO2 mass emissions from volumetric emissions vented to 
atmosphere using calculations in paragraph (v) of this section.
    (2) Calculate annual emissions of CH4, CO2, 
and N2O from gas well venting to flares during well 
completions and workovers not involving hydraulic fracturing as 
specified in paragraphs (h)(2)(i) and (h)(2)(ii) of this section.
    (i) Use the gas well venting volume and gas composition during well 
completions and workovers that are flared as determined using the 
methods specified in paragraphs (h) and (h)(1) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine emissions from the flare for gas well venting 
to a flare during completions and workovers without hydraulic 
fracturing.
    (i) Blowdown vent stacks. Calculate CO2 and 
CH4 blowdown vent stack emissions from the depressurization 
of equipment to reduce system pressure for planned or emergency 
shutdowns resulting from human intervention or to take equipment out of 
service for maintenance as specified in either paragraph (i)(2) or 
(i)(3) of this section. Equipment with a unique physical volume of less 
than 50 cubic feet as determined in paragraph (i)(1) of this section 
are not subject to the requirements in paragraphs (i)(2) through (i)(4) 
this section. The requirements in this paragraph (i) do not apply to 
blowdown vent stack emissions from depressurizing to a flare, over-
pressure relief, operating pressure control venting, blowdown of non-
GHG gases, and desiccant dehydrator blowdown venting before reloading.
    (1) Method for calculating unique physical volumes. You must 
calculate each unique physical volume (including pipelines, compressor 
case or cylinders, manifolds, suction bottles, discharge bottles, and 
vessels) between isolation valves, in cubic feet, by using engineering 
estimates based on best available data.
    (2) Method for determining emissions from blowdown vent stacks 
according to equipment type. If you elect to determine emissions 
according to each equipment type, using unique physical volumes as 
calculated in paragraph (i)(1) of this section, you must calculate 
emissions as specified in paragraphs (i)(2)(i) through (i)(2)(iii) of 
this section for each equipment type. Equipment types must be grouped 
into the following seven categories: station piping, pipeline venting, 
compressors, scrubbers/strainers, pig launchers and receivers, 
emergency shutdowns, and all other blowdowns greater than or equal to 
50 cubic feet.
    (i) Calculate the total annual natural gas emissions from each 
unique physical volume that is blown down

[[Page 13432]]

using either Equation W-14A or W-14B of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.018

Where:

Es,n = Annual natural gas emissions at standard 
conditions from each unique physical volume that is blown down, in 
cubic feet.
N = Number of occurrences of blowdowns for each unique physical 
volume in the calendar year. You must retain logs documenting the 
number of occurrences of blowdowns for each unique physical volume 
in the calendar year.
V = Unique physical volume between isolation valves, in cubic feet, 
as calculated in paragraph (i)(1) of this section.
C = Purge factor is 1 if the unique physical volume is not purged, 
or 0 if the unique physical volume is purged using non-GHG gases.
Ts = Temperature at standard conditions (60 [deg]F).
Ta = Temperature at actual conditions in the unique 
physical volume ([deg]F).
Ps = Absolute pressure at standard conditions (14.7 
psia).
Pa = Absolute pressure at actual conditions in the unique 
physical volume (psia).
Za = Compressibility factor at actual conditions for 
natural gas. You may use 1 if the temperature is above -10 degrees 
Fahrenheit and pressure is below 5 atmospheres, or if the 
compressibility factor at the actual temperature and pressure is 
0.98 or greater.
[GRAPHIC] [TIFF OMITTED] TP10MR14.019

Where:

Es,n = Annual natural gas emissions at standard 
conditions from each unique physical volume that is blown down, in 
cubic feet.
p = Individual occurrence of blowdown for the same unique physical 
volume.
N = Number of occurrences of blowdowns for each unique physical 
volume in the calendar year. You must retain logs documenting the 
number of occurrences of blowdowns for each unique physical volume 
in the calendar year.
Vp = Unique physical volume between isolation valves, in 
cubic feet, for each blowdown ``p.''
Ts = Temperature at standard conditions (60 [deg]F).
Ta,p = Temperature at actual conditions in the unique 
physical volume ([deg]F) for each blowdown ``p''.
Ps = Absolute pressure at standard conditions (14.7 
psia).
Pa,b,p = Absolute pressure at actual conditions in the 
unique physical volume (psia) at the beginning of the blowdown 
``p''.
Pa,e,p = Absolute pressure at actual conditions in the 
unique physical volume (psia) at the end of the blowdown ``p''; 0 if 
blowdown volume is purged using non-GHG gases.
Za = Compressibility factor at actual conditions for 
natural gas. You may use 1 if the temperature is above -10 degrees 
Fahrenheit and pressure is below 5 atmospheres, or if the 
compressibility factor at the actual temperature and pressure is 
0.98 or greater.

    (ii) Calculate the annual natural gas emissions, in cubic feet, 
from each equipment type by summing Es,n, as calculated in 
either Equation W-14A or Equation W-14B of this subpart, for all unique 
physical volumes associated with the equipment type.
    (iii) Calculate total annual CH4 and CO2 
volumetric and mass emissions from each equipment type by using the 
annual natural gas emission value calculated in paragraph (i)(2)(ii) of 
this section for the equipment type and the calculation method 
specified in paragraph (i)(4) of this section.
    (3) Method for determining emissions from blowdown vent stacks 
using a flow meter. In lieu of determining emissions from blowdown vent 
stacks using unique physical volumes as specified in paragraphs (i)(1) 
and (i)(2) of this section, you may use a flow meter and measure 
blowdown vent stack emissions. If you choose to use this method, you 
must measure the natural gas emissions from the blowdown(s) at the 
facility using a flow meter according to methods in Sec.  98.234(b), 
and calculate annual CH4 and CO2 volumetric and 
mass emissions measured by the meters according to paragraph (i)(4) of 
this section.
    (4) Method for converting from natural gas emissions to GHG 
volumetric and mass emissions. Calculate both CH4 and 
CO2 volumetric and mass emissions using the methods 
specified in paragraphs (u) and (v) of this section.
    (j) Onshore production storage tanks. Calculate CH4, 
CO2, and N2O (when flared) emissions from 
atmospheric pressure fixed roof storage tanks receiving hydrocarbon 
produced liquids from onshore petroleum and natural gas production 
facilities (including stationary liquid storage not owned or operated 
by the reporter), as specified in this paragraph (j). For wells flowing 
to gas-liquid separators with annual average daily throughput of oil 
greater than or equal to 10 barrels per day, calculate annual 
CH4 and CO2 using Calculation Method 1 or 2 as 
specified in paragraphs (j)(1) and (j)(2) of this section. For wells 
flowing directly to atmospheric storage tanks without passing through a 
wellhead separator with throughput greater than 10 barrels per day, 
calculate annual CH4 and CO2 emissions using 
Calculation Method 2 as specified in paragraph (j)(2) of this section. 
For wells flowing to gas-liquid separators or directly to atmospheric 
storage tanks with throughput less than 10 barrels per day, use 
Calculation Method 3 as specified in paragraphs (j)(3) of this section. 
You must also calculate emissions that may have occurred due to dump 
valves not closing properly using the method specified in paragraph 
(j)(6) of this section. If emissions from atmospheric pressure fixed 
roof storage tanks are routed to a vapor recovery system, you must 
adjust the emissions downward according to paragraph (j)(4) of this 
section. If emissions from atmospheric pressure fixed roof storage 
tanks are routed to a flare, you must calculate CH4, 
CO2, and N2O annual emissions as specified in 
paragraph (j)(5) of this section.
    (1) Calculation Method 1. Calculate annual CH4 and 
CO2 emissions from onshore production storage tanks using 
operating conditions in the last

[[Page 13433]]

wellhead gas-liquid separator before liquid transfer to storage tanks. 
Calculate flashing emissions with a software program, such as AspenTech 
HYSYS[supreg] or API 4697 E&P Tank, that uses the Peng-Robinson 
equation of state, models flashing emissions, and speciates 
CH4 and CO2 emissions that will result when the 
oil from the separator enters an atmospheric pressure storage tank. The 
following parameters must be determined for typical operating 
conditions over the year by engineering estimate and process knowledge 
based on best available data, and must be used at a minimum to 
characterize emissions from liquid transferred to tanks:
* * * * *
    (vii) Separator oil composition and Reid vapor pressure. If this 
data is not available, determine these parameters by using one of the 
methods described in paragraphs (j)(1)(vii)(A) through (j)(1)(vii)(C) 
of this section.
* * * * *
    (2) Calculation Method 2. Calculate annual CH4 and 
CO2 emissions by assuming that all of the CH4 and 
CO2 in solution at separator temperature and pressure is 
emitted from oil sent to storage tanks, using either of the methods in 
paragraphs (j)(2)(i) or (j)(2)(ii) of this section. You may use an 
appropriate standard method published by a consensus-based standards 
organization if such a method exists or you may use an industry 
standard practice as described in Sec.  98.234(b) to sample and analyze 
separator oil composition at separator pressure and temperature.
* * * * *
    (3) Calculation Method 3. Calculate CH4 and 
CO2 emissions using Equation W-15 of this section:
[GRAPHIC] [TIFF OMITTED] TP10MR14.020

Where:

Es,i = Annual total volumetric GHG emissions (either 
CO2 or CH4) at standard conditions in cubic 
feet.
EFi = Population emission factor for separators or wells 
in thousand standard cubic feet per separator or well per year, for 
crude oil use 4.2 for CH4 and 2.8 for CO2 at 
60 [deg]F and 14.7 psia, and for gas condensate use 17.6 for 
CH4 and 2.8 for CO2 at 60 [deg]F and 14.7 
psia.
Count = Total number of separators or wells with annual average 
daily throughput less than 10 barrels per day. Count only separators 
or wells that feed oil directly to the storage tank.
1,000 = Conversion from thousand standard cubic feet to standard 
cubic feet.

    (4) Determine if the storage tank receiving your separator oil has 
a vapor recovery system.
    (i) Adjust the emissions estimated in paragraphs (j)(1) through 
(j)(3) of this section downward by the magnitude of emissions recovered 
using a vapor recovery system as determined by engineering estimate 
based on best available data.
    (ii) [Reserved]
    (5) Determine if the storage tank receiving your separator oil is 
sent to flare(s).
    (i) Use your separator flash gas volume and gas composition as 
determined in this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine storage tank emissions from the flare.
    (6) Calculate emissions from occurrences of well pad gas-liquid 
separator liquid dump valves not closing during the calendar year by 
using Equation W-16 of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.021

Where:

Es,i,o = Annual volumetric GHG emissions at standard 
conditions from each storage tank in cubic feet that resulted from 
the dump valve on the gas-liquid separator not closing properly.
En = Storage tank emissions as determined in Calculation 
Methods 1, 2, or 3 in paragraphs (j)(1), (j)(2), and (j)(3) of this 
section (with wellhead separators) in standard cubic feet per year.
Tn = Total time a dump valve is not closing properly in 
the calendar year in hours. Estimate Tn based on 
maintenance, operations, or routine well pad inspections that 
indicate the period of time when the valve was malfunctioning in 
open or partially open position.
CFn = Correction factor for tank emissions for time 
period Tn is 2.87 for crude oil production. Correction 
factor for tank emissions for time period Tn is 4.37 for 
gas condensate production.
8,760 = Conversion to hourly emissions.

    (7) Calculate both CH4 and CO2 mass emissions 
from natural gas volumetric emissions using calculations in paragraph 
(v) of this section.
    (k) Transmission storage tanks. For vent stacks connected to one or 
more transmission condensate storage tanks, either water or 
hydrocarbon, without vapor recovery, in onshore natural gas 
transmission compression, calculate CH4 and CO2 
annual emissions from compressor scrubber dump valve leakage as 
specified in paragraphs (k)(1) through (k)(3) of this section. If 
emissions from compressor scrubber dump valve leakage are routed to a 
flare, you must calculate CH4, CO2, and 
N2O annual emissions as specified in paragraph (k)(4) of 
this section.
    (1) Except as specified in paragraph (k)(1)(iv) of this section, 
you must monitor the tank vapor vent stack annually for emissions using 
one of the methods specified in paragraphs (k)(1)(i) through 
(k)(1)(iii) of this section.
    (i) Use an optical gas imaging instrument according to methods set 
forth in Sec.  98.234(a)(1).
    (ii) Measure the tank vent directly using a flow meter or high 
volume sampler according to methods in Sec.  98.234(b) or (d) for a 
duration of 5 minutes.
    (iii) Measure the tank vent using a calibrated bag according to 
methods in Sec.  98.234(c) for a duration of 5 minutes or until the bag 
is full, whichever is shorter.
    (iv) You may annually monitor leakage through compressor scrubber 
dump valve(s) into the tank using an acoustic leak detection device 
according to methods set forth in Sec.  98.234(a)(5).
    (2) If the tank vapors from the vent stack are continuous for 5 
minutes, or the acoustic leak detection device detects a leak, then you 
must use one of the methods in either paragraph (k)(2)(i) or (k)(2)(ii) 
of this section and the requirements specified in paragraphs 
(k)(2)(iii) and (k)(2)(iv) of this section to quantify annual 
emissions.
    (i) Use a flow meter, such as a turbine meter, calibrated bag, or 
high volume sampler to estimate tank vapor volumes from the vent stack 
according to

[[Page 13434]]

methods set forth in Sec.  98.234(b) through (d). If you do not have a 
continuous flow measurement device, you may install a flow measuring 
device on the tank vapor vent stack. If the vent is directly measured 
for five minutes under paragraph (k)(1)(ii) or (k)(1)(iii) of this 
section to detect continuous leakage, this serves as the measurement.
    (ii) Use an acoustic leak detection device on each scrubber dump 
valve connected to the tank according to the method set forth in Sec.  
98.234(a)(5).
    (iii) Use the appropriate gas composition in paragraph (u)(2)(iii) 
of this section.
    (iv) Calculate CH4 and CO2 volumetric and 
mass emissions at standard conditions using calculations in paragraphs 
(t), (u), and (v) of this section, as applicable to the monitoring 
equipment used.
    (3) If a leaking dump valve is identified, the leak must be counted 
as having occurred since the beginning of the calendar year, or from 
the previous test that did not detect leaking in the same calendar 
year. If the leaking dump valve is fixed following leak detection, the 
leak duration will end upon being repaired. If a leaking dump valve is 
identified and not repaired, the leak must be counted as having 
occurred through the rest of the calendar year.
    (4) Calculate annual emissions from storage tanks to flares as 
specified in paragraphs (k)(4)(i) and (k)(4)(ii) of this section.
    (i) Use the storage tank emissions volume and gas composition as 
determined in paragraphs (k)(1) through (k)(3) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine storage tank emissions sent to a flare.
    (l) Well testing venting and flaring. Calculate CH4 and 
CO2 annual emissions from well testing venting as specified 
in paragraphs (l)(1) through (l)(5) of this section. If emissions from 
well testing venting are routed to a flare, you must calculate 
CH4, CO2, and N2O annual emissions as 
specified in paragraph (l)(6) of this section.
* * * * *
    (2) If GOR cannot be determined from your available data, then you 
must measure quantities reported in this section according to one of 
the procedures specified in paragraph (l)(2)(i) or (l)(2)(ii) of this 
section to determine GOR.
* * * * *
    (ii) You may use an industry standard practice as described in 
Sec.  98.234(b).
    (3) Estimate venting emissions using Equation W-17A (for oil wells) 
or Equation W-17B (for gas wells) of this section.
* * * * *
FR = Average annual flow rate in barrels of oil per day for the oil 
well(s) being tested.
* * * * *
D = Number of days during the calendar year that the well(s) is 
tested.
* * * * *
    (5) Calculate both CH4 and CO2 volumetric and 
mass emissions from natural gas volumetric emissions using calculations 
in paragraphs (u) and (v) of this section.
    (6) Calculate emissions from well testing if emissions are routed 
to a flare as specified in paragraphs (l)(6)(i) and (l)(6)(ii) of this 
section.
    (i) Use the well testing emissions volume and gas composition as 
determined in paragraphs (l)(1) through (4) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine well testing emissions from the flare.
    (m) Associated gas venting and flaring. Calculate CH4 
and CO2 annual emissions from associated gas venting not in 
conjunction with well testing (refer to paragraph (l): Well testing 
venting and flaring of this section) as specified in paragraphs (m)(1) 
through (m)(4) of this section. If emissions from associated gas 
venting are routed to a flare, you must calculate CH4, 
CO2, and N2O annual emissions as specified in 
paragraph (m)(5) of this section.
    (1) Determine the GOR of the hydrocarbon production from each well 
whose associated natural gas is vented or flared. If GOR from each well 
is not available, use the GOR from a cluster of wells in the same sub-
basin category.
    (2) If GOR cannot be determined from your available data, then you 
must use one of the procedures specified in paragraphs (m)(2)(i) or 
(m)(2)(ii) of this section to determine GOR.
    (i) You may use an appropriate standard method published by a 
consensus-based standards organization if such a method exists.
    (ii) You may use an industry standard practice as described in 
Sec.  98.234(b).
    (3) Estimate venting emissions using Equation W-18 of this section.
    [GRAPHIC] [TIFF OMITTED] TP10MR14.022
    
Where:

Es,n = Annual volumetric natural gas emissions, at the 
facility level, from associated gas venting at standard conditions, 
in cubic feet.
GORp,q = Gas to oil ratio, for well p in sub-basin q, in 
standard cubic feet of gas per barrel of oil; oil here refers to 
hydrocarbon liquids produced of all API gravities.
Vp,q = Volume of oil produced, for well p in sub-basin q, 
in barrels in the calendar year during time periods in which 
associated gas was vented or flared.
SGp,q = Volume of associated gas sent to sales, for well 
p in sub-basin q, in standard cubic feet of gas in the calendar year 
during time periods in which associated gas was vented or flared.
EREp,q = Emissions reported elsewhere, volume of 
associated gas for well p in sub-basin q, in standard cubic feet, 
during time periods in which associated gas was vented or flared and 
for which emission source types of this section calculate and report 
emissions from the associated gas stream prior to venting or flaring 
of the associated gas (i.e., Sec.  98.233(j) for onshore production 
storage tanks).
x = Total number of wells in sub-basin that vent or flare associated 
gas.
y = Total number of sub-basins in a basin that contain wells that 
vent or flare associated gas.

    (4) Calculate both CH4 and CO2 volumetric and 
mass emissions from volumetric natural gas emissions using calculations 
in paragraphs (u) and (v) of this section.
    (5) Calculate emissions from associated natural gas if emissions 
are routed to a flare as specified in paragraphs (m)(5)(i) and 
(m)(5)(ii) of this section.
    (i) Use the associated natural gas volume and gas composition as 
determined in paragraph (m)(1) through (m)(4) of this section.
    (ii) Use the calculation method of flare stacks in paragraph (n) of 
this section to determine associated gas emissions from the flare.
    (n) Flare stack emissions. Calculate CO2, 
CH4, and N2O emissions from a flare stack as 
specified in paragraphs (n)(1) through (n)(9) of this section.
    (1) If you have a continuous flow measurement device on the flare, 
you

[[Page 13435]]

must use the measured flow volumes to calculate the flare gas 
emissions. If all of the flare gas is not measured by the existing flow 
measurement device, then the flow not measured can be estimated using 
engineering calculations based on best available data or company 
records. If you do not have a continuous flow measurement device on the 
flare, you can use engineering calculations based on process knowledge, 
company records, and best available data.
    (2) If you have a continuous gas composition analyzer on gas to the 
flare, you must use these compositions in calculating emissions. If you 
do not have a continuous gas composition analyzer on gas to the flare, 
you must use the appropriate gas compositions for each stream of 
hydrocarbons going to the flare as specified in paragraphs (n)(2)(i) 
through (n)(2)(iii) of this section.
    (i) For onshore natural gas production, determine the GHG mole 
fraction using paragraph (u)(2)(i) of this section.
    (ii) For onshore natural gas processing, when the stream going to 
flare is natural gas, use the GHG mole fraction in feed natural gas for 
all streams upstream of the de-methanizer or dew point control, and GHG 
mole fraction in facility specific residue gas to transmission pipeline 
systems for all emissions sources downstream of the de-methanizer 
overhead or dew point control for onshore natural gas processing 
facilities. For onshore natural gas processing plants that solely 
fractionate a liquid stream, use the GHG mole fraction in feed natural 
gas liquid for all streams.
    (iii) For any applicable industry segment, when the stream going to 
the flare is a hydrocarbon product stream, such as methane, ethane, 
propane, butane, pentane-plus and mixed light hydrocarbons, then you 
may use a representative composition from the source for the stream 
determined by engineering calculation based on process knowledge and 
best available data.
    (3) Determine flare combustion efficiency from manufacturer. If not 
available, assume that flare combustion efficiency is 98 percent.
    (4) Convert GHG volumetric emissions to standard conditions using 
calculations in paragraph (t) of this section.
    (5) Calculate GHG volumetric emissions from flaring at standard 
conditions using Equations W-19 and W-20 of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.023

Where:

Es,CH4 = Annual CH4 emissions from flare stack 
in cubic feet, at standard conditions.
Es,CO2 = Annual CO2 emissions from flare stack 
in cubic feet, at standard conditions.
Vs = Volume of gas sent to flare in standard cubic feet, 
during the year as determined in paragraph (n)(1) of this section.
[eta] = Flare combustion efficiency, expressed as fraction of gas 
combusted by a burning flare (default is 0.98).
XCH4 = Mole fraction of CH4 in the feed gas to 
the flare as determined in paragraph (n)(2) of this section.
XCO2 = Mole fraction of CO2 in the feed gas to 
the flare as determined in paragraph (n)(2) of this section.
ZU = Fraction of the feed gas sent to an un-lit flare 
determined by engineering estimate and process knowledge based on 
best available data and operating records.
ZL = Fraction of the feed gas sent to a burning flare 
(equal to 1- ZU).
Yj = Mole fraction of hydrocarbon constituents j (such as 
methane, ethane, propane, butane, and pentanes-plus) in the feed gas 
to the flare as determined in paragraph (n)(1) of this section.
Rj = Number of carbon atoms in the hydrocarbon 
constituent j in the feed gas to the flare: 1 for methane, 2 for 
ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus).

    (6) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculation in paragraph (v) of this 
section.
    (7) Calculate N2O emissions from flare stacks using 
Equation W-40 in paragraph (z) of this section.
    (8) If you operate and maintain a CEMS that has both a 
CO2 concentration monitor and volumetric flow rate monitor 
for the combustion gases from the flare, you must calculate only 
CO2 emissions for the flare. You must follow the Tier 4 
Calculation Method and all associated calculation, quality assurance, 
reporting, and recordkeeping requirements for Tier 4 in subpart C of 
this part (General Stationary Fuel Combustion Sources). If a CEMS is 
used to calculate flare stack emissions, the requirements specified in 
paragraphs (n)(1) through (n)(7) are not required.
    (9) The flare emissions determined under paragraph (n) of this 
section must be corrected for flare emissions calculated and reported 
under other paragraphs of this section to avoid double counting of 
these emissions.
    (o) Centrifugal compressor venting. If you are required to report 
emissions from centrifugal compressor venting as specified in Sec.  
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct 
volumetric emission measurements specified in paragraph (o)(1) of this 
section using methods specified in paragraphs (o)(2) through (o)(5) of 
this section; perform calculations specified in paragraphs (o)(6) 
through (o)(9) of this section; and calculate CH4 and 
CO2 mass emissions as specified in paragraph (o)(11) of this 
section. If emissions from a compressor source are routed to a flare, 
paragraphs (o)(1) through (o)(11) of this section do not apply and 
instead you must calculate CH4, CO2, and 
N2O emissions as specified in paragraph (o)(12) of this 
section. If emissions from a compressor source are captured for fuel 
use or are routed to a thermal oxidizer, paragraphs (o)(1) through 
(o)(12) of this section do not apply and instead you must calculate and 
report emissions as specified in subpart C of this part. If emissions 
from a compressor source are routed to vapor recovery, the calculations 
specified in paragraphs (o)(1) through (o)(12) of this section do not 
apply. If you are required to report emissions from centrifugal 
compressor venting at an onshore petroleum and natural gas production 
facility as specified in Sec.  98.232(c)(19), you must calculate 
volumetric emissions as specified in paragraph (o)(10) of this section; 
and calculate CH4 and CO2 mass emissions as 
specified in paragraph (o)(11) of this section.
    (1) General requirements for conducting volumetric emission 
measurements. You must conduct volumetric emission measurements on each 
centrifugal compressor as specified in this paragraph. Compressor 
sources (as defined in Sec.  98.238) without manifolded vents must use 
a

[[Page 13436]]

measurement method specified in paragraph (o)(1)(i) or (o)(1)(ii) of 
this section. Manifolded compressor sources (as defined in Sec.  
98.238) must use a measurement method specified in paragraph (o)(1)(i), 
(o)(1)(ii), (o)(1)(iii), or (o)(1)(iv) of this section.
    (i) Centrifugal compressor source as found leak measurements. 
Measure venting from each compressor according to either paragraph 
(o)(1)(i)(A) or (o)(1)(i)(B) of this section at least once annually, 
based on the compressor mode (as defined in Sec.  98.238) in which the 
compressor was found at the time of measurement, except as specified in 
paragraphs (o)(1)(i)(C) and (o)(1)(i)(D) of this section. If additional 
measurements beyond the required annual testing are performed 
(including duplicate measurements or measurement of additional 
operating modes), then all measurements satisfying the applicable 
monitoring and QA/QC that is required by this paragraph (o) must be 
used in the calculations specified in this section.
    (A) For a compressor measured in operating-mode, you must measure 
volumetric emissions from blowdown valve leakage through the blowdown 
vent as specified in either paragraph (o)(2)(i)(A) or (o)(2)(i)(B) of 
this section and, if the compressor has wet seal oil degassing vents, 
measure volumetric emissions from wet seal oil degassing vents as 
specified in paragraph (o)(2)(ii) of this section. If a compressor has 
a continuously operating vapor recovery system for the wet seal 
degassing, then measurement of wet seal degassing is not required.
    (B) For a compressor measured in not-operating-depressurized-mode, 
you must measure volumetric emissions from isolation valve leakage as 
specified in either paragraph (o)(2)(i)(A), (o)(2)(i)(B), or 
(o)(2)(i)(C) of this section. If a compressor is not operated and has 
blind flanges in place throughout the reporting period, measurement is 
not required in this compressor mode.
    (C) You must measure the compressor as specified in paragraph 
(o)(1)(i)(B) of this section at least once in any three consecutive 
calendar years, provided the measurement can be taken during a 
scheduled shutdown. If three consecutive calendar years occur without 
measuring the compressor in not-operating-depressurized-mode, you must 
measure the compressor as specified in paragraph (o)(1)(i)(B) of this 
section at the next scheduled depressurized shutdown. The requirement 
specified in this paragraph does not apply if the compressor has blind 
flanges in place throughout the reporting year.
    (D) You must measure the compressor as specified in paragraph 
(o)(1)(i)(A) of this section at least once in any three consecutive 
calendar years, provided that the measurement can be taken when the 
compressor is in operating-mode. If three consecutive calendar years 
occur without measuring the compressor in operating-mode, you must 
measure the compressor as specified in paragraph (o)(1)(i)(A) of this 
section in the next calendar year that the compressor is in operating-
mode for more than 2,000 hours.
    (ii) Centrifugal compressor source continuous monitoring. Instead 
of measuring the compressor source according to paragraph (o)(1)(i) of 
this section for a given compressor, you may elect to continuously 
measure volumetric emissions from a compressor source as specified in 
paragraph (o)(3) of this section.
    (iii) Manifolded centrifugal compressor source as found leak 
measurements. For a compressor source that is part of a manifolded 
group of compressor sources (as defined in Sec.  98.238), instead of 
measuring the compressor source according to paragraph (o)(1)(i), 
(o)(1)(ii), or (o)(1)(iv) of this section, you may elect to measure 
combined volumetric emissions from the manifolded group of compressor 
sources by conducting leak measurements at the common vent stack as 
specified in paragraph (o)(4) of this section. The leak measurements 
must be conducted at the frequency specified in paragraphs 
(o)(1)(iii)(A) through (o)(1)(iii)(C) of this section.
    (A) A minimum of three leak measurements must be taken for each 
manifolded group of compressor sources in a calendar year.
    (B) The leak measurements may be performed while the compressors 
are in any compressor mode.
    (C) The three required leak measurements must be separated by a 
minimum of 60 days. If more than two leak measurements are performed, 
the first and last measurements in a calendar year must be separated by 
a minimum of 120 days.
    (iv) Manifolded centrifugal compressor source continuous 
monitoring. For a compressor source that is part of a manifolded group 
of compressor sources, instead of measuring the compressor source 
according to paragraph (o)(1)(i), (o)(1)(ii), or (o)(1)(iii) of this 
section, you may elect to continuously measure combined volumetric 
emissions from the manifolded group of compressor sources as specified 
in paragraph (o)(5) of this section.
    (2) Methods for performing as found leak measurements from 
individual centrifugal compressor sources. If conducting leak 
measurements for each compressor source, you must determine the 
volumetric emissions of leaks from blowdown valves and isolation valves 
as specified in paragraph (o)(2)(i) of this section, and the volumetric 
emissions of leaks from wet seal oil degassing vents as specified in 
paragraph (o)(2)(ii) of this section.
    (i) For blowdown valves on compressors in operating-mode and for 
isolation valves on compressors in not-operating-depressurized-mode, 
determine the volumetric emissions of leaks using one of the methods 
specified in paragraphs (o)(2)(i)(A) through (o)(2)(i)(C) of this 
section.
    (A) Measure the volumetric flow at standard conditions from the 
blowdown vent using calibrated bagging or high volume sampler according 
to methods set forth in Sec.  98.234(c) and Sec.  98.234(d), 
respectively.
    (B) Measure the volumetric flow at standard conditions from the 
blowdown vent using a temporary meter such as a vane anemometer 
according to methods set forth in Sec.  98.234(b).
    (C) For isolation valves, you may use an acoustic leak detection 
device according to methods set forth in Sec.  98.234(a) instead of 
measuring the isolation valve leakage through the blowdown vent as 
provided for in paragraphs (o)(2)(i)(A) or (o)(2)(i)(B) of this 
section.
    (ii) For wet seal oil degassing vents in operating-mode, determine 
vapor volumes at standard conditions, using a temporary meter such as a 
vane anemometer or permanent flow meter according to methods set forth 
in Sec.  98.234(b).
    (3) Methods for continuous leak measurement from individual 
centrifugal compressor sources. If you elect to conduct continuous 
volumetric emission measurements for an individual compressor source as 
specified in paragraph (o)(1)(ii) of this section, you must measure 
volumetric emissions as specified in paragraphs (o)(3)(i) and 
(o)(3)(ii) of this section.
    (i) Continuously measure the volumetric flow for the individual 
compressor source at standard conditions using a permanent meter 
according to methods set forth in Sec.  98.234(b).
    (ii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (o)(3)(i) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the compressor source and do not need to

[[Page 13437]]

be calculated separately using the method specified in paragraph (i) of 
this section for blowdown vent stacks.
    (4) Methods for performing as found leak measurements from 
manifolded groups of centrifugal compressor sources. If conducting leak 
measurements for a manifolded group of compressor sources, you must 
measure volumetric emissions of leaks as specified in paragraphs 
(o)(4)(i) and (o)(4)(ii) of this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and where emissions cannot be comingled with other 
non-compressor emission sources.
    (ii) Determine the volumetric flow at standard conditions from the 
common stack using one of the methods specified in paragraphs 
(o)(4)(ii)(A) through (o)(4)(ii)(C) of this section.
    (A) A temporary meter such as a vane anemometer according the 
methods set forth in Sec.  98.234(b).
    (B) Calibrated bagging according to methods set forth in Sec.  
98.234(c).
    (C) A high volume sampler according to methods set forth Sec.  
98.234(d).
    (5) Methods for continuous leak measurement from manifolded groups 
of centrifugal compressor sources. If you elect to conduct continuous 
volumetric emission measurements for a manifolded group of compressor 
sources as specified in paragraph (o)(1)(iv) of this section, you must 
measure volumetric emissions as specified in paragraphs (o)(5)(i) 
through (o)(5)(iii) of this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and where emissions cannot be comingled with other 
non-compressor emission sources.
    (ii) Continuously measure the volumetric flow for the manifolded 
group of compressor sources at standard conditions using a permanent 
meter according to methods set forth in Sec.  98.234(b).
    (iii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (o)(5)(ii) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the manifolded group of compressor sources and do not 
need to be calculated separately using the method specified in 
paragraph (i) of this section for blowdown vent stacks.
    (6) Method for calculating volumetric GHG emissions from as found 
leak measurements for individual centrifugal compressor sources. For 
compressor sources measured according to paragraph (o)(1)(i) of this 
section, you must calculate annual GHG emissions from the compressor 
sources as specified in paragraphs (o)(6)(i) through (o)(6)(iv) of this 
section.
    (i) Using Equation W-21 of this section, calculate the annual 
volumetric GHG emissions for each centrifugal compressor mode-source 
combination specified in paragraphs (o)(1)(i)(A) and (o)(1)(i)(B) of 
this section that was measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TP10MR14.024

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or 
CO2) emissions for measured compressor mode-source 
combination m, at standard conditions, in cubic feet.
MTs,m = Volumetric gas emissions for measured compressor 
mode-source combination m, in standard cubic feet per hour, measured 
according to paragraph (o)(2) of this section. If multiple 
measurements are performed for a given mode-source combination m, 
use the average of all measurements.
Tm = Total time the compressor is in the mode-source 
combination for which Es,i,m is being calculated in the 
reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas for 
measured compressor mode-source combination m; use the appropriate 
gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph 
(o)(1)(i)(A) or (o)(1)(i)(B) of this section that was measured for 
the reporting year.

    (ii) Using Equation W-22 of this section, calculate the annual 
volumetric GHG emissions from each centrifugal compressor mode-source 
combination specified in paragraph (o)(1)(i)(A) and (o)(1)(i)(B) of 
this section that was not measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TP10MR14.025

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or 
CO2) emissions for unmeasured compressor mode-source 
combination m, at standard conditions, in cubic feet.
EFm,s = Reporter emission factor for compressor mode-
source combination m, in standard cubic feet per hour, as calculated 
in paragraph (o)(6)(iii) of this section.
Tm = Total time the compressor was in the unmeasured 
mode-source combination m, for which Es,i,m is being 
calculated in the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas 
for unmeasured compressor mode-source combination m; use the 
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph 
(o)(1)(i)(A) or (o)(1)(i)(B) of this section that was not measured 
in the reporting year.

    (iii) Using Equation W-23 of this section, develop an emission 
factor for each compressor mode-source combination specified in 
paragraph (o)(1)(i)(A) and (o)(1)(i)(B) of this section. These emission 
factors must be used in Equation W-22 of this section to determine 
volumetric emissions from a centrifugal compressor in the mode-source 
combinations that were not measured in the reporting year.
[GRAPHIC] [TIFF OMITTED] TP10MR14.026


[[Page 13438]]


Where:

EFm,s = Reporter emission factor to be used in Equation 
W-22 of this section for compressor mode-source combination m, in 
standard cubic feet per hour. The reporter emission factor must be 
based on all compressors measured in compressor mode-source 
combination m in the current reporting year and the preceding two 
reporting years.
MTm,p,s = Average volumetric gas emission measurement for 
compressor mode-source combination m, for compressor p, in standard 
cubic feet per hour, calculated using all volumetric gas emission 
measurements (MTm in Equation W-21 of this section) for compressor 
mode-source combination m for compressor p in the current reporting 
year and the preceding two reporting years.
Countm = Total number of compressors measured in 
compressor mode-source combination m in the current reporting year 
and the preceding two reporting years.
m = Compressor mode-source combination specified in paragraph 
(o)(1)(i)(A) or (o)(1)(i)(B) of this section.

    (iv) The reporter emission factor in Equation W-23 of this section 
may be calculated by using all measurements from a single owner or 
operator instead of only using measurements from a single facility. If 
you elect to use this option, the reporter emission factor must be 
applied to all reporting facilities for the owner or operator.
    (7) Method for calculating volumetric GHG emissions from continuous 
monitoring of individual centrifugal compressor sources. For compressor 
sources measured according to paragraph (o)(1)(ii) of this section, you 
must use the continuous volumetric emission measurements taken as 
specified in paragraph (o)(3) of this section and calculate annual 
volumetric GHG emissions associated with the compressor source using 
Equation W-24A of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.027

Where:

Es,i,v = Annual volumetric GHGi (either CH4 or 
CO2) emissions from compressor source v, at standard 
conditions, in cubic feet.
Qs,v = Volumetric gas emissions from compressor source v, 
for reporting year, in standard cubic feet.
GHGi,v = Mole fraction of GHGi in the vent gas for 
compressor source v; use the appropriate gas compositions in 
paragraph (u)(2) of this section.

    (8) Method for calculating volumetric GHG emissions from as found 
leak measurements of manifolded groups of centrifugal compressor 
sources. For manifolded groups of compressor sources measured according 
to paragraph (o)(1)(iii) of this section, you must calculate annual 
volumetric GHG emissions using Equation W-24B of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.028

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or 
CO2) emissions for manifolded group of compressor sources 
g, at standard conditions, in cubic feet.
MTg,avg = Average volumetric gas emissions of all 
measurements performed in the reporting year according to paragraph 
(o)(4) of this section for the manifolded group of compressor 
sources g, in standard cubic feet per hour.
GHGi,g = Mole fraction of GHGi in the vent gas for 
manifolded group of compressor sources g; use the appropriate gas 
compositions in paragraph (u)(2) of this section.

    (9) Method for calculating volumetric GHG emissions from continuous 
monitoring of manifolded group of centrifugal compressor sources. For a 
manifolded group of compressor sources measured according to paragraph 
(o)(1)(iv) of this section, you must use the continuous volumetric 
emission measurements taken as specified in paragraph (o)(5) of this 
section and calculate annual volumetric GHG emissions associated with 
each manifolded group of compressor sources using Equation W-24C of 
this section. If the centrifugal compressors included in the manifolded 
group of compressor sources share the manifold with reciprocating 
compressors, you must follow the procedures in either this paragraph 
(o)(9) or paragraph (p)(9) of this section to calculate emissions from 
the manifolded group of compressor sources.
[GRAPHIC] [TIFF OMITTED] TP10MR14.029

Where:

Es,i,g = Annual volumetric GHGi (either CH4 or 
CO2) emissions from manifolded group of compressor 
sources g, at standard conditions, in cubic feet.
Qs,g = Volumetric gas emissions from manifolded group of 
compressor sources g, for reporting year, in standard cubic feet.
GHGi,g = Mole fraction of GHGi in the vent gas for 
measured manifolded group of compressor sources g; use the 
appropriate gas compositions in paragraph (u)(2) of this section.

    (10) Method for calculating volumetric GHG emissions from wet seal 
oil degassing vents at an onshore petroleum and natural gas production 
facility. You must calculate emissions from centrifugal compressor wet 
seal oil degassing vents at an onshore petroleum and natural gas 
production facility using Equation W-25 of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.030

Where:

Es,i = Annual volumetric GHGi (either CH4 or 
CO2) emissions from centrifugal compressor wet seals, at 
standard conditions, in cubic feet.
Count = Total number of centrifugal compressors that have wet seal 
oil degassing vents.

[[Page 13439]]

EFi,s = Emission factor for GHGi. Use 1.2 x 107 standard 
cubic feet per year per compressor for CH4 and 5.30 x 105 
standard cubic feet per year per compressor for CO2 at 60 
[deg]F and 14.7 psia.

    (11) Method for converting from volumetric to mass emissions. You 
must calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (12) General requirements for calculating volumetric GHG emissions 
from centrifugal compressors routed to flares. You must calculate and 
report emissions from all centrifugal compressor sources that are 
routed to a flare as specified in paragraphs (o)(12)(i) through 
(o)(12)(iii) of this section.
    (i) Emissions calculations under this paragraph (o) of this section 
are not required for compressor sources that are routed to a flare.
    (ii) If any compressor sources are routed to a flare, calculate the 
emissions for the flare stack as specified in paragraph (n) of this 
section and report emissions from the flare as specified in Sec.  
98.236(n), without subtracting emissions attributable to compressor 
sources from the flare.
    (iii) Report all applicable activity data for compressors with 
compressor sources routed to flares as specified in Sec.  98.236(o).
    (p) Reciprocating compressor venting. If you are required to report 
emissions from reciprocating compressor venting as specified in Sec.  
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct 
volumetric emission measurements specified in paragraph (p)(1) of this 
section using methods specified in paragraphs (p)(2) through (p)(5) of 
this section; perform calculations specified in paragraphs (p)(6) 
through (p)(9) of this section; and calculate CH4 and 
CO2 mass emissions as specified in paragraph (p)(11) of this 
section. If emissions from a compressor source are routed to a flare, 
paragraphs (p)(1) through (p)(11) of this section do not apply and 
instead you must calculate CH4, CO2, and 
N2O emissions as specified in paragraph (p)(12) of this 
section. If emissions from a compressor source are captured for fuel 
use or are routed to a thermal oxidizer, paragraphs (p)(1) through 
(p)(12) of this section do not apply and instead you must calculate and 
report emissions as specified in subpart C of this part. If emissions 
from a compressor source are routed to vapor recovery, the calculations 
specified in paragraphs (p)(1) through (p)(12) of this section do not 
apply. If you are required to report emissions from reciprocating 
compressor venting at an onshore petroleum and natural gas production 
facility as specified in Sec.  98.232(c)(11), you must calculate 
volumetric emissions as specified in paragraph (p)(10) of this section; 
and calculate CH4 and CO2 mass emissions as 
specified in paragraph (p)(11) of this section.
    (1) General requirements for conducting volumetric emission 
measurements. You must conduct volumetric emission measurements on each 
reciprocating compressor as specified in this paragraph. Compressor 
sources (as defined in Sec.  98.238) without manifolded vents must use 
a measurement method specified in paragraph (p)(1)(i) or (p)(1)(ii) of 
this section. Manifolded compressor sources (as defined in Sec.  
98.238) must use a measurement method specified in paragraph (p)(1)(i), 
(p)(1)(ii), (p)(1)(iii), or (p)(1)(iv) of this section.
    (i) Reciprocating compressor source as found leak measurements. 
Measure venting from each compressor according to either paragraph 
(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section at least 
once annually, based on the compressor mode (as defined in Sec.  
98.238) in which the compressor was found at the time of measurement, 
except as specified in paragraph (p)(1)(i)(D) of this section. If 
additional measurements beyond the required annual testing are 
performed (including duplicate measurements or measurement of 
additional operating modes), then all measurements satisfying the 
applicable monitoring and QA/QC that is required by this paragraph (o) 
must be used in the calculations specified in this section.
    (A) For a compressor measured in operating-mode, you must measure 
volumetric emissions from blowdown valve leakage through the blowdown 
vent as specified in either paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of 
this section, and measure volumetric emissions from reciprocating rod 
packing as specified in paragraph (p)(2)(ii) of this section.
    (B) For a compressor measured in standby-pressurized-mode, you must 
measure volumetric emissions from blowdown valve leakage through the 
blowdown vent as specified in either paragraph (p)(2)(i)(A) or 
(p)(2)(i)(B) of this section.
    (C) For a compressor measured in not-operating-depressurized-mode, 
you must measure volumetric emissions from isolation valve leakage as 
specified in either paragraph (p)(2)(i)(A), (p)(2)(i)(B), or 
(p)(2)(i)(C) of this section. If a compressor is not operated and has 
blind flanges in place throughout the reporting period, measurement is 
not required in this compressor mode.
    (D) You must measure the compressor as specified in paragraph 
(p)(1)(i)(C) of this section at least once in any three consecutive 
calendar years, provided the measurement can be taken during a 
scheduled shutdown. If there is no scheduled shutdown within three 
consecutive calendar years, you must measure the compressor as 
specified in paragraph (p)(1)(i)(C) of this section either prior to or 
during the next compressor shutdown when the replacement of the 
compressor rod packing occurs.
    (ii) Reciprocating compressor source continuous monitoring. Instead 
of measuring the compressor source according to paragraph (p)(1)(i) of 
this section for a given compressor, you may elect to continuously 
measure volumetric emissions from a compressor source as specified in 
paragraph (p)(3) of this section.
    (iii) Manifolded reciprocating compressor source as found leak 
measurements. For a compressor source that is part of a manifolded 
group of compressor sources (as defined in Sec.  98.238), instead of 
measuring the compressor source according to paragraph (p)(1)(i), 
(p)(1)(ii), or (p)(1)(iv) of this section, you may elect to measure 
combined volumetric emissions from the manifolded group of compressor 
sources by conducting leak measurements at the common vent stack as 
specified in paragraph (p)(4) of this section. The leak measurements 
must be conducted at the frequency specified in paragraphs 
(p)(1)(iii)(A) through (p)(1)(iii)(C) of this section.
    (A) A minimum of three leak measurements must be taken for each 
manifolded group of compressor sources in a calendar year.
    (B) The leak measurements may be performed while the compressors 
are in any compressor mode.
    (C) The three required leak measurements must be separated by a 
minimum of 60 days. If more than three leak measurements are performed, 
the first and last measurements in a calendar year must be separated by 
a minimum of 120 days.
    (iv) Manifolded reciprocating compressor source continuous 
monitoring. For a compressor source that is part of a manifolded group 
of compressor sources, instead of measuring the compressor source 
according to paragraph (p)(1)(i), (p)(1)(ii), or (p)(1)(iii) of this 
section, you may elect to continuously measure combined volumetric 
emissions from the manifolded group of compressors sources as specified 
in paragraph (p)(5) of this section.

[[Page 13440]]

    (2) Methods for performing as found leak measurements from 
individual reciprocating compressor sources. If conducting leak 
measurements for each compressor source, you must determine the 
volumetric emissions of leaks from blowdown valves and isolation valves 
as specified in paragraph (p)(2)(i) of this section. You must determine 
the volumetric emissions of leaks from reciprocating rod packing as 
specified in paragraph (p)(2)(ii) or (p)(2)(iii) of this section.
    (i) For blowdown valves on compressors in operating-mode or 
standby-pressurized-mode, and for isolation valves on compressors in 
not-operating-depressurized-mode, determine the volumetric emissions of 
leaks using one of the methods specified in paragraphs (p)(2)(i)(A) 
through (p)(2)(i)(C) of this section.
    (A) Measure the volumetric flow at standard conditions from the 
blowdown vent using calibrated bagging or high volume sampler according 
to methods set forth in Sec.  98.234(c) and Sec.  98.234(d), 
respectively.
    (B) Measure the volumetric flow at standard conditions from the 
blowdown vent using a temporary meter such as a vane anemometer, 
according to methods set forth in Sec.  98.234(b).
    (C) For isolation valves, you may use an acoustic leak detection 
device according to methods set forth in Sec.  98.234(a) instead of 
measuring the isolation valve leakage through the blowdown vent as 
provided for in paragraphs (p)(2)(i)(A) or (p)(2)(i)(B) of this 
section.
    (ii) For reciprocating rod packing equipped with an open-ended vent 
line on compressors in operating-mode, determine the volumetric 
emissions of leaks using one of the methods specified in paragraphs 
(p)(2)(ii)(A) and (p)(2)(ii)(B) of this section.
    (A) Measure the volumetric flow at standard conditions from the 
open-ended vent line using calibrated bagging or high volume sampler 
according to methods set forth in Sec.  98.234(c) and Sec.  98.234(d), 
respectively.
    (B) Measure the volumetric flow at standard conditions from the 
open-ended vent line using a temporary meter such as a vane anemometer, 
according to methods set forth in Sec.  98.234(b).
    (iii) For reciprocating rod packing not equipped with an open-ended 
vent line on compressors in operating-mode, you must determine the 
volumetric emissions of leaks using the method specified in paragraphs 
(p)(2)(iii)(A) and (p)(2)(iii)(B) of this section.
    (A) You must use the methods described in Sec.  98.234(a) to 
conduct annual leak detection of equipment leaks from the packing case 
into an open distance piece, or from the compressor crank case breather 
cap or other vent with a closed distance piece.
    (B) You must measure emissions found in paragraph (p)(2)(iii)(A) of 
this section using an appropriate meter, calibrated bag, or high volume 
sampler according to methods set forth in Sec.  98.234(b), (c), and 
(d), respectively.
    (3) Methods for continuous leak measurement from individual 
reciprocating compressor sources. If you elect to conduct continuous 
volumetric emission measurements for an individual compressor source as 
specified in paragraph (p)(1)(ii) of this section, you must measure 
volumetric emissions as specified in paragraphs (p)(3)(i) and 
(p)(3)(ii) of this section.
    (i) Continuously measure the volumetric flow for the individual 
compressor sources at standard conditions using a permanent meter 
according to methods set forth in Sec.  98.234(b).
    (ii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (p)(3)(i) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the compressor source and do not need to be calculated 
separately using the method specified in paragraph (i) of this section 
for blowdown vent stacks.
    (4) Methods for performing as found leak measurements from 
manifolded groups of reciprocating compressor sources. If conducting 
leak measurements for a manifolded group of compressor sources, you 
must measure volumetric emissions of leaks as specified in paragraphs 
(p)(4)(i) and (p)(4)(ii) of this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and where emissions cannot be comingled with other 
non-compressor emission sources.
    (ii) Determine the volumetric flow at standard conditions from the 
common stack using one of the methods specified in paragraph 
(p)(4)(ii)(A) through (p)(4)(ii)(C).
    (A) A temporary meter such as a vane anemometer according the 
methods set forth in Sec.  98.234(b).
    (B) Calibrated bagging according to methods set forth in Sec.  
98.234(c).
    (C) A high volume sampler according to methods set forth Sec.  
98.234(d).
    (5) Methods for continuous leak measurement from manifolded groups 
of reciprocating compressor sources. If you elect to conduct continuous 
volumetric emission measurements for a manifolded group of compressor 
sources as specified in paragraph (p)(1)(iv) of this section, you must 
measure volumetric emissions as specified in paragraphs (p)(5)(i) 
through (p)(5)(iii) of this section.
    (i) Measure at a single point in the manifold downstream of all 
compressor inputs and where emissions cannot be comingled with other 
non-compressor emission sources.
    (ii) Continuously measure the volumetric flow for the manifolded 
group of compressor sources at standard conditions using a permanent 
meter according to methods set forth in Sec.  98.234(b).
    (iii) If compressor blowdown emissions are included in the metered 
emissions specified in paragraph (p)(5)(ii) of this section, the 
compressor blowdown emissions may be included with the reported 
emissions for the manifolded group of compressor sources and do not 
need to be calculated separately using the method specified in 
paragraph (i) of this section for blowdown vent stacks.
    (6) Method for calculating volumetric GHG emissions from as found 
leak measurements for individual reciprocating compressor sources. For 
compressor sources measured according to paragraph (p)(1)(i) of this 
section, you must calculate GHG emissions from the compressor sources 
as specified in paragraphs (p)(6)(i) through (p)(6)(iv) of this 
section.
    (i) Using Equation W-26 of this section, calculate the annual 
volumetric GHG emissions for each reciprocating compressor mode-source 
combination specified in paragraphs (p)(1)(i)(A) through (p)(1)(i)(C) 
of this section that was measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TP10MR14.031

Where:

Es,i,m = Annual volumetric GHGi (either CH4 or 
CO2) emissions for measured compressor mode-source 
combination m, at standard conditions, in cubic feet.
MTs,m = Volumetric gas emissions for measured compressor 
mode-source combination m, in standard cubic feet

[[Page 13441]]

per hour, measured according to paragraph (p)(2) of this section. If 
multiple measurements are performed for a given mode-source 
combination m, use the average of all measurements.
Tm = Total time the compressor is in the mode-source 
combination m, for which Es,i,m is being calculated in 
the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas 
for measured compressor mode-source combination m; use the 
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph 
(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was 
measured for the reporting year.

    (ii) Using Equation W-27 of this section, calculate the annual 
volumetric GHG emissions from each reciprocating compressor mode-source 
combination specified in paragraph (p)(1)(i)(A), (p)(1)(i)(B), and 
(p)(1)(i)(C) of this section that was not measured during the reporting 
year.
[GRAPHIC] [TIFF OMITTED] TP10MR14.032

Where:
Es,i,m = Annual volumetric GHGi (either 
CH4 or CO2) emissions for unmeasured 
compressor mode-source combination m, at standard conditions, in 
cubic feet.
EFm,s = Reporter emission factor for compressor mode-
source combination m, in standard cubic feet per hour, as calculated 
in paragraph (p)(6)(iii) of this section.
Tm = Total time the compressor was in the unmeasured 
mode-source combination m, for which Es,i,m is being 
calculated in the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas 
for unmeasured compressor mode-source combination m; use the 
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph 
(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was 
not measured in the reporting year.

    (iii) Using Equation W-28 of this section, develop an emission 
factor for each compressor mode-source combination specified in 
paragraph (p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section. 
These emission factors must be used in Equation W-27 of this section to 
determine volumetric emissions from a reciprocating compressor in the 
mode-source combinations that were not measured in the reporting year.
[GRAPHIC] [TIFF OMITTED] TP10MR14.033

Where:
EFm,s = Reporter emission factor to be used in Equation 
W-27 of this section for compressor mode-source combination m, in 
standard cubic feet per hour. The reporter emission factor must be 
based on all compressors measured in compressor mode-source 
combination m in the current reporting year and the preceding two 
reporting years.
MTm,p,s = Average volumetric gas emission measurement for 
compressor mode-source combination m, for compressor p, in standard 
cubic feet per hour, calculated using all volumetric gas emission 
measurements (MTm in Equation W-26 of this section) for compressor 
mode-source combination m for compressor p in the current reporting 
year and the preceding two reporting years.
Countm = Total number of compressors measured in 
compressor mode-source combination m in the current reporting year 
and the preceding two reporting years.
m = Compressor mode-source combination specified in paragraph 
(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section.

    (A) Emission factors must be calculated annually for each 
compressor mode-source combination specified in paragraph 
((p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) of this section.
    (B) You must combine emissions for blowndown vents, measured in the 
operating and standby-pressurized modes.
    (iv) The reporter emission factor in Equation W-28 of this section 
may be calculated by using all measurements from a single owner or 
operator instead of only using measurements from a single facility. If 
you elect to use this option, the reporter emission factor must be 
applied to all reporting facilities for the owner or operator.
    (7) Method for calculating volumetric GHG emissions from continuous 
monitoring of individual reciprocating compressor sources. For 
compressor sources measured according to paragraph (p)(1)(ii) of this 
section, you must use the continuous volumetric emission measurements 
taken as specified in paragraph (p)(3) of this section and calculate 
annual volumetric GHG emissions associated with the compressor source 
using Equation W-29A of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.034

Where:
Es,i,v = Annual volumetric GHGi (either 
CH4 or CO2) emissions from compressor source 
v, at standard conditions, in cubic feet.
Qs,v = Volumetric gas emissions from compressor source v, 
for reporting year, in standard cubic feet.
GHGi,v = Mole fraction of GHGi in the vent gas 
for compressor source v; use the appropriate gas compositions in 
paragraph (u)(2) of this section.

    (8) Method for calculating volumetric GHG emissions from as found 
leak measurements of manifolded groups of reciprocating compressor 
sources. For manifolded groups of compressor sources measured according 
to paragraph (p)(1)(iii) of this section, you must calculate annual GHG 
emissions using Equation W-29B of this section.

[[Page 13442]]

[GRAPHIC] [TIFF OMITTED] TP10MR14.035

Where:
Es,i,g = Annual volumetric GHGi (either 
CH4 or CO2) emissions for manifolded group of 
compressor sources g, at standard conditions, in cubic feet.
MTg,avg = Average volumetric gas emissions of all 
measurements performed in the reporting year according to paragraph 
(p)(4) of this section for the manifolded group of compressor 
sources g, in standard cubic feet per hour.
GHGi,g = Mole fraction of GHGi in the vent gas 
for manifolded group of compressor sources g; use the appropriate 
gas compositions in paragraph (u)(2) of this section.

    (9) Method for calculating volumetric GHG emissions from continuous 
monitoring of manifolded group of reciprocating compressor sources. For 
a manifolded group of compressor sources measured according to 
paragraph (p)(1)(iv) of this section, you must use the continuous 
volumetric emission measurements taken as specified in paragraph (p)(5) 
of this section and calculate annual volumetric GHG emissions 
associated with each manifolded group of compressor sources using 
Equation W-29C of this section. If the reciprocating compressors 
included in the manifolded group of compressor sources share the 
manifold with centrifugal compressors, you must follow the procedures 
in either this paragraph (p)(9) or paragraph (o)(9) of this section to 
calculate emissions from the manifolded group of compressor sources.
[GRAPHIC] [TIFF OMITTED] TP10MR14.036

Where:
Es,i,g = Annual volumetric GHGi (either 
CH4 or CO2) emissions from manifolded group of 
compressor sources g, at standard conditions, in cubic feet.
Qs,g = Volumetric gas emissions from manifolded group of 
compressor sources g, for reporting year, in standard cubic feet.
GHGi,g = Mole fraction of GHGi in the vent gas 
for measured manifolded group of compressor sources g; use the 
appropriate gas compositions in paragraph (u)(2) of this section.

    (10) Method for calculating volumetric GHG emissions from 
reciprocating compressor venting at an onshore petroleum and natural 
gas production facility. You must calculate emissions from 
reciprocating compressor venting at an onshore petroleum and natural 
gas production facility using Equation W-29D of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.037

Where:

Es,i = Annual volumetric GHGi (either 
CH4 or CO2) emissions from reciprocating 
compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors.
EFi,s = Emission factor for GHGi. Use 9.48 x 
10³ standard cubic feet per year per compressor for 
CH4 and 5.27 x 10² standard cubic feet per 
year per compressor for CO2 at 60 [deg]F and 14.7 psia.

    (11) Method for converting from volumetric to mass emissions. You 
must calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (12) General requirements for calculating volumetric GHG emissions 
from reciprocating compressors routed to flares. You must calculate and 
report emissions from all reciprocating compressor sources that are 
routed to a flare as specified in paragraphs (p)(12)(i) through 
(p)(12)(iii) of this section.
    (i) Emissions calculations under this paragraph (p) of this section 
are not required for compressor sources that are routed to a flare.
    (ii) If any compressor sources are routed to a flare, calculate the 
emissions for the flare stack as specified in paragraph (n) of this 
section and report emissions from the flare as specified in Sec.  
98.236(n), without subtracting emissions attributable to compressor 
sources from the flare.
    (iii) Report all applicable activity data for compressors with 
compressor sources routed to flares as specified in Sec.  98.236(p).
    (q) Equipment leak surveys. You must use the methods described in 
Sec.  98.234(a) to conduct leak detection(s) of equipment leaks from 
all component types listed in Sec.  98.232(d)(7), (e)(7), (f)(5), 
(g)(3), (h)(4), and (i)(1). This paragraph (q) applies to component 
types in streams with gas content greater than 10 percent 
CH4 plus CO2 by weight. Component types in 
streams with gas content less than or equal to 10 percent 
CH4 plus CO2 by weight are exempt from the 
requirements of this paragraph (q) and do not need to be reported. 
Tubing systems equal to or less than one half inch diameter are exempt 
from the requirements of this paragraph (q) and do not need to be 
reported. For industry segments listed in Sec.  98.230(a)(3) through 
(a)(8), if equipment leaks are detected for component types listed in 
this paragraph (q), then you must calculate equipment leak emissions 
per component type per reporting facility using Equations W-30 of this 
section. For the industry segment listed in Sec.  98.230(a)(8), the 
results from Equation W-30 are used to calculate population emission 
factors on a meter/regulator run basis using Equation W-31 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.038

Where:

Es,p,i = Annual total volumetric emissions of 
GHGi from specific component type ``p'' (listed in Sec.  
98.232(d)(7), (e)(7), (f)(5), (g)(3), (h)(4), and (i)(1)) in 
standard (``s'')

[[Page 13443]]

cubic feet, as specified in paragraphs (q)(1) through (q)(8) of this 
section.
xp = Total number of specific component type ``p'' 
detected as leaking during annual leak surveys.
EFs,p = Leaker emission factor for specific component 
types listed in Table W-2 through Table W-7 of this subpart.
GHGi = For onshore natural gas processing facilities, 
concentration of GHGi, CH4 or CO2, 
in the total hydrocarbon of the feed natural gas; for onshore 
natural gas transmission compression and underground natural gas 
storage, GHGi equals 0.975 for CH4 and 1.1 x 
10^-2 for CO2 ; for LNG storage and LNG import 
and export equipment, GHGi equals 1 for CH4 
and 0 for CO2 ; and for natural gas distribution, 
GHGi equals 1 for CH4 and 1.1 x 
10^-2 CO2.
Tp,z = The total time the surveyed component ``z'', 
component type ``p'', was found leaking and operational, in hours. 
If one leak detection survey is conducted in the calendar year, 
assume the component was leaking for the entire calendar year, 
accounting for time the component was not operational (i.e. not 
operating under pressure) using engineering estimate based on best 
available data. If multiple leak detection surveys are conducted in 
the calendar year, assume that the component found to be leaking has 
been leaking since the previous survey (if not found leaking in the 
previous survey) or the beginning of the calendar year (if it was 
found leaking in the previous survey), accounting for time the 
component was not operational using engineering estimate based on 
best available data. For the last leak detection survey in the 
calendar year, assume that all leaking components continue to leak 
until the end of the calendar year, accounting for time the 
component was not operational using engineering estimate based on 
best available data.

    (1) You must conduct either one leak detection survey in a calendar 
year or multiple complete leak detection surveys in a calendar year. 
The leak detection surveys selected must be conducted during the 
calendar year.
    (2) Calculate both CO2 and CH4 mass emissions 
using calculations in paragraph (v) of this section.
    (3) Onshore natural gas processing facilities must use the 
appropriate default total hydrocarbon leaker emission factors for 
compressor components in gas service and non-compressor components in 
gas service listed in Table W-2 of this subpart.
    (4) Onshore natural gas transmission compression facilities must 
use the appropriate default total hydrocarbon leaker emission factors 
for compressor components in gas service and non-compressor components 
in gas service listed in Table W-3 of this subpart.
    (5) Underground natural gas storage facilities must use the 
appropriate default total hydrocarbon leaker emission factors for 
storage stations in gas service listed in Table W-4 of this subpart.
    (6) LNG storage facilities must use the appropriate default methane 
leaker emission factors for LNG storage components in gas service 
listed in Table W-5 of this subpart.
    (7) LNG import and export facilities must use the appropriate 
default methane leaker emission factors for LNG terminals components in 
LNG service listed in Table W-6 of this subpart.
    (8) Natural gas distribution facilities must use Equation W-30 of 
this section and the default methane leaker emission factors for 
transmission-distribution transfer station components in gas service 
listed in Table W-7 of this subpart to calculate component emissions 
from annual equipment leak surveys conducted at above grade 
transmission-distribution transfer stations. Natural gas distribution 
facilities are required to perform equipment leak surveys only at above 
grade stations that qualify as transmission-distribution transfer 
stations. Below grade transmission-distribution transfer stations and 
all metering-regulating stations that do not meet the definition of 
transmission-distribution transfer stations are not required to perform 
equipment leak surveys under this section.
    (i) Natural gas distribution facilities may choose to conduct 
equipment leak surveys at all above grade transmission-distribution 
transfer stations over multiple years, not exceeding a five year period 
to cover all above grade transmission-distribution transfer stations. 
If the facility chooses to use the multiple year option, then the 
number of transmission-distribution transfer stations that are 
monitored in each year should be approximately equal across all years 
in the cycle.
    (ii) Use Equation W-31 to determine the meter/regulator run 
population emission factors for each GHGi. The meter/
regulator run population emission factors calculated using Equation W-
31 must be used in Equation W-32B of this section to estimate emissions 
from above grade metering-regulating stations that are not 
transmission-distribution transfer stations. As additional survey data 
become available, you must recalculate the meter/regulator run 
population emission factors for each GHGi annually according 
to paragraph (q)(8)(iii) of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.039

Where:

EFs,MR,i = Meter/regulator run population emission factor 
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic 
feet of GHGi per operational hour of all meter/regulator 
runs.
Es,p,i,y = Annual total volumetric emissions at standard 
conditions of GHGi from component type ``p'' during year 
``y'' in standard (``s'') cubic feet, as calculated using Equation 
W-30 of this section.
p = Seven component types listed in Table W-7 of this subpart for 
transmission-distribution transfer stations.
Tw,y = The total time the surveyed meter/regulator run 
``w'' was operational, in hours during survey year ``y'' using 
engineering estimate based on best available data.
CountMR,y = Count of meter/regulator runs surveyed at 
above grade transmission-distribution transfer stations in year 
``y''.
y = Year of data included in emission factor ``EFs,MR,i'' 
according to paragraph (q)(8)(iii) of this section.
n = Number of years of data used to calculate emission factor 
``EFs,MR,i'' according to paragraph (q)(8)(iii) of this 
section.

    (iii) The emission factor ``EFs,MR,i'', based on annual 
equipment leak surveys at above grade transmission-distribution 
transfer stations, must be calculated annually. If the facility has 
submitted a smaller number of annual reports than the duration of the 
selected cycle period (up to 5 years), then all available data from the 
current year and previous years must be used in the emission

[[Page 13444]]

calculation. After the first cycle is completed, the survey will 
continue on a rolling basis by including the measurements from the 
current calendar year and as many of the previous calendar years as are 
needed to complete the survey cycle.
    (r) Equipment leaks by population count. This paragraph applies to 
emissions sources listed in Sec.  98.232 (c)(21), (f)(5), (g)(3), 
(h)(4), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(6) on streams with gas 
content greater than 10 percent CH4 plus CO2 by 
weight. Emissions sources in streams with gas content less than or 
equal to 10 percent CH4 plus CO2 by weight are 
exempt from the requirements of this paragraph (q) do not need to be 
reported. Tubing systems equal to or less than one half inch diameter 
are exempt from the requirements of paragraph (r) of this section and 
do not need to be reported. You must calculate emissions from all 
emission sources listed in this paragraph using Equation W-32A of this 
section, except for natural gas distribution facility emission sources 
listed in Sec.  98.232(i)(3). Natural gas distribution facility 
emission sources listed in Sec.  98.232(i)(3) must calculate emissions 
using Equation W-32B and according to paragraph (r)(6) of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.040

Where:
Es,e,i = Annual volumetric emissions of GHGi 
from the emission source type in standard cubic feet. The emission 
source type may be a component (e.g. connector, open-ended line, 
etc.), below grade metering-regulating station, below grade 
transmission-distribution transfer station, distribution main, or 
distribution service.
Es,MR,i = Annual volumetric emissions of GHGi 
from all meter/regulator runs at above grade metering regulating 
stations that are not above grade transmission distribution transfer 
stations, in standard cubic feet.
Counte = Total number of the emission source type at the 
facility. For onshore petroleum and natural gas production 
facilities, average component counts are provided by major equipment 
piece in Tables W-1B and Table W-1C of this subpart. Use average 
component counts as appropriate for operations in Eastern and 
Western U.S., according to Table W-1D of this subpart. Underground 
natural gas storage facilities must count each component listed in 
Table W-4 of this subpart. LNG storage facilities must count the 
number of vapor recovery compressors. LNG import and export 
facilities must count the number of vapor recovery compressors. 
Natural gas distribution facilities must count: (1) The number of 
distribution services by material type; (2) miles of distribution 
mains by material type; and (3) number of below grade metering-
regulating stations, by pressure type; as listed in Table W-7 of 
this subpart.
CountMR = Total number of meter/regulator runs at above grade 
metering-regulating stations that are not above grade transmission-
distribution transfer stations.
EFs,e = Population emission factor for the specific 
emission source type, as listed in Tables W-1A and W-4 through W-7 
of this subpart. Use appropriate population emission factor for 
operations in Eastern and Western U.S., according to Table W-1D of 
this subpart.
EFs,MR,i = Meter/regulator run population emission factor 
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic 
feet of GHGi per operational hour of all meter/regulator 
runs., as determined in Equation W-31.
GHGi = For onshore petroleum and natural gas production 
facilities, concentration of GHGi, CH4, or 
CO2, in produced natural gas as defined in paragraph 
(u)(2) of this section; for onshore natural gas transmission 
compression and underground natural gas storage, GHGi 
equals 0.975 for CH4 and 1.1 x 10^-2 for 
CO2; for LNG storage and LNG import and export equipment, 
GHGi equals 1 for CH4 and 0 for 
CO2; and for natural gas distribution, GHGi 
equals 1 for CH4 and 1.1 x 10^-2CO2.
Te = Average estimated time that each emission source 
type associated with the equipment leak emission was operational in 
the calendar year, in hours, using engineering estimate based on 
best available data.
Tw,avg = Average estimated time that each meter/regulator 
run was operational in the calendar year, in hours per meter/
regulator run, using engineering estimate based on best available 
data.

    (1) Calculate both CH4 and CO2 mass emissions 
from volumetric emissions using calculations in paragraph (v) of this 
section.
    (2) Onshore petroleum and natural gas production facilities must 
use the appropriate default whole gas population emission factors 
listed in Table W-1A of this subpart. Major equipment and components 
associated with gas wells are considered gas service components in 
reference to Table W-1A of this subpart and major natural gas equipment 
in reference to Table W-1B of this subpart. Major equipment and 
components associated with crude oil wells are considered crude service 
components in reference to Table W-1A of this subpart and major crude 
oil equipment in reference to Table W-1C of this subpart. Where 
facilities conduct EOR operations the emissions factor listed in Table 
W-1A of this subpart shall be used to estimate all streams of gases, 
including recycle CO2 stream. The component count can be 
determined using either of the calculation methods described in this 
paragraph (r)(2). The same calculation method must be used for the 
entire calendar year.
    (i) Component Count Method 1. For all onshore petroleum and natural 
gas production operations in the facility perform the following 
activities:
    (A) Count all major equipment listed in Table W-1B and Table W-1C 
of this subpart. For meters/piping, use one meters/piping per well-pad.
    (B) Multiply major equipment counts by the average component counts 
listed in Table W-1B and W-1C of this subpart for onshore natural gas 
production and onshore oil production, respectively. Use the 
appropriate factor in Table W-1A of this subpart for operations in 
Eastern and Western U.S. according to the mapping in Table W-1D of this 
subpart.
    (ii) Component Count Method 2. Count each component individually 
for the facility. Use the appropriate factor in Table W-1A of this 
subpart for operations in Eastern and Western U.S. according to the 
mapping in Table W-1D of this subpart.
    (3) Underground natural gas storage facilities must use the 
appropriate default total hydrocarbon population emission factors for 
storage wellheads in gas service listed in Table W-4 of this subpart.
    (4) LNG storage facilities must use the appropriate default methane 
population emission factor for LNG storage compressors in gas service 
listed in Table W-5 of this subpart.
    (5) LNG import and export facilities must use the appropriate 
default methane population emission factor for LNG terminal compressors 
in gas service listed in Table W-6 of this subpart.

[[Page 13445]]

    (6) Natural gas distribution facilities must use the appropriate 
methane emission factors as described in paragraph (r)(6) of this 
section.
    (i) Below grade metering-regulating stations, distribution mains, 
and distribution services must use the appropriate default methane 
population emission factors listed in Table W-7 of this subpart. Below 
grade transmission-distribution transfer stations must use the emission 
factor for below grade metering-regulating stations.
    (ii) Above grade metering-regulating stations (that are not above 
grade transmission-distribution transfer stations) must use the meter/
regulator run population emission factor calculated in Equation W-31. 
Natural gas distribution facilities that do not have above grade 
transmission-distribution transfer stations are not required to 
calculate emissions for above grade metering-regulating stations.
    (s) * * *
    (2) Offshore production facilities that are not under BOEMRE 
jurisdiction must use the most recent monitoring methods and 
calculation methods published by BOEMRE referenced in 30 CFR 250.302 
through 304 to calculate and report annual emissions (GOADS).
    (i) For any calendar year that does not overlap with the most 
recent BOEMRE emissions study publication, you may report the most 
recently reported emissions data submitted to demonstrate compliance 
with this subpart of part 98, with emissions adjusted based on the 
operating time for the facility relative to operating time in the 
previous reporting period.
* * * * *
    (3) If BOEMRE discontinues or delays their data collection effort 
by more than 4 years, then offshore reporters shall once in every 4 
years use the most recent BOEMRE data collection and emissions 
estimation methods to estimate emissions. These emission estimates 
would be used to report emissions from the facility sources as required 
in paragraph (s)(1)(i) of this section.
    (4) For either first or subsequent year reporting, offshore 
facilities either within or outside of BOEMRE jurisdiction that were 
not covered in the previous BOEMRE data collection cycle must use the 
most recent BOEMRE data collection and emissions estimation methods 
published by BOEMRE referenced in 30 CFR 250.302 through 304 to 
calculate and report emissions.
    (t) GHG volumetric emissions using actual conditions. If equation 
parameters in Sec.  98.233 are already at standard conditions, which 
results in volumetric emissions at standard conditions, then this 
paragraph does not apply. Calculate volumetric emissions at standard 
conditions as specified in paragraphs (t)(1) or (2) of this section, 
with actual pressure and temperature determined by engineering 
estimates based on best available data unless otherwise specified.
    (1) * * *
    [GRAPHIC] [TIFF OMITTED] TP10MR14.041
    
* * * * *
Za = Compressibility factor at actual conditions for natural gas. 
You may use 1 if the temperature is above -10 degrees Fahrenheit and 
pressure is below 5 atmospheres, or if the compressibility factor at 
the actual temperature and pressure is 0.98 or greater.

    (2) * * *
    [GRAPHIC] [TIFF OMITTED] TP10MR14.042
    
* * * * *
Za = Compressibility factor at actual conditions for GHG i. You may 
use 1 if the compressibility factor at the actual temperature and 
pressure is 0.98 or greater.
* * * * *
    (u) GHG volumetric emissions at standard conditions. Calculate GHG 
volumetric emissions at standard conditions as specified in paragraphs 
(u)(1) and (2) of this section.
    (2) * * *
    (iii) GHG mole fraction in transmission pipeline natural gas that 
passes through the facility for the onshore natural gas transmission 
compression industry segment. You may use either a default 95 percent 
methane and 1 percent carbon dioxide fraction for GHG mole fraction in 
natural gas or site specific engineering estimates based on best 
available data.
* * * * *
    (v) GHG mole fraction in natural gas stored in the LNG storage 
industry segment. You may use either a default 95 percent methane and 1 
percent carbon dioxide fraction for GHG mole fraction in natural gas or 
site specific engineering estimates based on best available data.
    (vi) GHG mole fraction in natural gas stored in the LNG import and 
export industry segment. For export facilities that receive gas from 
transmission pipelines, you may use either a default 95 percent methane 
and 1 percent carbon dioxide fraction for GHG mole fraction in natural 
gas or site specific engineering estimates based on best available 
data.
    (vii) GHG mole fraction in local distribution pipeline natural gas 
that passes through the facility for natural gas distribution 
facilities. You may use a default 95 percent methane and 1 percent 
carbon dioxide fraction for GHG mole fraction in natural gas or site 
specific engineering estimates based on best available data.
    (v) GHG mass emissions. Calculate GHG mass emissions in metric tons 
by converting the GHG volumetric emissions at standard conditions into 
mass emissions using Equation W-36 of this section.
[GRAPHIC] [TIFF OMITTED] TP10MR14.043


[[Page 13446]]


Where:

Massi = GHGi (either CH4, 
CO2, or N2O) mass emissions in metric tons.
Es,i = GHGi (either CH4, 
CO2, or N2O) volumetric emissions at standard 
conditions, in cubic feet.
Pi = Density of GHGi. Use 0.0526 kg/ft\3\ for 
CO2 and N2O, and 0.0192 kg/ft\3\ for 
CH4 at 60 [deg]F and 14.7 psia.

    (w) EOR injection pump blowdown. Calculate CO2 pump 
blowdown emissions from each EOR injection pump system as follows:
    (1) Calculate the total injection pump system volume in cubic feet 
(including pipelines, manifolds and vessels) between isolation valves.
* * * * *
    (3) Calculate the total annual CO2 emissions from each 
EOR injection pump system using Equation W-37 of this section:
* * * * *
MassCO2 = Annual EOR injection pump system emissions in 
metric tons from blowdowns.
N = Number of blowdowns for the EOR injection pump system in the 
calendar year.
Vv = Total volume in cubic feet of EOR injection pump 
system chambers (including pipelines, manifolds and vessels) between 
isolation valves.
* * * * *
    (x) EOR hydrocarbon liquids dissolved CO2. Calculate CO2 
emissions downstream of the storage tank from dissolved CO2 
in hydrocarbon liquids produced through EOR operations as follows:
    (1) Determine the amount of CO2 retained in hydrocarbon 
liquids after flashing in tankage at STP conditions. Annual samples of 
hydrocarbon liquids downstream of the storage tank must be taken 
according to methods set forth in Sec.  98.234(b) to determine 
retention of CO2 in hydrocarbon liquids immediately 
downstream of the storage tank. Use the annual analysis for the 
calendar year.
    (2) * * *
* * * * *
    Shl = Amount of CO2 retained in 
hydrocarbon liquids downstream of the storage tank, in metric tons 
per barrel, under standard conditions.
* * * * *
    (z) * * *
    (1) If a fuel combusted in the stationary or portable equipment is 
listed in Table C-1 of subpart C of this part, or is a blend containing 
one or more fuels listed in Table C-1, calculate emissions according to 
paragraph (z)(1)(i) of this section. If the fuel combusted is natural 
gas and is of pipeline quality specification and has a minimum high 
heat value of 950 Btu per standard cubic foot, use the calculation 
method described in paragraph (z)(1)(i) of this section and you may use 
the emission factor provided for natural gas as listed in Table C-1. If 
the fuel is natural gas, and is not pipeline quality or has a high heat 
value of less than 950 Btu per standard cubic feet, calculate emissions 
according to paragraph (z)(2) of this section. If the fuel is field 
gas, process vent gas, or a blend containing field gas or process vent 
gas, calculate emissions according to paragraph (z)(2) of this section.
    (i) For fuels listed in Table C-1 or a blend containing one or more 
fuels listed in Table C-1, calculate CO2, CH4, 
and N2O emissions according to any Tier listed in subpart C 
of this part. You must follow all applicable calculation requirements 
for that tier listed in Sec.  98.33, any monitoring or QA/QC 
requirements listed for that tier in Sec.  98.34, any missing data 
procedures specified in Sec.  98.35, and any recordkeeping requirements 
specified in Sec.  98.37.
    (ii) Emissions from fuel combusted in stationary or portable 
equipment at onshore natural gas and petroleum production facilities 
and at natural gas distribution facilities will be reported according 
to the requirements specified in Sec.  98.236(c)(19) and not according 
to the reporting requirements specified in subpart C of this part.
    (2) * * *
    (iii) * * *
* * * * *
Va = Volume of gas sent to combustion unit in actual 
cubic feet, during the year.
YCO2 = Mole fraction of CO2 constituent in gas 
sent to combustion unit.
* * * * *
Yj = Mole fraction of gas hydrocarbon constituents j 
(such as methane, ethane, propane, butane, and pentanes plus) in gas 
sent to combustion unit.
* * * * *
YCH4 = Mole fraction of methane constituent in gas sent 
to combustion unit.
* * * * *
    (vi) * * *
    [GRAPHIC] [TIFF OMITTED] TP10MR14.044
    
* * * * *

MassN2O = Annual N2O emissions from the 
combustion of a particular type of fuel (metric tons).
Fuel = Annual mass or volume of the fuel combusted (mass or volume 
per year, choose appropriately to be consistent with the units of 
HHV).
HHV = Higher heating value of fuel, mmBtu/unit of fuel (in units 
consistent with the fuel quantity combusted). For the higher heating 
value for field gas or process vent gas, use 1.235 x 10^-3 
mmBtu/scf for HHV.

0
6. Section 98.234 is amended by:
0
a. Revising paragraphs (a) introductory text and (d)(1);
0
b. Removing and reserving paragraph (f); and
0
c. Adding paragraph (h).
    The revisions read as follows:


Sec.  98.234  Monitoring and QA/QC requirements.

* * * * *
    (a) You must use any of the methods described as follows in this 
paragraph to conduct leak detection(s) of equipment leaks and through-
valve leakage from all source types listed in Sec.  98.233(k), (o), (p) 
and (q) that occur during a calendar year.
    (d) * * *
    (1) A technician following manufacturer instructions shall conduct 
measurements, including equipment manufacturer operating procedures and 
measurement methods relevant to using a high volume sampler, including 
positioning the instrument for complete capture of the equipment leak 
without creating backpressure on the source.
* * * * *
    (h) For well venting for liquids unloading, if a monitoring period 
other than the full calendar year is used to determine the cumulative 
amount of time in hours of venting for each well (the term 
``Tp'' in Equation W-7A and W-7B of Sec.  98.233) or the 
number of unloading events per well (the term ``Vp'' in 
Equations W-8 and W-9 of Sec.  98.233), then the monitoring period must 
begin before February 1 of the reporting year and must not end before 
December 1 of the reporting year. The end of one monitoring period must 
immediately precede the start of the next monitoring period for the 
next reporting year. All production days must be monitored and all 
venting accounted for.
0
7. Section 98.235 is revised to read as follows:

[[Page 13447]]

Sec.  98.235  Procedures for estimating missing data.

    Except as specified in Sec.  98.233, whenever a value of a 
parameter is unavailable for a GHG emission calculation required by 
this subpart (including, but not limited to, if a measuring device 
malfunctions during unit operation, a required gas sample is not taken, 
or activity data are not collected), you must follow the procedures 
specified in paragraphs (a) through (h) of this section, as applicable.
    (a) If you choose to take quarterly gas samples as allowed in Sec.  
98.233(d) in lieu of using a continuous gas analyzer, and there is a 
missing sample, you must substitute the average value of the last four 
samples for which data are available.
    (b) If you did not conduct monitoring as specified in Sec.  
98.233(k) for a transmission storage tank(s), you must assume the vent 
stack(s) connected to the transmission storage tank(s) was leaking for 
the entire calendar year.
    (c) For stationary and portable combustion sources that use the 
calculation methods of subpart C of this part, you must use the missing 
data procedures in subpart C of this part.
    (d) For each missing value of a parameter that should have been 
measured using a continuous flow meter, composition analyzer, 
thermocouple, or pressure gauge, you must substitute the arithmetic 
average of the quality-assured values of that parameter immediately 
preceding and immediately following the missing data incident. If the 
``after'' value is not obtained by the end of the reporting year, you 
may use the ``before'' value for the missing data substitution. If, for 
a particular parameter, no quality-assured data are available prior to 
the missing data incident, you must use the first quality-assured value 
obtained after the missing data period as the substitute data value. A 
value is quality-assured according to the procedures specified in Sec.  
98.234.
    (e) For the first six months of required data collection, 
facilities that become newly subject to this subpart W may use best 
engineering estimates for any data that cannot reasonably be measured 
or obtained according to the requirements of this subpart.
    (f) For the first six months of required data collection, 
facilities that are currently subject to this subpart W and that 
acquire new wells that were not previously subject to this subpart W 
may use best engineering estimates for any data related to those newly 
acquired wells that cannot reasonably be measured or obtained according 
to the requirements of this subpart.
    (g) For each missing value of any activity data not described in 
this section, you must substitute data value(s) using the best 
available estimate(s) of the parameter(s), based on all available 
process data (including, but not limited to, processing rates, 
operating hours).
    (h) You must report information for all measured and substitute 
values of a parameter, and the procedures used to substitute an 
unavailable value of a parameter per the requirements in Sec.  
98.236(bb).
0
8. Section 98.236 is revised to read as follows:


Sec.  98.236  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain reported emissions and related information 
as specified in this section.
    (a) The annual report must include the information specified in 
paragraphs (a)(1) through (8) of this section for each applicable 
industry segment. The annual report must also include annual emissions 
totals, in metric tons of CO2e of each GHG, for each 
applicable industry segment listed in paragraphs (a)(1) through (a)(8) 
of this section, and each applicable emission source listed in 
paragraphs (b) through (z) of this section.
    (1) Onshore petroleum and natural gas production. For the 
equipment/activities specified in paragraphs (a)(1)(i) through 
(a)(1)(xvii) of this section, report the information specified in the 
applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Natural gas driven pneumatic pumps. Report the information 
specified in paragraph (c) of this section.
    (iii) Acid gas removal units. Report the information specified in 
paragraph (d) of this section.
    (iv) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (v) Liquids unloading. Report the information specified in 
paragraph (f) of this section.
    (vi) Completions and workovers with hydraulic fracturing. Report 
the information specified in paragraph (g) of this section.
    (vii) Completions and workovers without hydraulic fracturing. 
Report the information specified in paragraph (h) of this section.
    (viii) Onshore production storage tanks. Report the information 
specified in paragraph (j) of this section.
    (ix) Well testing. Report the information specified in paragraph 
(l) of this section.
    (x) Associated natural gas. Report the information specified in 
paragraph (m) of this section.
    (xi) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (xii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (xiii) Reciprocating compressors. Report the information specified 
in paragraph (p) of this section.
    (xiv) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (xv) EOR injection pumps. Report the information specified in 
paragraph (w) of this section.
    (xvi) EOR hydrocarbon liquids. Report the information specified in 
paragraph (x) of this section.
    (xvii) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (2) Offshore petroleum and natural gas production. Report the 
information specified in paragraph (s) of this section.
    (3) Onshore natural gas processing. For the equipment/activities 
specified in paragraphs (a)(3)(i) through (a)(3)(vii) of this section, 
report the information specified in the applicable paragraphs of this 
section.
    (i) Acid gas removal units. Report the information specified in 
paragraph (d) of this section.
    (ii) Dehydrators. Report the information specified in paragraph (e) 
of this section.
    (iii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (iv) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (v) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (4) Onshore natural gas transmission compression. For the 
equipment/activities specified in paragraphs (a)(4)(i) through 
(a)(4)(vii) of this section, report the information specified in the 
applicable paragraphs of this section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.

[[Page 13448]]

    (iii) Transmission storage tanks. Report the information specified 
in paragraph (k) of this section.
    (iv) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (v) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (vi) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (vii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (5) Underground natural gas storage. For the equipment/activities 
specified in paragraphs (a)(5)(i) through (a)(5)(vi) of this section, 
report the information specified in the applicable paragraphs of this 
section.
    (i) Natural gas pneumatic devices. Report the information specified 
in paragraph (b) of this section.
    (ii) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (iii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (6) LNG storage. For the equipment/activities specified in 
paragraphs (a)(6)(i) through (a)(6)(v) of this section, report the 
information specified in the applicable paragraphs of this section.
    (i) Flare stacks. Report the information specified in paragraph (n) 
of this section.
    (ii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (iii) Reciprocating compressors. Report the information specified 
in paragraph (p) of this section.
    (iv) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (v) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (7) LNG import and export equipment. For the equipment/activities 
specified in paragraphs (a)(7)(i) through (a)(7)(vi) of this section, 
report the information specified in the applicable paragraphs of this 
section.
    (i) Blowdown vent stacks. Report the information specified in 
paragraph (i) of this section.
    (ii) Flare stacks. Report the information specified in paragraph 
(n) of this section.
    (iii) Centrifugal compressors. Report the information specified in 
paragraph (o) of this section.
    (iv) Reciprocating compressors. Report the information specified in 
paragraph (p) of this section.
    (v) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (vi) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (8) Natural gas distribution. For the equipment/activities 
specified in paragraphs (a)(8)(i) through (a)(8)(iii) of this section, 
report the information specified in the applicable paragraphs of this 
section.
    (i) Combustion equipment. Report the information specified in 
paragraph (z) of this section.
    (ii) Equipment leak surveys. Report the information specified in 
paragraph (q) of this section.
    (iii) Equipment leaks by population count. Report the information 
specified in paragraph (r) of this section.
    (b) Natural gas pneumatic devices. You must indicate whether the 
facility contains the following types of equipment: continuous high 
bleed natural gas pneumatic devices, continuous low bleed natural gas 
pneumatic devices, and intermittent bleed natural gas pneumatic 
devices. If the facility contains any continuous high bleed natural gas 
pneumatic devices, continuous low bleed natural gas pneumatic devices, 
or intermittent bleed natural gas pneumatic devices, then you must 
report the information specified in paragraphs (b)(1) through (b)(4) of 
this section.
    (1) The number of natural gas pneumatic devices as specified in 
paragraphs (b)(1)(i) and (b)(1)(ii) of this section.
    (i) The total number of devices, determined according to Sec.  
98.233(a)(1) and (a)(2).
    (ii) If the reported value in paragraph (b)(1)(i) of this section 
is an estimated value determined according to Sec.  98.233(a)(2), then 
you must report the information specified in paragraphs (b)(1)(ii)(A) 
through (b)(1)(ii)(C) of this section.
    (A) The number of devices reported in paragraph (b)(1)(i) of this 
section that are counted.
    (B) The number of devices reported in paragraph (b)(1)(i) of this 
section that are estimated (not counted).
    (C) Whether the calendar year is the first calendar year of 
reporting or the second calendar year of reporting.
    (2) Estimated average number of hours in the calendar year that the 
natural gas pneumatic devices reported in paragraph (b)(1)(i) of this 
section were operating in the calendar year (``Tt'' in Equation W-1 of 
this subpart).
    (3) Annual CO2 emissions, in metric tons CO2, 
for the natural gas pneumatic devices combined, calculated using 
Equation W-1 of this subpart and Sec.  98.233(a)(4), and reported in 
paragraph (b)(1)(i) of this section.
    (4) Annual CH4 emissions, in metric tons CH4, 
for the natural gas pneumatic devices combined, calculated using 
Equation W-1 of this subpart and Sec.  98.233(a)(4), and reported in 
paragraph (b)(1)(i) of this section.
    (c) Natural gas driven pneumatic pumps. You must indicate whether 
the facility has any natural gas driven pneumatic pumps. If the 
facility contains any natural gas driven pneumatic pumps, then you must 
report the information specified in paragraphs (c)(1) through (c)(4) of 
this section.
    (1) Count of natural gas driven pneumatic pumps.
    (2) Average estimated number of hours in the calendar year the 
pumps were operational (``T'' in Equation W-2 of this subpart).
    (3) Annual CO2 emissions, in metric tons CO2, 
for all natural gas driven pneumatic pumps combined, calculated 
according to Sec.  98.233(c)(1) and (c)(2).
    (4) Annual CH4 emissions, in metric tons CH4, 
for all natural gas driven pneumatic pumps combined, calculated 
according to Sec.  98.233(c)(1) and (c)(2).
    (d) Acid gas removal units. You must indicate whether your facility 
has any acid gas removal units that vent directly to the atmosphere, to 
a flare or engine, or to a sulfur recovery plant. If your facility 
contains any acid gas removal units that vent directly to the 
atmosphere, to a flare or engine, or to a sulfur recovery plant, then 
you must report the information specified in paragraphs (d)(1) and 
(d)(2) of this section.
    (1) You must report the information specified in paragraphs 
(d)(1)(i) through (d)(1)(vi) of this section for each acid gas removal 
unit.
    (i) A unique name or ID number for the acid gas removal unit. For 
the onshore petroleum and natural gas production industry segment, a 
different name or ID may be used for a single acid gas removal unit for 
each location it operates at in a given year.
    (ii) Total feed rate entering the acid gas removal unit, using a 
meter or engineering estimate based on process knowledge or best 
available data, in million cubic feet per year.

[[Page 13449]]

    (iii) The calculation method used to calculate CO2 
emissions from the acid gas removal unit, as specified in Sec.  
98.233(d).
    (iv) Whether any CO2 emissions from the acid gas removal 
unit are recovered and transferred outside the facility, as specified 
in Sec.  98.233(d)(11). If any CO2 emissions from the acid 
gas removal unit were recovered and transferred outside the facility, 
then you must report the annual quantity of CO2, in metric 
tons CO2, that was recovered and transferred outside the 
facility.
    (v) Annual CO2 emissions, in metric tons CO2, 
from the acid gas removal unit, calculated using any one of the 
calculation methods specified in Sec.  98.233(d) and as specified in 
Sec.  98.233(d)(10) and (11).
    (vi) Sub-basin ID (for the onshore petroleum and natural gas 
production industry segment only).
    (2) You must report information specified in paragraphs (d)(2)(i) 
through (d)(2)(iii) of this section, applicable to the calculation 
method reported in paragraph (d)(1)(iii) of this section, for each acid 
gas removal unit.
    (i) If you used Calculation Method 1 or Calculation Method 2 as 
specified in Sec.  98.233(d) to calculate CO2 emissions from 
the acid gas removal unit, then you must report the information 
specified in paragraphs (d)(2)(i)(A) and (d)(2)(i)(B) of this section.
    (A) Annual average volumetric fraction of CO2 in the 
vent gas exiting the acid gas removal unit.
    (B) Annual volume of gas vented from the acid gas removal unit, in 
cubic feet.
    (ii) If you used Calculation Method 3 as specified in Sec.  
98.233(d) to calculate CO2 emissions from the acid gas 
removal unit, then you must report the information specified in 
paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(D) of this section.
    (A) Which equation was used; Equation W-4A or W-4B.
    (B) Annual average volumetric fraction of CO2 in the 
natural gas flowing out of the acid gas removal unit, as specified in 
Equation W-4A or Equation W-4B of this subpart.
    (C) Annual average volumetric fraction of CO2 content in 
natural gas flowing into the acid gas removal unit, as specified in 
Equation W-4A or Equation W-4B of this subpart.
    (D) The natural gas flow rate used, as specified in Equation W-4A 
of this subpart, reported as either total annual volume of natural gas 
flow into the acid gas removal unit in cubic feet at actual conditions; 
or total annual volume of natural gas flow out of the acid gas removal 
unit, as specified in Equation W-4B of this subpart, in cubic feet at 
actual conditions,.
    (iii) If you used Calculation Method 4 as specified in Sec.  
98.233(d) to calculate CO2 emissions from the acid gas 
removal unit, then you must report the information specified in 
paragraphs (d)(2)(iii)(A) through (d)(2)(iii)(L) of this section, as 
applicable to the simulation software package used.
    (A) The name of the simulation software package used.
    (B) Natural gas feed temperature, in degrees Fahrenheit.
    (C) Natural gas feed pressure, in pounds per square inch.
    (D) Natural gas flow rate, in standard cubic feet per minute.
    (E) Acid gas content of the feed natural gas, in mole percent.
    (F) Acid gas content of the outlet natural gas, in mole percent.
    (G) Unit operating hours, excluding downtime for maintenance or 
standby, in hours per year.
    (H) Exit temperature of the natural gas, in degrees Fahrenheit.
    (I) Solvent pressure, in pounds per square inch.
    (J) Solvent temperature, in degrees Fahrenheit.
    (K) Solvent circulation rate, in gallons per minute.
    (L) Solvent weight, in pounds per gallon.
    (e) Dehydrators. You must indicate whether your facility contains 
any of the following equipment: absorbent dehydrators with an annual 
average daily natural gas throughput greater than or equal to 0.4 
million standard cubic feet per day, glycol dehydrators with an annual 
average daily natural gas throughput less than 0.4 million standard 
cubic feet per day, and dehydrators that use desiccant. If your 
facility contains any of the equipment listed in this paragraph (e), 
then you must report the applicable information in paragraphs (e)(1) 
through (e)(3).
    (1) For each absorbent dehydrator that has an annual average daily 
natural gas throughput greater than or equal to 0.4 million standard 
cubic feet per day (as specified in Sec.  98.233(e)(1)), you must 
report the information specified in paragraphs (e)(1)(i) through 
(e)(1)(xviii) of this section for the dehydrator.
    (i) A unique name or ID number for the dehydrator. For the onshore 
petroleum and natural gas production industry segment, a different name 
or ID may be used for a single dehydrator for each location it operates 
at in a given year.
    (ii) Dehydrator feed natural gas flow rate, in million standard 
cubic feet per day, determined by engineering estimate based on best 
available data.
    (iii) Dehydrator feed natural gas water content, in pounds per 
million standard cubic feet.
    (iv) Dehydrator outlet natural gas water content, in pounds per 
million standard cubic feet.
    (v) Dehydrator absorbent circulation pump type (e.g., natural gas 
pneumatic, air pneumatic, or electric).
    (vi) Dehydrator absorbent circulation rate, in gallons per minute.
    (vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene 
glycol (DEG), or ethylene glycol (EG)).
    (viii) Whether stripper gas is used in dehydrator.
    (ix) Whether a flash tank separator is used in dehydrator.
    (x) Total time the dehydrator is operating, in hours.
    (xi) Temperature of the wet natural gas, in degrees Fahrenheit.
    (xii) Pressure of the wet natural gas, in pounds per square inch 
gauge.
    (xiii) Mole fraction of CH4 in wet natural gas.
    (xiv) Mole fraction of CO2 in wet natural gas.
    (xv) Whether any dehydrator emissions are vented to a vapor 
recovery device.
    (xvi) Whether any dehydrator emissions are vented to a flare or 
regenerator firebox/fire tubes. If any emissions are vented to a flare 
or regenerator firebox/fire tubes, report the information specified in 
paragraphs (e)(1)(xvi)(A) through (e)(1)(xvi)(C) of this section for 
these emissions from the dehydrator.
    (A) Annual CO2 emissions, in metric tons CO2, 
for the dehydrator, calculated according to Sec.  98.233(e)(6).
    (B) Annual CH4 emissions, in metric tons CH4, 
for the dehydrator, calculated according to Sec.  98.233(e)(6).
    (C) Annual N2O emissions, in metric tons N2O, 
for the dehydrator, calculated according to Sec.  98.233(e)(6).
    (xvii) Whether any dehydrator emissions are vented to the 
atmosphere without being routed to a flare or regenerator firebox/fire 
tubes. If any emissions are not routed to a flare or regenerator 
firebox/fire tubes, then you must report the information specified in 
paragraphs (e)(1)(xvii)(A) and (e)(1)(xvii)(B) of this section for 
those emissions from the dehydrator.
    (A) Annual CO2 emissions, in metric tons CO2, 
for the dehydrator when not venting to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1) and (e)(5).
    (B) Annual CH4 emissions, in metric tons CH4, 
for the dehydrator when not venting to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(1) and (e)(5).

[[Page 13450]]

    (xviii) Sub-basin ID (for the onshore petroleum and natural gas 
production industry segment only).
    (2) For glycol dehydrators with an annual average daily natural gas 
throughput less than 0.4 million standard cubic feet per day (as 
specified in Sec.  98.233(e)(2)), you must report the information 
specified in paragraphs (e)(2)(i) through (e)(2)(v) of this section for 
the entire facility.
    (i) The total number of dehydrators at the facility.
    (ii) Whether any dehydrators reported in paragraph (e)(2)(i) of 
this section were vented to a vapor recovery device. If any dehydrators 
reported in paragraph (e)(2)(i) of this section were vented to a vapor 
recovery device, then you must report the total number of dehydrators 
at the facility that vented to a vapor recovery device.
    (iii) Whether any dehydrators reported in paragraph (e)(2)(i) of 
this section were vented to a control device other than a vapor 
recovery device or a flare or regenerator firebox/fire tubes. If any 
dehydrators reported in paragraph (e)(2)(i) of this section were vented 
to a control device other than a vapor recovery device or a flare or 
regenerator firebox/fire tubes, then you must specify the type of 
control device and the number of dehydrators at the facility that were 
vented to each type of control device.
    (iv) Whether any dehydrators reported in paragraph (e)(2)(i) of 
this section were vented to a flare or regenerator firebox/fire tubes. 
If any dehydrators reported in paragraph (e)(2)(i) of this section were 
vented to a flare or regenerator firebox/fire tubes, then you must 
report the information specified in paragraphs (e)(2)(iv)(A) through 
(e)(2)(iv)(D) of this section.
    (A) The total number of dehydrators venting to a flare or 
regenerator firebox/fire tubes.
    (B) Annual CO2 emissions, in metric tons CO2, 
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this 
section, calculated according to Sec.  98.233(e)(6).
    (C) Annual CH4 emissions, in metric tons CH4, 
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this 
section, calculated according to Sec.  98.233(e)(6).
    (D) Annual N2O emissions, in metric tons N2O, 
for the dehydrators reported in paragraph (e)(2)(iv)(A) of this 
section, calculated according to Sec.  98.233(e)(6).
    (v) For dehydrators reported in paragraph (e)(2)(i) of this section 
that were not vented to a flare or regenerator firebox/fire tubes, 
report the information specified in paragraphs (e)(2)(v)(A) and 
(e)(2)(v)(B) of this section.
    (A) Annual CO2 emissions in metric tons CO2, 
for emissions from all dehydrators reported in paragraph (e)(2)(i) of 
this section that were not vented to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2), (e)(4), and 
(e)(5), where emissions are added together for all such dehydrators.
    (B) Annual CH4 emissions in metric tons CO2, 
for emissions from all dehydrators reported in paragraph (e)(2)(i) of 
this section that were not vented to a flare or regenerator firebox/
fire tubes, calculated according to Sec.  98.233(e)(2), (e)(4), and 
(e)(5), where emissions are added together for all such dehydrators.
    (3) For dehydrators that use desiccant (as specified in Sec.  
98.233(e)(3)), you must report the information specified in paragraphs 
(e)(3)(i) through (e)(3)(iii) of this section for the entire facility.
    (i) The same information specified in paragraphs (e)(2)(i) through 
(e)(2)(iv) of this section for glycol dehydrators, and report the 
information under this paragraph for dehydrators that use desiccant.
    (ii) Annual CO2 emissions, in metric tons 
CO2, for emissions from all desiccant dehydrators reported 
under paragraph (e)(3)(i) of this section that are not venting to a 
flare or regenerator firebox/fire tubes, calculated according to Sec.  
98.233(e)(3), (e)(4), and (e)(5), and summing for all such dehydrators.
    (iii) Annual CH4 emissions, in metric tons 
CH4, for emissions from all desiccant dehydrators reported 
in paragraph (e)(3)(i) of this section that are not venting to a flare 
or regenerator firebox/fire tubes, calculated according to Sec.  
98.233(e)(3), (e)(4), and (e)(5), and summing for all such dehydrators.
    (f) Liquids unloading. You must indicate whether well venting for 
liquids unloading occurs at your facility, and if so, which methods (as 
specified in Sec.  98.233(f)) were used to calculate emissions. If your 
facility performs well venting for liquids unloading and uses 
Calculation Method 1, then you must report the information specified in 
paragraph (f)(1) of this section. If the facility performs liquids 
unloading and uses Calculation Method 2 or 3, then you must report the 
information specified in paragraph (f)(2) of this section.
    (1) For each sub-basin and well tubing diameter and pressure 
grouping for which you used Calculation Method 1 to calculate natural 
gas emissions from well venting for liquids unloading, report the 
information specified in paragraphs (f)(1)(i) through (f)(1)(xii) of 
this section. Report information separately for wells with plunger 
lifts and wells without plunger lifts.
    (i) Sub-basin ID.
    (ii) Well tubing diameter and pressure group ID.
    (iii) Plunger lift indicator.
    (iv) Count of wells vented to the atmosphere for the sub-basin/well 
tubing diameter and pressure grouping.
    (v) Percentage of wells for which the monitoring period used to 
determine the cumulative amount of time venting was not the full 
calendar year.
    (vi) Cumulative amount of time wells were vented (sum of 
``Tp'' from Equation W-7A or W-7B of this subpart), in 
hours.
    (vii) Cumulative number of unloadings vented to the atmosphere for 
each well, aggregated across all wells in the sub-basin/well tubing 
diameter and pressure grouping.
    (viii) Annual natural gas emissions, in standard cubic feet, from 
well venting for liquids unloading, calculated according to Sec.  
98.233(f)(1).
    (ix) Annual CO2 emissions, in metric tons 
CO2, from well venting for liquids unloading, calculated 
according to Sec.  98.233(f)(1) and Sec.  98.233(f)(4).
    (x) Annual CH4 emissions, in metric tons CH4, 
from well venting for liquids unloading, calculated according to Sec.  
98.233(f)(1) and Sec.  98.233(f)(4).
    (xi) For each well tubing diameter group and pressure group 
combination, you must report the information specified in paragraphs 
(f)(1)(xi)(A) through (f)(1)(xi)(E) of this section for each individual 
well not using a plunger lift that was tested during the year.
    (A) API number of tested well.
    (B) Casing pressure, in pounds per square inch absolute.
    (C) Internal casing diameter, in inches.
    (D) Measured depth of the well, in feet.
    (E) Average flow rate of the well venting over the duration of the 
liquids unloading, in standard cubic feet per hour.
    (xii) For each well tubing diameter group and pressure group 
combination, you must report the information specified in paragraphs 
(f)(1)(xii)(A) through (f)(1)(xii)(E) of this section for each 
individual well using a plunger lift that was tested during the year.
    (A) The API well number.
    (B) The tubing pressure, in pounds per square inch absolute.
    (C) The internal tubing diameter, in inches.
    (D) Measured depth of the well, in feet.
    (E) Average flow rate of the well venting over the duration of the 
liquids unloading, in standard cubic feet per hour.
    (2) For each sub-basin for which you used Calculation Method 2 or 3 
(as

[[Page 13451]]

specified in Sec.  93.233(f)) to calculate natural gas emissions from 
well venting for liquids unloading, you must report the information in 
(f)(2)(i) through (f)(2)(x) of this section. Report information 
separately for each calculation method.
    (i) Sub-basin ID.
    (ii) Calculation method.
    (iii) Plunger lift indicator.
    (iv) Number of wells vented to the atmosphere.
    (v) Cumulative number of unloadings vented to the atmosphere for 
each well, aggregated across all wells.
    (vi) Annual natural gas emissions, in standard cubic feet, from 
well venting for liquids unloading, calculated according to Sec.  
98.233(f)(2) or Sec.  98.233(f)(3), as applicable.
    (vii) Annual CO2 emissions, in metric tons 
CO2, from well venting for liquids unloading, calculated 
according to Sec.  98.233(f)(2) or Sec.  98.233(f)(3), as applicable, 
and Sec.  98.233(f)(4).
    (viii) Annual CH4 emissions, in metric tons 
CH4, from well venting for liquids unloading, calculated 
according to Sec.  98.233(f) (2) or Sec.  98.233(f)(3), as applicable, 
and Sec.  98.233(f)(4).
    (ix) For wells without plunger lifts, the average internal casing 
diameter, in inches.
    (x) For wells with plunger lifts, the average internal tubing 
diameter, in inches.
    (g) Completions and workovers with hydraulic fracturing. You must 
indicate whether your facility had any gas well completions or 
workovers with hydraulic fracturing during the calendar year. If your 
facility had gas well completions or workovers with hydraulic 
fracturing during the calendar year, then you must report information 
specified in paragraphs (g)(1) through (g)(10) of this section, for 
each sub-basin and well type combination. Report information separately 
for completions and workovers.
    (1) Sub-basin ID.
    (2) Well type.
    (3) Number of completions or workovers in the category.
    (4) Calculation method used.
    (5) If you used Equation W-10A to calculate annual volumetric total 
gas emissions, then you must report the information specified in 
paragraphs (g)(5)(i) and (g)(5)(ii) of this section.
    (i) Cumulative backflow time, in hours, for each sub-basin 
(``Tp'' in Equation W-10A).
    (ii) Measured flowback rate, in standard cubic feet per hour, for 
each sub-basin (``FRs,p'' in Equation W-12A).
    (6) If you used Equation W-10B to calculate annual volumetric total 
gas emissions for completions that vent gas to the atmosphere, then you 
must report the vented natural gas volume, in standard cubic feet, for 
each well in the sub-basin (``FVs,p'' in Equation W-10B).
    (7) Annual gas emissions, in standard cubic feet 
(``Es,n'' in Equation W-10A or W-10B).
    (8) Annual CO2 emissions, in metric tons CO2.
    (9) Annual CH4 emissions, in metric tons CH4.
    (10) If the well emissions were vented to a flare, then you must 
report the total N2O emissions, in metric tons 
N2O.
    (h) Completions and workovers without hydraulic fracturing. You 
must indicate whether the facility had any gas well completions without 
hydraulic fracturing or any gas well workovers without hydraulic 
fracturing, and if the activities occurred with or without flaring. If 
the facility had gas well completions or workovers without hydraulic 
fracturing, then you must report the information specified in 
paragraphs (h)(1) through (h)(4) of this section, as applicable.
    (1) For each sub-basin with gas well completions without hydraulic 
fracturing and without flaring, report the information specified in 
paragraphs (h)(1)(i) through (h)(1)(vi) of this section.
    (i) Sub-basin ID.
    (ii) Number of well completions that vented gas directly to the 
atmosphere without flaring.
    (iii) Total number of hours that gas vented directly to the 
atmosphere during backflow for all completions in the sub-basin 
category (the sum of all ``Tp'' for completions that vented 
to the atmosphere as used in Equation W-13B).
    (iv) Average daily gas production rate for all completions without 
hydraulic fracturing in the sub-basin without flaring, in standard 
cubic feet per hour (average of all ``Vp'' used in Equation 
W-13B).
    (v) Annual CO2 emissions, in metric tons CO2, 
that resulted from completions venting gas directly to the atmosphere 
(``Es,p'' from Equation W-13B for completions that vented 
directly to the atmosphere, converted to mass emissions according to 
Sec.  98.233(h)(1)).
    (vi) Annual CH4 emissions, in metric tons 
CH4, that resulted from completions venting gas directly to 
the atmosphere (Es,p from Equation W-13B for completions 
that vented directly to the atmosphere, converted to mass emissions 
according to Sec.  98.233(h)(1)).
    (2) For each sub-basin with gas well completions without hydraulic 
fracturing and with flaring, report the information specified in 
paragraphs (h)(2)(i) through (h)(2)(vii) of this section.
    (i) Sub-basin ID.
    (ii) Number of well completions that flared gas.
    (iii) Total number of hours that gas vented to a flare during 
backflow for all completions in the sub-basin category (the sum of all 
``Tp'' for completions that vented to a flare from Equation 
W-13B).
    (iv) Average daily gas production rate for all completions without 
hydraulic fracturing in the sub-basin with flaring, in standard cubic 
feet per hour (the average of all ``Vp'' from Equation W-
13B).
    (v) Annual CO2 emissions, in metric tons CO2, 
that resulted from completions that flared gas calculated according to 
Sec.  98.233(h)(2).
    (vi) Annual CH4 emissions, in metric tons 
CH4, that resulted from completions that flared gas 
calculated according to Sec.  98.233(h)(2).
    (vii) Annual N2O emissions, in metric tons 
N2O, that resulted from completions that flared gas 
calculated according to Sec.  98.233(h)(2).
    (3) For each sub-basin with gas well workovers without hydraulic 
fracturing and without flaring, report the information specified in 
paragraphs (h)(3)(i) through (h)(3)(iv) of this section.
    (i) Sub-basin ID.
    (ii) Number of workovers that vented gas to the atmosphere without 
flaring.
    (iii) Annual CO2 emissions, in metric tons 
CO2 per year, that resulted from workovers venting gas 
directly to the atmosphere (``Es,wo'' in Equation W-13A for 
workovers that vented directly to the atmosphere, converted to mass 
emissions as specified in Sec.  98.233(h)(1)).
    (iv) Annual CH4 emissions, in metric tons CH4 
per year, that resulted from workovers venting gas directly to the 
atmosphere (``Es,wo'' in Equation W-13A for workovers that 
vented directly to the atmosphere, converted to mass emissions as 
specified in Sec.  98.233(h)(1)).
    (4) For each sub-basin with gas well workovers without hydraulic 
fracturing and with flaring, report the information specified in 
paragraphs (h)(4)(i) through (h)(4)(v) of this section.
    (i) Sub-basin ID.
    (ii) Number of workovers that flared gas.
    (iii) Annual CO2 emissions, in metric tons 
CO2 per year, that resulted from workovers that flared gas 
calculated as specified in Sec.  98.233(h)(2).
    (iv) Annual CH4 emissions, in metric tons CH4 
per year, that resulted from workovers that flared gas, calculated as 
specified in Sec.  98.233(h)(2).
    (v) Annual N2O emissions, in metric tons N2O 
per year, that resulted from

[[Page 13452]]

workovers that flared gas calculated as specified in Sec.  
98.233(h)(2).
    (i) Blowdown vent stacks. You must indicate whether your facility 
has blowdown vent stacks. If your facility has blowdown vent stacks, 
then you must report whether emissions were calculated by equipment 
type or by using flow meters. If you calculated emissions by equipment 
type, then you must report the information specified in paragraph 
(i)(1) of this section. If you calculated emissions using flow meters, 
then you must report the information specified in paragraph (i)(2) of 
this section.
    (1) Report by equipment type. If you calculated emissions from 
blowdown vent stacks by equipment type, then you must report the 
equipment types and the information specified in paragraphs (i)(1)(i) 
through (i)(1)(iii) of this section for each equipment type. If a 
blowdown event resulted in emissions from multiple equipment types, 
then you must report the information in paragraphs (i)(1)(i) through 
(i)(1)(iii) of this section for the equipment type that represented the 
largest portion of the emissions for the blowdown event.
    (i) Total number of blowdowns in the calendar year for the 
equipment type (the sum of equation variable ``N'' from Equation W-14A 
or Equation W-14B of this subpart, for all unique physical volumes for 
the equipment type).
    (ii) Annual CO2 emissions for the equipment type, in 
metric tons CO2, calculated according to Sec.  
98.233(i)(2)(iii).
    (iii) Annual CH4 emissions for the equipment type, in 
metric tons CH4, calculated according to Sec.  
98.233(i)(2)(iii).
    (2) Report by flow meter. If you elect to calculate emissions from 
blowdown vent stacks by using a flow meter according to Sec.  
98.233(i)(3), then you must report the information specified in 
paragraphs (i)(2)(i) and (i)(2)(ii) of this section for the facility.
    (i) Annual CO2 emissions from all blowdown vent stacks 
at the facility, in metric tons CO2 (the sum of all 
CO2 mass emission values calculated according to Sec.  
98.233(i)(3), for all flow meters).
    (ii) Annual CH4 emissions from all blowdown vent stacks 
at the facility, in metric tons CH4, (the sum of all 
CH4 mass emission values calculated according to Sec.  
98.233(i)(3), for all flow meters).
    (j) Onshore production storage tanks. You must indicate whether 
your facility sends produced oil to atmospheric tanks. If your facility 
sends produced oil to atmospheric tanks, then you must indicate which 
Calculation Method(s) you used to calculate GHG emissions, and you must 
report the information specified in paragraphs (j)(1) and (j)(2) of 
this section as applicable. If any atmospheric tanks were observed to 
have malfunctioning dump valves during the calendar year, then you must 
indicate that dump valves were malfunctioning and you must report the 
information specified in paragraph (j)(3) of this section.
    (1) If you used Calculation Method 1 or Calculation Method 2 to 
calculate GHG emissions, then you must report the information specified 
in paragraphs (j)(1)(i) through (j)(1)(xiv) of this section for each 
sub-basin and by calculation method.
    (i) Sub-basin ID.
    (ii) Calculation method used, and name of the software package used 
if using Calculation Method 1.
    (iii) The total annual gas-liquid separator oil volume that is sent 
to applicable onshore production storage tanks, in barrels.
    (iv) The average gas-liquid separator temperature, in degrees.
    (v) The average gas-liquid separator pressure, in pounds per square 
inch gauge.
    (vi) The average sales oil or stabilized oil API gravity, in 
degrees.
    (vii) The minimum and maximum concentration (mole fraction) of 
CO2 in flash gas from onshore production storage tanks.
    (viii) The minimum and maximum concentration (mole fraction) of 
CH4 in flash gas from onshore production storage tanks.
    (ix) The number of wells sending oil to gas-liquid separators or 
directly to atmospheric tanks.
    (x) The number of atmospheric tanks.
    (xi) An estimate of the number of atmospheric tanks, not on well-
pads, receiving your oil.
    (xii) If any emissions from the atmospheric tanks at your facility 
were controlled with vapor recovery systems, then you must report the 
information specified in paragraphs (j)(1)(xii)(A) through 
(j)(1)(xii)(E) of this section.
    (A) The number of atmospheric tanks that control emissions with 
vapor recovery systems.
    (B) Total CO2 mass, in metric tons CO2, that 
was recovered during the calendar year using a vapor recovery system.
    (C) Total CH4 mass, in metric tons CH4, that 
was recovered during the calendar year using a vapor recovery system.
    (D) Annual CO2 emissions, in metric tons CO2, 
from atmospheric tanks equipped with vapor recovery systems.
    (E) Annual CH4 emissions, in metric tons CH4, 
from atmospheric tanks equipped with vapor recovery systems.
    (xiii) If any atmospheric tanks at your facility vented gas 
directly to the atmosphere without using a vapor recovery system or 
without flaring, then you must report the information specified in 
paragraphs (j)(1)(xiii)(A) through (j)(1)(xiii)(C) of this section.
    (A) The number of atmospheric tanks that vented gas directly to the 
atmosphere without using a vapor recovery system or without flaring.
    (B) Annual CO2 emissions, in metric tons CO2, 
that resulted from venting gas directly to the atmosphere.
    (C) Annual CH4 emissions, in metric tons CH4, 
that resulted from venting gas directly to the atmosphere.
    (xiv) If you controlled emissions from any atmospheric tanks at 
your facility with one or more flares, then you must report the 
information specified in paragraphs (j)(1)(xiv)(A) through 
(j)(1)(xiv)(D) of this section.
    (A) The number of atmospheric tanks that controlled emissions with 
flares.
    (B) Annual CO2 emissions, in metric tons CO2, 
from atmospheric tanks that controlled emissions with one or more 
flares.
    (C) Annual CH4 emissions, in metric tons CH4, 
from atmospheric tanks that controlled emissions with one or more 
flares.
    (D) Annual N2O emissions, in metric tons N2O, 
from atmospheric tanks that controlled emissions with one or more 
flares.
    (2) If you used Calculation Method 3 to calculate GHG emissions, 
then you must report the information specified in paragraph (j)(2)(i) 
through (j)(2)(iii) of this paragraph.
    (i) Report the information specified in paragraphs (j)(2)(i)(A) 
through (j)(2)(i)(F) of this section, at the basin level, for 
atmospheric tanks where emissions were calculated using Calculation 
Method 3.
    (A) The total annual oil throughput that is sent to all atmospheric 
tanks in the basin, in barrels.
    (B) An estimate of the fraction of oil throughput reported in 
paragraph (j)(2)(i)(A) sent to atmospheric tanks in the basin that 
controlled emissions with flares.
    (C) An estimate of the fraction of oil throughput reported in 
paragraph (j)(2)(i)(A) sent to atmospheric tanks in the basin that 
controlled emissions with vapor recovery systems.
    (D) The number of atmospheric tanks in the basin.
    (E) The number of wells with gas-liquid separators (``Count'' from 
Equation W-15 of this subpart) in the basin.

[[Page 13453]]

    (F) The number of wells without gas-liquid separators (``Count'' 
from Equation W-15 of this subpart) in the basin.
    (ii) Report the information specified in paragraphs (j)(2)(ii)(A) 
through (j)(2)(ii)(D) of this section for each sub-basin with 
atmospheric tanks whose emissions were calculated using Calculation 
Method 3 and that did not control emissions with flares.
    (A) Sub-basin ID.
    (B) The number of atmospheric tanks in the sub-basin that did not 
control emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2, 
from atmospheric tanks in the sub-basin that did not control emissions 
with flares, calculated using Equation W-15 of this subpart.
    (D) Annual CH4 emissions, in metric tons CH4, 
from atmospheric tanks in the sub-basin that vented gas directly to the 
atmosphere, calculated using Equation W-15 of this subpart.
    (iii) Report the information specified in paragraphs (j)(2)(iii)(A) 
through (j)(2)(iii)(E) of this section for each sub-basin with 
atmospheric tanks whose emissions were calculated using Calculation 
Method 3 and that controlled emissions with flares.
    (A) Sub-basin ID.
    (B) The number of atmospheric tanks in the sub-basin that 
controlled emissions with flares.
    (C) Annual CO2 emissions, in metric tons CO2, 
from atmospheric tanks that controlled emissions with flares.
    (D) Annual CH4 emissions, in metric tons CH4, 
from atmospheric tanks that controlled emissions with flares.
    (E) Annual N2O emissions, in metric tons N2O, 
from atmospheric tanks that controlled emissions with flares.
    (3) If any gas-liquid separator liquid dump values did not close 
properly during the calendar year, then you must report the information 
specified in paragraphs (j)(3)(i) through (j)(3)(iv) of this section.
    (i) The total number of gas-liquid separators whose liquid dump 
valves did not close properly during the calendar year.
    (ii) The total time the dump valves on gas-liquid separators did 
not close properly in the calendar year, in hours (``Tn'' in 
Equation W-16 of this subpart).
    (iii) Annual CO2 emissions, in metric tons 
CO2, that resulted from dump valves on gas-liquid separators 
not closing properly during the calendar year, calculated using 
Equation W-16 of this subpart.
    (iv) Annual CH4 emissions, in metric tons 
CH4, that resulted from the dump valves on gas-liquid 
separators not closing properly during the calendar year, calculated 
using Equation W-16 of this subpart.
    (k) Transmission storage tanks. You must indicate whether your 
facility contains any transmission storage tanks. If your facility 
contains at least one transmission storage tank, then you must report 
the information specified in paragraphs (k)(1) through (k)(3) of this 
section for each transmission storage tank vent stack.
    (1) For each transmission storage tank vent stack, report the 
information specified in (k)(1)(i) through (k)(1)(iv) of this section.
    (i) The unique name or ID number for the transmission storage tank 
vent stack.
    (ii) Method used to determine if dump valve leakage occurred.
    (iii) Indicator whether scrubber dump valve leakage occurred for 
the transmission storage tank vent.
    (iv) Indicator if there is a flare attached to the transmission 
storage tank vent stack.
    (2) If scrubber dump valve leakage occurred for a transmission 
storage tank vent stack, as reported in paragraph (k)(1)(iii), and the 
vent stack vented directly to the atmosphere during the calendar year, 
then you must report the information specified in paragraphs (k)(2)(i) 
through (k)(2)(v) of this section for each transmission storage vent 
stack where scrubber dump valve leakage occurred.
    (i) Method used to measure the leak rate.
    (ii) Measured leak rate (average leak rate from a continuous flow 
measurement device), in standard cubic feet per hour.
    (iii) Duration of time that venting occurred, in hours (may use 
best available data if a continuous flow measurement device was used).
    (iv) Annual CO2 emissions, in metric tons 
CO2, that resulted from venting gas directly to the 
atmosphere, calculated according to Sec.  98.233(k)(1) through (k)(3).
    (v) Annual CH4 emissions, in metric tons CH4, 
that resulted from venting gas directly to the atmosphere, calculated 
according to Sec.  98.233(k)(1) through (k)(3).
    (3) If scrubber dump valve leakage occurred for a transmission 
storage tank vent stack, as reported in paragraph (k)(1)(iii), and the 
vent stack vented to a flare during the calendar year, then you must 
report the information specified in paragraphs (k)(3)(i) through 
(k)(3)(vi) of this section.
    (i) Method used to measure the leak rate.
    (ii) Measured leakage rate (average leak rate from a continuous 
flow measurement device) in standard cubic feet per hour.
    (iii) Duration of time that flaring occurred in hours (may use best 
available data if a continuous flow measurement device was used).
    (iv) Annual CO2 emissions, in metric tons 
CO2, that resulted from flaring gas, calculated according to 
Sec.  98.233(k)(4).
    (v) Annual CH4 emissions, in metric tons CH4, 
that resulted from flaring gas, calculated according to Sec.  
98.233(k)(4).
    (vi) Annual N2O emissions, in metric tons 
N2O, that resulted from flaring gas, calculated according to 
Sec.  98.233(k)(4).
    (l) Well testing. You must indicate whether you performed gas well 
or oil well testing, and if the testing of gas wells or oil wells 
resulted in vented or flared emissions during the calendar year. If you 
performed well testing that resulted in vented or flared emissions 
during the calendar year, then you must report the information 
specified in paragraphs (l)(1) through (l)(4) of this section, as 
applicable.
    (1) If you used Equation W-17A to calculate annual volumetric 
natural gas emissions at actual conditions from oil wells and the 
emissions are not vented to a flare, then you must report the 
information specified in paragraphs (l)(1)(i) through (l)(1)(vi) of 
this section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days in the calendar year.
    (iii) Average gas to oil ratio for well(s) tested, in cubic feet of 
gas per barrel of oil.
    (iv) Average flow rate for well(s) tested, in barrels of oil per 
day.
    (v) Annual CO2 emissions, in metric tons CO2, 
calculated according to Sec.  98.233(l).
    (vi) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec.  98.233(l).
    (2) If you used Equation W-17A to calculate annual volumetric 
natural gas emissions at actual conditions from oil wells and the 
emissions are vented to a flare, then you must report the information 
specified in paragraphs (l)(2)(i) through (l)(2)(vii) of this section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days in the calendar year.
    (iii) Average gas to oil ratio for well(s) tested, in cubic feet of 
gas per barrel of oil.
    (iv) Average flow rate for well(s) tested, in barrels of oil per 
day.
    (v) Annual CO2 emissions, in metric tons CO2, 
calculated according to Sec.  98.233(l).
    (vi) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec.  98.233(l).

[[Page 13454]]

    (vii) Annual N2O emissions, in metric tons 
N2O, calculated according to Sec.  98.233(l).
    (3) If you used Equation W-17B to calculate annual volumetric 
natural gas emissions at actual conditions from gas wells and the 
emissions were not vented to a flare, then you must report the 
information specified in paragraphs (l)(3)(i) through (l)(3)(v) of this 
section.
    (i) Number of wells tested in the calendar year.
    (ii) Average number of well testing days in the calendar year.
    (iii) Average annual production rate for well(s) tested, in actual 
cubic feet per day.
    (iv) Annual CO2 emissions, in metric tons 
CO2, calculated according to Sec.  98.233(l).
    (v) Annual CH4 emissions, in metric tons CH4, 
calculated according to Sec.  98.233(l).
    (4) If you used Equation W-17B to calculate annual volumetric 
natural gas emissions at actual conditions from gas wells and the 
emissions were vented to a flare, then you must report the information 
specified in paragraphs (l)(4)(i) through (l)(4)(vi) of this section.
    (i) Number of wells tested in calendar year.
    (ii) Average number of well testing days in the calendar year.
    (iii) Average annual production rate for well(s) tested, in actual 
cubic feet per day.
    (iv) Annual CO2 emissions, in metric tons 
CO2, calculated according to Sec.  98.233(l).
    (v) Annual CH4 emissions, in metric tons CH4, 
calculated according to Sec.  98.233(l).
    (vi) Annual N2O emissions, in metric tons 
N2O, calculated according to Sec.  98.233(l).
    (m) Associated natural gas. You must indicate whether any 
associated gas was vented or flared during the calendar year. If 
associated gas was vented or flared during the calendar year, then you 
must report the information specified in paragraphs (m)(1) through 
(m)(9) of this section for each sub-basin.
    (1) Sub-basin ID.
    (2) Indicator whether any associated gas was vented directly to the 
atmosphere without flaring.
    (3) Indicator whether any associated gas was flared.
    (4) Average gas to oil ratio, in standard cubic feet of gas per 
barrel of oil (average of the ``GOR'' values used in Equation W-18 of 
this subpart).
    (5) Volume of oil produced, in barrels, in the calendar year during 
the time periods in which associated gas was vented or flared (the sum 
of ``Vp,q'' used in Equation W-18 of this subpart).
    (6) Total volume of associated gas sent to sales, in standard cubic 
feet, in the calendar year during time periods in which associated gas 
was vented or flared (the sum of ``SG'' values used in Equation W-18 of 
this subpart).
    (7) Total volume of emissions reported elsewhere, in standard cubic 
feet, during time periods in which associated gas was vented or flared 
and which are calculated and reported under other paragraphs of this 
section, in standard cubic feet (the sum of ``EREp,q'' values used in 
Equation W-18 of this subpart).
    (8) If you had associated gas emissions directly to the atmosphere 
without flaring, then you must report the information specified in 
paragraphs (m)(8)(i) through (m)(8)(iii) of this section for each sub-
basin.
    (i) Total number of wells for which associated gas was vented 
directly to the atmosphere without flaring.
    (ii) Annual CO2 emissions, in metric tons 
CO2, calculated according to Sec.  98.233(m)(3) and (m)(4).
    (iii) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec.  98.233(m)(3) and (m)(4).
    (9) If you had associated gas emissions that were flared, then you 
must report the information specified in paragraphs (m)(9)(i) through 
(m)(9)(iv) of this section for each sub-basin.
    (i) Total number of wells for which associated gas was flared.
    (ii) Annual CO2 emissions, in metric tons 
CO2, calculated according to Sec.  98.233(m)(5).
    (iii) Annual CH4 emissions, in metric tons 
CH4, calculated according to Sec.  98.233(m)(5).
    (iv) Annual N2O emissions, in metric tons 
N2O, calculated according to Sec.  98.233(m)(5).
    (n) Flare stacks. You must indicate if your facility contains any 
flare stacks. You must report the information specified in paragraphs 
(n)(1) through (n)(12) of this section for each flare stack at your 
facility, and for each industry segment applicable to your facility.
    (1) Unique name or ID for the flare stack. For the onshore 
petroleum and natural gas production industry segment, a different name 
or ID may be used for a single flare stack for each location where it 
operates at in a given calendar year.
    (2) Indicate whether the flare stack has a continuous flow 
measurement device.
    (3) Indicate whether the flare stack has a continuous gas 
composition analyzer on feed gas to the flare.
    (4) Volume of gas sent to the flare, in standard cubic feet (``Va'' 
in Equation W-19 of this subpart).
    (5) Fraction of the feed gas sent to an un-lit flare (``Zu'' in 
Equation W-19 of this subpart).
    (6) Flare combustion efficiency, expressed as the fraction of gas 
combusted by a burning flare.
    (7) Mole fraction of CH4 in the feed gas to the flare 
(``XCH4'' in Equation W-19 of this subpart).
    (8) Mole fraction of CO2 in the feed gas to the flare 
(``XCO2'' in Equation W-20 of this subpart).
    (9) Annual CO2 emissions, in metric tons CO2 
(refer to Equation W-20 of this subpart).
    (10) Annual CH4 emissions, in metric tons CH4 
(refer to Equation W-19 of this subpart).
    (11) Annual N2O emissions, in metric tons N2O 
(refer to Equation W-40 of this subpart).
    (12) Indicate whether a CEMS was used to measure emissions from the 
flare. If a CEMS was used to measure emissions from the flare, then you 
are not required to report N2O and CH4 emissions 
for the flare stack.
    (o) Centrifugal compressors. You must indicate whether your 
facility has centrifugal compressors. You must report the information 
specified in paragraphs (o)(1) and (o)(2) of this section for all 
centrifugal compressors at your facility. For each compressor source or 
manifolded group of compressor sources that you conduct as found leak 
measurements as specified in Sec.  98.233(o)(2) or (o)(4), you must 
report the information specified in paragraph (o)(3) of this section. 
For each compressor source or manifolded group of compressor sources 
that you conduct continuous monitoring as specified in Sec.  
98.233(o)(3) or (o)(5), you must report the information specified in 
paragraph (o)(4) of this section. Centrifugal compressors in onshore 
petroleum and natural gas production are not required to report 
information in paragraphs (o)(1) through (o)(4) of this section and 
instead must report the information specified in paragraph (o)(5) of 
this section.
    (1) Compressor activity data. Report the information specified in 
paragraphs (o)(1)(i) through (o)(1)(xvi) of this section for each 
compressor located at your facility.
    (i) Unique name or ID for the centrifugal compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in not-operating-depressurized-mode.
    (iv) Indicate whether the compressor was measured in operating-
mode.
    (v) Indicate whether the compressor was measured in not-operating-
depressurized-mode.

[[Page 13455]]

    (vi) Indicate whether any compressor sources are part of a 
manifolded group of compressor sources.
    (vii) Indicate whether any compressor sources are routed to a 
flare.
    (viii) Indicate whether any compressor sources have vapor recovery.
    (ix) Indicate whether emissions from any compressor sources are 
captured for fuel use or are routed to a thermal oxidizer.
    (x) Indicate whether the compressor has blind flanges installed.
    (xi) Indicate whether the compressor has wet or dry seals.
    (xii) If the compressor has wet seals, the number of wet seals.
    (xiii) Compressor power rating (hp).
    (xiv) Year compressor was installed.
    (xv) Compressor model name and description.
    (xvi) Date of last maintenance shutdown that compressor was 
depressurized.
    (2) Compressor source emission vent. For each compressor source at 
each compressor, report the information specified in paragraphs 
(o)(2)(i) through (o)(2)(viii) of this section.
    (i) Centrifugal compressor name or ID. Use the same ID as in 
paragraph (o)(1)(i) of this section.
    (ii) Centrifugal compressor source (wet seal, isolation valve, or 
blowdown valve).
    (iii) Unique name or ID for the emission vent. If the emission vent 
is connected to a manifolded group of compressor sources, use the same 
emission vent ID for each compressor source.
    (iv) Emission vent type. Indicate whether the emission vent is for 
a single compressor source or manifolded group of compressor sources 
and whether the emissions from the emission vent are released to the 
atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), 
or vapor recovery.
    (v) Indicate whether an as found leak measurement(s) as identified 
in Sec.  98.233(o)(2) or (o)(4) was conducted on the emission vent.
    (vi) Indicate whether continuous leak measurements as identified in 
Sec.  98.233(o)(3) or (o)(5) were conducted on the emission vent.
    (vii) Report emissions as specified in paragraphs (o)(2)(vii)(A) 
and (o)(2)(vii)(B) of this section for the emission vent. For emission 
vents associated with individual compressor sources that use an as 
found leak measurement(s), calculate emissions by summing all emissions 
from all compressor mode-source combinations for the emission vent.
    (A) Annual CO2 emissions, in metric tons CO2.
    (B) Annual CH4 emissions, in metric tons CH4.
    (viii) If the emission vent is routed to flare, combustion, or 
vapor recovery, report the percentage of time that the respective 
device was operational.
    (3) As found leak measurement sample data. If the measurement 
methods specified in paragraphs Sec.  98.233(o)(2) or (o)(4) are 
conducted, report the information specified in paragraph (o)(3)(i) of 
this section. If the measurement method specified in paragraph Sec.  
98.233(o)(2) is performed, report the information specified in 
paragraph (o)(3)(ii) of this section.
    (i) For each as found leak measurement performed on an emission 
vent, report the information specified in paragraphs (o)(3)(i)(A) 
through (o)(3)(i)(E) of this section.
    (A) Name or ID of emission vent. Use same emission vent ID as in 
paragraph (o)(2)(iii) of this section.
    (B) Sample date.
    (C) Leak measurement method.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the emission vent, report the 
mode of operation the compressor was in when the sample was taken.
    (ii) For each compressor mode-source combination where a reporter 
emission factor as calculated in equation W-24 was used to calculate 
emissions in Equation W-23, report the information specified in 
paragraphs (o)(3)(ii)(A) through (o)(3)(ii)(D) of this section
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission 
factor, in standard cubic feet per hour (EFm,s in Equation 
W-24).
    (C) The total number of compressors measured in the compressor 
mode-source combination in the current reporting year and the preceding 
two reporting years (Countm in Equation W-24).
    (D) Indicate whether the compressor mode-source combination 
reporter emission factor is facility-specific or corporate.
    (4) Continuous leak measurement data. If the measurement methods 
specified in paragraphs Sec.  98.233(o)(3) or (o)(5) are conducted, 
report the information specified in paragraphs (o)(4)(i) and (o)(4)(ii) 
of this section for each continuous measurement conducted on each 
emission vent associated with each compressor source or manifolded 
group of compressor sources.
    (i) Name or ID of emission vent. Use same emission vent ID as in 
paragraph (o)(2)(iii) of this section.
    (ii) Measured volume of flow during the reporting year, in million 
standard cubic feet.
    (5) Centrifugal compressors with wet seal degassing vents in 
onshore petroleum and natural gas production must report the 
information specified in paragraphs (o)(5)(i) through (o)(5)(iii) of 
this section.
    (i) Number of centrifugal compressors that have wet seal oil 
degassing vents.
    (ii) Annual CO2 emissions, in metric tons 
CO2, from centrifugal compressors with wet seal oil 
degassing vents.
    (iii) Annual CH4 emissions, in metric tons 
CH4, from centrifugal compressors with wet seal oil 
degassing vents.
    (p) Reciprocating compressors. You must indicate whether your 
facility has reciprocating compressors. You must report the information 
specified in paragraphs (p)(1) and (p)(2) of this section for all 
reciprocating compressors at your facility. For each compressor source 
or manifolded group of compressor sources that you conduct as found 
leak measurements as specified in Sec.  98.233(p)(2) or (p)(4), you 
must report the information specified in paragraph (p)(3) of this 
section. For each compressor source or manifolded group of compressor 
sources that you conduct continuous monitoring as specified in Sec.  
98.233(p)(3) or (p)(5), you must report the information specified in 
paragraph (p)(4) of this section. Reciprocating compressors in onshore 
petroleum and natural gas production are not required to report 
information in paragraphs (p)(1) through (p)(4) of this section and 
instead must report the information specified in paragraph (p)(5) of 
this section.
    (1) Compressor activity data. Report the information specified in 
paragraphs (p)(1)(i) through (p)(1)(xvi) of this section for each 
compressor located at your facility.
    (i) Unique name or ID for the reciprocating compressor.
    (ii) Hours in operating-mode.
    (iii) Hours in standby-depressurized-mode.
    (iv) Hours in not-operating-depressurized-mode.
    (v) Indicate whether the compressor was measured in operating-mode.
    (vi) Indicate whether the compressor was measured in standby-
depressurized-mode.
    (vii) Indicate whether the compressor was measured in not-
operating-depressurized-mode.
    (viii) Indicate whether any compressor sources are part of a 
manifolded group of compressor sources.
    (ix) Indicate whether any compressor sources are routed to a flare.

[[Page 13456]]

    (x) Indicate whether any compressor sources have vapor recovery.
    (xi) Indicate whether emissions from any compressor sources are 
captured for fuel use or are routed to a thermal oxidizer.
    (xii) Indicate whether the compressor has blind flanges installed.
    (xiii) Compressor power rating (hp).
    (xiv) Year compressor was installed.
    (xv) Compressor model name and description.
    (xvi) Date of last maintenance shutdown for rod packing 
replacement.
    (2) Compressor source emission vent. For each compressor source at 
each compressor, report the information specified in paragraphs 
(p)(2)(i) through (p)(2)(viii) of this section.
    (i) Reciprocating compressor name or ID. Use the same ID as in 
paragraph (p)(1)(i) of this section.
    (ii) Reciprocating compressor source (isolation valve, blowdown 
valve, or rod packing).
    (iii) Unique name or ID for the emission vent. If the emission vent 
is connected to a manifolded group of compressor sources, use the same 
emission vent ID for each compressor source.
    (iv) Emission vent type. Indicate whether the emission vent is for 
a single compressor source or manifolded group of compressor sources 
and whether the emissions from the emission vent are released to the 
atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), 
or vapor recovery.
    (v) Indicate whether an as found leak measurement(s) as identified 
in Sec.  98.233(p)(2) or (p)(4) was conducted on the emission vent.
    (vi) Indicate whether continuous leak measurements as identified in 
Sec.  98.233(p)(3) or (p)(5) were conducted on the emission vent.
    (vii) Report emissions as specified in paragraphs (p)(2)(vii)(A) 
and (p)(2)(vii)(B) of this section for the emission vent. For emission 
vents associated with individual compressor sources that use an as 
found leak measurement(s), calculate emissions by summing all emissions 
from all compressor mode-source combinations for the emission vent.
    (A) Annual CO2 emissions, in metric tons CO2.
    (B) Annual CH4 emissions, in metric tons CH4.
    (viii) If the emission vent is routed to flare, combustion, or 
vapor recovery, report the percentage of time that the respective 
device was operational.
    (3) As found leak measurement sample data. If the measurement 
methods specified in paragraphs Sec.  98.233(p)(2) or (p)(4) are 
conducted, report the information specified in paragraph (p)(3)(i) of 
this section. If the measurement method specified in paragraph Sec.  
98.233(p)(2) is performed, report the information specified in 
paragraph (p)(3)(ii) of this section.
    (i) For each as found leak measurement performed on an emission 
vent, report the information specified in paragraphs (p)(3)(i)(A) 
through (p)(3)(i)(E) of this section.
    (A) Name or ID of emission vent. Use same emission vent ID as in 
paragraph (p)(2)(iii) of this section.
    (B) Sample date.
    (C) Leak measurement method.
    (D) Measured flow rate, in standard cubic feet per hour.
    (E) For each compressor attached to the emission vent, report the 
mode of operation the compressor was in when the sample was taken.
    (ii) For each compressor mode-source combination where a reporter 
emission factor as calculated in equation W-28 was used to calculate 
emissions in Equation W-27, report the information specified in 
paragraphs (p)(3)(ii)(A) through (p)(3)(ii)(D) of this section
    (A) The compressor mode-source combination.
    (B) The compressor mode-source combination reporter emission 
factor, in standard cubic feet per hour (EFm,s in Equation 
W-28).
    (C) The total number of compressors measured in the compressor 
mode-source combination in the current reporting year and the preceding 
two reporting years (Countm in Equation W-28).
    (D) Indicate whether the compressor mode-source combination 
reporter emission factor is facility-specific or corporate.
    (4) Continuous leak measurement data. If the measurement methods 
specified in paragraphs Sec.  98.233(p)(3) or (p)(5) are conducted, 
report the information specified in paragraphs (p)(4)(i) and (p)(4)(ii) 
of this section for each continuous measurement conducted on each 
emission vent associated with each compressor source or manifolded 
group of compressor sources.
    (i) Name or ID of emission vent. Use same emission vent ID as in 
paragraph (p)(2)(iii) of this section.
    (ii) Measured volume of flow during the reporting year, in million 
standard cubic feet.
    (5) Reciprocating compressors in onshore petroleum and natural gas 
production must report the information specified in paragraphs 
(p)(5)(i) through (p)(5)(iii) of this section.
    (i) Number of reciprocating compressors.
    (ii) Annual CO2 emissions, in metric tons 
CO2, from reciprocating compressors.
    (iii) Annual CH4 emissions, in metric tons 
CH4, from reciprocating compressors.
    (q) Equipment leak surveys. If your facility is subject to the 
requirements of Sec.  98.233(q), then you must report the information 
specified in paragraphs (q)(1) and (q)(2) of this section. Natural gas 
distribution facilities must also report the information specified in 
paragraph (q)(3) of this section.
    (1) You must report the information specified in paragraphs 
(q)(1)(i) and (ii) of this section.
    (i) The number of complete equipment leak surveys performed during 
the calendar year.
    (ii) Natural gas distribution facilities performing equipment leak 
surveys across a multiple year leak survey cycle must report the number 
of years in the leak survey cycle.
    (2) You must indicate whether your facility contains any of the 
component types listed in Sec.  98.232(d)(7), (e)(7), (f)(5), (g)(3), 
(h)(4), or (i)(1), for your facility's industry segment. For each 
component type that is located at your facility, you must report the 
information specified in paragraphs (q)(2)(i) through (q)(2)(v) of this 
section. If a component type is located at your facility and no leaks 
were identified from that component, then you must report the 
information in paragraphs (q)(2)(i) through (q)(2)(v) of this section 
but report a zero (``0'') for the information required according to 
paragraphs (q)(2)(iii), (q)(2)(iv), and (q)(2)(v) of this section.
    (i) Component type.
    (ii) Total number of the surveyed component type that were 
identified as leaking in the calendar year (``xp'' in 
Equation W-30 of this subpart for the component type).
    (iii) Average time the surveyed components were found leaking and 
operational, in hours (average of ``Tp,z'' from Equation W-
30 of this subpart for the component type).
    (iv) Annual CO2 emissions, in metric tons 
CO2, for the component type.
    (v) Annual CH4 emissions, in metric tons CH4, 
for the component type.
    (3) Natural gas distribution facilities must report the information 
specified in paragraphs (q)(3)(i) through (q)(3)(viii) of this section.
    (i) Number of above grade transmission-distribution transfer 
stations surveyed in the calendar year.
    (ii) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in the calendar year 
(``CountMR,y'' from

[[Page 13457]]

Equation W-31 of this subpart, for the current calendar year).
    (iii) Average time that meter/regulator runs surveyed in the 
calendar year were operational, in hours (average of 
``Tw,y'' from Equation W-31 of this subpart, for the current 
calendar year).
    (iv) Number of above grade transmission-distribution transfer 
stations surveyed in the current leak survey cycle.
    (v) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in current leak survey cycle 
(sum of ``CountMR,y'' from Equation W-31 of this subpart, 
for all calendar years in the current leak survey cycle).
    (vi) Average time that meter/regulator runs surveyed in the current 
leak survey cycle were operational, in hours (average of 
``Tw,y'' from Equation W-31 of this subpart, for all years 
included in the leak survey cycle).
    (vii) Meter/regulator run CO2 emission factor based on 
all surveyed transmission-distribution transfer stations in the current 
leak survey cycle, in standard cubic feet of CO2 per meter/
regulator run operating hour (``EFs,MR,i'' for 
CO2 calculated using Equation W-31 of this subpart).
    (viii) Meter/regulator run CH4 emission factor based on 
all surveyed transmission-distribution transfer stations in the current 
leak survey cycle, in standard cubic feet of CH4 per meter/
regulator run operating hour (``EFs,MR,i'' for 
CH4 calculated using Equation W-31 of this subpart).
    (r) Equipment leaks by population count. If your facility is 
subject to the requirements of Sec.  98.233(r), then you must report 
the information specified in paragraph (r)(1) of this section. Natural 
gas distribution facilities must also report the information specified 
in paragraph (r)(2) of this section. Onshore petroleum and natural gas 
production facilities must also report the information specified in 
paragraph (r)(3) of this section.
    (1) You must indicate whether your facility contains any of the 
emission source types covered by Sec.  98.233(r), for the applicable 
industry segment. You must report the information specified in 
paragraphs (r)(1)(i) through (r)(1)(v) of this section separately for 
each emission source type that is located at your facility. Onshore 
petroleum and natural gas production facilities must report the 
information specified in paragraphs (r)(1)(i) through (r)(1)(v) of this 
section separately by component type, service type, and geographic 
location (i.e., Eastern U.S or Western U.S.).
    (i) Emission source type. Onshore petroleum and natural gas 
production facilities must report the component type, service type and 
geographic location.
    (ii) Total number of the emission source type at the facility 
(``Counte'' in Equation W-32A of this subpart).
    (iii) Average estimated time that the emission source type was 
operational in the calendar year, in hours (``Te'' in 
Equation W-32A of this subpart).
    (iv) Annual CO2 emissions, in metric tons 
CO2, for the emission source type.
    (v) Annual CH4 emissions, in metric tons CH4, 
for the emission source type.
    (2) Natural gas distribution facilities must also report the 
information specified in paragraphs (q)(2)(i) through (q)(2)(viii) of 
this of this section.
    (i) Number of above grade transmission-distribution transfer 
stations at the facility.
    (ii) Number of above grade metering-regulating stations that are 
not transmission-distribution transfer stations at the facility.
    (iii) Number of below grade transmission-distribution transfer 
stations at the facility.
    (iv) Number of below grade metering-regulating stations that are 
not transmission-distribution transfer stations at the facility.
    (v) Total number of meter/regulator runs at above grade metering-
regulating stations that are not above grade transmission-distribution 
transfer stations (``CountMR'' in Equation W-32B of this 
subpart).
    (vi) Average estimated time that each meter/regulator run was 
operational in the calendar year, in hours per meter/regulator run 
(``Tw,avg'' in Equation W-32B of this subpart).
    (vii) Annual CO2 emissions, in metric tons 
CO2, from above grade metering regulating stations that are 
not above grade transmission-distribution transfer stations.
    (viii) Annual CH4 emissions, in metric tons 
CH4, from above grade metering regulating stations that are 
not above grade transmission-distribution transfer stations.
    (3) Onshore petroleum and natural gas production facilities must 
also report the information specified in paragraphs (r)(3)(i) and 
(r)(3)(ii) of this section.
    (i) Calculation method used.
    (ii) Onshore petroleum and natural gas production facilities must 
report the information specified in paragraphs (r)(3)(ii)(A) and 
(r)(3)(ii)(B) of this section, for each major equipment type, 
production type (i.e., natural gas or crude oil), and geographic 
location combination in Tables W-1B and W-1C of this subpart.
    (A) An indication of whether the facility contains the major 
equipment type.
    (B) If the facility does contain the equipment type, the count of 
the major equipment type.
    (s) Offshore petroleum and natural gas production. You must report 
the information specified in paragraphs (s)(1) through (s)(3) of this 
section for each emission source type listed in the most recent BOEMRE 
study.
    (1) Annual CO2 emissions, in metric tons CO2.
    (2) Annual CH4 emissions, in metric tons CH4.
    (3) Annual N2O emissions, in metric tons N2O.
    (t) [Reserved]
    (u) [Reserved]
    (v) [Reserved]
    (w) EOR injection pumps. You must indicate whether CO2 
EOR injection was used at your facility during the calendar year and if 
any EOR injection pump blowdowns occurred during the year. If any EOR 
injection pump blowdowns occurred during the calendar year, then you 
must report the information specified in paragraphs (w)(1) through 
(w)(8) of this section for each EOR injection pump system.
    (1) Sub-basin ID.
    (2) EOR injection pump system identifier.
    (3) Pump capacity, in barrels per day.
    (4) Total volume of EOR injection pump system equipment chambers, 
in cubic feet (``Vv'' in Equation W-37 of this subpart).
    (5) Number of blowdowns for the EOR injection pump system in the 
calendar year.
    (6) Density of critical phase EOR injection gas, in kilograms per 
cubic foot (``Rc'' in Equation W-37 of this subpart).
    (7) Mass fraction of CO2 in critical phase EOR injection 
gas (``GHGCO2'' in Equation W-37 of this subpart).
    (8) Annual CO2 emissions, in metric tons CO2, 
from EOR injection pump system blowdowns.
    (x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon 
liquids were produced through EOR operations. If hydrocarbon liquids 
were produced through EOR operations, you must report the information 
specified in paragraphs (x)(1) through (x)(4) of this section for each 
sub-basin category with EOR operations.
    (1) Sub-basin ID.
    (2) Total volume of hydrocarbon liquids produced through EOR 
operations in the calendar year, in barrels (``Vhl'' in 
Equation W-38 of this subpart).
    (3) Average CO2 retained in hydrocarbon liquids 
downstream of the storage tank, in metric tons per barrel under 
standard conditions (``Shl'' in Equation W-38 of this 
subpart).

[[Page 13458]]

    (4) Annual CO2 emissions, in metric tons CO2, 
from CO2 retained in hydrocarbon liquids produced through 
EOR operations downstream of the storage tank (``MassCO2'' 
in Equation W-38 of this subpart).
    (y) [Reserved]
    (z) Combustion equipment at onshore petroleum and natural gas 
production facilities and natural gas distribution facilities. If your 
facility is required by Sec.  98.232(c)(22) or (i)(7) to report 
emissions from combustion equipment, then you must indicate whether 
your facility has any combustion units subject to reporting according 
to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section. If your 
facility contains any combustion units subject to reporting according 
to paragraphs (a)(1)(xvii) or (a)(8)(i) of this section, then you must 
report the information specified in paragraphs (z)(1) and (z)(2) of 
this section, as applicable.
    (1) Indicate whether the combustion units include: external fuel 
combustion units with a rated heat capacity less than or equal to 5 
million Btu per hour; or, internal fuel combustion units that are not 
compressor-drivers, with a rated heat capacity less than or equal to 1 
mmBtu/hr (or the equivalent of 130 horsepower). If the facility 
contains external fuel combustion units with a rated heat capacity less 
than or equal to 5 million Btu per hour or internal fuel combustion 
units that are not compressor-drivers, with a rated heat capacity less 
than or equal to 1 million Btu per hour (or the equivalent of 130 
horsepower), then you must report the information specified in 
paragraphs (z)(1)(i) and (z)(1)(ii) of this section for each unit type.
    (i) The type of combustion unit.
    (ii) The total number of combustion units.
    (2) Indicate whether the combustion units include: external fuel 
combustion units with a rated heat capacity greater than 5 million Btu 
per hour; internal fuel combustion units that are not compressor-
drivers, with a rated heat capacity greater than 1 million Btu per hour 
(or the equivalent of 130 horsepower); or, internal fuel combustion 
units of any heat capacity that are compressor-drivers. If your 
facility contains: external fuel combustion units with a rated heat 
capacity greater than 5 mmBtu/hr; internal fuel combustion units that 
are not compressor-drivers, with a rated heat capacity greater than 1 
million Btu per hour (or the equivalent of 130 horsepower); or internal 
fuel combustion units of any heat capacity that are compressor-drivers, 
then you must report the information specified in paragraphs (z)(2)(i) 
through (z)(2)(vi) for each combustion unit type and fuel type 
combination.
    (i) The type of combustion unit.
    (ii) The type of fuel combusted.
    (iii) The quantity of fuel combusted in the calendar year, in 
thousand standard cubic feet, gallons, or tons.
    (iv) Annual CO2 emissions, in metric tons 
CO2, calculated according to Sec.  98.233(z)(1) and (z)(2).
    (v) Annual CH4 emissions, in metric tons CH4, 
calculated according to Sec.  98.233(z)(1) and (z)(2).
    (vi) Annual N2O emissions, in metric tons 
N2O, calculated according to Sec.  98.233(z)(1) and (z)(2).
    (aa) Each facility must report the information specified in 
paragraphs (aa)(1) through (aa)(9) of this section, for each applicable 
industry segment, by using best available data. If a quantity required 
to be reported is zero, you must report zero as the value.
    (1) For onshore petroleum and natural gas production, report the 
data specified in paragraphs (aa)(1)(i) and (aa)(1)(ii) of this 
section.
    (i) Report the information specified in paragraphs (aa)(1)(i)(A) 
through (aa)(1)(i)(D) of this section for the basin as a whole.
    (A) The quantity of gas produced in the calendar year from wells, 
in thousand standard cubic feet. This includes gas that is routed to a 
pipeline, vented or flared, or used in field operations. This does not 
include gas injected back into reservoirs or shrinkage resulting from 
lease condensate production.
    (B) The quantity of gas produced in the calendar year for sales, in 
thousand standard cubic feet.
    (C) The quantity of crude oil produced in the calendar year for 
sales, not including lease condensates, in barrels.
    (D) The quantity of lease condensate produced in the calendar year 
for sales, in barrels.
    (ii) Report the information specified in paragraphs (aa)(1)(ii)(A) 
through (aa)(1)(ii)(M) of this section for each unique sub-basin 
category.
    (A) State.
    (B) County.
    (C) Formation type.
    (D) The number of producing wells at the end of the calendar year.
    (E) The number of producing wells acquired during the calendar 
year.
    (F) The number of producing wells divested during the calendar 
year.
    (G) The number of wells completed during the calendar year.
    (H) The number of wells taken out of production during the calendar 
year.
    (I) Average mole fraction of CH4 in produced gas.
    (J) Average mole fraction of CO2 in produced gas.
    (K) If an oil sub-basin, report the average GOR of all wells, in 
thousand standard cubic feet per barrel.
    (L) If an oil sub-basin, report the average API gravity of all 
wells.
    (M) If an oil sub-basin, report average low pressure separator 
pressure, in pounds per square inch gauge.
    (2) For offshore production, report the quantities specified in 
paragraphs (aa)(2)(i) through (aa)(2)(iii) of this section.
    (i) The quantity of gas produced from the offshore platform in the 
calendar year for sales, in thousand standard cubic feet.
    (ii) The quantity of oil produced from the offshore platform in the 
calendar year for sales, in barrels.
    (iii) The quantity of condensate produced from the offshore 
platform in the calendar year for sales, in barrels.
    (3) For natural gas processing, report the quantities specified in 
paragraphs (aa)(3)(i) through (aa)(3)(vii) of this section.
    (i) The quantity of produced gas received at the gas processing 
plant in the calendar year, in thousand standard cubic feet.
    (ii) The quantity of processed (residue) gas leaving the gas 
processing plant in the calendar year, in thousand standard cubic feet.
    (iii) The quantity of NGLs (bulk and fractionated) received at the 
gas processing plant in the calendar year, in barrels.
    (iv) The quantity of NGLs (bulk and fractionated) leaving the gas 
processing plant in the calendar year, in barrels.
    (v) Average mole fraction of CH4 in produced gas 
received.
    (vi) Average mole fraction of CO2 in produced gas 
received.
    (vii) Indicate whether the facility fractionates NGLs.
    (4) For natural gas transmission compression, report the quantity 
specified in paragraphs (aa)(4)(i) through (aa)(4)(v) of this section.
    (i) The quantity of gas transported through the compressor station 
in the calendar year, in thousand standard cubic feet.
    (ii) Number of compressors.
    (iii) Total compressor power rating of all compressors combined, in 
horsepower.
    (iv) Average upstream pipeline pressure, in pounds per square inch 
gauge.
    (v) Average downstream pipeline pressure, in pounds per square inch 
gauge.
    (5) For underground natural gas storage, report the quantities 
specified

[[Page 13459]]

in paragraphs (aa)(5)(i) through (aa)(5)(iii) of this section.
    (i) The quantity of gas injected into storage in the calendar year, 
in thousand standard cubic feet.
    (ii) The quantity of gas withdrawn from storage in the calendar 
year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (6) For LNG import equipment, report the quantity of LNG imported 
in the calendar year, in thousand standard cubic feet.
    (7) For LNG export equipment, report the quantity of LNG exported 
in the calendar year, in thousand standard cubic feet.
    (8) For LNG storage, report the quantities specified in paragraphs 
(aa)(8)(i) through (aa)(8)(iii) of this section.
    (i) The quantity of LNG added into storage in the calendar year, in 
thousand standard cubic feet.
    (ii) The quantity of LNG withdrawn from storage in the calendar 
year, in thousand standard cubic feet.
    (iii) Total storage capacity, in thousand standard cubic feet.
    (9) For natural gas distribution, report the quantities specified 
in paragraphs (aa)(9)(i) through (aa)(9)(vii) of this section.
    (i) The quantity of natural gas received at all custody transfer 
stations in the calendar year, in thousand standard cubic feet. This 
value may include meter corrections, but only for the calendar year 
covered by the annual report.
    (ii) The quantity of natural gas withdrawn from in-system storage 
in the calendar year, in thousand standard cubic feet.
    (iii) The quantity of natural gas added to in-system storage in the 
calendar year, in thousand standard cubic feet.
    (iv) The quantity of natural gas delivered to end users, in 
thousand standard cubic feet. This value does not include stolen gas, 
or gas that is otherwise unaccounted for.
    (v) The quantity of natural gas transferred to third parties such 
as other LDCs or pipelines, in thousand standard cubic feet. This value 
does not include stolen gas, or gas that is otherwise unaccounted for.
    (vi) The quantity of natural gas consumed by the LDC for 
operational purposes, in thousand standard cubic feet.
    (vii) The estimated quantity of gas stolen in the calendar year, in 
thousand standard cubic feet.
    (bb) For any missing data procedures used, report the information 
in paragraphs (bb)(1) through (bb)(5) in this section for each 
individual missing data value used in a calculation. Aggregation of 
missing data values within a component, well, sub-basin, or basin is 
not acceptable. If missing data is substituted for the same parameter 
in non-consecutive periods during the calendar year, the information in 
paragraphs (bb)(1) through (bb)(5) in this section should be reported 
for each period separately.
    (1) The date(s) the missing data is used.
    (2) The equation(s) in which the missing data is used.
    (3) The description of the unique or unusual circumstance that led 
to missing data use, including information on any equipment or 
components involved and any procedures that were not followed.
    (4) The description of the procedures used to substitute an 
unavailable value of a parameter.
    (5) The description of how the owner or operator will avoid the use 
of missing data in the future, such as mitigation strategies or changes 
to standard operating procedures.
0
9. Section 98.238 is amended by:
0
a. Adding a definition for ``Associated gas venting or flaring'' in 
alphabetical order;
0
b. Removing the definition for ``Component'';
0
c. Adding definitions for ``Compressor mode'' and ``Compressor source'' 
in alphabetical order;
0
d. Removing the definitions for ``Equipment leak'' and ``Equipment leak 
detection'';
0
e. Adding definitions for ``Manifolded compressor source'' and 
``Manifolded group of compressor sources'' in alphabetical order;
0
f. Revising the definition for ``Meter/regulator run'';
0
g. Adding definitions for ``Reduced emissions completion'' and 
``Reduced emissions workover'' in alphabetical order; and
0
h. Revising the definition for ``Sub-basin category, for onshore 
natural gas production''.
    The revisions and additions read as follows:


Sec.  98.238  Definitions.

* * * * *
    Associated gas venting or flaring means the venting or flaring of 
natural gas which 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. This 
does not include venting or flaring resulting from activities that are 
reported elsewhere, including tank venting, well completions, and well 
workovers.
* * * * *
    Compressor mode means the operational and pressurized status of a 
compressor. For a centrifugal compressor, ``mode'' refers to either 
operating -mode or not-operating-depressurized -mode. For a 
reciprocating compressor, ``mode'' refers to either: operating -mode, 
standby-pressurized -mode, or not-operating-depressurized -mode.
    Compressor source means any type of vent or valve (i.e., wet seal, 
blowdown valve, isolation valve, or rod packing) on a centrifugal or 
reciprocating compressor.
* * * * *
    Manifolded compressor source means a compressor source (as defined 
in this section) that is manifolded to a common vent that routes gas 
from multiple compressors.
    Manifolded group of compressor sources means a collection of any 
combination of manifolded compressor sources (as defined in this 
section) that are manifolded to a common vent.
    Meter/regulator run means a series of components used in regulating 
pressure or metering natural gas flow or both. At least one meter, at 
least on regulator, or any combination of both on a single run of 
piping is considered one meter/regulator run.
* * * * *
    Reduced emissions completion means a well completion following 
hydraulic fracturing where gas flowback that is otherwise vented is 
captured, cleaned, and routed to the flow line or collection system, 
re-injected into the well or another well, used as an on-site fuel 
source, or used for other useful purpose that a purchased fuel or raw 
material would serve, with no direct release to the atmosphere.
    Reduced emissions workover means a well workover with hydraulic 
fracturing (i.e., refracturing) where gas flowback that is otherwise 
vented is captured, cleaned, and routed to the flow line or collection 
system, re-injected into the well or another well, used as an on-site 
fuel source, or used for other useful purpose that a purchased fuel or 
raw material would serve, with no direct release to the atmosphere.
* * * * *
    Sub-basin category, for onshore natural gas production, means a 
subdivision of a basin into the unique combination of wells with the 
surface coordinates within the boundaries of an individual county and 
subsurface completion in one or more of each of the following five 
formation types: Oil, high

[[Page 13460]]

permeability gas, shale gas, coal seam, or other tight gas reservoir 
rock. The distinction between high permeability gas and tight gas 
reservoirs shall be designated as follows: High permeability gas 
reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs 
with <=0.1 millidarcy permeability. Permeability for a reservoir type 
shall be determined by engineering estimate. Wells that produce only 
from high permeability gas, shale gas, coal seam, or other tight gas 
reservoir rock are considered gas wells; gas wells producing from more 
than one of these formation types shall be classified into only one 
type based on the formation with the most contribution to production as 
determined by engineering knowledge. All wells that produce hydrocarbon 
liquids (with or without gas) and do not meet the definition of a gas 
well in this sub-basin category definition are considered to be in the 
oil formation. All emission sources that handle condensate from gas 
wells in high permeability gas, shale gas, or tight gas reservoir rock 
formations are considered to be in the formation that the gas well 
belongs to and not in the oil formation.
* * * * *
[FR Doc. 2014-04408 Filed 3-7-14; 8:45 am]
BILLING CODE 6560-50-P

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