Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards, 75177-75354 [2015-26486]

Download as PDF Vol. 80 Tuesday, No. 230 December 1, 2015 Part II Environmental Protection Agency tkelley on DSK3SPTVN1PROD with RULES2 40 CFR Parts 60 and 63 Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards; Final Rule VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00001 Fmt 4717 Sfmt 4717 E:\FR\FM\01DER2.SGM 01DER2 75178 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 60 and 63 [EPA–HQ–OAR–2010–0682; FRL–9935–40– OAR] RIN 2060–AQ75 Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards Environmental Protection Agency (EPA). ACTION: Final rule. AGENCY: This action finalizes the residual risk and technology review conducted for the Petroleum Refinery source categories regulated under national emission standards for hazardous air pollutants (NESHAP) Refinery MACT 1 and Refinery MACT 2. It also includes revisions to the Refinery MACT 1 and MACT 2 rules in accordance with provisions regarding establishment of MACT standards. This action also finalizes technical corrections and clarifications for the new source performance standards (NSPS) for petroleum refineries to improve consistency and clarity and address issues related to a 2008 industry petition for reconsideration. Implementation of this final rule will result in projected reductions of 5,200 tons per year (tpy) of hazardous air pollutants (HAP) which will reduce cancer risk and chronic health effects. DATES: This final action is effective on February 1, 2016. The incorporation by reference of certain publications for part 63 listed in the rule is approved by the Director of the Federal Register as of February 1, 2016. The incorporation by reference of certain publications for part 60 listed in the rule were approved by the Director of the Federal Register as of June 24, 2008. ADDRESSES: The Environmental Protection Agency (EPA) has established a docket for this action under Docket ID No. EPA–HQ–OAR–2010–0682. All documents in the docket are listed on the www.regulations.gov Web site. Although listed in the index, some information is not publicly available, e.g., confidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through https://www.regulations.gov, or in hard copy at the EPA Docket Center, WJC tkelley on DSK3SPTVN1PROD with RULES2 SUMMARY: VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 West Building, Room Number 3334, 1301 Constitution Ave. NW., Washington, DC. The Public Reading Room hours of operation are 8:30 a.m. to 4:30 p.m. Eastern Standard Time (EST), Monday through Friday. The telephone number for the Public Reading Room is (202) 566–1744, and the telephone number for the Air and Radiation Docket and Information Center is (202) 566–1742. FOR FURTHER INFORMATION CONTACT: For questions about this final action, contact Ms. Brenda Shine, Sector Policies and Programs Division, Refining and Chemicals Group (E143–01), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina, 27711; telephone number: (919) 541– 3608; fax number: (919) 541–0246; and email address: shine.brenda@epa.gov. For specific information regarding the risk modeling methodology, contact Mr. Ted Palma, Health and Environmental Impacts Division (C539–02), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541– 5470; fax number: (919) 541–0840; and email address: palma.ted@epa.gov. For information about the applicability of the NESHAP to a particular entity, contact Ms. Maria Malave, Office of Enforcement and Compliance Assurance, U.S. Environmental Protection Agency, William Jefferson Clinton Building, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564–7027; fax number: (202) 564–0050; and email address: malave.maria@epa.gov. SUPPLEMENTARY INFORMATION: Preamble Acronyms and Abbreviations. We use multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here: 10/25 tpy emissions equal to or greater than 10 tons per year of a single pollutant or 25 tons per year of cumulative pollutants AEGL acute exposure guideline levels APCD air pollution control devices API American Petroleum Institute BAAQMD Bay Area Air Quality Management District BDT best demonstrated technology BLD bag leak detectors BSER best system of emission reductions Btu/ft2 British thermal units per square foot Btu/scf British thermal units per standard cubic foot CAA Clean Air Act CBI confidential business information CCU catalytic cracking units CDX Central Data Exchange PO 00000 Frm 00002 Fmt 4701 Sfmt 4700 CEDRI Compliance and Emissions Data Reporting Interface CEMS continuous emission monitoring system CFR Code of Federal Regulations CO carbon monoxide CO2 carbon dioxide CO2e carbon dioxide equivalents COMS continuous opacity monitoring system COS carbonyl sulfide CPMS continuous parameter monitoring system CRA Congressional Review Act CRU catalytic reforming units CS2 carbon disulfide DCU delayed coking units EPA Environmental Protection Agency ERPG emergency response and planning guidelines ERT Electronic Reporting Tool ESP electrostatic precipitator FCCU fluid catalytic cracking unit FGCD fuel gas combustion device FMP flare management plan FR Federal Register FTIR Fourier transform infrared spectroscopy GC gas chromatograph GHG greenhouse gases H2S hydrogen sulfide HAP hazardous air pollutants HCl hydrogen chloride HCN hydrogen cyanide HF hydrogen fluoride HFC highest fenceline concentration HI hazard index HQ hazard quotient ICR information collection request IRIS Integrated Risk Information System km kilometers LAER lowest achievable emission rate lb/day pounds per day LDAR leak detection and repair LEL lower explosive limit LTD long tons per day MACT maximum achievable control technology MIR maximum individual risk mph miles per hour MPV miscellaneous process vent NAICS North American Industry Classification System NESHAP National Emissions Standards for Hazardous Air Pollutants NFS near-field interfering source NHVCZ combustion zone net heating value Ni nickel NOX nitrogen oxides NRDC Natural Resources Defense Council NSPS new source performance standards NTTAA National Technology Transfer and Advancement Act OAQPS Office of Air Quality Planning and standards OECA Office of Enforcement and Compliance Assurance OEHHA Office of Environmental Health Hazard Assessment OEL open-ended line OMB Office of Management and Budget PM particulate matter PM2.5 particulate matter 2.5 micrometers in diameter and smaller ppbv parts per billion by volume ppm parts per million E:\FR\FM\01DER2.SGM 01DER2 75179 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations ppmv parts per million by volume PRA Paperwork Reduction Act PRD pressure relief device 1 psia pounds per square inch absolute psig pounds per square inch gauge REL reference exposure level REM Model Refinery Emissions Model RFA Regulatory Flexibility Act RTC response to comment RTR Risk and Technology Review SAB Science Advisory Board SBA Small Business Administration SCAQMD South Coast Air Quality Management District SCR selective catalytic reduction SISNOSE significant economic impact on a substantial number of small entities SO2 sulfur dioxide SRP sulfur recovery plant SRU sulfur recovery unit SSM startup, shutdown and malfunction TOSHI target organ-specific hazard index tpy tons per year UMRA Unfunded Mandates Reform Act URE unit risk estimate UV–DOAS ultraviolet differential optical absorption spectroscopy VCS voluntary consensus standards VOC volatile organic compounds °F degrees Fahrenheit DC the concentration difference between the highest measured concentration and the lowest measured concentration mg/m3 micrograms per cubic meter tkelley on DSK3SPTVN1PROD with RULES2 Background Information. On June 30, 2014, the EPA proposed revisions to both of the petroleum refinery NESHAP based on our residual risk and technology review (RTR). In that action, we also proposed to revise the NESHAP pursuant to CAA section 112(d)(2) and (3), to revise the SSM provisions in the NESHAP, and to make technical corrections to the NSPS to address issues related to reconsideration of the final NSPS subpart Ja rule in 2008. In this action, we are finalizing decisions and revisions for these rules. We summarize some of the more significant comments received regarding the proposed rule and provide our responses in this preamble. A summary of all other public comments on the proposal and the EPA’s responses to those comments is provided in the ‘‘Response to Comment’’ document, which is available in Docket ID No. EPA–HQ–OAR–2010–0682. The ‘‘track changes’’ version of the regulatory language that incorporates the changes in this final action is also available in the docket for this rulemaking. Organization of this Document. This preamble is organized as follows: I. General Information A. Does this action apply to me? B. Where can I get a copy of this document and other related information? 1 This term is common vernacular to describe the variety of devices regulated as pressure relief valves subject to the requirements in 40 CFR part 63 subpart CC. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 C. Judicial Review and Administrative Reconsideration II. Background A. What is the statutory authority for this action? B. How do the NESHAP and NSPS regulate air pollutant emissions from refineries? C. What changes did we propose for the Petroleum Refinery NESHAP and NSPS in our June 30, 2014 RTR proposal? III. What is included in this final rule? A. What are the final NESHAP amendments based on the risk review for the Petroleum Refinery source categories? B. What are the final NESHAP amendments based on the technology review for the Petroleum Refinery source categories? C. What are the final NESHAP amendments pursuant to section 112(d)(2) & (3) for the Petroleum Refinery source categories? D. What are the final NESHAP amendments addressing emissions during periods of SSM? E. What other revisions to the NESHAP and NSPS are being promulgated? F. What are the requirements for submission of performance test data to the EPA? G. What are the effective and compliance dates of the NESHAP and NSPS? H. What materials are being incorporated by reference? IV. What is the rationale for our final decisions and amendments to the Petroleum Refinery NESHAP and NSPS? A. Residual Risk Review for the Petroleum Refinery Source Categories B. Technology Review for the Petroleum Refinery Source Categories C. Refinery MACT Amendments Pursuant to CAA section 112(d)(2) and (d)(3) D. NESHAP Amendments Addressing Emissions During Periods of SSM E. Technical Amendments to Refinery MACT 1 and 2 F. Technical Amendments to Refinery NSPS Subparts J and Ja V. Summary of Cost, Environmental, and Economic Impacts and Additional Analyses Conducted A. What are the affected facilities, the air quality impacts and cost impacts? B. What are the economic impacts? C. What are the benefits? D. Impacts of This Rulemaking on Environmental Justice Populations E. Impacts of This Rulemaking on Children’s Health VI. Statutory and Executive Order Reviews A. Executive Orders 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Reduction Act (PRA) C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act (UMRA) E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks PO 00000 Frm 00003 Fmt 4701 Sfmt 4700 H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution or Use I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR part 51 J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations K. Congressional Review Act (CRA) I. General Information A. Does this action apply to me? Regulated Entities. Categories and entities potentially regulated by this action are shown in Table 1 of this preamble. TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS FINAL ACTION NAICS a Code NESHAP and source category Petroleum Refining Industry ......... a North American Industry 324110 Classification System. Table 1 of this preamble is not intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be affected by the final action for the source categories listed. To determine whether your facility is affected, you should examine the applicability criteria in the appropriate NESHAP or NSPS. If you have any questions regarding the applicability of any aspect of these NESHAP or NSPS, please contact the appropriate person listed in the preceding FOR FURTHER INFORMATION CONTACT section of this preamble. B. Where can I get a copy of this document and other related information? In addition to being available in the docket, an electronic copy of this final action will also be available on the Internet through the Technology Transfer Network (TTN) Web site, a forum for information and technology exchange in various areas of air pollution control. Following signature by the EPA Administrator, the EPA will post a copy of this final action at: https://www.epa.gov/ttn/atw/petref.html. Following publication in the Federal Register, the EPA will post the Federal Register version and key technical documents at this same Web site. Additional information is available on the RTR Web site at https://www.epa. gov/ttn/atw/rrisk/rtrpg.html. This information includes an overview of the RTR program, links to project Web sites E:\FR\FM\01DER2.SGM 01DER2 75180 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations for the RTR source categories, and detailed emissions and other data we used as inputs to the risk assessments. C. Judicial Review and Administrative Reconsideration Under CAA section 307(b)(1), judicial review of this final action is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by February 1, 2016. Under CAA section 307(b)(2), the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce the requirements. Section 307(d)(7)(B) of the CAA further provides that ‘‘[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.’’ This section also provides a mechanism for the EPA to reconsider the rule ‘‘[i]f the person raising an objection can demonstrate to the Administrator that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.’’ Any person seeking to make such a demonstration should submit a Petition for Reconsideration to the Office of the Administrator, U.S. EPA, Room 3000, WJC Building, 1200 Pennsylvania Ave. NW., Washington, DC 20460, with a copy to both the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT section, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 Pennsylvania Ave. NW., Washington, DC 20460. II. Background tkelley on DSK3SPTVN1PROD with RULES2 A. What is the statutory authority for this action? 1. NESHAP Section 112 of the CAA establishes a two-stage regulatory process to address emissions of hazardous air pollutants (HAP) from stationary sources. In the first stage, we must identify categories of sources emitting one or more of the HAP listed in CAA section 112(b) and then promulgate technology-based NESHAP for those sources. ‘‘Major sources’’ are those that emit, or have the potential to emit, any single HAP at a rate of 10 tons per year (tpy) or more, or 25 tpy or more of any combination of VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 HAP. For major sources, these standards are commonly referred to as maximum achievable control technology (MACT) standards and must reflect the maximum degree of emission reductions of HAP achievable (after considering cost, energy requirements, and non-air quality health and environmental impacts). In developing MACT standards, CAA section 112(d)(2) directs the EPA to consider the application of measures, processes, methods, systems or techniques, including but not limited to those that reduce the volume of or eliminate HAP emissions through process changes, substitution of materials, or other modifications; enclose systems or processes to eliminate emissions; collect, capture, or treat HAP when released from a process, stack, storage, or fugitive emissions point; are design, equipment, work practice, or operational standards; or any combination of the above. For these MACT standards, the statute specifies certain minimum stringency requirements, which are referred to as MACT floor requirements, and which may not be based on cost considerations. See CAA section 112(d)(3). For new sources, the MACT floor cannot be less stringent than the emission control achieved in practice by the best-controlled similar source. The MACT standards for existing sources can be less stringent than floors for new sources, but they cannot be less stringent than the average emission limitation achieved by the bestperforming 12-percent of existing sources in the category or subcategory (or the best-performing 5 sources for categories or subcategories with fewer than 30 sources). In developing MACT standards, we must also consider control options that are more stringent than the floor, under CAA section 112(d)(2). We may establish standards more stringent than the floor, based on the consideration of the cost of achieving the emissions reductions, any non-air quality health and environmental impacts, and energy requirements. In the second stage of the regulatory process, the CAA requires the EPA to undertake 2 different analyses, which we refer to as the technology review and the residual risk review. Under the technology review, we must review the technology-based standards and revise them ‘‘as necessary (taking into account developments in practices, processes, and control technologies)’’ no less frequently than every eight years, pursuant to CAA section 112(d)(6). Under the residual risk review, we must evaluate the risk to public health remaining after application of the PO 00000 Frm 00004 Fmt 4701 Sfmt 4700 technology-based standards and revise the standards, if necessary, to provide an ample margin of safety to protect public health or to prevent, taking into consideration costs, energy, safety and other relevant factors, an adverse environmental effect. The residual risk review is required within eight years after promulgation of the technologybased standards, pursuant to CAA section 112(f). In conducting the residual risk review, if the EPA determines that the current standards provide an ample margin of safety to protect public health, it is not necessary to revise the MACT standards pursuant to CAA section 112(f).2 For more information on the statutory authority for this rule, see 79 FR 36879. 2. NSPS Section 111 of the CAA establishes mechanisms for controlling emissions of air pollutants from stationary sources. Section 111(b) of the CAA provides authority for the EPA to promulgate NSPS that apply only to newly constructed, reconstructed and modified sources. Once the EPA has elected to set NSPS for new and modified sources in a given source category, CAA section 111(d) calls for regulation of existing sources, with certain exceptions explained below. Specifically, section 111(b) of the CAA requires the EPA to establish emission standards for any category of new and modified stationary sources that the Administrator, in his or her judgment, finds ‘‘causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.’’ The EPA has previously made endangerment findings under this section of the CAA for more than 60 stationary source categories and subcategories that are now subject to NSPS. Section 111 of the CAA gives the EPA significant discretion to identify the affected facilities within a source category that should be regulated. To define the affected facilities, the EPA can use size thresholds for regulation and create subcategories based on source type, class or size. Emission limits also may be established either for equipment within a facility or for an entire facility. For listed source categories, the EPA must establish ‘‘standards of performance’’ that apply 2 The U.S. Court of Appeals has affirmed this approach of implementing CAA section 112(f)(2)(A): NRDC v. EPA, 529 F.3d 1077, 1083 (D.C. Cir. 2008) (‘‘If EPA determines that the existing technology-based standards provide an ‘ample margin of safety,’ then the Agency is free to readopt those standards during the residual risk rulemaking.’’). E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations to sources that are constructed, modified or reconstructed after the EPA proposes the NSPS for the relevant source category.3 The EPA also has significant discretion to determine the appropriate level for the standards. Section 111(a)(1) of the CAA provides that NSPS are to reflect the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. This level of control is commonly referred to as best demonstrated technology (BDT) or the best system of emission reduction (BSER). The standard that the EPA develops, based on the BSER achievable at that source, is commonly a numerical emission limit, expressed as a performance level (i.e., a rate-based standard). Generally, the EPA does not prescribe a particular technological system that must be used to comply with a NSPS. Rather, sources remain free to elect whatever combination of measures will achieve equivalent or greater control of emissions. Costs are also considered in evaluating the appropriate standard of performance for each category or subcategory. The EPA generally compares control options and estimated costs and emission impacts of multiple, specific emission standard options under consideration. As part of this analysis, the EPA considers numerous factors relating to the potential cost of the regulation, including industry organization and market structure, control options available to reduce emissions of the regulated pollutant(s) and costs of these controls. tkelley on DSK3SPTVN1PROD with RULES2 B. How do the NESHAP and NSPS regulate air pollutant emissions from refineries? The EPA promulgated the petroleum refinery NESHAP pursuant to CAA section 112(d)(2) and (3) for refineries located at major sources in two separate rules. On August 18, 1995, the first 3 Specific statutory and regulatory provisions define what constitutes a modification or reconstruction of a facility. 40 CFR 60.14 provides that an existing facility is modified and, therefore, subject to an NSPS, if it undergoes any physical change in the method of operation which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted. 40 CFR 60.15, in turn, provides that a facility is reconstructed if components are replaced at an existing facility to such an extent that the capital cost of the new equipment/components exceed 50-percent of what is believed to be the cost of a completely new facility. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 petroleum refinery MACT standard was promulgated in 40 CFR part 63, subpart CC (60 FR 43620). This rule is known as ‘‘Refinery MACT 1’’ and covers the ‘‘Sources Not Distinctly Listed,’’ meaning it includes all emissions sources from petroleum refinery process units, except those listed separately under the section 112(c) source category list and expected to be regulated by other MACT standards (for example, boilers and process heaters). Some of the emission sources regulated in Refinery MACT 1 include miscellaneous process vents (MPV), storage vessels, wastewater, equipment leaks, gasoline loading racks, marine tank vessel loading and heat exchange systems. On April 11, 2002 (67 FR 17762), EPA promulgated a second MACT standard regulating certain process vents that were listed as a separate source category under CAA section 112(c) and that were not addressed as part of the Refinery MACT 1. This standard, which is referred to as ‘‘Refinery MACT 2’’, covers process vents on catalytic cracking units (CCU) (including FCCU), CRU and SRU and is codified as 40 CFR part 63, subpart UUU. Finally, on October 28, 2009, we revised Refinery MACT 1 by adding MACT standards for heat exchange systems, which the EPA had not addressed in the original 1995 Refinery MACT 1 rule (74 FR 55686). In this same 2009 action, we updated the crossreferences to the General Provisions in 40 CFR part 63. On June 20, 2013 (78 FR 37133), we promulgated minor revisions to the heat exchange provisions of Refinery MACT 1. On September 27, 2012, Air Alliance Houston, California Communities Against Toxics and other environmental and public health groups filed a lawsuit alleging that the EPA missed statutory deadlines to review and revise Refinery MACT 1 and 2. The EPA reached an agreement to settle that litigation and entered into a Consent Decree. The Consent Decree provides for the Administrator to sign a final action no later than September 30, 2015. Refinery NSPS subparts J and Ja regulated criteria pollutant emissions, including particulate matter (PM), sulfur dioxide (SO2), nitrogen oxides (NOX) and carbon monoxide (CO) from FCCU catalyst regenerators, fuel gas combustion devices (FGCD) and sulfur recovery plants. Refinery NSPS subpart Ja also regulates criteria pollutant emissions from fluid coking units and DCU. The NSPS for petroleum refineries (40 CFR part 60, subpart J) were promulgated in 1974, amended in 1976 and amended again in 2008, following PO 00000 Frm 00005 Fmt 4701 Sfmt 4700 75181 a review of the standards. As part of the review that led to the 2008 amendments to the Refinery NSPS subpart J, the EPA developed separate standards of performance for new process units (40 CFR part 60, subpart Ja). However, the EPA received multiple petitions for reconsideration on issues related to those standards. The Administrator granted the petitions for reconsideration. The EPA addressed petition issues related to process heaters and flares by promulgating amendments to the Refinery NSPS subparts J and Ja on September 12, 2012 (77 FR 56422). In this action, we are finalizing technical corrections and clarifications to NSPS subparts J and Ja raised by American Petroleum Institute (API) in their 2008 petition for reconsideration that were not addressed by the final NSPS amendments of 2012. The petroleum refining industry consists of facilities that engage in converting crude oil into refined products, including liquefied petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel oils, lubricating oils and feedstocks for the petrochemical industry. Currently, 142 facilities have emission sources regulated by either or both Refinery MACT 1 and 2. Petroleum refinery activities start with the receipt of crude oil for storage at the refinery, include all the petroleum handling and refining operations, and terminate with loading of refined products into pipelines, tank or rail cars, tank trucks, or ships or barges that take products from the refinery to distribution centers. Petroleum-specific process units include FCCU and CRU. Other units and processes found at petroleum refineries (as well as at many other types of manufacturing facilities) include storage vessels and wastewater treatment plants. HAP emitted by this industry include organics (e.g., acetaldehyde, benzene, formaldehyde, hexane, phenol, naphthalene, 2methylnaphthalene, dioxins, furans, ethyl benzene, toluene and xylene); reduced sulfur compounds (i.e., carbonyl sulfide (COS), carbon disulfide (CS2))); inorganics (e.g., hydrogen chloride (HCl), hydrogen cyanide (HCN), chlorine, hydrogen fluoride (HF)); and metals (e.g., antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, mercury, manganese and nickel (Ni)). This industry also emits criteria pollutants and other non-HAP, including NOX, PM, SO2, volatile organic compounds (VOC), CO, greenhouse gases (GHG) and total reduced sulfur. E:\FR\FM\01DER2.SGM 01DER2 75182 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 C. What changes did we propose for the Petroleum Refinery NESHAP and NSPS in our June 30, 2014, RTR proposal? On June 30, 2014, the EPA published a proposed rule in the Federal Register addressing the RTR for the Petroleum Refinery NESHAP, 40 CFR part 63, subparts CC and UUU. The proposal also included changes pursuant to section 112(d)(2) and (3) and technical revisions to the NSPS. Specifically, we proposed: (1) Pursuant to CAA sections 112(d)(2) and (3): a. Refinery MACT 1: • Adding MACT Standards for DCU decoking operations. • Adding operational requirements for flares used as APCD in Refinery MACT 1 and 2. • Adding requirements and clarifications for vent control bypasses in Refinery MACT 1. b. Refinery MACT 2: • Revising the CRU purge vent exemption. (2) Pursuant to CAA sections 112(d)(6) and 112(f)(2): • Revising Refinery MACT 1 to crossreference the corresponding storage vessel requirements in the Generic MACT (40 CFR part 63, subpart WW, as applicable), and revising the definition of Group 1 storage vessels to include smaller capacity storage vessels and to include storage vessels storing materials with lower vapor pressures. (3) Pursuant to CAA section 112(d)(6): a. Refinery MACT 1: • Allowing refineries to meet the leak detection and repair (LDAR) requirements in Refinery MACT 1 by monitoring for leaks using optical gas imaging in place of EPA Method 21, once the monitoring protocol set forth in Appendix K is promulgated. • Amending the Marine Tank Vessel Loading Operations NESHAP, 40 CFR part 63, subpart Y, to delete the exclusion for marine vessel loading operations at petroleum refineries. • Establishing a fenceline monitoring work practice standard to improve the management of fugitive emissions. b. Refinery MACT 2: • Incorporating requirements consistent with those in Refinery NSPS subpart Ja for FCCU including: • Requiring the use of 3-hour averages rather than daily averages for parameter operating limits (e.g., depending on the type of control device: Opacity, total power, secondary current, pressure drop, and/or liquid-to-gas ratio). • Removing the Refinery NSPS subpart J incremental PM emissions allowance for post combustion devices VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 when burning liquid or solid fuels, and removing the 30 percent opacity limit for units complying with NSPS subpart J. • Adding requirements for FCCU controls to include bag leak detectors (BLD) as an option to continuous opacity monitoring system (COMS). • Incorporating total power and the secondary current operating limits for electrostatic precipitators (ESP). • Requiring daily checks of the air or water pressure to the spray nozzles on jet ejector-type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles. • Requiring FCCU periodic performance testing on a frequency of once every 5 years, as opposed to the current rule, which only requires an initial performance test. • Including a correlation equation for the use of oxygen-enriched air for SRU. • Allowing SRU subject to Refinery NSPS subpart Ja with a capacity greater than 20 long tons per day (LTD) to comply with Refinery NSPS subpart Ja as a means of complying with Refinery MACT 2. (4) Other proposed changes include: • Removing exemptions from the rule requirements for periods of SSM in order to ensure that the NESHAP are consistent with the court decision in Sierra Club v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008). • Clarifying requirements related to open-ended valves or lines. • Adding electronic reporting requirements. • Updating the General Provisions cross-reference tables. • Making technical corrections and clarifications to NSPS subparts J and Ja. subparts J and Ja to address issues raised in the reconsideration of these rules. III. What is included in this final rule? This action finalizes the EPA’s determinations pursuant to the RTR provisions of CAA section 112 for the Petroleum Refinery source categories and amends the Petroleum Refinery NESHAP based on those determinations. This action also finalizes other changes to the NESHAP including revising Refinery MACT 1 and 2 pursuant to CAA section 112 (d)(2) and (3), including revising requirements for flares and pressure relief devices (PRD). This action finalizes changes to the SSM provisions to ensure that the subparts are consistent with the court decision in Sierra Club v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), adds electronic reporting requirements in Refinery MACT 1 and 2; and updates the General Provisions cross-reference tables. Finally, this action finalizes technical corrections and clarifications to Refinery NSPS We determined that there are developments in practices, processes and control technologies that warrant revisions to the MACT standards for this source category. Therefore, to satisfy the requirements of CAA section 112(d)(6), we are revising the MACT standards to amend 40 CFR part 63, subpart Y to delete the exclusion for marine vessel loading operations at petroleum refineries. Removing this exclusion will require small marine vessel loading operations (i.e., operations with HAP emissions less than 10/25 tpy) and offshore marine vessel loading operations to use submerged filling based on the cargo filling line requirements in 46 CFR 153.282, as proposed. We are also finalizing a fenceline monitoring work practice standard to improve the management of fugitive emissions and finalizing EPA Methods 325A and 325B to support the work PO 00000 Frm 00006 Fmt 4701 Sfmt 4700 A. What are the final NESHAP amendments based on the risk review for the Petroleum Refinery source categories? The EPA is promulgating final amendments to the Petroleum Refinery NESHAP pursuant to CAA section 112(f) that expand the existing Refinery MACT 1 control requirements and extend these requirements to smaller tanks and tanks with lower vapor pressures. Specifically, consistent with the proposal, the EPA is amending Refinery MACT 1 by revising the definition of Group 1 storage vessels to include storage vessels with capacities greater than or equal to 20,000 gallons but less than 40,000 gallons if the maximum true vapor pressure is 1.0 psia or greater and to include storage tanks greater than 40,000 gallons if the maximum true vapor pressure is 0.75 psia or greater. The EPA is also adding a cross-reference to the storage vessel requirements in the Generic MACT (40 CFR part 63, subpart WW and subpart CC), which include requirements for guide pole controls and other fittings as well as inspection requirements. After considering the public comments, the final amendments include minor changes from our proposed requirements to clarify language and correct typographical and referencing errors. B. What are the final NESHAP amendments based on the technology review for the Petroleum Refinery source categories? 1. Refinery MACT 1 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 practice, with some changes from proposal to address issues raised by commenters. Key revisions include: New provisions for reduced monitoring for facilities with consistently low fenceline concentrations; requirements for alternatives to passive monitoring; revised placement guidance to allow perimeter monitoring within a facility’s property boundary provided all sources are encompassed within the monitoring perimeter; reductions in the number of monitors required for subareas and segregated areas; clarifications on monitor placement for internal roadways or other right-of-ways and marine docks; and revised timelines for submitting periodic reports (quarterly rather than semiannually) and implementing the work practice standard (2 years after promulgation rather than 3 years as proposed). We are also revising Refinery MACT 1 storage vessel requirements as described above under the risk review, as proposed. 2. Refinery MACT 2 We determined that there are developments in practices, processes and control technologies that warrant revisions to the MACT standards for this source category. Therefore, to satisfy the requirements of CAA section 112(d)(6), we are revising the Refinery MACT 2 standard for FCCU subject to Refinery NSPS subpart J or those electing to comply with the Refinery NSPS subpart J requirements. As proposed, we are removing the incremental PM limit when burning liquid or solid fuels. We are finalizing a 20-percent opacity operating limit evaluated on a 3-hour average, which differs from the proposal to eliminate the 30-percent opacity limit and instead allow only for a site-specific opacity operating limit or control device parameter monitoring. As proposed, we are finalizing requirements to make Refinery MACT 2 consistent with Refinery NSPS subpart Ja for FCCU by including 3-hour averages rather than daily averages for parameter operating limits, and by including 3-hour averages rather than daily averages for the sitespecific opacity operating limit. We are also finalizing requirements, as proposed, for FCCU controls to include adding BLD as an option to COMS, incorporating total power and the secondary current operating limits for ESP and requiring daily checks of the air or water pressure to the spray nozzles on jet ejector-type wet scrubbers or other types of wet scrubbers equipped with atomizing spray nozzles. Finally, we are finalizing, as proposed, requirements for FCCU periodic performance testing at a frequency of once every 5 years rather VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 than the current requirements for a onetime initial performance test. However, for owners or operators complying with the Refinery NSPS subpart J option (with the 20-percent opacity operating limit discussed above), if the PM emissions are within 80-percent of the PM limit during any periodic performance test (i.e., emissions exceed 0.8 lb PM/1,000 lbs of coke burn-off), the refinery owner or operator must conduct subsequent performance tests on an annual basis. Based on comments received, we are also adding requirements in the final rule for owners or operators of FCCU to conduct a onetime test for HCN emissions from the FCCU concurrent with their first periodic performance test, which must be conducted on or before August 1, 2017 for all FCCU subject to Refinery MACT 2. For SRU, as proposed, we are finalizing a correlation equation for the use of oxygen-enriched air. Additionally, as proposed, we are finalizing requirements to allow sulfur recovery plants subject to Refinery NSPS subpart Ja with a capacity greater than 20 LTD to comply with Refinery NSPS subpart Ja as a means of complying with Refinery MACT 2. C. What are the final NESHAP amendments pursuant to section 112(d)(2) & (3) for the Petroleum Refinery source categories? 1. Refinery MACT 1 We are finalizing MACT standards for DCU decoking operations that require that each coke drum be depressured to a closed blowdown system until the coke drum pressure is 2 psig with minor revisions from proposal. Specifically, we are finalizing provisions for existing DCU affected sources to average over a 60-cycle (i.e., 60 batch) basis to comply with the 2 psig limit, rather than the proposed requirement to meet the 2 psig limit on a per venting event basis. In addition, we are finalizing requirements for new DCU affected sources to depressure to 2.0 psig on a per-event, not-to-exceed basis, adding one significant digit to the limit for new DCU affected sources. For both new and existing DCU affected sources, we are finalizing specific provisions for DCU with water overflow design and for double quenching. We are finalizing operational requirements and the associated monitoring, recordkeeping and reporting requirements for flares used as APCD in Refinery MACT 1 and 2 with revisions to the requirements proposed. Prior to these amendments, Refinery MACT 1 and 2 cross-referenced the PO 00000 Frm 00007 Fmt 4701 Sfmt 4700 75183 General Provisions requirements at 40 CFR 63.11(b). As proposed, this final action replaces the cross reference to the General Provisions and incorporates enhanced flare operational requirements directly into the Refinery MACT regulations. As proposed, the final rule amendments require that refinery flares operate with continuously lit pilot flames at all times. Consistent with our proposal, we are finalizing requirements for flares to operate with no visible emissions and comply with consolidated requirements related to flare tip velocity, but in the final rule these direct emissions limits apply when flare vent gas flow is below the smokeless capacity of the flare rather than at all times. Above the smokeless capacity of the flare, we are establishing a work practice standard related to the visible emissions and velocity limits; these work practice standards are described in more detail in section III.D.1 of this preamble. We are finalizing new operational requirements related to combustion zone gas properties with revisions from proposal. In response to comments on the proposal, we are finalizing requirements that flares meet a minimum operating limit of 270 BTU/ scf NHVcz on a 15-minute average, and are allowing refinery owners or operators to use a corrected heat content of 1,212 BTU/scf for hydrogen to demonstrate compliance with this operating limit. We had proposed two separate sets of limits, one being more stringent if an olefins/hydrogen mixture was present in the waste gas. For each set of limits, we proposed three different alternative combustion zone operating limits: One based on the combustion zone net heat content with no correction for the heat content of hydrogen, one based on the lower flammability limit and one based on the combustibles concentration. We proposed that these limits be determined on a 15-minute ‘‘feed-forward’’ block average approach (i.e., compositional data are collected every 15 minutes, after which adjustments are made). We have included an additional option for refiners to comply where more frequent data are collected (using direct net heating value monitoring) to calculate the combustion limit using net heating value data from the same 15-minute block period. We are simplifying the compliance approach to a single operating limit based only on the combustion zone net heating value (with a hydrogen correction). As proposed, we are requiring refinery owners or operators to characterize the composition of waste gas, assist gas and E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75184 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations fuel to demonstrate compliance with the operational requirements. As proposed, we are also finalizing in this rule a burden reduction option to use grab sampling every 8 hours rather than continuous vent gas composition or heat content monitors. We are also including, based on public comment, provisions to conduct limited initial sampling and process knowledge to characterize flare gas composition for flares in ‘‘dedicated’’ service as an alternative to collecting grab samples during each specific event. We are finalizing a requirement for daily visible emissions observations as proposed, but, based on public comment, we are allowing owners or operators to use video surveillance cameras to demonstrate compliance with the visible emissions limit as an alternative to the daily visible emissions observations. For PRD, we are finalizing requirements for monitoring systems that are capable of identifying and recording the time and duration of each pressure release to the atmosphere, as proposed. Certain PRD with low set pressures or low emission potential or in liquid service would not be subject to these monitoring requirements. We are finalizing requirements to minimize or prevent atmospheric releases of HAP through PRD. Instead of the proposed prohibition on such releases, we are finalizing work practice requirements that require both preventive measures as well as root cause analysis and corrective action that will incentivize refinery owners or operators to eliminate the causes of the releases. We are finalizing requirements for bypass lines with minor revisions from those proposed. Specifically, we are not adopting the proposed requirement to install quantitative flow monitors and thus are leaving in place the requirement to use flow indicators on bypass lines. In addition, we are maintaining the requirements to estimate and report the quantity of organic HAP released. In response to public comment, we are also clarifying changes to remove the proposed reference to air intrusion and specifying that reporting of bypasses is only required when ‘‘regulated material’’ is discharged to the atmosphere as a result of a bypass of a control device. We are also finalizing revisions to the definition of miscellaneous process vent, as proposed. These revisions include deletion of exclusions associated with episodic releases and vents from in situ sampling systems. As proposed, the final amendments require that these vents must meet the standards applicable to MPV. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 2. Refinery MACT 2 For CRU vents, we are finalizing the vessel pressure limit exclusion of 5 psig to apply only to passive depressurization, as proposed. D. What are the final NESHAP amendments addressing emissions during periods of SSM? We are finalizing, as proposed, changes to Refinery MACT 1 and 2 to eliminate the SSM exemption. Consistent with Sierra Club v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), the EPA has established standards in this rule that apply at all times. EPA is revising Table 6 of subpart CC of 40 CFR part 63 and Table 44 to subpart UUU of 40 CFR part 63 (the General Provisions Applicability Tables) to change several references related to requirements that apply during periods of SSM. We also are eliminating or revising certain recordkeeping and reporting requirements related to the eliminated SSM exemptions. We also are removing or modifying inappropriate, unnecessary or redundant language in the absence of the SSM exemption. Further, for certain emission sources in both MACT 1 and 2, we are establishing standards to address emissions during these periods. These are described below. 1. Refinery MACT 1 We are finalizing a work practice standard for PRD that requires refinery owners or operators to establish prevention measures for each PRD in organic HAP service. Under the work practice standard, where a direct release occurs, the refinery is required to perform root cause analysis and implement corrective action. The work practice standard also limits the number of events that a PRD may release to the atmosphere during a 3-year period, as explained further in the section IV.D. of this preamble. We are also finalizing a work practice standard for emergency flaring events that requires refinery owners or operators to establish prevention measures, including the development of a flare management plan (FMP), and perform root cause analysis and implement corrective action following flaring events during which the velocity of waste gas going to the flare or visible emissions limits (i.e., opacity) at the flare tip are exceeded, and to limit the number of these events allowed in a 3year period, as explained further in section IV.D. of this preamble. Both of these work practice standards are consistent with the EPA’s goal to improve the effectiveness of the rules. PO 00000 Frm 00008 Fmt 4701 Sfmt 4700 These requirements will provide a strong incentive for facilities, over time, to better operate their processes to prevent PRD and flare releases. We are also finalizing requirements for opening process equipment to the atmosphere during maintenance events after draining and purging to a closed system, provided the hydrocarbon content is less than or equal to 10percent of the lower explosive limit (LEL). For those situations where 10percent LEL cannot be demonstrated, the equipment may be opened and vented to the atmosphere if the pressure is less than or equal to 5 psig, provided there is no active purging of the equipment to the atmosphere until the LEL criterion is met. This 5 psig allowance is only available during shutdown. We are also providing additional allowances for situations where it is not technically feasible to depressurize a control system where there is no more than 72 lbs VOC per day vented to the atmosphere, consistent with our Group 1 applicability cutoff for control of process vents, or for catalyst changeout activities where hydrotreater pyrophoric catalyst must be purged. Provisions to demonstrate that process equipment is opened only after the LEL, pressure or mass in the vessel requirement is met includes documenting the procedures for equipment openings and procedures for verifying that the openings meet the specific, above-discussed requirements using site-specific procedures used to de-inventory equipment for safety purposes (i.e., hot work or vessel entry procedures). 2. Refinery MACT 2 The Refinery MACT 2 standards regulate all HAP emissions from the three refinery process vents subject to Refinery MACT 2. For FCCU, the standard specifies a CO limit as a surrogate for organic HAP and specifies a PM limit (or Ni limit) as a surrogate for metal HAP. Compliance with the organic HAP emissions limit is demonstrated using a continuous CO monitor; compliance with the metal HAP emissions limit is demonstrated using either COMS or control device parameter monitoring systems (CPMS). At proposal, with the removal of the exemptions in the Refinery MACT 2 rule for periods of startup and shutdown, we recognized the need for alternative standards during some startup and shutdown situations, and we proposed alternative requirements. For this final rule, we are including a 1-percent minimum oxygen limit as an alternative to the 500 ppmv hourly CO limit during FCCU startup for partial E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations burn FCCU with CO boilers, as proposed. We are extending that alternative limit to all FCCU and extending it to apply during shutdown. We are not finalizing the proposed alternative opacity limit for FCCU during startup. Instead, based on public comments received, we are finalizing an alternative minimum cyclone face velocity limit as a means to demonstrate compliance with the PM limit during both startup and shutdown, regardless of the type of FCCU and its control device. We are finalizing alternative standards for sulfur recovery plant (SRP) incinerator temperature and excess oxygen limits during SRP shutdown, as proposed, and we are extending the proposed alternative standards to startup as well. tkelley on DSK3SPTVN1PROD with RULES2 E. What other revisions to the NESHAP and NSPS are being promulgated? We are finalizing technical amendments to NSPS subparts J and Ja with limited changes from what we proposed. First, in response to comments, we are revising the NSPS requirements that a flow sensor have a ‘‘measurement sensitivity’’ of no more than 5-percent of the flow rate to an ‘‘accuracy’’ requirement that the flow sensor have an accuracy of 5-percent of the flow rate. This change will make the requirements more clear and consistent between the flow meter requirements in the NSPS and the MACT standards since it is the same flow meter subject to these requirements. We are also revising flare flow rate accuracy requirements in Refinery NSPS subpart Ja to make them consistent with those we are finalizing in Refinery MACT 1. Finally, we are revising 40 CFR 60.101a(b) to begin as ‘‘Except for flares and delayed coking units . . .’’ to correct an inadvertent error. We proposed revisions to this sentence solely to allow sources subject to Refinery NSPS subpart J to comply with the provisions in Refinery NSPS subpart Ja instead. However, the words ‘‘and delayed coking units’’ were inadvertently omitted from the initial part of the sentence. Thus, as intended, we are finalizing revisions to this sentence to allow sources subject to Refinery NSPS subpart J to comply with the provisions in Refinery NSPS subpart Ja. F. What are the requirements for submission of performance test data to the EPA? As proposed, the EPA is taking a step to increase the ease and efficiency of data submittal and data accessibility. Specifically, the EPA is finalizing the requirement for owners or operators of VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Petroleum Refinery facilities to submit electronic copies of certain required performance test reports through the EPA’s Central Data Exchange (CDX) using the Compliance and Emissions Data Reporting Interface (CEDRI). The EPA believes that the electronic submittal of the reports addressed in this rulemaking will increase the usefulness of the data contained in those reports, is in keeping with current trends in data availability, will further assist in the protection of public health and the environment and will ultimately result in less burden on the regulated community. Electronic reporting can also eliminate paperbased, manual processes, thereby saving time and resources, simplifying data entry, eliminating redundancies, minimizing data reporting errors and providing data quickly and accurately to the affected facilities, air agencies, the EPA and the public. As mentioned in the preamble of the proposal, the EPA Web site that stores the submitted electronic data, WebFIRE, will be easily accessible to everyone and will provide a user-friendly interface that any stakeholder could access. By making the records, data and reports addressed in this rulemaking readily available, the EPA, the regulated community and the public will benefit when the EPA conducts its CAArequired technology and risk-based reviews. As a result of having reports readily accessible, our ability to carry out comprehensive reviews will be increased and achieved within a shorter period of time. We anticipate fewer or less substantial information collection requests (ICRs) in conjunction with prospective CAArequired technology and risk-based reviews may be needed. We expect this to result in a decrease in time spent by industry to respond to data collection requests. We also expect the ICRs to contain less extensive stack testing provisions, as we will already have stack test data electronically. Reduced testing requirements would be a cost savings to industry. The EPA should also be able to conduct these required reviews more quickly. While the regulated community may benefit from a reduced burden of ICRs, the general public benefits from the agency’s ability to provide these required reviews more quickly, resulting in increased public health and environmental protection. Air agencies could benefit from more streamlined and automated review of the electronically submitted data. Having reports and associated data in electronic format will facilitate review through the use of software ‘‘search’’ options, as well as the downloading and PO 00000 Frm 00009 Fmt 4701 Sfmt 4700 75185 analyzing of data in spreadsheet format. The ability to access and review air emission report information electronically will assist air agencies to more quickly and accurately determine compliance with the applicable regulations, potentially allowing a faster response to violations which could minimize harmful air emissions. This benefits both air agencies and the general public. For a more thorough discussion of electronic reporting required by this rule, see the discussion in the preamble of the proposal. In summary, in addition to supporting regulation development, control strategy development, and other air pollution control activities, having an electronic database populated with performance test data will save industry, air agencies, and the EPA significant time, money, and effort while improving the quality of emission inventories, air quality regulations, and enhancing the public’s access to this important information. G. What are the effective and compliance dates of the NESHAP and NSPS? The final amendments to the NESHAP and NSPS in this action are effective on February 1, 2016. As proposed, new sources must comply with these requirements by the effective date of the final rule or upon startup, whichever is later. As proposed, existing sources are required to comply with the final DCU and CRU requirements no later than 3 years after the effective date of the final rule. Similarly, as proposed, owners or operators are required to comply with the new operating and monitoring requirements for existing flares no later than 3 years after the effective date of the final rule. We proposed to provide 3 years from the effective date of the final rule for refinery owners or operators to install and begin monitoring (collecting samples) around the fenceline of their existing facility. If refinery owners and operators determined that a site-specific monitoring plan was needed, they would also need to submit and receive approval for such a plan during the 3year compliance period. Based on information submitted during the comment period, we are finalizing requirements that refinery owners or operators begin collecting samples around the fenceline within 2 years of the effective date of the final rule. Based on information submitted during the comment period, 1 year is sufficient time to identify proper monitoring locations and to install the required monitoring stations around the facility E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75186 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations fenceline. However, owners or operators may need additional monitoring systems to account for near-field interfering sources (NFS), for which the development and approval of a sitespecific fenceline monitoring plan is required. We expect that the sitespecific fenceline monitoring plans can take an additional year to develop, submit and obtain approval. Consequently, we are providing 2 years from the effective date of the final rule for refinery owners or operators to install and begin collecting samples around the fenceline of their facility. As proposed, we are requiring that existing sources comply with the submerged filling requirement for marine vessel loading on the effective date of the final rule. As proposed, we are providing 18 months after the effective date of the final rule to conduct required performance tests and comply with any revised operating limits for FCCU. We proposed to require refinery owners or operators to comply with the revisions to the SSM provisions of Refinery MACT 1 and 2 on the effective date of the final rule. As proposed, this final rule requires refinery owners or operators to comply with the limits in Refinery MACT 2 or the alternative limits in this final rule during startup and shutdown for FCCU and SRU on the effective date of the final rule. The flare work practice standards for high-load flaring events (events exceeding the smokeless capacity of the flare) require development of FMP (or revision of an existing plan) to specifically consider emergency shutdown and other high load events. In this FMP, refinery owners or operators must consider measures that can be implemented to reduce the frequency and magnitude of these high-load flaring events. This may include installation of a flare gas recovery system. Additionally, the work practice standards will require refinery owners or operators to identify and implement measures that may involve process changes. Therefore, we are establishing a compliance date of 3 years from the effective date of the final rule for refinery owners or operators to comply with the work practice standards for high load flaring events. We also note that this compliance period is consistent with the compliance time provided for the flare operating limits. For atmospheric PRD in HAP service we are establishing a work practice standard that requires a process hazard analysis and implementation of a minimum of three redundant measures to prevent atmospheric releases. Alternately, refinery owners or VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 operators may elect to install closed vent systems to route these PRD to a flare, drain (for liquid thermal relief valves) or other control system. We anticipate that sources will need to identify the most appropriate preventive measures or control approach; design, install and test the system; install necessary process instrumentation and safety systems; and may need to time installations with equipment shutdown or maintenance outages. Therefore, we have established a compliance date of 3 years from the effective date of the final rule for refinery owners or operators to comply with the work practice standards for atmospheric PRD. As proposed, we are requiring compliance with the electronic reporting provisions for performance tests conducted for Refinery MACT 1 and 2 on the effective date of the final rule. Finally, we are finalizing additional requirements for storage vessels under CAA sections 112(d)(6) and (f)(2) with a compliance date 90 days after the effective date of the final rule, as proposed. H. What materials are being incorporated by reference? In this final rule, the EPA is including regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is incorporating by reference the following documents described in the amendments to 40 CFR 63.14: • ASTM D1945–03 (Reapproved 2010), Standard Test Method for Analysis of Natural Gas by Gas Chromatography, (Approved January 1, 2010). • ASTM D1945–14, Standard Test Method for Analysis of Natural Gas by Gas Chromatography. • ASTM D6196–03 (Reapproved 2009), Standard Practice for Selection of Sorbents, Sampling, and Thermal Desorption Analysis Procedures for Volatile Organic Compounds in Air, (Approved March 1, 2009). • ASTM D6348–03 (Reapproved 2010), Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1 through A8, (Approved October 1, 2010). • ASTM D6348–12e1, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy. • ASTM D6420–99 (Reapproved 2010), Standard Test Method for Determination of Gaseous Organic PO 00000 Frm 00010 Fmt 4701 Sfmt 4700 Compounds by Direct Interface Gas Chromatography-Mass Spectrometry. • ASTM UOP539–12, Refinery Gas Analysis by GC. • BS EN 14662–4:2005, Ambient air quality—Standard method for the measurement of benzene concentrations—Part 4: Diffusive sampling followed by thermal desorption and gas chromatography, June 27, 2005. • EPA–454/B–08–002, Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final), March 2008. • EPA–454/R–99–005, Meteorological Monitoring Guidance for Regulatory Modeling Applications, February 2000. • ISO 16017–2:2003(E): Indoor, ambient and workplace air—Sampling and analysis of volatile organic compounds by sorbent tube/thermal desorption/capillary gas chromatography—Part 2: Diffusive sampling, May 15, 2003. • Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources’’ Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, prepared by Texas Commission on Environmental Quality, January 31, 2003.4 The EPA has made, and will continue to make, these documents available electronically through www.regulations.gov and/or in hard copy at the appropriate EPA office (see the ADDRESSES section of this preamble for more information). IV. What is the rationale for our final decisions and amendments to the Petroleum Refinery NESHAP and NSPS? A. Residual Risk Review for the Petroleum Refinery Source Categories 1. What did we propose pursuant to CAA section 112(f) for the Petroleum Refinery source categories? The results of our residual risk review for the Petroleum Refinery source categories were published in the June 30, 2014 proposal at (79 FR 36934 through 36942), and included assessment of chronic and acute inhalation risk, as well as multipathway and environmental risk, to inform our decisions regarding acceptability and ample margin of safety. The results indicated that both the actual and 4 The requirements in § 63.655(i)(5)(iii)(G) associated with this incorporation by reference have not changed, but are being modified to properly be incorporated into § 63.14(s). E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 allowable inhalation cancer risks to the individual most exposed are no greater than approximately 100-in-1 million, which is the presumptive limit of acceptability. In addition, the maximum chronic non-cancer target organ-specific hazard index (TOSHI) due to inhalation exposures was less than 1. The evaluation of acute non-cancer risks, which was conservative, showed acute risks below a level of concern. Based on the results of the refined site-specific multipathway analysis, we also concluded that the ingestion cancer risk to the individual most exposed through ingestion is considerably less than 100in-1 million. In determining risk acceptability, we also evaluated population impacts because of the large number of people living near facilities in the source category. We estimated that 5-million people are exposed to increased cancer risks of greater than 1in-1 million and 100,000 people are exposed to increased cancer risks of greater than 10-in-1 million, but, as noted previously, no individual is exposed to increased cancer risks of greater than 100-in-1 million. Considering the above information, we proposed that the risks remaining after implementation of the existing NESHAP for the Refinery MACT 1 and 2 source categories is acceptable. However, we noted that the risks based on allowable emissions are at the presumptive limit of acceptable risk, and that a large number of people are exposed to risks of greater than 1-in-1 million, and we solicited comment on whether EPA should conclude that the risk was unacceptable based on the health information before the Agency. We also proposed that the original Refinery MACT 1 and 2 MACT standards, along with the proposed requirements for storage vessels, provide an ample margin of safety to protect public health. Finally, we proposed that it is not necessary to set a more stringent standard to prevent, taking into consideration costs, energy, safety, and other relevant factors, an adverse environmental effect. 2. How did the risk review change for the Petroleum Refinery source categories? As part of the final risk assessment, we conducted a screening level analysis of how the information we received during the public comment period, along with the changes we are making to the proposed rule, would change our proposed risk estimates (More details can be found in the ‘‘Final Residual Risk Assessment for the Petroleum Refining Source Sector’’, Docket ID No. EPA– HQ–OAR–2010–0682). VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 First, we received approximately 20 emissions inventory updates for specific facilities. These updates included revised emission estimates, revised release latitude/longitude locations and other release characteristic revisions. The updates provided evidence that the quantity of HAP emitted at these specific facilities is lower than considered in the risk modeling for the proposed rule. Our assessment of the effects of these changes suggests that the cancer maximum individual risk (MIR) based on actual emissions may be closer to 40-in-1 million, as opposed to 60-in1 million, as projected at proposal. We did not quantify the reductions in chronic or acute non-cancer risks from these updates. We calculated allowable emissions using the Refinery Emissions Model (REM), which estimates emissions based on each refinery’s capacities and throughputs [See discussion at 79 FR 36888, June 30, 2014.] The allowable emission estimates for point and fugitive sources were not specific to a particular latitude/ longitude location so we assumed them to release from the centroid of the facility. Therefore, the predicted cancer MIR of approximately 100-in-1 million based on allowable emissions and reported in the proposal risk characterization does not change based on the submitted emissions revisions. We did not quantify changes to other actual risk metrics as part of the screening level analysis (i.e., incidence, populations in risk bins, multipathway and ecological analyses), but we would expect some minor reductions from those presented in the proposed risk characterization. Second, we are establishing work practice standards in the final rule for PRD releases and emergency flaring events, which under the proposed rule would not have been allowed. Thus, because we did not consider such nonroutine emissions under our risk evaluation for the proposed rule, we performed a screening assessment of risk associated with these non-routine events for the final rule. [We provide further details on the screening approach in ‘‘Final Residual Risk Assessment for the Petroleum Refining Source Sector’’ in Docket ID No. EPA– HQ–OAR–2010–0682.] We extracted information on these events from the 2011 Petroleum Refinery ICR data that included the process unit identification, mass of emissions, duration of release, and description of the incident. We identified the highest HAP mass releases for both PRDs and flares from these non-routine events. We assumed these HAP emission releases could PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 75187 occur at any facility in the source category. Our analysis suggests that these HAP emissions could increase the MIR based on actual emissions by as much as 2-in-1 million. Because the PRD and flaring events were the worst case HAP mass emission release events reported in the 2011 Refinery ICR for the source category, we are assuming that actual and allowable risks are no different for these events (i.e., a MIR of 2-in-1 million). A MIR increase of 2-in1 million attributable to these events, added to our previous estimate for allowable risk at proposal will not appreciably change our proposed determination that the MIR based on allowable emissions are approximately 100-in-1 million. We note that the MIR estimate attributable to these nonroutine PRD and flaring events was estimated using a conservative, screening-level assessment, while the MIR estimate at proposal was based on a refined risk assessment. By adding a screening estimate to a refined risk estimate, we are merely defining an upper limit that we expect the combined risks from both the routine and non-routine emissions to be. Similarly, we estimate chronic noncancer hazard index (HI) values attributable to the additional exposures resulting from non-routine flaring and PRD HAP emissions to be well below 1 (HIimmune-system of 0.007) such that there is no appreciable change in the maximum chronic non-cancer HI of 0.9 estimated at proposal for routine emissions, which was based on neurological effects. The screening analysis projects that the maximum predicted acute noncancer risk from non-routine PRD and flare emissions results in a hazard quotient (HQ) based on a recommended reference exposure level limit (REL) of up to 14 from benzene emissions. While the analysis shows that there is a potential for HQs exceeding 1 for benzene, because of the many uncertainties and conservative nature of this screening analysis, the likelihood of such exposure and risk are low. At proposal, we projected a HQ based on the REL for benzene of up to 2 from routine emissions. If we conservatively combine the routine and non-routine emissions analyses, we would expect the potential for HQs based on the REL for benzene to have the potential to increase above 2. However, as projected at proposal, we estimate that the acute HQs calculated using acute exposure guideline levels (AEGL) and emergency response and planning guidelines (ERPG) values for all pollutants including benzene would still be well E:\FR\FM\01DER2.SGM 01DER2 75188 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 below 1 considering both routine and non-routine emissions. Considering all of these factors, we do not project risks to be significantly different from what we proposed. Based on the risk analysis, as informed by the screening level analysis based on information obtained during the comment period, we are finalizing our determination that the risk remaining after promulgation of the NESHAP is acceptable. 3. What key comments did we receive on the risk review and what are our responses? We received numerous comments on the residual risk assessment analyses and results. We summarize the key comments received below, along with our responses. A complete summary of all public comments received and our responses are in the ‘‘Response to Comment’’ Document in the public docket (Docket ID No. EPA–HQ–OAR– 2010–0682). Comment: Several commenters agreed that the EPA has correctly concluded that the proposed rule requirements protect the public with an ample margin of safety from refinery emissions. Other commenters noted that EPA found residual risks remaining after implementation of the MACT standards to be acceptable, and in light of the acceptability determination argued that the proposed changes to the rule are not justified. The commenters noted that the EPA’s detailed emissions inventory assessment and risk modeling results demonstrated that, at every U.S. refinery, category-specific risks are below the EPA’s presumptive limit of acceptable risk (i.e., cancer risk of less than 100-in-1 million). Other commenters stated the EPA’s risk estimates are understated and that the EPA should reduce the benchmark of what it considers acceptable lifetime cancer risk instead of the upper limit of 100-in-1 million. One commenter provided an extensive critique of the cancer, chronic and acute affects levels used in the risk assessment and recommended that the EPA use California Office of Environmental Health Hazard Assessment’s (OEHHA) new toxicity values for several chemicals. The commenter provided some references for the approaches used to derive the California values. The commenter also asserted that risks would be unacceptable had these more protective values been used in the risk assessment. Some commenters stated the risks from petroleum refinery emissions are underestimated because the EPA did not but should have included interaction of multiple VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 pollutants, accounted for exposure to multiple sources, and assessed the cumulative risks from facility-wide emissions and multiple nearby sources impacting an area. Response: The approximately 100-in1 million benchmark was established in the Benzene NESHAP (54 FR 38044, September 14, 1989), which Congress specifically referenced in CAA section 112(f)(2)(B). While this presumptive level provides a benchmark for judging the acceptability of MIR, it is important to recognize that it does not constitute a rigid line for making that determination. The EPA considers the specific uncertainties of the emissions, health effects and risk information for the source category in question when deciding whether the risk posed by that source category is acceptable. In addition, the source category-specific decision of what constitutes an acceptable level of risk is a holistic one; that is, the EPA considers all potential health impacts—chronic and acute, cancer and non-cancer, and multipathway—along with their uncertainties, when determining whether the source category presents an unacceptable risk. Regarding the comment that in light of the acceptability determination the proposed changes to the rule are not justified, we note that we also are required to ensure that the standards provide an ample margin of safety to protect public health. That analysis is separate from the acceptability analysis, and the determination of acceptability does not automatically lead us to conclude that the standards provide an ample margin of safety to protect public health. Regarding the comments that the EPA should use the new California OEHHA values, we disagree. The EPA’s chemical-specific toxicity values are derived using risk assessment guidelines and approaches that are well established and vetted through the scientific community, and follow rigorous peer review processes.5 The RTR program gives preference to the EPA values for use in risk assessments and uses other values, as appropriate, when those values are derived with methods and peer review processes consistent with those followed by the EPA. The approach for selecting appropriate toxicity values for use in the RTR Program has been endorsed by the Science Advisory Board (SAB).6 5 Integrated Risk Information System (IRIS). IRIS Guidance documents available at https://www.epa. gov/iris/backgrd.html. 6 https://yosemite.epa.gov/sab/sabproduct.nsf/0/ b031ddf79cffded38525734f00649caf!Open Document&TableRow=2.3#2. PO 00000 Frm 00012 Fmt 4701 Sfmt 4700 The EPA scientists reviewed the information provided by the commenter regarding the California values and concluded that further information is needed to evaluate the scientific basis and rationale for the recent changes in California OEHHA risk assessment methods. The EPA will work on gathering the necessary information to conduct an evaluation of the scientific merit and the appropriateness of the use of California OEHHA’s new toxicity values in the agency decisions. Until the EPA has completed its evaluation, it is premature to determine what role these values might play in the RTR process. Therefore, the EPA did not use the new California OEHHA toxicity values as part of this current action. For more detailed responses regarding appropriate reference values for specific pollutants, see the ‘‘Response to Comment’’ document in the public docket (Docket ID No. EPA–HQ–OAR– 2010–0682). Concerning comments that we should consider aggregate risks from multiple pollutants and sources, we note that we have done this to the extent it is appropriate to do so. We modeled whole-facility risks for both chronic cancer and non-cancer impacts to understand the risk contribution of the sources within the Petroleum Refinery source categories. The individual cancer risks for the source categories were aggregated for all carcinogens. In assessing non-cancer hazard from chronic exposures to pollutants that have similar modes of action or (where this information is absent) that affect the same target organ, we summed the HQs. This process creates, for each target organ, a TOSHI, defined as the sum of HQs for individual HAP that affect the same organ or organ system. Wholefacility risks were estimated based on the 2011 ICR emissions data obtained from facilities, which included emissions from all sources at the refinery, not just Refinery MACT 1 and 2 emission sources (e.g., emissions were included for combustion units and units subject to the Hazardous Organic NESHAP, if present at the refinery). We disagree with the commenter’s assertion that additional quantitative assessment of risks from sources outside the source category is required under the statute. The statute requires the EPA to provide the quantitative risk information necessary to inform RTR regulatory decisions, and to this end, the EPA conducted a comprehensive assessment of the risks associated with exposure to the HAP emitted by the source category and supplemented that with additional E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations information available about other possible concurrent and relevant risks. Further, the risk assessment modeling accounts for the effects of multiple facilities that may be in close proximity when estimating concentration and risk impacts at each block centroid. When evaluating the risks associated with a particular source category, we combined the impacts of all facilities within the same source category and assessed chronic exposure and risk for all census blocks with at least one resident (i.e., locations where people may reasonably be assumed to reside). The MIR considers the combined impacts of all sources in the category that may be in close proximity (i.e., cumulative impact of all refineries). Comment: Several commenters stated that the EPA underestimated exposure because emissions are underreported and underestimated. The commenters noted that for the risk assessment for the refineries rule, the EPA evaluated (1) the emissions reported to the agency pursuant to the 2011 Petroleum Refinery ICR as sources’ ‘‘actual’’ emissions, and (2) the emissions the EPA estimates that the existing standards currently allow sources to emit using the REM, which it describes as ‘‘allowable’’ emissions. According to the commenters, both the EPA’s ‘‘actual’’ and ‘‘allowable’’ emissions data sets are incomplete and undercount emissions, causing the EPA to significantly underestimate the resulting risk in its risk analysis. For example, the commenters noted that the EPA assumed the flare destruction efficiency to be 98 percent, while the EPA’s own estimates suggest flare efficiency is 93.9 percent. The commenters also noted that the EPA has further understated risks by ignoring emissions during unplanned SSM events and by ignoring HAP for which no reference values are established. One commenter cited the TCEQ Emissions Event Database as evidence that SSM emissions are a severe public health problem because data show that nearly 1 million pounds of HAP are reported from Texas refineries between 2009 and 2013. According to these commenters, the EPA needs to adopt standards that provide greater protection, including protection from the risks of accidents. Response: We used the best and most robust facility-specific HAP emissions inventory available to us, which was the 2011 ICR, in performing the analysis for the proposed rule. We conducted a thorough and exhaustive review of the data submitted through the ICR and we followed up on source-specific information on a facility-by-facility basis, as documented in the ‘‘Emissions Data Quality Memorandum and VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Development of the Risk Model Input File’’ (see Docket ID No. EPA–HQ– OAR–2010–0682–0076). In addition, we took steps ahead of issuing the 2011 ICR to make sure that facilities could, as accurately as practicable, estimate their HAP emissions for purposes of responding to the inventory portion of that ICR. We prepared a Refinery Protocol to provide guidance to refinery owners or operators to use the best available, site-specific data when developing their emissions inventory, to ensure all emission sources are included in the inventory, and to have a consistent set of emission factors that all respondents use if no site-specific emissions data were available. If sitespecific emissions data were available, sites were to use these data preferentially over the default factors. We developed the default factors provided in the protocol from the best data available at the time. The ICR-submitted information for allowable emissions did not include emission estimates for all HAP and all emission sources. Consequently, we used the REM to estimate allowable emissions. The REM relies on model plants that vary based on throughput capacity. Each model plant contains process-specific default emission factors, adjusted for compliance with the Refinery MACT 1 and 2 emission standards. We agree with the commenters that studies have shown that many refinery flares are operating less efficiently than 98 percent. Prior to proposing this rule, we conducted a flare ad hoc peer review to advise the EPA on factors affecting flare performance (see discussion in the June 30, 2014, proposal at 79 FR 36905). However, we disagree with the commenters that the risk analysis should consider this level of performance since the existing MACT standard does not allow it. For purposes of the risk analysis, we evaluate whether it is necessary to tighten the existing MACT standard in order to provide an ample margin of safety. Thus, in reviewing whether the existing standards provide an ample margin of safety, we review the level of emissions the MACT standards allow. In the present case, we considered the level of performance assumed in establishing the MACT standard for purposes of determining whether the MACT standard provides an ample margin of safety. However, we did recognize that facilities were experiencing performance issues with flares and that many flares were not meeting the assumed performance level at the time we promulgated the MACT standard. Thus, we proposed, and are finalizing, PO 00000 Frm 00013 Fmt 4701 Sfmt 4700 75189 revisions to the flare operating requirements to ensure that the flares meet the required performance level. These provisions are consistent with the EPA’s goals to improve the effectiveness of our rules. Similarly, we do not include startup, shutdown (including maintenance events) and malfunction emissions that are not allowed under the standard as part of our evaluation of whether the standards provide an ample margin of safety. Regarding the HAP emissions from SSM events that the commenter is concerned with, we note that our review of the TCEQ incident database indicates that many of the large reported release events were of SO2 emissions and only a few had significant HAP emissions. Because in the final rule we are establishing work practice standards for PRD and emergency flaring events, we performed a screening-level risk analysis to address changes in facility HAP emission releases due to these events. Details on this analysis are presented in the final risk report for the source category (For more details see Appendix 13 of the ‘‘Final Residual Risk Assessment for the Petroleum Refining Source Sector,’’ Docket ID No. EPA– HQ–OAR–2010–0682). As for HAP with no reference value, the SAB addressed this issue in its May 7, 2010, response to the EPA Administrator. In that response, the SAB Panel recommended that, for HAP that do not have dose-response values from the EPA’s list, the EPA should consider and use, as appropriate, additional sources for such values that have undergone adequate and rigorous scientific peer review. The SAB panel further recommended that the inclusion of additional sources of dose-response values into the EPA’s list should be adequately documented in a transparent manner in any residual risk assessment case study. We agree with this approach and have considered other sources of dose-response data when conducting our risk determinations under RTR. However, in some instances no sources of information beyond the EPA’s list are available. Compounds without health benchmarks are typically those without significant health effects compared to compounds with health benchmarks, and in such cases we assume these compounds will have a negligible contribution to the overall health risks from the source category. A tabular summary of HAPs that have dose response values for which an exposure assessment was conducted is presented in Table 3.1–1 of the ‘‘Final Residual Risk Assessment for the Petroleum Refining Source Sector’’, Docket ID No. EPA–HQ–OAR–2010–0682. E:\FR\FM\01DER2.SGM 01DER2 75190 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 Comment: A few commenters asserted that the EPA should decide that it is unjust and inconsistent with the CAA’s health protection purpose to allow the high health risks caused by refineries to fall disproportionately on communities of color and lower income communities who are least equipped to deal with the resulting health effects. Because of that disparity, the commenter stated that the EPA should recognize that the risks found are unacceptable and set stronger national standards for all exposed Americans. Response: For this rulemaking, the EPA conducted both pre- and postcontrol risk-based assessments with analysis of various socio-economic factors for populations living near petroleum refineries (see Docket ID Nos. EPA–HQ–OAR–2010–0682–0226 and –0227) and determined that there are more African-Americans, Other and multiracial groups, Hispanics, lowincome individuals, and individuals with less than a high school diploma compared to national averages. In determining the need for tighter residual risk standards, the EPA strives to limit to no higher than 100-in-1 million the estimated cancer risk for persons living near a plant if exposed to the maximum pollutant concentration for 70 years and to protect the greatest number of persons to an individual lifetime risk of no higher than 1-in-1 million. Although we consider the risk for all people regardless of racial or socioeconomic status, communities near petroleum refineries will particularly benefit from the risk reductions associated with this rule. In particular, as discussed later, the fenceline monitoring work practice standard will be a further improvement in the way fugitive emissions are managed and will provide an extra measure of protection for surrounding communities. 4. What is the rationale for our final decisions for the risk review? As described in section IV.A.2 of this preamble, we performed a screeninglevel analysis to assess the risks associated with inventory updates we received for specific facilities and with emissions events that were previously not included in the risk assessment because the proposed rule did not allow them. Because we are finalizing work practice standards to regulate emission events associated with PRD releases and emergency flaring, we considered the effect these work practice standards would have on risks. As discussed in section IV.A.2 of this preamble, we project that accounting for these emergency events in the baseline risks after implementation of the MACT VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 standards does not appreciably change the risks, and at most, could increase the proposed rule estimate of MIR by approximately 2-in-1 million. Therefore, we would project that any controls applied to these emergency events, including the work practice standards for PRDs and emergency flaring in this final rule, would not appreciably change the proposed post-control risks. Although we would anticipate minimal additional risk reductions, we reviewed more stringent alternatives to the work practice standards for PRD releases and emergency flaring events included in this final rule, and we found that the costs of increasing flare capacity to control all PRD releases and to eliminate all visible emissions during emergency flaring were too high. We estimate the capital costs of applying the velocity and visible emissions limit at all times would be approximately $3 billion, and we estimate that the costs of controlling all PRD releases with flares would be approximately $300 million. [See the discussion in the ‘‘Flare Control Option Impacts for Final Refinery Sector Rule’’, Docket ID No. EPA–HQ–OAR–2010– 0682 and the PRD work practice standard discussion in section IV.C of this preamble.] Further, we did not receive comments on additional control technologies that we should have considered for other emission sources (e.g., tanks, DCUs) beyond those considered and described at proposal. Consequently, as discussed in section IV.A.2, we conclude that the risks from the Petroleum Refinery source categories are acceptable and that, with the additional requirements for storage vessels that we are finalizing, as proposed, the Refinery MACT 1 and 2 rules provide an ample margin of safety to protect public health. We also maintain, based on the rationale presented in the preamble to the proposed rule, that the current standards prevent, taking into consideration costs, energy, safety and other relevant factors, an adverse environmental effect. B. Technology Review for the Petroleum Refinery Source Categories 1. What did we propose pursuant to CAA section 112(d)(6) for the Refinery MACT 1 (40 CFR part 63, subpart CC) source category? The results of our technology review for the Petroleum Refinery source categories were published in the June 30, 2014, proposal at (79 FR 36913 through 36928). The technology review was conducted for both MACT source categories as described below. PO 00000 Frm 00014 Fmt 4701 Sfmt 4700 a. Refinery MACT 1 Refinery MACT 1 sources include MPV, storage vessels, equipment leaks, gasoline loading racks, marine vessel loading operations, cooling towers/heat exchange systems and wastewater. Based on technology reviews for the sources described above, we proposed that it was not necessary to revise Refinery MACT 1 requirements for MPV, gasoline loading racks, cooling towers/heat exchange systems, and wastewater. For storage vessels, we proposed revisions pursuant to the technology review. Specifically, we proposed to cross-reference the storage vessel requirements in the Generic MACT (40 CFR part 63, subpart WW) to require controls on floating roof fittings (e.g., guidepoles, ladder wells and access hatches) and to revise the definition of Group 1 storage vessels to include smaller tanks with lower vapor pressures. For equipment leaks, we proposed to allow refineries to meet LDAR requirements in Refinery MACT 1 by monitoring for leaks via optical gas imaging in place of the EPA Method 21, using monitoring requirements to be specified in a not-yet-proposed appendix K to 40 CFR part 60. For marine vessel loading, we proposed to amend the Marine Tank Vessel Loading Operations MACT standards (40 CFR part 63, subpart Y) to require small marine vessel loading operations (i.e., operations with HAP emissions less than 10/25 tpy) and offshore marine vessel loading operations at petroleum refineries to use submerged filling based on the cargo filling line requirements in 46 CFR 153.282. We also proposed an additional work practice standard under the technology review to manage fugitive emissions from the entire petroleum refinery through a fenceline monitoring and corrective action standard. As part of the work practice standard, we specified the monitoring technology and approach that must be used, and we developed a fenceline benzene concentration action level above which refinery owners or operators would be required to implement corrective action to reduce their fenceline concentration to below this action level. The action level we proposed was consistent with the emissions projected from fugitive sources compliant with the provisions of the refinery MACT standards as modified by the additional controls proposed for storage vessels. b. Refinery MACT 2 The Refinery MACT 2 source category regulates HAP emissions from FCCU, CRU and SRU process vents. We E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations proposed to revise Refinery MACT 2 to incorporate the developments in monitoring practices and control technologies reflected in Refinery NSPS subpart Ja (73 FR 35838). This included proposing to incorporate the Refinery NSPS subpart Ja PM limit for new FCCU sources and to revise the monitoring provisions in Refinery MACT 2 to require all FCCU sources to meet operating limits consistent with the requirements in Refinery NSPS subpart Ja. The existing MACT standard provided that a refiner could demonstrate compliance with the PM limit in the MACT by meeting the 30percent opacity limit requirement of Refinery NSPS subpart J; we proposed to eliminate that provision and instead establish control device operating limits or site-specific opacity limits similar to those required in Refinery NSPS subpart Ja. We also proposed to incorporate the use of 3-hour averages rather than daily averages for monitoring data to demonstrate compliance with the FCCU site-specific opacity and Ni operating limits. We proposed additional control device-specific monitoring alternatives for various control devices on FCCU, including BLD monitoring as an option to COMs for owners or operators of FCCU using fabric filter-type control systems, and total power and secondary current operating limits for owners or operators of ESPs. We also proposed to add a requirement to perform daily checks of the air or water pressure to atomizing spray nozzles for owners or operators of FCC wet gas scrubbers. Finally, we proposed to require a performance test once every 5 years for all FCCU in place of the one-time performance test required by the current Refinery MACT 2. At proposal, we did not identify any developments in practices, processes and control technologies for CRU process vents based on our technology review. For SRU, we proposed to include the Refinery NSPS subpart Ja allowance for oxygen-enriched air as a development in practice and to allow SRU to comply with Refinery NSPS subpart Ja as a means of complying with Refinery MACT 2. tkelley on DSK3SPTVN1PROD with RULES2 2. How did the technology review change for the Petroleum Refinery source categories? a. Refinery MACT 1 We are finalizing most of our technology review decisions for Refinery MACT 1 emissions sources as proposed; however, as described briefly below, we are revising certain proposed requirements. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 We are not taking final action adopting the use of appendix K to 40 CFR part 60 for optical gas imaging for refinery equipment subject to the LDAR requirements in Refinery MACT 1 because we have not yet proposed appendix K. After considering the public comments, we are finalizing the proposed fenceline monitoring requirements, with a few revisions. First, we have made numerous clarifications in this final rule to the language for the fenceline monitoring siting method and analytical method (i.e., Methods 325 A and B, respectively). Specific comments on these methods, along with our responses and explanations of the revisions to the regulatory text are discussed in the ‘‘Response to Comment’’ document. Second, we are finalizing a revised compliance schedule for fenceline monitoring, which will require refinery owners or operators to have the fenceline monitors in place and collecting benzene concentration data no later than 2 years from the effective date of the final rule, as opposed to 3 years in the proposed rule. Third, we have removed the requirement for refinery owners or operators to obtain the EPA approval for the corrective action plan. Fourth, we are requiring the submittal of the fenceline monitoring data on a quarterly basis, as opposed to on a semiannual basis as proposed. Fifth, we are providing guidelines for operators to use in requesting use of an alternative fenceline monitoring technology to the passive sorbent samplers set forth in Method 325B. Finally, to reduce the burden of monitoring, we are finalizing provisions that would allow refinery owners or operators to reduce the frequency of fenceline monitoring for areas that consistently stay well below the fenceline benzene concentration action level. Specifically, we are allowing refinery owners or operators to monitor every other two weeks (i.e., skip period monitoring) if over a two-year period, each sample collected at a specific monitoring location is at or below 0.9 mg/m3. If every sample collected from that sampling location during the subsequent 2-years is at or below 0.9 mg/ m3, the monitoring frequency may be reduced from every other two weeks to quarterly. After an additional two years, the monitoring can be reduced to semiannually and finally to annually, provided the samples continue to be at or below 0.9 mg/m3 during all sampling events at that location. If at any time a sample for a monitoring location that is monitored at a reduced frequency PO 00000 Frm 00015 Fmt 4701 Sfmt 4700 75191 returns a concentration greater than 0.9 mg/m3, the owner or operator must return to the original sampling requirements for one quarter (monitor every two weeks for the next six monitoring periods for that location); if every sample collected from this quarter is at or below 0.9 ug/m3, then the sampling frequency reverts back to the reduced monitoring frequency for that monitoring location; if not then the sampling frequency reverts back to the original biweekly monitoring frequency. b. Refinery MACT 2 We are finalizing, as proposed, our determination that it is not necessary to revise the requirements for CRU pursuant to the technology review and we are finalizing our determination that it is necessary to revise the MACT for SRU and FCCU. For SRU, we are finalizing the revisions as proposed. For FCCU, we are making modifications to the proposed requirements in light of public comment. As discussed previously, we proposed to remove the alternative in Refinery MACT 2 for owners or operators to demonstrate compliance with the PM limits on FCCU by meeting a 30-percent opacity standard as provided in Refinery NSPS subpart J and instead make the FCCU operating limits in Refinery MACT 2 consistent with Refinery NSPS subpart Ja. Based on the Refinery NSPS subpart J review in 2008, we determined that a 30-percent opacity limit does not adequately assure compliance with the PM emissions limit (see discussion in the proposed rule at 79 FR 36929, June 30, 2014). Thus, we included other monitoring approaches in Refinery NSPS subpart Ja. Comments received on this proposal, along with data available to the Agency, confirmed that the 30-percent opacity standard is not adequate on its own to demonstrate compliance with the PM (or metal HAP) emissions limit in Refinery MACT 2. We also received comments that the site-specific opacity alternative, which is the only compliance option proposed for FCCU with tertiary cyclones, would essentially require owners or operators with these FCCU configurations to meet an opacity limit of 10-percent. According to commenters, opacity increases with decreasing particle size, so that it is common to exceed 10-percent opacity during soot blowing or other similar events that produce very fine particulates even though mass emissions have not changed appreciably. Based on the available data, we have determined that a 20-percent opacity operating limit is well correlated with E:\FR\FM\01DER2.SGM 01DER2 75192 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations facilities meeting a limit of 1.0 lb PM/ 1,000 lbs coke burn-off. Therefore, we are retaining the option in Refinery MACT 2 to comply with Refinery NSPS subpart J except we are adding a 20percent opacity operating limit in Refinery MACT 2, evaluated on a 3-hour basis. To ensure that FCCU owners or operators complying with the Refinery NSPS subpart J option can meet the 1.0 lb PM/1,000 lbs emissions limit at all times, we are finalizing requirements that owners or operators conduct the performance test during higher PM periods, such as soot blowing. Where the PM emissions are within 80-percent of the PM limit during any periodic performance test, we are requiring the refinery owner or operator to conduct subsequent performance tests on an annual basis instead of on a 5-year basis. We are finalizing our proposed requirement that compliance with the control device operating limits in the other compliance alternatives be demonstrated on a 3-hour basis, instead of the 24-hour basis currently allowed in Refinery MACT 2. 3. What key comments did we receive on the technology review, and what are our responses? a. Refinery MACT 1 The majority of comments received regarding the proposed amendments to Refinery MACT 1 pursuant to our technology review dealt with the proposed fenceline monitoring requirements. The primary comments on the fenceline monitoring requirements are in this section along with our responses. Comment summaries and the EPA’s responses for additional issues raised regarding the proposed requirements resulting from our technology review are in the ‘‘Response to Comment’’ document in the public docket (Docket ID No. EPA– HQ–OAR–2010–0682). tkelley on DSK3SPTVN1PROD with RULES2 i. Legal Authority and Need for Fenceline Monitoring Comment: Numerous commenters claimed that the proposed fenceline monitoring program would unlawfully impose what is effectively an ambient air quality standard for benzene, which is not authorized by CAA section 112, which only authorizes the control of emission sources. The commenters argued it is an ambient standard because sources are required to meet the benzene level set or ‘‘perform injunctive relief which may or may not address the source of the benzene.’’ The commenter quoted language from the proposal as support that EPA has described the benzene level as an ambient standard: VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 ‘‘We are proposing a HAP concentration to be measured in the ambient air around a refinery, that if exceeded, would trigger corrective action to minimize fugitive emissions.’’ 79 FR at 36920 (June 30, 2014). The commenter further noted that this requirement is not just ‘‘monitoring’’ because it establishes a ‘‘not-to-be exceeded’’ level. Therefore, the commenters stated, the EPA should not finalize this portion of the proposal. Response: We disagree with the comment that the fenceline proposal is an ambient air standard. First, the owner or operator must place the monitors on the facility fenceline to measure emissions from the facility, i.e., on the property of the refiner. While we recognize that we used the term ‘‘ambient air’’ in the preamble to the proposal, we note that the placement requirements for the monitors make clear that the monitors are not monitoring ambient air, which EPA has defined at 40 CFR 50.1(e) as ‘‘that portion of the atmosphere, external to buildings, to which the general public has access.’’ Second, the proposed EPA Method 325A sets out procedures to subtract background concentrations and contributions to the fenceline benzene concentrations from non-refinery emission sources, so that the benzene concentrations measured are attributable to the refinery. In other words, the fenceline monitoring work practice standard uses a benzene concentration difference, referred to as the DC (essentially an upwind and downwind concentration difference) to isolate the refinery’s emissions contribution. Furthermore, we disagree that the fact that refiners are required to perform corrective action if the fenceline benzene concentration action level is exceeded makes the benzene action level an ambient standard. As an initial matter sources are not directly responsible for demonstrating that an area is meeting an ambient standard; rather that burden falls on states. See e.g., CAA section 110(a)(2). Moreover, the ‘‘corrective action’’ is simply that sources must ensure that fugitive emission sources on the property are not emitting HAP at levels that will result in exceedances of the fenceline benzene concentration action level. In other words, the purpose of the fenceline monitoring work practice is to ensure that sources are limiting HAP emissions at the fenceline, which are solely attributable to emissions from sources within the facility. In fact, the fenceline benzene concentration action level was established using emissions inventories reported by the facilities, assuming PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 compliance with the MACT standards. Finally, monitoring is conducted as part of the work practice standard to identify sources that will require additional controls to reduce their impact on the fenceline benzene concentration. In that sense, the fenceline monitoring work practice standard is not different than, for example, our MACT standard for refinery heat exchangers. If a facility is exceeding the relevant cooling water pollutant concentration ‘‘level’’ when it performs a periodic test, it must undertake corrective action to bring the concentration down below the action level. Comment: Several commenters noted that EPA’s authority under section 112(d) is to set ‘‘emissions standards’’ and quoted the CAA definition of that term: ‘‘A requirement . . . which limits the quantity, rate, or concentration of emissions of air pollutants on a continuous basis, including any requirement relating to the operation or maintenance of a source to assure continuous emission reduction, and any design, equipment, work practice or operational standard promulgated under this Act.’’ 42 U.S.C. 7602(k). The commenters argued that the proposed fenceline monitoring standard does not meet this definition because it would not ‘‘limit the quantity, rate, or concentration of emissions’’ from any given emissions point. Also, the commenters claimed that the EPA did not designate fenceline monitoring as a work practice under CAA section 112(h) since the EPA did not even mention CAA section 112(h), nor did it conduct any analysis to show that fenceline monitoring meets the CAA section 112(h) factors. Response: We disagree with the commenters’ assertion that the proposed fenceline monitoring work practice standard is not authorized under CAA section 112(d)(6). Contrary to the commenter’s claims, we specifically proposed the fenceline monitoring standard under CAA section 112(d)(6) to be a work practice standard that is applied broadly to fugitive emissions sources located at petroleum refineries. As discussed above, the proposed standard does more than impose monitoring as some commenters suggested; it also will limit emissions from refineries because it requires the owner or operator to identify and reduce HAP emissions through a monitoring and repair program, as do many work practice standards authorized under CAA Section 112(h) and 112(d). We note that the sources addressed by the fenceline monitoring standard— refinery fugitive emissions sources such as wastewater collection and treatment E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations operations, equipment leaks, heat exchange systems and storage vessels in the Refinery MACT 1 rule—are already subject to work practice standards. Our review of these requirements indicates that this fenceline monitoring work practice standard would be a further improvement in the way fugitive emissions are managed and would provide an extra measure of protection for surrounding communities. The commenter claims EPA did not analyze how the fenceline monitoring requirement meets the criteria in section 112(h). However, that is a misinterpretation of how the criteria apply. The criteria are assessed with regard to whether it is feasible to ‘‘prescribe or enforce an emission standard for a source’’, and do not apply to the work practice standard. Consistent with the criteria in section 112(h)(2), we determined and established that work practice standards are appropriate for these Refinery MACT fugitive emissions at the time we established the initial MACT standard. In the proposal, (79 FR at 36919, June 30, 2014), we reaffirmed that it is impracticable to directly measure fugitive emission sources at refineries but did not consider it necessary to reiterate these findings as part of this proposal to revise the existing MACT for these sources under CAA section 112(d)(6). We note that the commenters do not provide any grounds to support a reevaluation of whether these fugitive emission sources are appropriately regulated by a work practice standard. Comment: Several commenters questioned the EPA’s authority under the CAA to promulgate a rule that amounts to an ongoing information gathering and reporting obligation. The commenters stated that the EPA has not demonstrated that the proposed fenceline monitoring program represents an actual emission reduction technology improvement. A commenter stated that compliance assurance methods, including monitoring, for fugitive emissions and other emission standards are established as part of the emission standard and EPA’s authority to gather information that is not directly required for compliance with a specific standard but is related to air emissions is found in CAA section 114. Under CAA section 114, the requirement must be related to one of the stated purposes and must be reasonable. The commenter did not believe that the EPA has demonstrated that the costs of fenceline monitoring are reasonable in light of the information already available to the EPA and in light of many other means by VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 which the EPA could obtain such information. Response: We disagree with the commenters’ assertion that the authority for the fenceline monitoring requirement falls under CAA section 114 and not CAA section 112(d) because it is an ‘‘ongoing information gathering and reporting obligation.’’ The issue here is not whether EPA could have required the fenceline monitoring requirement under CAA section 114, but rather did EPA support that it was a development in processes practices or controls technology under section 112(d)(6). As an initial matter, we disagree with the commenters’ characterization of the fenceline monitoring standard as ‘‘an information gathering and reporting obligation.’’ We have repeatedly stated that we consider the fenceline monitoring requirement to be a work practice standard that will ensure sources take corrective action if monitored benzene levels (as a surrogate for HAP emissions from fugitive emissions sources) exceed the fenceline benzene concentration action level. The standard requires refinery owners or operators to monitor the benzene concentration at the refinery perimeter, to evaluate the refinery’s contribution as estimated by taking the concentration difference between the highest and lowest concentrations (DC) in each period, and to conduct root cause analysis and take corrective action to minimize emissions if the concentration difference is higher (on an annual average) than the benzene concentration action level. Thus, the fenceline monitoring requirement goes well beyond ‘‘information gathering and reporting.’’ In addition, the commenters again read section 112(d)(6) too narrowly by suggesting that a program considered as a development must be a ‘‘technology’’ improvement. Section 112(d)(6) of the CAA requires the EPA to review and revise the MACT standards, as necessary, taking into account developments in ‘‘practices, processes and control technologies.’’ Consistent with our long-standing practice for the technology review of MACT standards, in section III.C of the proposal (see 79 FR 36900, June 30, 2014), we list five types of ‘‘developments’’ we consider. Fenceline monitoring fits squarely within two of those five types of developments (emphasis added): • Any add-on control technology or other equipment that was not identified and considered during development of the original MACT standards. • Any work practice or operational procedure that was not identified or PO 00000 Frm 00017 Fmt 4701 Sfmt 4700 75193 considered during development of the original MACT standards. As used here, ‘‘other equipment’’ is clearly separate from and in addition to ‘‘add-on control’’ technology and is broad enough to include monitoring equipment. In this case, fenceline monitoring is a type of equipment that we did not identify and consider during development of the original MACT standards. Additionally, the fenceline standard is a work practice standard, involving monitoring, root cause analysis and corrective action not identified at the time of the original MACT standards. Therefore, the fenceline requirements are a development in practices that will improve how facilities manage fugitive emissions and EPA appropriately relied on section 112(d)(6) in requiring this standard. Comment: Some commenters contended that because the fenceline monitoring standard is in essence an ambient standard, the only justification that can be used to support it would be under CAA section 112(f)(2). The commenters stated that EPA determined that the MACT standards pose an acceptable level of risk and protect the public health with an ample margin of safety and thus, section 112(f) does not support imposition of the fenceline monitoring requirement. Several commenters stated that the Agency expressly acknowledges that imposition of additional emission standards for fugitive emissions from refinery sources are not warranted under CAA section 112(f). Some commenters suggested that because the existing MACT standards protect public health with an ample margin of safety, the fenceline monitoring requirement imposes an unnecessary burden on industry because it is not necessary to achieve acceptable risk or provide an ample margin of safety. Response: EPA is not relying on section 112(f)(2) as the basis for the fenceline monitoring requirement. As provided in a previous response to comment, we disagree with the commenters that the fenceline monitoring requirement is an ambient standard and therefore, we do not need to consider what authority would be appropriate for establishing an ambient standard that would apply to fugitive sources of emissions at refineries. We also disagree with the commenters who suggest that EPA may not require fenceline monitoring pursuant to section 112(d)(6) because EPA has not determined that fenceline monitoring is necessary to ensure an acceptable level of risk or the provide an ample margin of safety. Section 112(d)(6) does not E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75194 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations require EPA to factor in the health considerations provided in section 112(f)(2) when making a determination whether it is ‘‘necessary’’ to revise the MACT. Comment: Commenters stated that the pilot studies undertaken by the EPA and pilot studies undertaken by the refining industry (see the API Fenceline Study in the docket for this rulemaking) demonstrate either that there is no underestimation of emissions and thus, no need for the fenceline monitoring work practice standard, or that fenceline benzene data cannot be used to validate emission estimates. Commenters stated that none of the refineries in the API study of the proposed refinery fenceline standard had study-averaged DC concentrations that exceeded the proposed action level of 9 mg/m3 and thus the study provides some evidence that U.S. refineries are not underestimating emissions. Furthermore, the commenter stated that there is significant ambient air monitoring performed that further supports low benzene concentrations in the vicinities of refineries and cited ambient monitoring data collected by the Southeast Texas Regional Planning Commission Air Quality Group and the Texas Commission on Environmental Quality (TCEQ). Response: We disagree that the API fenceline study demonstrates that there is no underestimation of emissions. The API report referred to by the commenter actually shows higher DC concentrations than what we expected, when we compare the distribution of DC’s presented in the API fenceline study to the distribution of benzene concentrations at the 142 refineries we modeled (see memorandum ‘‘Fenceline Ambient Benzene Concentrations Surrounding Petroleum Refineries’’, EPA–HQ–OAR–2010–0682–0208). [Note that API did not identify the facilities in their study, so we were not able to perform a one-to-one comparison of the measured DC concentrations with the modeled fenceline concentrations.] Furthermore, the API conducted the study primarily during the fall and winter months (October to March) when the ambient temperatures are lower than the annual averages. While this may not impact equipment leak emissions, temperature can have a significant impact on emissions from storage vessels and wastewater treatment systems, so it is likely that the annual average DC for the facilities tested could be higher than the ‘‘winter’’ averages measured in the API study. Based on our review of the API study data, we interpret the results to indicate that there may be higher concentrations of VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 benzene on the fenceline attributable to fugitive emissions than anticipated at some facilities. These studies are an indication that the standard we are finalizing will achieve the goal of ensuring that the owners or operators manage fugitive emissions within the refinery. This regulatory approach also fits with the EPA’s goals to improve the effectiveness of rules. Specifically, in this case, we are improving the effectiveness of the rule in two ways. First, we are establishing a fenceline benzene trigger to manage overall fugitive HAP emissions, rather than establishing further requirements on many individual emission points. Secondly, the rule incentivizes facilities to reduce fugitive HAP emissions below the fenceline benzene trigger by providing regulatory options for reduced monitoring. Regarding ambient monitoring data, we note that existing ambient monitors are not located at the fenceline; they are located away from sources, and concentrations typically decrease exponentially with distance from the emissions source. We are encouraged that data referenced by the commenter indicate that ambient levels of benzene are within levels that are protective of human health in communities, but note that analysis of benzene concentrations in communities does not necessarily indicate that refineries located near these communities are adequately managing their fugitive HAP emissions. Comment: Several commenters reiterated that they do not believe the proposed fenceline monitoring is a technology development for equipment leaks, storage vessels or wastewater sources. However, if the EPA finalizes the fenceline monitoring requirements, the commenters suggested that there is no longer a need or regulatory basis for imposing both the fenceline monitoring requirements and the existing MACT standards for fugitive HAP emission sources. Thus, the EPA should remove the current MACT requirements for LDAR, storage vessels and wastewater handling and treatment from Refinery MACT 1 if the EPA promulgates fenceline monitoring. Addition of fenceline monitoring on top of the existing MACT requirements, they argue, would violate the Executive Order 12866 mandate to avoid redundant, costly regulatory requirements that provide no emission reductions. Response: We disagree that the fenceline monitoring standards we are finalizing in this rule are redundant to MACT emissions standards for fugitive HAP emissions sources. The MACT PO 00000 Frm 00018 Fmt 4701 Sfmt 4700 standards impose requirements on fugitive HAP emissions sources consistent with the requirements in CAA section 112(d)(2) & (3), and the fenceline monitoring requirement is not a replacement for those requirements. Rather, based on our review of these standards, we concluded that fenceline monitoring is a development in practices, processes or control technologies that would improve management of fugitive emissions in a cost-effective manner. In selecting this development as an across-the-board means of improving management of fugitive emissions, we rejected other more costly developments that would have applied independently to each fugitive emissions source. Requiring refineries to establish a fenceline monitoring program that identifies HAP emission sources that cause elevated benzene concentrations at the fenceline and correcting high emissions through a more focused effort augments but does not replace the existing requirements. We found that, through early identification of significant fugitive HAP releases through fenceline monitoring, compliance with the existing MACT standards for these emissions sources could be improved and that it was necessary to revise the existing standards because fenceline monitoring is a cost-effective development in processes, practices, and control technologies. We note that the existing MACT requirements are based on the MACT floor (the best performers), and as such, provide a significant degree of emission reductions from the baseline. The action level for the fenceline work practice standard, by contrast, is not based on the best performers but rather on the highest value expected on the fenceline from any refinery, based on the modeling of refinery emission inventories. As such it is not representative of the best performers and could not be justified as meeting the requirements of section 112(d)(2)and (3). If we were to remove the existing standards for fugitive emission sources at the refinery, we would not be able to justify that sources are meeting the level of control we identified as the MACT floor when we first promulgated the MACT. Nor could we justify the fenceline monitoring program we are promulgating as representing the MACT floor because we considered cost (and not the best performers as previously noted) in identifying the components of the program. Although the fenceline monitoring standard on its own cannot be justified as meeting the MACT floor requirement for each of the separate E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 types of fugitive emission sources, that does not mean that it is not an effective enhancement of those MACT requirements. To the contrary, it works in tandem with the existing MACT requirements to provide improved management of fugitive emissions and, in that sense, it is precisely the type of program that we believe Congress had in mind when enacting section 112(d)(6). ii. Rule Should Require Real-Time Monitoring Technology for Fenceline Monitoring. Comment: Numerous commenters stated that the proposed fenceline standards, which require monitoring using 2-week integrated passive samplers, are flawed and weak for a number of reasons, including that the monitoring method does not provide real-time data, does not provide adequate spatial coverage of the fenceline, and does not provide a mechanism to identify the specific emission source impacting the fenceline to manage fugitive emissions. Several commenters suggested that this monitoring technology is not state of the art. They claimed that there are superior systems in place at refineries that are technically and economically feasible, including at Shell Deer Park, Texas; BP Whiting, Indiana; and Chevron Richmond, California. Further, they claimed that these systems more effectively achieve the objective of reducing fugitive emissions. They claimed several systems are superior to the proposed system, including openpath systems such as ultraviolet differential optical absorption (UV DOAS) and Fourier transform infrared spectroscopy (FTIR), as well as point monitors such as gas chromatographs. A number of commenters suggested that open-path monitors should be required, stating that this technology is capable of providing real-time analysis and data on air pollution, is able to analyze multiple pollutants simultaneously at low, nearambient concentrations, and is capable of providing more complete geographic coverage. The commenters also stated that the benefits of real-time monitors are particularly important in communities close to refineries, where they believe refinery emissions are a major source of toxic pollutants and short-term upset events that can have significant public health impacts. In particular, the commenters stated that open-path monitors promote an individual’s rightto-know, in real-time, about harmful pollution events affecting their communities, and will allow refinery owners or operators to immediately identify fugitive emissions and VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 undertake swift corrective action to reduce these emissions. Some commenters suggested that, if the EPA rejects these open-path real-time monitors, then at a minimum the EPA should require the use of active daily monitoring, such as auto-gas chromatograph (GC) systems. Finally, a number of commenters recommended that the EPA provide sufficient flexibility in its regulations to allow state and local jurisdictions to develop, demonstrate, and subsequently require the use of alternative monitoring programs, provided these monitoring programs are at least equivalent to those in the final rule. Response: We understand that many commenters believe real-time monitoring would not only help refinery owners or operators in identifying emission sources, but also would warn the community of releases in real time. Both open-path systems and active sampling systems (such as auto-GCs) mentioned by the commenters, are monitoring systems capable of yielding monitoring data quickly—ranging from a few minutes to about a day. However, these ‘‘real-time’’ systems have not been demonstrated to be able to achieve all of the goals stated by the commenters— specifically, able to provide real-time analysis and data on multiple pollutants simultaneously at low-, near-ambient concentrations, with more complete geographic (or spatial) coverage of the fenceline. The real-time open-path systems suggested by the commenters are all limited in that they are not sensitive enough to detect benzene at the levels needed to ensure that fenceline monitoring achieves its intended goal. The fenceline monitoring system needs to be capable of measuring at sub-ppbv levels—well below the 9 mg/m3 fenceline benzene concentration action level in the final rule, in order to determine the DC. In the proposal, we discussed two open-path monitoring technologies, FTIR and UV–DOAS. For the proposed rule, we analyzed the feasibility of employing UV–DOAS over FTIR because the UV–DOAS is more sensitive to detection of benzene than FTIR, as we described in the proposal. We reviewed performance data on several UV–DOAS systems in support of the proposed rule, and for this final rule, we considered information submitted during the comment period. We found that the lowest detection limit reported for any commercially-available UV–DOAS system is on the order of 3 ppbv over a 200-meter path length, whereas the fenceline benzene concentration action level is 2.8 ppbv (equivalent concentration to 9 mg/m3). PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 75195 This system is being installed at the Shell Deer Park refinery but has not been field validated yet. Thus, we do not yet know the detection capabilities of the system, as installed. Based on the lowest reported detection limit, it cannot achieve the detection levels needed to demonstrate compliance with the fenceline standard in this final rule. This system also will only cover approximately 5 percent of the fenceline at Shell Deer Park, instead of the full fenceline coverage of the passive diffusive tube monitoring system we proposed. Facilities would have to deploy a monitoring system consisting of many open-path monitors to achieve the same spatial coverage as the passive diffusive tube monitoring system. For the final rule, we also reviewed other UV–DOAS systems in operation at refineries that commenters identified. However, reported detection limits for these systems are even higher than for the type of system being installed at Shell Deer Park. For example, we reviewed the open-path UV–DOAS system information from BP Whiting and found that they were able to verify a detection limit of 8 ppbv path average concentration for benzene over a 1,500meter optical path. This is well above the 2.8 ppbv fenceline benzene concentration action level, let alone the sub-ppbv levels necessary to determine the DC. Moreover, this system, though commercially available, was optimized by developing alternative software to improve the detection limit (see memorandum ‘‘Meeting Minutes for April 21, 2015, Meeting Between the U.S. EPA and BP Whiting’’ in Docket ID No. EPA–HQ–OAR–2010–0682). Thus, the system, as installed, would not be readily available to other refineries. We reviewed data for the UV–DOAS system at the Chevron Richmond refinery and found that this system, with optical path lengths ranging from 500 to 1,000 meters, has a reported benzene detection limit of 5 ppbv averaged over the path length. Again, this is above the fenceline benzene concentration action level at the fenceline established in this final rule. In addition, we could not find any information to support the reported detection limit. We note that the public Web site operated by the City of Richmond, California indicates that information provided by the system is informational only, not quality assured, and not to be used for emergency response or health purposes. We also disagree with the commenter’s claim that if the EPA does not finalize requirements for real-time open-path monitors then, at a minimum, the EPA should require active daily monitoring. There are two methods of E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75196 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations active monitoring. One method, which we will refer to as the ‘‘auto-GC method,’’ uses a dedicated gas chromatograph at each monitoring location and can return ambient air concentration results multiple times a day or even hourly. The other method, which we refer to as ‘‘method 2,’’ uses an active pump to collect gas in a sorbent tube or in an evacuated canister over a 1-day period, for later analysis at a central location. While active sampling monitoring networks are capable of measuring multiple pollutants and would likely be able to detect benzene at sub-ppbv levels as necessary to demonstrate compliance with the fenceline requirements in this final rule, they consist of discreet monitors and would not provide any better spatial coverage of the refinery fenceline than a passive diffusive tube monitoring network. Further, as shown in Table 9 of the proposed rule (see 79 FR 36923, June 30, 2014), like open-path systems, an active sampling monitoring network would cost many times that of a passive diffusive tube monitoring network. At proposal, we estimated the costs of active daily sampling based on ‘‘method 2’’ to be approximately 10 times higher than for the proposed passive monitoring (see memorandum ‘‘Fenceline Monitoring Technical Support Document’’, Docket ID No. EPA–HQ–OAR–2010–0682–0210). We note that this type of active daily sampling based on method 2 does not necessarily yield results within 24 hours as the sample analysis would be conducted separately. We did not specifically estimate the costs of an auto-GC alternative, but the capital costs would be at least 20 to 30 times that for the passive diffusive tube system, would require shelters and power supplies at all monitoring locations and would have operating costs similar to the ‘‘method 2’’ active monitoring option we considered. To date, there are no commerciallyavailable, real-time open-path monitors capable of detecting benzene at the subppbv levels necessary to demonstrate compliance with the fenceline requirements in this final rule. Only a system that can detect such levels will result in effective action by facilities to identify and control fugitive emissions in excess of those contemplated by the MACT standards. Further, active monitoring systems, while potentially capable of detecting benzene at subppbv levels, like open-path systems, become very costly when enough monitors are located around the facility to approach the spatial coverage of the passive diffusive tubes. However, we VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 believe that the state of technology is advancing and that the capabilities of these systems will continue to improve and that the costs will likely decrease. If a refinery owner or operator can demonstrate that a particular technology would be able to comply with the fenceline standards, the owner or operator can request the use of an alternative test method under the provisions of 40 CFR 63.7(f). A discussion of the specific requirements for these requests can be found in the first comment and response summary of Chapter 8.3 of the ‘‘Response to Comment’’ document. Comment: One commenter stated that the required monitoring should include real-time monitoring of all chemicals released by refineries that pose risks to human health. The commenter stated that the limited scope of monitoring required by the proposed rule appears to be guided by the EPA’s judgment that fugitive, or ‘‘unintended’’ emissions pose the greatest threat to public health. On the contrary, communities may well suffer from the effects of chemicals released into the air under normal, permitted emissions. A more expansive monitoring strategy would account for both routine and fugitive emissions. Several commenters noted that monitoring is limited to benzene as opposed to multiple HAP. One commenter noted that ill health experienced by refinery neighbors is due in large part to the synergistic effects of multiple chemicals. Therefore, the commenter stated that it is essential that the rule require monitoring of the full range of chemicals with health implications. Other commenters recommended that the fenceline monitoring requirement be amended to include additional contaminants, such as VOC, that may negatively impact human health and the environment. Conversely, other commenters stated that the EPA has appropriately selected benzene as a target analyte and surrogate for HAP emissions from petroleum refineries, as benzene is a common constituent in refinery feedstocks and numerous refinery streams, and is present in most HAPcontaining streams in a refinery. Response: As part of the CAA section 112(d)(6) technology review, the EPA identified the fenceline monitoring standard as a development in practices, processes or control technologies that could improve management of fugitive HAP emissions. Thus, to the extent the commenter is suggesting that the EPA require the fenceline monitoring system to monitor for emissions of non-HAP pollutants, such request goes beyond the scope of our action. Furthermore, to the PO 00000 Frm 00020 Fmt 4701 Sfmt 4700 extent that the commenter is raising health concerns, although we address residual risk remaining after implementation of the MACT standards under CAA section 112(f)(2), we note that the MACT standards themselves, including this requirement, are aimed at protecting public health, especially in surrounding communities. As we explained in the proposal, and as we determine for this final rule, the MACT standards as modified by additional requirements for storage vessels, provide an ample margin of safety to protect public health. We did not propose and are not finalizing a fenceline monitoring requirement as necessary to provide an ample margin of safety under CAA section 112(f)(2). Petroleum refining emissions can contain hundreds of different compounds, including many different HAP, and no single method can detect every HAP potentially emitted from refineries. While several HAP are amenable to quantification via passive diffusive tube monitoring using the same adsorbent tubes used for benzene (e.g., toluene, xylenes and ethyl benzene, which have uptake rates in Table 12.1 in Method 325B), we selected benzene as a surrogate because it is present in nearly all refinery fugitive emissions. By selecting a single HAP as a surrogate for all fugitive HAP, we are able to establish a clear action level, which simplifies the determination of compliance for refinery owners or operators and simplifies the ability of regulators and the public to determine whether sources are complying with the work practice standard. As described in the proposal preamble, benzene is ubiquitous at refineries and present in nearly all refinery process streams, including crude oil, gasoline and wastewater. Additionally, benzene is primarily emitted from ground level, fugitive sources that are the focus of the work practice standard. Thus, we conclude that monitoring of benzene is appropriate and sufficient to identify emission events for which the monitoring program is targeting. Consequently, we are not requiring quantification of other pollutants although refinery owners or operators could choose to analyze the diffusive tube samples for additional HAP in conducting root cause analysis and corrective action. iii. Fenceline Monitoring Action Level Comment: Several commenters stated that the action level for fenceline monitoring (i.e., 9 mg/m3 or 2.8 ppbv), was set too high. Some of these commenters noted that the EPA selected 9 mg/m3 as the highest modeled benzene E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations concentration at any refinery fenceline. One commenter stated that this was arbitrary and capricious and stated the action threshold level makes little sense because only 2 of the 142 modeled facilities are expected to have fenceline concentrations above 4 mg/m3. Several commenters noted that the average modeled benzene concentration is 0.8 mg/m3, which is more than an order of magnitude less than the proposed fenceline benzene concentration action level. Two commenters argued for a lower action level threshold, citing the proposed California OEHHA rule, which finalized new and revised benzene reference exposure levels (REL) that are more stringent than the ones the EPA used in the residual risk assessment supporting the proposed rule. Two commenters stated that while the fenceline benzene concentration action level of 9 mg/m3 is relatively protective compared to standards adopted by many states, including Louisiana and Texas, it is still 80-percent higher than the European Union’s standard of 5 mg/m3. The commenter urged the agency to consider adopting a stricter standard comparable to what other industrialized nations use. Several commenters stated that the EPA’s 9 mg/m3 action level is inconsistent with the statutory text and objectives of CAA sections 112(d) and (f), which direct the EPA to focus on the best-performing, lowest-emitting sources, in order to require the ‘‘maximum achievable’’ emission reductions. The commenters stated that the EPA promulgated the 9 mg/m3 limit without properly following the statutory requirements for establishing MACT floor limits, pointing out that the EPA made no determination of whether or not these general models were representative of the emissions levels actually achieved by the submitting refinery, and no connection was drawn between the best performing sources and the eventual 9 mg/m3 limit. On the other hand, several commenters opposed the 9 mg/m3 action level suggesting that it was not achievable and that it is arbitrary. Some commenters noted that emission/ dispersion models are always very sitespecific and do not necessarily yield a result that is reliable or reproducible. Several commenters stated that additional studies are necessary to allow the agency to account for these variables and set a more appropriate concentration corrective action level. Commenters suggested a 2-year data gathering effort at all refineries and data evaluation before determining a specific threshold to use. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Several commenters recommended action levels ranging from 15 mg/m3 to 20 mg/m3 of benzene to account for the variability expected in monitoring data. The commenters stated that modeling biases have underestimated the necessary action level to achieve the stated goals of the program. Response: First, it is important to note that the purpose of the standard has not changed between proposal and promulgation, namely that it is a technology-based standard that is an advancement in practices to manage fugitive emissions. It is not intended to be a separate or new MACT standard promulgated pursuant to CAA sections 112(d)(2) and (3) for which a ‘‘floor’’ analysis would be required.7 Nor is it a standard that we are promulgating pursuant to CAA section 112(f)(2) as necessary to provide an ample margin of safety to protect public health or prevent an adverse environmental effect.8 Thus, claims that a standard should reflect European Union healthbased standards or the California OEHHA rule are misplaced. We also disagree with the suggestion that the proposed monitoring requirement will allow for higher emissions. As noted elsewhere, we are retaining all of the source-specific requirements for fugitive emissions sources that exist in Refinery MACT 1. We disagree with the commenters that suggest that the proposed action level of 9 mg/m3 is too low and may not be achievable even for well-performing facilities. As discussed in the preamble for the proposed rule, we selected the 9 mg/m3 benzene action level because it is the highest value on the fenceline predicted by the dispersion modeling and, thus, is a level that we estimate that no refinery should exceed when in full compliance with the MACT standards, as amended by this final rule. All of the results of our pilot study, the API study, and the other ambient monitoring data near refineries clearly indicate that this level is achievable. Furthermore, we expect the fenceline concentration difference measured following the procedures in the final 7 To the extent that the commenters are suggesting that EPA must re-perform the MACT floor analysis for purposes of setting a standard pursuant to section 112(d)(6), we note that the D.C. Circuit has rejected this argument numerous times, most recently in National Association for Surface Finishing et al. v. EPA No. 12–1459 in the U.S. Court of Appeals for the District of Columbia. 8 Although we did not establish this limit to address residual risk under CAA section 112(f)(2), the limit was derived from the same inventory used for our risk modelling. Thus, based on our current reference concentration for benzene, the 9 mg/m3 action level will also ensure that people living near the refinery will not be exposed to cancer risks exceeding 100-in-1 million. PO 00000 Frm 00021 Fmt 4701 Sfmt 4700 75197 rule to be indicative of refinery source contributions and we have provided procedures to isolate these concentrations from outside sources, as well as background. We expect that the fenceline monitoring standard will result in improved fugitive HAP emissions management as it will alert the refinery owners or operators of fugitive sources releasing high levels of HAPs, such as large leaks, faulty tank seals, etc. iv. Fenceline Monitoring Root Cause Analysis and Corrective Action Provisions Comment: A number of commenters objected to the proposal’s ‘‘open-ended’’ provisions allowing the EPA to direct refinery owners or operators to change their operations in order to achieve the fenceline limit, with no regulatory limits on costs and without consideration of the impact to safe operations or operability of the plant. Another commenter stated that the EPA must properly assess the costs associated with the root cause analysis/ corrective action requirements and should establish a cost effectiveness threshold for any required root cause analysis/corrective action to ensure that limited resources are effectively and efficiently applied for the control of emissions. One commenter stated the proposed fenceline benzene concentration action level is effectively an ambient air standard, because corrective action to achieve that level is required and that if a facility’s initial corrective action is unsuccessful, the rule provides that further action is required and the EPA must approve that further corrective action plan. Thus, the commenter argued, the EPA would essentially be able to dictate corrective actions, with no bounds on what could be required and no consideration of whether any cost-effective actions are available to assure the action level is met. The commenter continued that such a requirement converts a work practice program to an emission limitation and such ambient air limits are not authorized by CAA section 112. Several commenters noted that LDAR and current work practice programs have no similar requirement for the EPA approval, and the commenters suggested that the requirement for the EPA approval of any second corrective action should not be included in 40 CFR 63.658(h). Another commenter recommended that, if after corrective action, a facility still has an exceedance for the next sampling episode, then the facility should be required to do more than it E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75198 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations did after the first root cause analysis, as the prior corrective action clearly did not correct the problem. The commenter stated that one corrective action measure the EPA should include in all such instances is higher-quality monitoring such as UV–DOAS for at least 1 year to monitor, identify, correct and assure ongoing compliance after the exceedance problem is fixed. Response: The ‘‘on-going’’ requirement to achieve the fenceline benzene concentration action level is no different in concept from the LDAR requirements for equipment or heat exchange systems in the Refinery MACT 1 rule, which requires the refinery owner or operator to repair the source of the emissions regardless of what it takes until compliance with the standard is achieved. We disagree with the claim that the EPA must assess the costs associated with the root cause analysis/corrective action requirements and establish a cost effectiveness threshold for any required root cause analysis/corrective action to ensure that limited resources are effectively and efficiently applied for the control of emissions. We did not attempt to project the costs of the root cause analysis/corrective action for at least two reasons. First, based on the dispersion modeling of the benzene emissions reported in response to the inventory section of the 2011 ICR, we project that no refinery should exceed that fenceline benzene concentration action level if in full compliance with the MACT standards, as amended by this action. Thus, assuming compliance with the MACT standards, we would expect that there are no costs for root cause analysis/corrective action. To the extent that there are exceedances of the action level, the premise of the fenceline monitoring is to provide the refinery owners or operators with the flexibility to identify the most efficient approaches to reduce the emissions that are impacting the fenceline level. Since the choice of control is a very site-specific decision, we would have no way to know how to estimate the costs. Thus, the source is in the best position to ensure that resources are effectively and efficiently spent to address any exceedance. We intended the proposed requirement for refinery owners or operators to submit a corrective action plan for the EPA approval to provide the Administrator with information that they were making a good-faith effort to reduce emissions below the fenceline benzene concentration action level, as expeditiously as practicable. However, we understand the importance for refinery owners or operators to begin VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 corrective action as soon as possible, without having to wait for the EPA approval. Therefore, we are finalizing the requirement for refinery owners or operators to submit such plans but we are not finalizing the requirement that the EPA must approve the plan prior to the corrective action being taken. We previously responded to comments regarding UV–DOAS or other open-path monitoring systems in this section, explaining that the current detection limits for these systems exceeds the action level threshold and, thus, these systems would not provide usable data to inform corrective action. Thus, we disagree that the EPA should require these systems for all facilities whose first attempt at corrective action is ineffective. v. Fenceline Monitor Siting Requirements Comment: Numerous commenters provided suggestions on, or requested clarification of, the monitor siting requirements. Several commenters stated that proposed Method 325A uses the terms ‘‘fenceline or property boundary,’’ while it should consistently use the term ‘‘property boundary’’ or even ‘‘property line’’ as the fenceline location. Several commenters stated that Sections 8.2.2.1.4 and 8.2.2.3 of Draft Method 325A specify that samplers be placed just beyond the intersection where the measured angle intersects the property boundary and this could require placing monitors on other people’s property, in a road, in a water body or in a railroad right-of-way. The commenters suggested that facilities should be allowed to place monitors at any vector location that meets other requirements between the property boundary and the source nearest the property boundary. They stated that facilities need this clarification to avoid obstructions (e.g., buildings or trees) that may be at the property line. Numerous commenters requested that the rule clarify where monitors need to be placed in special circumstance, such as refineries bisected by a road, railroad or other public right-of-way or a boundary next to a navigable waterway. Several commenters stated that refiners should not need to place monitors on these property boundaries or other property boundaries where there are no residences within 500 feet of the property line. Commenters also asked if areas that had non-refinery operations, but are still inside the property boundary, would be included for purposes of determining where to site monitors. A few commenters expressed concern about the approach for determining the PO 00000 Frm 00022 Fmt 4701 Sfmt 4700 number of required monitors at a site based on the acreage, noting that it is unfair to small facilities and will leave gaps in monitoring coverage for very large facilities. Some commenters recommended amending the proposed rule to require the placement of fenceline monitors at fixed distances along facilities’ perimeters with no maximum number of monitors. Some commenters stated that the rule should specify an acceptable range on the 2,000-foot spacing requirement or the radial placement requirement as it may be necessary to address accessibility or safety concerns. Several commenters suggested that a lower minimum number of sampling monitors should be required for very small refineries or small ‘‘subareas.’’ These commenters noted that refineries often include disconnected parcels that can be very small (e.g., 10 acres or less). If each disconnected parcel must be treated as a separate subarea, then both sampler siting options in Draft Method 325A would result in unnecessarily large numbers of samplers extremely close together. Some commenters recommended that Method 325A specify that samplers need not be placed closer than 500 feet (versus the normal 2,000-foot interval specified in Option 2) along the fenceline from an adjoining sampler, regardless of whether the radial or linear approach is used and should waive the minimum number of samplers specified in Sections 8.2.2.1.1, 8.2.2.2.1, and 8.2.3.1. Another commenter added that the rule should waive the requirement for additional samplers in Sections 8.2.2.1.5 and 8.2.3.5 if the 500-foot minimum spacing criterion is compromised. Response: We agree that the Method 325A should provide clear and consistent language. We have revised the language to be consistent in referring to the ‘‘property boundary’’. We have also revised the Method to allow placement of monitors at any radial distance along either a vector location or linear location (that meets the other placement requirements) between the property boundary and the source nearest the property boundary. That is, the monitors do not need to be placed exactly on the property boundary or outside of the property boundary. They may be placed within the property closer to the center of the plant as long as the monitor is still external to all potential emission sources. We do note that if the monitors are placed farther in from the property boundary, the owner or operator should take care to ensure, if possible, that the radial distance from the sources to the monitors is at least 50 E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations meters. If the perimeter line of the actual placement of the fenceline monitors is closer than 50 meters to one or more sources, then the additional monitor citing requirements will apply. We have revised subparagraphs of Section 8.2.2 to provide this allowance. This clarification should address issues related to obstructions such as tall walls located at the facility boundary. We intended that the fenceline monitoring would create a monitoring perimeter capable of detecting emissions from all fugitive emission sources at the refinery facility. We have long established that a road or other right of way that bisects a plant site does not make the plant site two separate facilities, and, thus, would not be considered part of the property boundary. As we agree that monitors need only be placed around the property boundary of the facility, it would not be necessary to place monitors along a road or other right-ofway that bisects a facility. We have clarified this in the final rule and Method 325A. If the facility is bounded by a waterway on one or more sides, then the shoreline is the facility boundary and monitors should be placed along this boundary. If the waterway bisects the facility, the waterway would be considered internal to the facility and monitors would only be needed at the facility perimeter. Regarding the comment that monitors should not be required where there is no residence within 500 feet of the property line, we disagree. We proposed and are finalizing the fenceline monitoring standards under CAA section 112(d)(6) as a means to improve fugitive HAP emissions management, regardless of whether there are people living near a given boundary of the facility. Regarding the clarification requested about monitor placement considering non-refinery operations, the property boundary monitors should be placed outside of all sources at the refinery. This is because moving the monitoring line inward to exclude the non-refinery source could lead to an underestimation of the DC compared to the monitoring external of the entire site. If the nonrefinery source is suspected of contributing significantly to the maximum concentration measured at the fenceline, a site-specific monitoring plan and monitoring location specific near-field interfering source (NFS) corrections will be needed to address this situation. Section 8.2.3 of Method 325A includes language to provide some flexibility when using the linear VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 placement (±10% or ±250 feet). We consider it reasonable to provide similar placement allowance criteria for the radial placement option (±1 degree). We are not providing requirements that would allow small area refineries to use fewer than 12 monitoring sites. We do not consider that any refinery would be so small as to warrant fewer than 12 monitors; however, we did not necessarily consider very small subareas for irregularly shaped facilities or segregated operations. When considering these subareas, we agree that fewer than 12 monitoring sites should be appropriate. Therefore, we have provided that monitors do not need to be placed closer than 152 meters (500 feet) (or 76 meters (250 feet) if known sources are within 50 meters (162 feet) of the monitoring perimeter, which is likely for these subareas or segregated areas) with a stipulation that a minimum of 3 monitoring locations be used per subarea or segregated area. We note, however, that this distance provision does not obviate the near source extra monitoring siting requirements or the requirement to have a minimum of three monitors per subarea or segregated area. If facility owners or operators have questions regarding the required locations of monitors for a specific application, they should contact the EPA (or designated authority) to resolve questions about acceptable monitoring placement. vi. Compliance Time for Fenceline Monitoring Requirements Comment: Some commenters supported EPA’s proposal to provide 3 years to put a fenceline monitoring program in place, but the commenters believe that timing is unclear in the proposed regulatory language, which appears in Table 11 to subpart CC, and requested that the EPA add the initial compliance date to 40 CFR 63.658(a). One commenter stated that instituting this program for all 142 major source U.S. refineries would require considerable time. Based on their experience with their pilot study, one commenter noted that commercially available weather guards meeting the specifications of proposed Method 325A are not available and would need to be fabricated. Additionally, a commenter stated that only a limited number of laboratories in the U.S. are able to perform the necessary analyses. According to the commenter, considerable time and effort will be needed to qualify additional laboratories and to expand the capacity of existing laboratories to handle the samples from 142 refineries. PO 00000 Frm 00023 Fmt 4701 Sfmt 4700 75199 Other commenters disagreed with the EPA’s proposed compliance time and suggested that the EPA shorten the timeline for implementation at refineries so that possible corrective action occurs much sooner than proposed. The commenters suggested that deployment of passive samplers can proceed more promptly than proposed, especially since the EPA has simultaneously proposed specific ‘‘monitor siting and sample collection requirements as EPA method 325A of 40 CFR part 63, Appendix A, and specific methods analyzing the sorbent tube samples as EPA Method 325B of 40 CFR part 63, Appendix A.’’ Moreover, the commenter noted, a principal reason that the EPA selected passive monitors over active monitors was due to the relative ‘‘ease of deployment.’’ The commenter claimed this ease of deployment rationale is undermined by a 3-year grace period to deploy passive monitors when the EPA is providing very specific criteria for their use. The commenter suggested that the EPA require full compliance with the passive monitoring requirement within 1 year of the effective date of the rule. Response: While we realize that it will take some time for the refinery owners or operators to understand the final rule and develop a compliant monitoring program, we agree that in requiring the passive sampler monitoring system, we recognized the ease of implementation and deployment. Although industry commenters identified issues they faced in the API pilot study while trying to implement the monitoring method, we note that the 12 facilities that participated in the API pilot study installed the fenceline monitors and began sampling in late 2013 with relative ease and within months of obtaining the draft methods. Thus, we disagree with the suggestion that 3 years is insufficient and agree with other commenters that 3 years is in fact too long. However, we also are aware that the API pilot facilities used the direct DC approach proposed and did not attempt to develop site-specific monitoring programs to correct for interfering near-field sources. Although we expect that facilities could complete direct implementation of the proposed fenceline monitoring requirement within 1 year after the effective date of the rule, as suggested by some commenters, facilities that choose to develop a site-specific monitoring plan would need a longer period of time. Therefore, we are finalizing requirements that specify that facilities must begin monitoring for the official E:\FR\FM\01DER2.SGM 01DER2 75200 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 determination of DC values no later than 2 years after the effective date of the rule. vii. Fenceline Monitoring Recordkeeping and Reporting Requirements Comment: Some commenters suggested that facilities should be required to submit the monitoring data via the ERT only if they exceed the fenceline benzene concentration action level and that all remaining data should be kept on-site and available for inspection or upon request of the EPA, citing that this is consistent with EPA’s semiannual NESHAP reporting of only exceptions (i.e., deviations). Other commenters requested that the EPA only post the rolling annual average concentration values and not the 2-week monitoring data. These commenters indicated concern that if errors are present in the raw data that are submitted semiannually to the EPA, the data, errors and all, will be released to the public and correcting them will not take place or will not take place in a timely manner. One commenter added that there is very little useful information that can be gleaned from the raw data and posting it simply invites misunderstandings. Commenters also stated that the EPA should adopt reporting requirements to ensure that facilities report the monitoring data appropriately. Specifically, commenters recommended that 40 CFR 63.655(h)(8)(i) should be clarified to only require reporting of valid data and cautioned that data should be processed to allow accurate calculations of annual averages to be used for reporting and evaluation. To accomplish this, commenters recommended that the rule provide 75 days from the end of a 6-month sampling period to report to the EPA, rather than the proposed 45-day period, in order to provide adequate time to obtain quality-assured results for all 2week sampling periods. One commenter applauded the proposal’s requirements for electronic reporting of the fenceline concentration data and making the resulting information publicly available. However, the commenter recommended that the EPA consider a more truncated data reporting period that is more consistent with the associated milestones of collecting a 14-day sampling episode. As is, the commenter claimed, the proposed rule would have a lag time of up to 7.5 months between data collection and posting. The commenter indicated that data reporting on a more frequent schedule will not only provide transparency, but will VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 provide states and local agencies with information about air quality at refineries at a frequency that could allow informed activities to address leaks much more quickly and protect public health. Response: We disagree with the commenters who suggest that facilities only report the rolling annual average or only exceedances of the fenceline benzene concentration action level because the commenters believe there is little information to be gleaned from the raw data. Monitoring data are useful in understanding emissions, testing programs, and in determining and ensuring compliance. We generally require reporting of all test data, not just values calculated from test data and/or where a facility exceeds an emissions or operating limit. For example, when we conduct risk and technology reviews for source categories, we are adding requirements for facilities to submit performance test data into the ERT, not just performance test data that indicates an exceedance of an applicable requirement. In the Mercury and Air Toxics Rule, we require facilities to report direct measurements made with CEMS, such as gas concentrations, and we require hourly reporting of all measured and calculated emissions values (see discussion at 77 FR 9374, February 16, 2012). In particular, for the fenceline monitoring requirements in this final rule, we offer facilities options for delineating background benzene emissions and benzene emissions not attributable to the refinery, and we offer options for reduced monitoring, making it even more necessary that we have all of the data to review to ensure that testing and analyses are being done correctly and in compliance with the requirements set out in the regulations, and that root cause analyses and corrective actions are being performed where necessary. Therefore, as proposed, we are finalizing the requirements that facilities report the individual 2-week sampling period results for each monitor, in addition to the calculated DC values in their quarterly reporting. Regarding commenters’ concerns that facilities post accurate data and have sufficient time to perform quality assurance on the data, in the final rule, we have established provisions for how sources are to address outliers and data corrections. Additionally, as proposed, we do not require an initial report until facilities have collected 1 year of data so that facilities do not report the data until a rolling annual average value can be determined. This will allow refinery staff and analytical laboratories to iron out any issues that might arise as they PO 00000 Frm 00024 Fmt 4701 Sfmt 4700 implement these methods for the first time. Once this initial data collection period is complete, we anticipate that data quality issues should be infrequent. Therefore, we are providing a 45-day period following each quarterly period before facilities must submit the monitoring results, which should provide facilities adequate time to correct any data errors prior to reporting the data. Regarding comments that suggest reporting each 2-week sample result soon after its collection, we disagree. This frequency would put undue burden on the refinery owners or operators in trying to collect, review and quality assure the data prior to reporting. However, we agree with commenters that more frequent reporting of the fenceline monitoring data would be useful. Therefore, we have revised the reporting frequency for the fenceline monitoring data to be quarterly in the final rule rather than semiannually as proposed. Additionally, we understand that there is a lot of interest in how these data will be presented to the public, and we plan to reach out to all stakeholders on appropriate approaches for presenting this information in ways that are helpful and informative. b. Refinery MACT 2 This section provides comment and responses for the key comments received regarding the technology review amendments proposed for Refinery MACT 2. Comment summaries and the EPA’s responses for additional issues raised regarding the proposed requirements resulting from our technology review are in the ‘‘Response to Comment’’ document in the public docket (Docket ID No. EPA–HQ–OAR– 2010–0682). i. FCCU We received comments on the consideration of developments in pollution controls, the averaging time for FCCU PM limits, and the FCCU opacity limit, as discussed below. Comment: One commenter stated that the EPA failed to consider developments in pollution controls for HAP from FCCUs for two reasons. First, the commenter contended that cost is not a valid consideration to evaluate if a ‘‘development’’ in pollution control is necessary pursuant to section 7412(d)(2), (3), (6), unless the EPA is setting a ‘‘beyond-the-floor’’ requirement. Second, the commenter claimed that the EPA’s review of developments is nearly 10 years old and misses some important pollution control E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations improvements in the industry. For example, the commenter noted that Valero Benicia installed a combination of controls in 2012 including a scrubber, SCR and CO Boiler that combine exhaust streams from the FCCU and coking and reportedly eliminate HAP emissions entirely from these sources. The commenter also asserted that EPA consent decrees impose lower effective limits on PM than the EPA considered under the technology review. The commenter identified the BP Whiting facility as subject to 0.7 lb PM/1,000 lbs coke burn-off at one FCCU and 0.9 lb PM/1,000 lbs coke burn-off at another and claimed these limits are lower than the 1.0 lb PM/1,000 lbs coke burn-off limit currently mandated by Refinery MACT 2. Response: We disagree that we cannot consider costs when determining if it is necessary to revise an existing MACT standard based on developments in practices, processes and control technologies. The commenter suggests that we cannot consider costs because of the requirements in CAA section 112(d)(2) and (3) for establishing initial MACT standards and which do not allow for consideration of costs until the second, ‘‘beyond the floor’’ phase of the analysis. As discussed previously in this preamble where we respond to comments on the fenceline monitoring requirements, to the extent that the commenters are suggesting that EPA must re-perform the MACT floor analysis for purposes of setting a standard pursuant to section 112(d)(6), we note that the D.C. Circuit has rejected this argument numerous times, most recently in National Association for Surface Finishing et al. v. EPA No. 12–1459 in the U.S. Court of Appeals for the District of Columbia. Regarding the claim that the EPA did not consider the types of controls at the Valero and BP facilities, we disagree. The control measures for both of those facilities are controls that existed at the time of the development of the MACT standard. Thus, we did not identify these technologies as developments in control technologies during the technology review. However, we did identify developments in processes or practices that reflect better control by the existing technology and we reviewed modified emission limits that reflect that better level of control. The commenter suggested that we failed to consider a level of zero when the Valero facility was able to achieve zero emissions through a combined SCR, boiler and scrubber. However, the commenter provided no information to support such a claim and we are skeptical that such a result could be VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 achieved. We note that the SCR is designed specifically to reduce NOX emissions, and would not be capable of reducing significantly, much less eliminating completely, HAP emissions. Similarly, based on our long-standing understanding of the processes, neither a boiler nor a scrubber could achieve such a result. Regarding the level of emissions achieved at the BP Whiting facility, we note that we evaluated control systems that can meet 0.5 lb PM/ 1,000 lb coke burn-off, which is a lower limit than that at BP Whiting. We determined that these were costeffective to require for new units that are installing a new control system. However, we determined that retrofitting controls designed to meet a PM limit of 1.0 lb PM/1,000 lbs coke burn-off to now meet a limit of 0.5 lb PM/1,000 lbs coke burn-off was not cost-effective when considering PM and PM2.5 emissions reductions. We projected the cost of the 0.5 lb PM/1,000 lbs coke burn-off limit in retrofit cases to be $23,000 per ton PM emissions reduced. To meet a limit of 0.7 lb PM/ 1,000 lbs coke burn-off or 0.9 lb PM/ 1,000 lbs coke burn-off, as is the case for BP Whiting, the retrofit costs would be similar to this 0.5 lb PM/1,000 lb coke burn-off option, but the reductions would be even less, resulting in costs over $23,000 per ton. As metal HAP content of FCCU PM is approximately 0.1 to 0.2-percent of the total PM, the cost of requiring this lower limit for existing FCCU is over $10 million per ton of metal HAP reduced. Therefore, we determined that it is not necessary to revise the PM standard for existing FCCU sources. Comment: Refinery MACT 2 requires the owner or operator to demonstrate compliance with the PM FCCU limits by complying with the operating limits established during the performance test on a daily (i.e., 24-hour) average basis. Several commenters objected to the EPA’s proposal to revise this requirement to a 3-hour averaging time. Commenters restated EPA’s arguments for 3-hour averaging time as: (1) Daily average could allow FCCUs to exceed limits for short periods while still complying with the daily average, (2) consistency with NSPS subpart Ja and (3) consistency with duration of testing. The commenters stated that the EPA had not provided any data that show that the daily average could allow FCCUs to exceed limits for short periods and, therefore, the EPA is using a hypothetical compliance assurance argument to change emission limits. The commenters stated that a change in emission limits is not authorized by PO 00000 Frm 00025 Fmt 4701 Sfmt 4700 75201 CAA section 112 because the emission limitations in Refinery MACT 2 for FCCUs were established as daily averages following the floor and ample margin of safety requirements in section 112(d)(2) of the CAA. The commenters also state that the EPA’s additional arguments for the change to a 3-hour average are irrelevant and legally deficient. The commenters stated that the combination of a numerical emission limit and an averaging period frames the stringency of a limitation and that a reduction in either of those factors results in a significant lowering of the operating limit. The commenters conclude that the EPA has proposed to change the stringency of the requirements without justification, and the CAA requires that such a change in stringency be justified pursuant to CAA section 112(d)(6) or (f)(2). The commenters stated that increasing stringency for consistency with NSPS rules is not a criterion for a CAA section 112(d)(6) action. Rather that section requires a change to be due to ‘‘developments.’’ The only change in technology since the 2002 promulgation of Refinery MACT 2 is the availability of PM continuous emission monitoring system (CEMS), which is unproven. One commenter noted that changing the averaging time is a very significant modification considering that the compliance limits would apply for periods of SSM. This commenter stated that it is unlikely that existing operations can consistently be in compliance with a new 3-hour average since the current daily averaging was put in place to recognize that there will be periods of operating variability that do not represent the longer term performance of an FCCU. The commenters recommended that the EPA retain the daily averaging requirement. Response: We disagree with the commenters’ statement that reducing the averaging time from a 24-hour basis to a 3-hour basis for demonstrating compliance with the FCCU PM emission limit, using operating limits established during the performance test, is a change to the MACT floor. The emission limit of 1.0 lb PM/1,000 lbs coke burn-off is the MACT floor, and we are not changing the PM emissions limit (or alternate Ni limits) in Table 1 to subpart UUU (except to remove the incremental PM limit that did not comport with the MACT floor emissions limitation). However, whether or not it is a change from the MACT floor is not relevant. Pursuant to CAA section 112(d)(6), the EPA must revise MACT standards ‘‘as necessary’’ considering developments in practices, processes and control technologies. For this E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75202 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations exercise, we considered any of the following to be a ‘‘development’’: • Any add-on control technology or other equipment that was not identified and considered during development of the original MACT standards. • Any improvements in add-on control technology or other equipment (that were identified and considered during development of the original MACT standards) that could result in additional emissions reduction. • Any work practice or operational procedure that was not identified or considered during development of the original MACT standards. • Any process change or pollution prevention alternative that could be broadly applied to the industry and that was not identified or considered during development of the original MACT standards. • Any significant changes in the cost (including cost effectiveness) of applying controls (including controls the EPA considered during the development of the original MACT standards). In determining whether there are ‘‘developments,’’ we review, among other things, EPA regulations promulgated after adoption of the MACT, such as the NSPS we identified in this instance. We identified the enhanced monitoring requirements for these operating limits as a development in practices that will help ensure FCCU owners or operators are properly operating control devices and, thus, are meeting the PM emission limit at all times. We further determined that this enhanced monitoring was cost effective and proposed that it was necessary to revise the existing standard pursuant to CAA section 112(d)(6). While we do not have continuous PM emissions data that show actual deviations of the PM limit, we do not need such data in order to conclude that such deviations could occur when daily averages are used. The Refinery MACT 2 (i.e., subpart UUU) rule requires owners or operators to establish operating limits based on three 1-hour runs during the performance test. As a matter of simple mathematics, a source could demonstrate that it is meeting the operating limit based on a 24-hour average but could be exceeding the 1.0 lb PM/1,000 lbs coke burn-off emission limit based on a 24-hour average or for one or more individual 3-hour periods during that 24-hour average. For example, an owner or operator could operate with a power input 5-percent higher than the operating limit for 23 hours, have the ESP off (zero power) for one hour, and still comply with a 24hour average operating limit. However, VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 it would be difficult for this same unit to meet the 1.0 lb PM/1,000 lbs coke burn-off emissions limit over a 24-hour period, and it certainly would not meet the limit for every 3-hour period during that day. As the operating limit can be established to correspond with 1.0 lb PM/1,000 lbs coke burn-off, the 5percent higher power input would likely correspond with a 0.95 lb PM/ 1,000 lbs coke burn-off emissions rate (5-percent lower). Uncontrolled emissions are typically 6 to 8 lbs/1,000 lbs coke burn-off. Thus, this unit would have emissions averaging approximately 1.2 lbs PM/1,000 lbs coke burn-off during this 24-hour period [i.e., (0.95*23+7)/24], but would be in compliance with the 24-hour average operating limit. The unit would obviously also be out of compliance with the 3-hour average over the period when the power was turned off. We also have concerns that the operating limits are not always linear with the emissions, so that the longer averaging times do not effectively ensure compliance with the PM emissions limit. Therefore, as proposed, we are finalizing the requirement for owners or operators to comply with the operating limits on a 3-hour basis, rather than the 24-hour basis currently in the rule. Comment: The technology review for FCCUs resulted in the EPA proposing to remove the 30-percent opacity alternative limit for demonstrating compliance with the PM emissions limit that is available for refineries complying with the Refinery NSPS 40 CFR part 63, subpart J. Two commenters supported the EPA’s proposed removal of the 30percent opacity limit for FCCUs. Other commenters stated that current technology is good enough for a 10- or 20-percent opacity limit. On the other hand, several commenters stated that the proposed removal of the 30-percent opacity limit must meet the criteria specified in CAA section 112(d)(6) and (f)(2), which requires analysis of the statutory basis, environmental impacts, costs, operational and compliance feasibility and impacts, that the EPA has not conducted. The commenters claimed that had the EPA conducted a proper analysis, the EPA would have determined that the proposed change to remove the 30-percent opacity limit is not necessary or supportable. Additionally, these commenters stated that since the underlying PM emissions limit is unchanged, there is no emission reduction justification for this proposed change, and the change would not meet the CAA section 112(d)(6) requirement of being cost effective. The commenters also noted that processes or practices for PO 00000 Frm 00026 Fmt 4701 Sfmt 4700 existing FCCUs have not changed, as required for a CAA section 112(d)(6) revision. Several commenters urged the EPA to maintain the 30-percent opacity limit for these FCCUs. As a practicable and cost-effective alternative to address the EPA’s concern as to whether compliance with a 30-percent opacity limit ensures compliance with the PM emissions limit, commenters suggested annual performance tests to confirm that the FCCU is meeting the PM emissions limit, rather than performance tests every 5 years, as proposed. One commenter stated that the EPA never intended for the opacity limit in Refinery NSPS subpart J to be used to demonstrate compliance with the PM emissions limit, but instead to assure the PM controls operate properly. The commenter stated that the EPA’s conclusion that the 30-percent opacity limit may not be sufficiently stringent to ensure compliance with the underlying PM emissions limit is based on a false premise as to the purpose of the opacity standard because as the EPA states, ‘‘Opacity of emissions is indicative of whether control equipment is properly maintained and operated.’’ Several commenters stated that the proposed elimination of the 30-percent opacity limit currently in Refinery MACT 2 leaves existing FCCUs that use cyclones with no viable alternative approach to demonstrate compliance with the PM emissions limit without adding or replacing controls. They stated the other approaches for demonstrating compliance with the PM emissions limit in Refinery MACT 2 (such as development of a site-specific opacity limit) do not work for them. The commenters stated that although they believe that more frequent performance tests would show that the FCCUs are in fact meeting the PM emissions limit, the absence of the 30-percent opacity limit would force FCCUs using cyclones for PM control to install additional, costly PM controls (e.g., ESPs or wet gas scrubbers). They projected that these additional controls would cost tens of millions of dollars per FCCU and would require at least 3 years of compliance time. Additionally, one commenter stated that even FCCUs with additional downstream PM controls would not be able to achieve a site-specific limit at all times and needed the availability of the alternative 30-percent opacity limit. One commenter estimated that installing an ESP to meet the proposed 10-percent opacity limit would cost approximately $121,000/ton, assuming a 32 tpy PM emission reduction. The commenter noted that the ESP would also increase GHG emissions and require more energy E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations resources from the facility. The commenter concluded that installing an ESP is neither cost effective nor appropriate considering non-air quality environmental and health impacts and energy requirements, and recommended that the EPA maintain the current NSPS subpart J alternative limits and add additional alternative limits into Refinery MACT 2 only as optional limits for demonstrating compliance with the PM emissions limit. Response: In promulgating Refinery MACT 2, the EPA identified the 1.0 lb PM/1,000 lbs coke burn-off limit as the MACT floor but allowed a compliance option for FCCUs subject to Refinery NSPS subpart J to comply with an opacity limit up to 30 percent with one 6-minute allowance to exceed the 30percent opacity in any 1-hour period. As stated in the proposal, compliance studies have shown that the 30-percent opacity limit does not correlate well with the 1.0 lb PM/1,000 lbs coke burnoff limit, and that an FCCU can comply with the 30-percent opacity limit while its emissions exceed the PM emissions limit.9 Regardless of whether the 30percent opacity limit in Refinery NSPS subpart J was designed to ‘‘ensure that the control device was operated properly,’’ Refinery MACT 2 allows sources subject to NSPS subpart J to use the 30-percent opacity limit to demonstrate continuous compliance with the PM emissions limit. We have determined that the 30-percent opacity limit is inadequate for the purpose of demonstrating continuous compliance with the PM emissions limits in Refinery MACT 2. As such, we proposed to remove this opacity limit and require the owner or operator to either demonstrate compliance with the PM emissions limit by continuously monitoring the control device parameters established during the performance test or establish and monitor a site-specific opacity limit. For clarity, we note that we proposed to allow a site-specific opacity limit, not a 10-percent opacity limit as some commenters suggest. The site-specific opacity limit can be significantly higher than 10 percent, but it cannot be lower than 10 percent. While the compliance study indicates that a 30-percent opacity limit does not correlate well with a 1.0 lb PM/1,000 lbs coke burn-off emissions limit, further review of this same study indicates that a 20-percent opacity limit provides a reasonable correlation with units 9 Compliance Investigations and Enforcement of Existing Air Emission Regulations at Region 5 Petroleum Refineries. U.S. Environmental Protection Agency, Region 5—Air and Radiation, Chicago, Illinois. March 9, 1998. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 meeting the 1.0 lb PM/1,000 lbs coke burn-off emissions limit. We also reviewed the data submitted by the commenters regarding PM emissions and opacity correlation. While the data suggest that there is variability and uncertainty in the PM/opacity correlation, the data do not support that a 30-percent opacity limit would ensure compliance even when considering the uncertainty associated with the PM/ opacity correlation. Based on the variability of the 3-run average opacity limits, we determined that, if the 3-hour average opacity exceeded 20-percent, then it was highly likely (98 to 99percent confidence) that the FCCU emissions from the unit tested would exceed the PM emissions limit. After considering the public comments, reviewing the data submitted with those comments, and further review of the compliance study, in this final rule we are adding a 20-percent opacity limit, evaluated on a 3-hour average basis for units subject to NSPS subpart J. As we noted above, a 20percent opacity limit provides a reasonable correlation with the PM emissions limit, and an exceedance of this 20-percent opacity limit will provide evidence that the PM emissions limit is exceeded. However, it is possible that units could still exceed the PM emissions limit while complying with the 20-percent opacity limit, if those units operate close to the 1 lb PM/ 1,000 lbs coke burn-off emissions limit. To address this concern, we considered the commenters’ suggestion to require a performance test annually rather than once every 5 years. Some commenters suggested that this option specifically apply to FCCUs with cyclones, but this option is applicable to any control system operating very near the PM emissions limit and using an opacity limit to demonstrate continuous compliance. We have determined that the Refinery NSPS subpart J compliance procedures in Refinery MACT 2, in combination with a 20-percent opacity limit demonstrated on a 3-hour average basis and with annual performance tests when a test indicates PM emissions are greater than 80-percent of the limit (i.e., 0.80 lb PM/1,000 lbs coke burn-off), will ensure continuous compliance with the PM emissions limit. FCCUs with measured PM emissions during the performance test at or below 0.80 lb PM/ 1000 lbs of coke burn-off will remain subject to the requirement to conduct performance tests once every 5 years, consistent with the requirements we proposed. We do not agree with commenters that the proposed opacity revision would add significant cost or PO 00000 Frm 00027 Fmt 4701 Sfmt 4700 75203 compliance burden. The control devicespecific monitoring parameters that were proposed rely on parameters commonly used to control the operation of the control device, so the monitoring systems should be already available. Further, since we are merely changing the opacity limit, we expect these units will already have opacity monitoring systems needed to demonstrate compliance with the PM emissions limit and would not incur costs for new equipment. Comment: Several commenters stated that they agree with the EPA’s determination in the proposal that the current CO limits provide adequate control of HCN. Two commenters stated that there are limited HCN emissions data and that more data are needed before the Agency can appropriately determine whether an HCN standard is necessary and justified. One commenter noted that the process undertaken by the EPA to estimate HCN emissions was flawed, and likely overestimates HCN emissions significantly. Another commenter stated that they performed HCN stack testing at three refineries and subsequent modeling at two refineries and concluded that the ambient HCN emissions were well below the applicable health limits. In contrast, some commenters expressed concerns about high HCN levels. One commenter stated that the EPA should consider re-evaluating the benefit of low NOX emissions from the FCCU, if that is indeed the cause of higher HCN emissions, because exposing people to HCN is not acceptable. The commenter also noted that the community now also has the increased dangers of storing and transporting aqueous ammonia, which is used in some cases to achieve low NOX emissions from the FCCU. One commenter stated that the EPA must set stronger HCN standards on FCCU emissions because of the high release amounts reported, the fact that non-cancer risk is driven by emissions of HCN from FCCU, and the fact that the EPA has never set standards for HCN emissions. The commenter provided a report that they believe shows that the EPA has not shown that CO is a reasonable or lawful surrogate to control HCN and has not shown that the conditions necessary for a surrogate are met with regard to CO and HCN, which is an inorganic nonmetallic HAP. Further, the report indicates that SCR is a reasonable and cost effective method for controlling HCN and that the EPA failed to review and consider other viable methods to control HCN and must do so to satisfy its legal obligations in this rulemaking. E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75204 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Response: At the time we promulgated the MACT, we determined that the control strategy used by the best performing facilities to reduce organic HAP emissions was the use of complete combustion, which occurs when the CO concentration is reduced to 500 ppmv (see the proposal for Refinery MACT 2 at 63 FR 48899, September 11, 1998). We rejected arguments that some facilities operate at CO levels well below 500 ppmv and, thus, the MACT floor should be set at a lower CO concentration because once CO concentrations reached 500 ppmv, there was no longer a correlation between reduced CO concentrations and reduced HAP concentrations. And, in fact, emissions of certain HAP, such as formaldehyde, tended to increase as CO concentrations were reduced below 500 ppmv.10 In the current rulemaking action, we determined at the time of the proposed rule that this also holds true for HCN emissions. That is, once CO emissions are reduced to below 500 ppmv (i.e., complete combustion is achieved), we no longer see a direct correlation between CO concentrations and HCN emissions. All of the HCN emissions data we have were reported from units operating at or below the 500 ppmv CO limit (i.e., in the complete combustion range), so it is not surprising that there is not a strong correlation between CO and HCN from the FCCU ICR source test data. However, catalyst vendor data and combustion kinetic theory support the fact that, in the partial burn mode (with CO concentrations of 2 to 6-percent, which is 20,000 to 60,000 ppmv), HCN concentrations exiting the FCCU regenerator are much greater than for units using complete combustion FCCU regenerators or the concentration exiting a post-combustion device used in conjunction with a partial burn FCCU regenerator. Therefore, we maintain that complete combustion is the primary control needed to achieve controlled levels of HCN emissions. We initially thought the higher levels of HCN emissions that were reported by sources achieving complete combustion might be due to a switch away from platinum-based combustion promoters to palladium-based combustion promoters. However, many of the units that were tested and that had some of the lowest HCN emissions used palladium-based oxygen promoters. Therefore, it appears unlikely that 10 U.S. EPA, 2001. Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units—Background Information for Promulgated Standards and Response to Comments. Final Report.EPA–453/R–01–011. June. p. 1–19. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 palladium-based catalyst promoters are linked to the higher HCN emissions. We also evaluated one commenter’s argument that CO is not a good surrogate for HCN emissions, but that SCR are a reasonable and cost-effective control strategy. We are not aware of any data that suggest that an SCR removes HCN and the commenter did not provide any support for that premise. At proposal, we evaluated HCN control on units using extra oxygen or converting back to platinumbased promoters to oxidize any HCN formed. This would cause more NOX formation, which would then require post-combustion NOX control, such as an SCR. However, if HCN emissions are not a function of CO concentration beyond that required to achieve complete combustion (as noted by the commenter), then more aggressive combustion conditions and the use of an SCR (to remove the NOX formed) may not be a viable control strategy. Therefore, considering all of the data currently available and the comments received regarding HCN emissions and controls, we maintain that the only proven control technique is the use of complete combustion as defined by a CO level of 500 ppmv or less. We are not establishing a more stringent CO level because, once complete combustion is achieved, (i.e., CO concentrations drop below 500 ppmv), no further reduction in HCN emissions are achieved. For the purposes of Refinery MACT 2, we consider the emission limits and operating requirements for organic HAP in Tables 8 through 14 to subpart UUU of part 63 adequate to also limit HCN emissions. Finally, we understand concerns about the reported HCN emissions being higher than anticipated and the need for more data to better determine HCN emissions levels. To address these concerns, we are finalizing a requirement that facility owners or operators conduct a performance test for HCN from all FCCU at the same time they conduct the first PM performance test on the FCCU following promulgation of this rule. Facility owners or operators that conducted a performance test for HCN from a FCCU in response to the refinery ICR or subsequent to the 2011 Petroleum Refinery ICR following appropriate methods are not required to retest that FCCU. PO 00000 Frm 00028 Fmt 4701 Sfmt 4700 4. What is the rationale for our final approach for the technology review? a. Refinery MACT 1 We did not receive substantive comments concerning our proposal that it was not necessary to revise Refinery MACT 1 requirements for MPV, gasoline loading racks and cooling towers/heat exchange systems. Based on the rationale provided in the preamble to the proposed rule, we are taking final action concluding that it is not necessary pursuant to CAA section 112(d)(6) to revise the MACT requirements for MPV, gasoline loading racks and cooling towers/heat exchange systems emission sources at refineries. We proposed that the options for additional wastewater controls are not cost effective and thus it was not necessary to revise the MACT for these emission sources. We received public comments suggesting that emissions from wastewater systems are higher than modeled and that we should develop additional technology standards for wastewater treatment systems regardless of cost. As we discussed in the proposal, emissions from wastewater are difficult to measure and emission estimates rely on process data and empirical correlations, which introduces uncertainty into the estimates. Although we do not have evidence, based on the process data we collected, that emissions are higher than modeled at proposal, we note that the fenceline monitoring program effectively ensures that wastewater emissions are not significantly greater than those included in the emissions inventory and modeled in the risk assessment. Furthermore, we believe that cost is a valid consideration in determining whether it is necessary within the meaning of section 112(d)(6) to revise requirements and that we are not required to establish additional controls regardless of cost. Consequently, we conclude that it is not necessary to revise the Refinery MACT 1 requirements for wastewater systems pursuant to CAA section 112(d)(6). For storage vessels, we identified a number of options, including requiring tank fitting controls for external and internal floating roof tanks, controlling smaller tanks with lower vapor pressures and requiring additional monitoring to prevent roof landings, liquid level overfills and to identify leaking vents as developments in practices, processes and control technology. We proposed to crossreference the storage vessel requirements in the Generic MACT (effectively requiring additional control for tank roof fittings) and to revise the E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations definition of Group 1 storage vessels to include smaller tanks with lower vapor pressures. We received comments that we could have required additional controls on tanks and monitoring for landings, overfills and leaking vents described above. We also received comments related to clarifications of specific rule references and overlap provisions. We addressed these comments in the ‘‘Response to Comments’’ document, and we maintain that the additional control options described by the commenters (tank roof landing/degassing requirements or use of geodesic domes to retrofit external floating roofs) are not cost-effective. Consequently, based on the rationale provided in the preamble to the proposed rule and our consideration of public comments, we are finalizing the requirements as proposed with minor clarifications of the rule references. However, as with wastewater systems, we note that the fenceline monitoring program will ensure that the owner or operator is effectively managing fugitive emissions sources and should detect landings, overfills, and leaking vents. For equipment leaks, we identified specific developments in practices, processes and control technologies that included requiring repair of leaking components at lower leak definitions, requiring monitoring of connectors, and allowing the use of the optical imaging camera as an alternative method of monitoring for leaks. We proposed to establish an alternative method for refineries to meet LDAR requirements in Refinery MACT 1. This alternative would allow refineries to monitor for leaks via optical gas imaging in place of EPA Method 21, using monitoring requirements to be specified in a not yet proposed appendix K to 40 CFR part 60. However, the development of appendix K is taking longer than anticipated. Therefore, we are not finalizing this alternative monitoring method in Refinery MACT 1. We received comments suggesting that additional requirements be imposed to further reduce emissions from leaking equipment components, such as requiring ‘‘leakless’’ equipment, reducing the leak threshold, and eliminating delay of repair provisions. As provided in the ‘‘Response to Comments’’ document, we do not agree that these additional requirements are cost-effective. Based on the rationale provided in the preamble to the proposed rule and our consideration of public comments, we conclude that it is not necessary to revise the Refinery MACT 1 requirements for equipment leaks. Again, however, the fenceline monitoring program is intended to VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 ensure that large leaks from fugitive emissions sources, including equipment leaks, are more quickly identified and repaired, thereby helping to reduce emissions from leaking equipment components. For marine vessel loading, we identified control of marine vessel loading operations with HAP emissions of less than 10/25 tpy and the use of lean oil absorption systems as developments that we considered in the technology review. We proposed to amend 40 CFR part 63, subpart Y to require small marine vessel loading operations (i.e., operations with HAP emissions less than 10/25 tpy) and offshore marine vessel loading operations to use submerged filling based on the cargo filling line requirements in 46 CFR 153.282. We received comments that other options considered during the technology review of the standard were costeffective for small marine vessel loading operations and should be required. As provided in the ‘‘Response to Comments,’’ we continue to believe those other controls are not costeffective because of the high costs of controls for limited additional organic HAP emission reduction. Therefore, we are finalizing these amendments as proposed. Finally, we proposed that it was necessary to revise the MACT to require fenceline monitoring as a means to manage fugitive emissions from the entire petroleum refinery, which includes sources such as wastewater collection and treatment operations, equipment leaks and storage vessels. We received numerous comments regarding the proposed requirement to conduct fenceline monitoring, many of which we address above and the remainder of which we respond to in the ‘‘Response to Comments’’ document. After considering comments, we maintain that the proposed work practice standard is authorized under section 112 of the CAA and will improve fugitive management at the refinery. Therefore, we are finalizing the key components of fenceline monitoring work practice as proposed. These requirements include the use of passive diffusive tube samplers (although we are providing a mechanism to request approval for alternative monitoring systems provided certain criteria are met), the 9 mg/m3 on a rolling annual average basis action level, and the need to perform corrective action to comply with the action level. Based on public comments received, we are making numerous revisions to clarify the fenceline monitor siting requirements. This includes provisions PO 00000 Frm 00029 Fmt 4701 Sfmt 4700 75205 to allow siting of monitors within the property boundary as long as all emissions sources at the refinery are included within the monitoring perimeter. We are also clarifying that we do not consider public roads or public waterways that bisect a refinery to be property boundaries, and owners or operators do not need to place monitors along the internal public right-of-ways. We are also providing provisions to allow fixed placement of monitors at 500 feet intervals (with a minimum of 3 monitors) for subareas or segregated areas. If an emissions source is near the monitoring perimeter, an additional monitor siting requirement would still apply. The 500 feet provision is provided to reduce burden for facilities with irregular shapes or noncontiguous property areas that we did not fully consider at proposal. We also received comments on the compliance time and reporting requirements associated with the fenceline monitoring provisions. Upon consideration of public comments, we have revised the compliance period to 2 years after the effective date of the final rule. Thus, beginning no later than 2 years after the effective date of the rule, the source must have a fenceline monitoring system that is collecting samples such that the first rolling annual average DC value would be completed no later than 3 years after the effective date of the final rule. Facilities will have 45 days after the completion of the first year of sampling, as proposed, to submit the initial data set. We are reducing the proposed compliance period from 3 years to 2 years because the passive diffusive tube monitors are easy to deploy and pilot study demonstrations indicate that significant time is not needed to deploy the monitors. However, the reduced compliance period still provides time to resolve site-specific monitor placement issues and to provide time to develop and implement a site-specific monitoring plan, if needed. We are increasing the fenceline monitoring reporting frequency (after the first year of data collection) from semiannually to quarterly to provide more timely dissemination of the data collected via this monitoring program. b. Refinery MACT 2 We proposed to revise Refinery MACT 2 to incorporate the developments in monitoring practices and control technologies reflected in the Refinery NSPS subpart Ja limits and monitoring provisions (73 FR 35838, June 24, 2008). We are finalizing most of these provisions as proposed. Specifically, we are incorporating the E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75206 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Refinery NSPS subpart Ja PM limit for new FCCU sources. We are also finalizing compliance options for FCCU that are not subject to Refinery NSPS subpart J or Ja. These options would allow such sources to elect to comply with the Refinery NSPS subpart Ja monitoring provisions to demonstrate compliance with the emissions PM limit. We are revising the averaging period for the control device operating limits or site-specific opacity limits to be on a 3-hour average basis in order to more directly link the operating limit to the duration of the performance test runs, on which they are based, as proposed. We are incorporating additional control device-specific monitoring alternatives for various control devices on FCCU, including BLD monitoring as an option to COMS for owners or operators of FCCU using fabric filter-type control systems and total power and secondary current operating limits for owners or operators of ESPs. We are adding an additional requirement to perform daily checks of the air or water pressure to atomizing spray nozzles for owners or operators of FCCU wet gas scrubbers not subject to the pressure drop operating limit, as proposed. Finally, we finalizing requirements to conduct a performance test at least once every 5 years for all FCCU, as proposed. These requirements are being finalized to ensure that control devices are continuously operated in a manner similar to the operating conditions of the performance test and to ensure that the emissions limits, which are assessed based on the results of three 1-hour test runs, are achieved at all times. We also proposed to eliminate the Refinery NSPS subpart J compliance option that allows refineries to meet the 30-percent opacity emissions limit requirement and revise the MACT to include control device operating limits or site-specific opacity limits identical to those required in Refinery NSPS subpart Ja. We received numerous comments, particularly from owners or operators of FCCU that employ tertiary cyclones to control FCCU PM emissions. According to the commenters, opacity is not a direct indicator of PM emissions because finer particles will increase opacity readings without a corresponding mass increase in PM emissions. Additionally, the commenters stated that the site-specific opacity limit generally leads to a sitespecific operating limit of 10-percent opacity, which is too stringent and does not adequately account for variability between PM emissions and opacity readings. According to the commenters, VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 FCCU with tertiary cyclones would need to be retrofitted with expensive and costly controls in order to meet the 10-percent opacity limit, even though they are meeting the 1 lb/1000 lbs coke burn PM emissions limit. It was not our intent to require units to retrofit their controls simply to meet the site-specific opacity limit. However, the existing 30percent opacity limit in the subpart J compliance option is not adequate to ensure compliance with the PM emissions limit at all times. After reviewing the public comments and available data, we determined that, rather than removing the subpart J compliance option altogether, it is sufficient to add an opacity operating limit of 20-percent opacity determined on a 3-hour average basis to the existing subpart J compliance option and to require units complying with this operating limit to conduct annual performance tests (rather than one every 5 years) when the PM emissions measured during the source test are greater than 0.80 lb PM/1,000 lbs coke burn-off. These provisions improve assurance that these units are, in fact, achieving the required PM emissions limitation without requiring units to retrofit controls due to variability in the correlation of PM emissions and opacity. We did not propose to revise the organic HAP emissions limits for FCCU to further address HCN emissions. We received numerous comments on this issue. We continue to believe that complete combustion is the appropriate control needed to control HCN emissions. Consequently, for the purposes of Refinery MACT 2, we are not changing the MACT standards to further reduce emissions of HCN. However, we understand that there are uncertainties and high variability in HCN emissions measured from FCCU. In order to address the need for more data to better characterize HCN emissions levels, we are finalizing a requirement for refinery owners or operators to conduct a performance test for HCN from all FCCU (except those units that were tested previously using acceptable methods as outlined in the 2011 Refinery ICR) during the first PM test required as part of the on-going compliance requirements for FCCU metal HAP emissions. These data will be useful to the EPA in understanding HCN emissions from FCU and may help to inform future regulatory reviews for this source category. We proposed that there have been no developments in practices, processes, and control technologies for CRU based on our technology review and that therefore it is not necessary to revise PO 00000 Frm 00030 Fmt 4701 Sfmt 4700 these standards. Based on the rationale provided in the preamble to the proposed rule and our consideration of public comments, we are finalizing our conclusion. For SRU, we identified the Refinery NSPS subpart Ja allowance for oxygenenriched air as a development in practice and we proposed that it was necessary to revise the MACT to allow SRU to comply with Refinery subpart Ja as a means of complying with Refinery MACT 2. The key issue identified by commenters was that Refinery NSPS subpart Ja includes a flow monitoring alternative for determining the average oxygen concentration in the enriched air stream and that this was not included in the proposed amendments to Refinery MACT 2. This was an oversight on our part. We are, based on the rationale provided in the preamble to the proposed rule and our consideration of public comments, finalizing the SRU revisions as proposed but with inclusion of the flow monitoring alternative provisions that are in Refinery NSPS subpart Ja for this source. C. Refinery MACT Amendments Pursuant to CAA Section 112(d)(2) and (d)(3) 1. What did we propose pursuant to CAA section 112(d)(2) and (d)(3) for the Petroleum Refinery source categories? We proposed the following revisions to the Refinery MACT 1 and 2 standards pursuant to CAA section 112(d)(2) and (3) 11: (1) Adding MACT standards for DCU decoking operations; (2) revising the CRU purge vent pressure exemption; (3) adding operational requirements for flares used as APCD in Refinery MACT 1 and 2; and (4) adding requirements and clarifications for vent control bypasses in Refinery MACT 1. For DCU, we proposed to require that prior to venting or draining, each coke drum must be depressured to a closed blowdown system until the coke drum vessel pressure is 2 psig or less. As proposed, the 2 psig limit would apply to each vessel opening/venting/draining event at new or existing affected DCU facilities. For the CRU, we proposed to require that any emissions during the active 11 The EPA has authority under CAA section 112(d)(2) and (d)(3) to set MACT standards for previously unregulated emission points. EPA also retains the discretion to revise a MACT standard under the authority of section 112(d)(2) and (3), see Portland Cement Ass’n v. EPA, 665 F.3d 177, 189 (D.C. Cir. 2011), such as when it identifies an error in the original standard. See also Medical Waste Institute v. EPA, 645 F. 3d at 426 (upholding EPA action establishing MACT floors, based on postcompliance data, when originally-established floors were improperly established). E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations purging or depressuring of CRU vessels meet the applicable organic HAP emission limitations in Tables 15 and 16 to subpart UUU regardless of the vessel pressure. For flares, we proposed to remove cross references to the General Provisions requirements for flares used as control devices at 40 CFR 63.11(b) and to incorporate enhanced flare operational requirements directly into the Refinery MACT rules. The proposed rule amendments included: • A ban on flaring of halogenated vent streams. • A requirement to operate with continuously lit pilot flames at all times and to equip the pilot system with an automated device to relight the pilot if it is extinguished. • A requirement to operate with no visible emissions except for periods not to exceed a total of 5 minutes during any 2 consecutive hours and to monitor for visible emissions daily. • A requirement to operate with the flare tip velocity less than 60-feet-persecond or the velocity limit calculated by an equation provided in the proposed rule. • A requirement to meet one of three combustion zone gas properties operating limits based on the net heating value, lower flammability limit, or combustion concentration. Owners or operators could elect to comply with any one of the three limits at any time. Two separate sets of operating limits were proposed: One for gas streams not meeting all three ‘‘hydrogen-olefin interaction criteria’’ specified in the rule and a more stringent set of limits for gas streams meeting all three hydrogenolefin interaction criteria. The combustion zone net heating value considered steam assist rates but not ‘‘perimeter air’’ assist rates. • For air-assisted flares, a requirement to meet an additional ‘‘dilution parameter’’ operating limit determined based on the combustion zone net heating values above, the diameter of the flare and the perimeter air assist rates. The proposed amendments for flares also included detailed monitoring requirements to determine these operating parameters either through continuous parameter monitoring systems or grab sampling, detailed calculation instructions for determining these parameters on a 15-minute block average, and detailed recordkeeping and reporting requirements. We also proposed provisions to allow owners or operators to request alternative emissions limitations that would apply in place of the proposed operating limits. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 We proposed to revise the definition of MPV to remove the current exclusion for in situ sampling systems (onstream analyzers). We also proposed to limit the exclusion for gaseous streams routed to a fuel gas system to apply only to those systems for which any flares receiving gas from the fuel gas system are in compliance with the proposed flare monitoring and operating limits. We note that we also proposed revisions related to monitoring of bypass lines, but these revisions were proposed to address concerns related to SSM releases and are described in further detail in section IV.D. of this preamble. We proposed that emissions of HAP may not be discharged to the atmosphere from PRD in organic HAP service to address concerns related to SSM releases. To ensure compliance with this proposed amendment, we proposed to require that sources monitor PRD using a system that is capable of identifying and recording the time and duration of each pressure release and of notifying operators that a pressure release has occurred. This proposed requirement was addressed in section IV.A.4. of the preamble for the proposal. 2. How did the revisions pursuant to CAA section 112(d)(2) and (3) change since proposal? We proposed identical standards for existing and new DCU decoking operations, but we are finalizing standards for new and existing sources that are not identical. We are finalizing provisions that will require owners or operators of existing DCU sources to comply with a 2 psig limit averaged over 60 cycles (i.e., 60 venting events), rather than meet the 2 psig limit on a per venting event basis, as proposed. We are finalizing provisions that will require owners or operators of new DCU sources to comply with a 2.0 psig limit on a per event, not-to-exceed basis. We are adding one significant digit to the limit for new DCU affected sources because our re-review of permit requirements conducted in response to comments identified that the best performing DCU source is required to comply with a 2.0 psig limit on a per event basis. In response to comments regarding the proposed prohibition on draining prior to achieving the pressure limit, we are finalizing specific provisions for DCU with water overflow design and for double quenching. For flares, we are not finalizing the ban that we proposed on halogenated vent streams and we are not finalizing the proposed requirement to equip the flare pilot system with an automated device to relight an extinguished pilot. PO 00000 Frm 00031 Fmt 4701 Sfmt 4700 75207 We are revising the MACT to include the proposed no visible emissions limit and the flare tip velocity limit as direct emissions limits only when the flare vent gas flow rate is below the smokeless capacity of the flare. Under the revised standard, when the flare is operating above the smokeless capacity, an exceedance of the no visible emission limit and/or flare tip velocity limit is not a violation of the standard but instead triggers a work practice standard. Flares operate above the smokeless capacity only when there is an emergency release event and thus the work practice standard is intended to address emissions during such emergency release events. (See section IV.D. of this preamble for more details regarding this work practice standard). We are also adding provisions that would allow sources to use video surveillance of the flare as an alternative to daily Method 22 visible emissions observations. For flares, we are also simplifying the combustion zone gas property operating limits by finalizing a requirement only for the net heating value of the combustion zone gas. We are finalizing requirements that flares meet a minimum operating limit of 270 BTU/ scf NHVcz on a 15-minute average, as proposed, and we are allowing refinery owners or operators to use a corrected heat content of 1212 BTU/scf for hydrogen to demonstrate compliance with this operating limit. We are not finalizing separate combustion zone operating limits for gases meeting the hydrogen-olefin interaction criteria that were proposed. We are also not finalizing the alternative combustion zone operating limits based on lower flammability limit or combustibles concentration. We are finalizing ‘‘dilution parameter’’ requirements for air-assisted flares, but we are providing a limit only for the net heating value dilution parameter. Similar to the requirements we are finalizing for the combustion zone parameters, we are finalizing requirements that flares meet a minimum operating limit of 22 BTU/ft2 NHVdil on a 15-minute average, as proposed, and we are allowing refinery owners or operators to use a corrected heat content of 1,212 BTU/scf for hydrogen to demonstrate compliance with this operating limit. We are not finalizing separate dilution parameter operating limits for gases meeting the hydrogen-olefin interaction criteria that were proposed. We are also not finalizing the alternative dilution parameter operating limits based on lower flammability limit or combustibles concentration. E:\FR\FM\01DER2.SGM 01DER2 75208 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations We are providing an alternative to use initial sampling period and process knowledge for flares in dedicated service as an alternative to continuous or on-going grab sample requirements for determining waste gas net heat content. We are finalizing revisions to the definition of MPV, as proposed. We are establishing work practice standards that apply to PRD releases in place of the proposed prohibition on PRD releases to the atmosphere. The work practice standards that we are finalizing for PRD require refiners to establish proactive, preventative measures for each PRD to identify and correct direct releases of HAP to the atmosphere as a result of pressure release events. Over time, these proactive measures will reduce the occurrence of releases and the magnitude of releases when they occur, while avoiding the environmental disbenefits of having additional flare capacity on standby to control these unpredictable and infrequent events. Refinery owners or operators will be required to perform a root cause analysis/corrective action following such pressure release events. In addition, a second release event in a 3year period from the same PRD with the same root cause on the same equipment is a deviation of the work practice standard. A third release event in a 3-year period from the same PRD is a deviation of the work practice standard regardless of the root cause. PRD release events related to force majeure events are not considered in these hard limits. 3. What key comments did we receive on the proposed revisions pursuant to CAA section 112(d)(2) and (3) and what are our responses? tkelley on DSK3SPTVN1PROD with RULES2 i. DCU Comment: Several commenters argued that the EPA incorrectly set the MACT floor emission limitation for DCU. Commenters noted that CAA section 112(d)(3)(A) states that the MACT limit for existing sources ‘‘shall not be less stringent, and may be more stringent than the average emission limitation achieved by the best performing 12percent of the existing sources’’ excluding those first achieving that level within 18 months prior to proposal or 30 months prior to promulgation, whichever is later. According to the commenters, the EPA failed to follow this procedure in setting the 2 psig vent limit as a MACT floor because the EPA incorrectly considered permit limits and other non-performance based criteria instead of basing the MACT floor on the actual performance of sources. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Commenters stated that the EPA improperly considered permit limits that should have been excluded from consideration, as well as considering permit limits for closed facilities instead of using more accurate data from operating DCUs at sources that submitted actual emissions data. Specifically, commenters stated that the DCU at the non-operational plant (Hovensa) should not be included. One commenter noted that they operate one of the South Coast DCU listed as subject to a 2 psig limit and asserted that it does not currently meet that emission limitation. The commenter claimed that significant capital investment would be required in order for the DCU to comply with the 2 psig limit. According to one commenter, data for six of the eight DCU they claim the EPA considered for the MACT floor should not be counted in determining the limit that represents the average emission limitation actually achieved 18 months prior to the proposal. Response: CAA section 112(d)(3)(A) states that the existing source standard shall not be less stringent than the average emission limitation achieved by the best performing 12-percent of the existing sources (for which the Administrator has emissions information), excluding those sources that have, within 18 months before the emission standard is proposed or within 30 months before such standard is promulgated, whichever is later, first achieved a level of emission rate or emission reduction which complies, or would comply if the source is not subject to such standard, with the lowest achievable emission rate (as defined by section 171) applicable to the source category and prevailing at the time, in the category or subcategory for categories and subcategories with 30 or more sources. We consider a 2 psig emissions limitation to be equivalent to the lowest achievable emission rate (LAER) emission limits. Thus, we agree with the commenter that sources that first meet the 2 psig limit on or after December 30, 2012, should be excluded from the MACT floor analysis. We also agree that under CAA section 112(d)(3)(A), the MACT floor analysis focuses on those sources that are achieving the emission limit (i.e., the emission limitation ‘‘achieved by . . . ’’). The EPA has previously determined that the 6th-percentile unit is a reasonable estimate of the average emission limitation achieved by the best performing 12-percent of sources especially when averaging across units with and without control requirements. As noted in our DCU MACT floor PO 00000 Frm 00032 Fmt 4701 Sfmt 4700 analysis memorandum (Docket ID No. EPA–HQ–OAR–2010–0682–0203), the 6th-percentile is represented by the fifth-best performing DCU. If we exclude the two South Coast refineries and the two Marathon Garyville DCU because these sources were not implementing the 2 psig permit limit prior to December 30, 2012, the fifth-best performing DCU would be represented by the Bay Area refineries (4.6 psig). However, based on the 2011 Petroleum Refinery ICR responses, 25 out of 75 (33percent) DCU have a ‘‘typical coke drum pressure when first vented to the atmosphere’’ of 2 psig or less and 10 out of 75 (13-percent) DCU have a ‘‘typical coke drum pressure when first vented to the atmosphere’’ of 1 psig or less. While we acknowledge that these data represent ‘‘typical’’ operations and not necessarily a never-to-be-exceeded emissions limitation, we conclude that this information is sufficient for us to conclude that the average emission limitation achieved by the best performing 12-percent of sources is consistent with a 2 psig emissions limitation. This is because facility owners or operators commonly target to operate at approximately half the allowable emissions limit to ensure that they can comply with the emissions limit at all times. Therefore, we maintain that an average venting pressure of 2 psig is the MACT floor level for decoking operation at existing sources based on the ICR responses and considering the average performance expected. Comment: Four commenters suggested that the 2 psig limit, if finalized, should be based on a rolling 30-day average per DCU rather than a never to be exceeded ‘‘instantaneous’’ standard. According to the commenters, an instantaneous standard is unnecessary to address HAPs with chronic health impacts and adds cost and compliance challenges. According to the commenters, chronic health impacts are not materially affected by short-term variability, but instead depend on the average concentration of exposure over a 70-year lifetime; therefore, there is no health based or environmental reason for requiring an instantaneous limit. The commenters noted that there would be additional capital costs to comply with a 2 psig not-to-be-exceeded limit compared to a 30-day average 2 psig limit vent pressure. One commenter specifically requested that the EPA also confirm that a pressure of 2.4 psig is compliant with the 2 psig limit vent pressure. Another commenter also requested clarification that the vent pressure can be rounded to E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations one significant figure when determining compliance. Response: For new sources, the MACT floor emission limit for DCU is based on the best-performing source. Based on this and other comments received, we again reviewed existing permit conditions. Based on this review, we found that one of the permit requirements specified the pressure limit as 2.0 psig for each coke drum venting event. Therefore, we are finalizing the new source MACT floor as 2.0 psig on a per coke drum venting event basis. As discussed in response to the previous comment, we are basing the MACT floor for existing source DCU on responses we received from the 2011 Petroleum Refinery ICR. Because the ICR requested the ‘‘typical coke drum pressure when first vented to the atmosphere,’’ we do not consider the information provided in ICR responses to reflect a ‘‘never-to-be-exceeded’’ limit. Therefore, we evaluated whether it is reasonable to allow averaging, and if so, what averaging period should be provided. Health risks are not considered in establishing MACT requirements, so we do not consider the argument that chronic effects are evaluated over a 70year period to be relevant to a determination of the MACT floor. However, a primary consideration regarding averaging periods is how the averaging period was considered in setting the floor and whether the intended reductions will occur under a different averaging period. According to the heat balance method for estimating DCU emissions, DCU decoking operations emissions are directly proportional to the average bed temperature. While the relationship is not exactly linear, the average bed temperature is expected to be a function of the venting pressure. Moreover, the shape of the pressure-temperature correlation curve is such that the emissions at 6 psig are almost exactly but not quite three times the emissions at 2 psig. Given the expected linearity of the emissions with venting pressures, we are not concerned with an occasional venting event above 2 psig because the average emissions from a facility meeting an average 2 psig pressure limit would be identical to the emissions achieved by a facility that vented each time at 2 psig. That is, given the expected linearity in the projected DCU emissions to the venting pressure, we conclude that it is reasonable to allow averaging across events and that the precise averaging period is not a critical concern. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Most industry commenters requested a 30-day average. However, different facilities have different numbers of DCU, different numbers of drums per DCU and different cycle times. Consequently, basing the averaging period across a given time period would result in significantly different number of venting events included in a 30-day average for different facilities and generally provide more flexibility to larger refineries and less flexibility to smaller refineries. Based on the ICR responses, almost half of all DCU operate with two drums and about 90percent of DCU have two to four coke drums; however, a few DCU have six or even eight drums. Also, based on the ICR responses, the average complete coke drum cycle time is 32 hours, but can be as short as 18 hours and as long as 48 hours. Reviewing the ICR responses, we found that a 30-day average would include 30 events for some facilities and more than 250 events at other facilities. Since the existing source MACT standards apply ‘‘in combination’’ to ‘‘all releases associated with decoking operations’’ at a given facility, we determined that it was reasonable to consider an averaging period that applies to the number of venting events from all coke drums at the facility rather than to all coke drums for a specific DCU for a specified period of time. This provides a more consistent basis for the averaging period and allows the same operational flexibility for small refineries as large refineries. Based on the ICR responses, the median (typical) DCU has 60 venting events in a 30-day period. Providing an averaging period of 60 venting events provides a more consistent averaging basis for all facilities, regardless of the number of DCU at the facility and the number of drums and cycle times for different DCU. Additionally, it eliminates issues with respect to how to handle operating days versus non-operating days, e.g., in the event of a turn-around resulting in a limited number of venting events in a 30-calendar day period. Therefore, we are establishing a 2 psig limit based on a 60-event average considering all coke drum venting events at an existing source and we are finalizing a 2.0 psig limit on a per coke drum venting event for DCU at new sources. We have consistently maintained our policy to round to the last digit provided in the emission limit, a pressure of 2.4 psig would round to 2 psig and would be compliant with a requirement to depressure each coke drum to a closed blowdown system until the coke drum vessel pressure is 2 psig or less, but it would not be PO 00000 Frm 00033 Fmt 4701 Sfmt 4700 75209 compliant with the revised new source provision to depressure until the coke drum vessel pressure is 2.0 psig or less. A coke drum pressure of 2.04, however, would be compliant with the revised new source requirement pressure limit of 2.0 psig. ii. Refinery Flares Comment: Several commenters suggested that the proposed flare operating limits were too complex. The commenters recommended that the EPA eliminate the dual flare combustion zone heat content limits related to the proposed hydrogen-olefin interaction criteria and instead finalize a single combustion zone net heating value of approximately 200 BTU/scf, which would minimize the unnecessary burning of supplemental gas but still ensure good combustion efficiency. A few commenters suggested that the EPA based the proposed combustion zone limits on an invalid data analysis, that the 1 minute PFTIR data should not be used to establish combustion efficiency correlations, and that the emission limits should be set so as to provide an equal chance of false positives and negatives. A few commenters suggested that the EPA should assign hydrogen a heating value of 1,212 BTU/scf to more accurately reflect its flammability in a NHV basis and that doing so is consistent with some recent flare consent decrees and would help reduce natural gas supplementation for facilities complying only with the NHVcz metric. Several commenters suggested that neither scientific literature nor the available flare test data support the EPA’s claim of an adverse hydrogenolefin interaction on combustion efficiency and that the EPA should not finalize the more restrictive combustion zone operating limits for all flare types. These commenters suggested that the EPA did not provide any evidence the assumed hydrogen-olefin effect actually exists; that statistical analysis demonstrates the EPA developed their limit based on random differences in data; that the PFTIR data analysis method of using the individual minuteby-minute data instead of the test average data is flawed and leads to invalid conclusions; and that proper analysis of the data demonstrates the more stringent operating limits for hydrogen-olefin conditions cannot be supported. Some commenters suggested that there is evidence to support more stringent flare combustion zone limits for a narrowly defined high concentration propylene-only condition as outlined in some of the recent flare E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75210 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations consent decrees but that the flare test data do not support more stringent operating limits for the proposed hydrogen-olefins criteria by the EPA. Additionally, one commenter suggested that if the EPA decides to proceed with the more restrictive combustion zone limits for the hydrogen-olefins interaction cases then the final rule should not expand beyond an interaction between hydrogen and propylene. Several commenters suggested that the proposed 15-minute feed forward averaging time for flares (e.g., combustion zone parameters, air-assist dilution parameters and associated flow rates) is arbitrary, unrealistic and unworkable and that the feed forward compliance determination should not be finalized and, if it is finalized, the averaging time should be extended to 1-hour, 3-hour, or 24-hour. To support these suggested averaging periods, commenters claimed that typical standards for combustion devices are averaged over these suggested timeframes, noting as an example, recent refinery flare consent decrees that contain a 3-hour average. The commenters also asserted that both a GC and calorimeter will be needed to obtain data rapidly enough to try and maintain a 15-minute average; that the feed forward approach requires calculation artifices to attempt to correct for the fact that compliance cannot be determined until the averaging period is over; and that a longer averaging time is needed for instrument and control response time. Response: In addressing these comments, we further analyzed the flare emissions test data. First, to address concerns that the minute-by-minute analysis produced flawed results, we recompiled the data into approximate ‘‘15-minute averages’’ to the extent practical based on the duration of a given test run (e.g., a 10-minute run was used as 1 run and a 32-minute run was divided into 2 runs of 16 minutes each). We do not find significant differences in the data or that different conclusions would be drawn from the data based on this approach as compared with the minute-by-minute analysis used for the proposed rule. Next, we evaluated the 15-minute run data using the normal net heating value for hydrogen of 274 Btu/scf, which is the value we used in the analysis for the proposed rule and also evaluated the data using the 1,212 Btu/scf, the value recommended by some commenters. The 1,212 Btu/scf value is based on a comparison between the lower flammability limit and net heating value of hydrogen compared to light organic VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 compounds and has been used in several consent decrees to which the EPA is a party. Based on our analysis, we determined that using a 1,212 Btu/ scf value for hydrogen greatly improves the correlation between combustion efficiency and the combustion zone net heating value over the entire array of data. Using the net heating value of 1,212 Btu/scf for hydrogen also greatly reduced the number of ‘‘type 2 failures’’ (instances when the combustion efficiency is high, but the gas does not meet the NHVcz limit). One of the primary motivations for the proposed approach to provide alternative limits based on lower flammability limits and combustibles concentrations was to reduce these type 2 failures. Therefore, we proposed all three of these parameters (i.e., NHVcz, LFL and total combustibles) and allowed flare owners or operators to comply with any of the parameter limits at any time. When using the net heating value of 1,212 Btu/ scf for hydrogen, the other two alternatives no longer provide any improvement in the ability to predict good flare performance. Consequently, we are simplifying the operating limits to use only NHVcz. Next, we re-evaluated whether to finalize the proposed dual combustion zone operating limits for refinery flares that met certain hydrogen-olefins interactions or to finalize a single combustion zone net heating value limit. The newly re-compiled PFTIR run average flare dataset suggests that higher operating limits may be appropriate for some olefin-hydrogen mixtures. However, the dataset using 15-minute test average runs is much smaller than the set using 1-minute runs and thus creates a greater level of uncertainty. In addition, we cannot definitively conclude that a dual combustion zone limit for refinery flares meeting certain hydrogen-olefins interactions is appropriate given these uncertainties. Thus, in order to minimize these uncertainties and streamline the compliance requirements, we used all of the 15-minute test run average data together as a single dataset in an effort to determine an appropriate, singular combustion zone net heating value operational limit. Finally, we conducted a Monte Carlo analysis to help assess the impacts of extending the averaging time on the test average flare dataset of 15-minute runs to 1-hour or 3-hour averaging time alternatives. While we consider it reasonable to provide a longer averaging time for logistical reasons, the Monte Carlo analysis demonstrated, consistent with concerns described in our proposal, that short periods of poor PO 00000 Frm 00034 Fmt 4701 Sfmt 4700 performance can dramatically limit the ability of a flare to achieve the desired control efficiency. Consequently, we find it necessary to finalize the proposed 15-minute averaging period to ensure that the 98-percent control efficiency for flares is achieved at all times. However, we understand that flare vent gas flow and composition are variable. While a short averaging time is needed to ensure adequate control given this variability, we also understand the complications that this variability places on flare process control in efforts to meet the NHVcz limit. Therefore, we are clarifying that the 270 Btu/scf NHVcz value is an operational limit that must be calculated according to the requirements in this rule. We also clarify that compliance with this operational limit must be evaluated using the equations and calculation methods provided in the rule. We proposed a feed forward calculation method to allow refinery owners or operators a means by which to adjust steam (or air) and, if necessary, supplemental natural gas flow, in order to meet the limit. In other words, ‘‘feed forward’’ refers to the fact that the rule requires the refinery owners or operators to use the net heating value of the vent gas (NHVvg) going into the flare in one 15-minute period to adjust the assist media (i.e., steam or air) and/or the supplemental gas in the next 15minute period, as necessary for the equation in the rule to calculate an NHVcz limit of 270 BTU/scf or greater. We recognize that when a subsequent measurement value is determined, the instantaneous NHVcz based on that compositional analysis and the flow rates that exist at the time may not be above 270 Btu/scf. We clarify that this is not a deviation of the operating limit. Rather, the owner or operator is only required to make operational adjustments based on that information to achieve, at a minimum, the net heating value limit for the subsequent 15-minute block average. Failure to make adjustments to assist media or supplemental natural gas using the equation provided for calculating an NHVcz limit of 270 BTU/scf, using the NHVvg from the previous period, would be a deviation of the operating limit. Alternatively, if the owner or operator is able to directly measure the NHVvg on a more frequent basis, such as with a calorimeter (and optional hydrogen analyzer), the process control system is able to adjust more quickly, and the owner or operator can make adjustments to assist media or supplemental natural gas more quickly. In this manner, the owner or operator is not limited by E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations relying on NHVvg data that may not represent the current conditions. Therefore, the owner or operator may opt to use the NHVvg from the same period to comply with the operating limit. Based on the results of all of our analyses, the EPA is finalizing a single minimum NHVcz operating limit for flares subject to the Petroleum Refinery MACT standards of 270 BTU/scf during any 15-minute period. The agency believes, given the results from the various data analyses conducted, that this operating limit is appropriate, reasonable and will ensure that refinery flares meet 98-percent destruction efficiency at all times when operated in concert with the other suite of requirements refinery flares need to achieve (e.g., flare tip velocity requirements, visible emissions requirements, and continuously lit pilot flame requirements). For more detail regarding our data re-analysis, please see the memorandum titled ‘‘Flare Control Option Impacts for Final Refinery Sector Rule’’ in Docket ID No. EPA–HQ–OAR–2010–0682. Comment: Numerous commenters objected to the proposed requirements to have the velocity and visible emissions limits apply at all times for flares. Commenters suggested that flares are not designed to meet the visible emissions and flare tip velocity requirements when being operated beyond their smokeless capacity and suggested several alternative approaches: remove the visible emissions and flare tip velocity requirements from the rule altogether; exempt flares from these requirements during emergencies; or add a requirement to maintain a visible flame present at all times or include a work practice standard in the rule when flares are operated beyond their smokeless capacity at full hydraulic load. The commenters identified full hydraulic load as the maximum flow the flare can receive based on the piping diameter of the flare header and operating pressure of processes connected to the flare header system. They also specified that full hydraulic load would only occur if all sources connected to the flare header vented at the same time, which might result from an emergency shutdown due to a plant-wide power failure. According to commenters, flares are typically designed to operate in a smokeless manner at 20 to 30-percent of full hydraulic load. Thus, they claimed, flares have two different design capacities: A ‘‘smokeless capacity’’ to handle normal operations and typical process variations and a ‘‘hydraulic load capacity’’ to handle very large volumes VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 of gases discharged to the flare as a result of an emergency shutdown. According to commenters, this is inherent in all flare designs and it has not previously been an issue because the flare operating limits did not apply during malfunction events. However, if flares are required to operate in a smokeless capacity during emergency releases, the commenters claimed that refineries would have to quadruple the number of flares at each refinery to control an event that may occur once every 2 to 5 years. To support their suggestions, commenters pointed out that flaring during emergencies is the optimum way of handling very large releases and that the flare test data clearly demonstrate that visible emissions and/or high flare tip velocity do not suggest poor destruction efficiency during such events. The commenters also argued that operators should not have conflicting safety and environmental considerations to deal with during these times. The commenters stated that refiners are still subject to a civil suit even if the EPA uses its enforcement discretion where such a release would violate the limit and in order to avoid such liability, many new flares would have to be built. Commenters estimated that 500 new large flare systems at a capital cost in excess of $10–20 billion would need to be built because of the amount of smokeless design capacity that would be needed and that this significant investment would take the industry at least a decade to install. Response: At the time of the proposed rule, we did not have any information indicating that flares were commonly operated during emergency releases at exit velocities greater than 400 ft/sec (which is 270 miles per hour (mph)). Similarly, we did not have information to indicate that flares were commonly designed to have a smokeless capacity that is only 20 to 30-percent of their ‘‘hydraulic load capacity.’’ While we are uncertain that refineries actually would install additional flares to the degree the commenters claim, based on the possibility that there may be an event every 2 to 5 years that would result in a deviation of the smokeless limit, we also recognize that it would be environmentally detrimental to operate hundreds of flares on hot standby in an effort to never have any releases to a flare that exceed the smokeless capacity of that flare. This is because operating hundreds of new flares to prevent smoking during these rare events will generate more ongoing emissions from idling flares than the no visible emissions limit might prevent during one of these events. Therefore, we PO 00000 Frm 00035 Fmt 4701 Sfmt 4700 75211 considered alternative operating limits or alternative standards that could apply during these emergency release events. As an alternative to the proposed requirement that flares meet the visible emissions and velocity limits at all times, we considered a work practice standard for the limited times when the flow to the flare exceeds the smokeless capacity of the flare. Owners or operators of flares would establish the smokeless capacity of the flare based on design specification of the flare. Below this smokeless capacity, the velocity and visible emissions standards would apply as proposed. Above the smokeless capacity, flares would be required to perform root cause analysis and take corrective action to prevent the recurrence of a similarly caused event. Multiple events from the same flare in a given time period would be a deviation of the work practice standard. Force majeure events would not be included in the event count for this requirement. Based on industry claims that there is a hydraulic load flaring event, on average, every 4.4 years, we assumed the best performers would have no more than one event every 6 years, or a probability of 16.7-percent of having an event in any given year. We found that, over a long period of time such as 20 years, half of these best performers would have 2 events in a 3 year period, which would still result in over half the ‘‘best performing’’ flares having a deviation of the work practice standard if it was limited to 2 events in 3 years. Conversely, only 6 percent would have 3 events in 3 years over this same time horizon. Based on this analysis, 3 events in 3 years would appear to be ‘‘achievable’’ for the average of the best performing flares. Pursuant to CAA section 112(d)(2) and (3), we are finalizing a work practice standard for flares that is based on the best practices of the industry, and considers the rare hydraulic load events that inevitably occur at even the best performing facilities. The best performing facilities have flare management plans that include measures to minimize flaring during events that may cause a significant release of material to a flare. Therefore, we are requiring owners or operators of affected flares to develop a flare management plan specifically to identify procedures that will be followed to limit discharges to the flare as a result of process upsets or malfunctions that cause the flare to exceed its smokeless capacity. We are specifically requiring refinery owners or operators to implement appropriate prevention measures applicable to these E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75212 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations emergency flaring events (similar to the prevention measures we are requiring in this final rule to minimize the likelihood of a PRD release). Refiners will be required to develop a flare minimization plan that describes these proactive measures and reports smokeless capacity. Refiners will need to conduct a specific root cause analysis and take corrective action for any flare event above smokeless design capacity that also exceeds the velocity and/or visible emissions limit. If the root cause analysis indicates that the exceedance is caused by operator error or poor maintenance, the exceedance is a deviation from the work practice standard. A second event within a rolling 3-year period from the same root cause on the same equipment is a deviation from the standard. Events caused by force majeure, which is defined in this subpart, would be excluded from a determination of whether there has been a second event. Finally, and again excluding force majeure events, a third opacity or velocity limit exceedance occurring from the same flare in a rolling 3-year period is a deviation of the work practice standard, regardless of the cause. Comment: Several commenters suggested that the EPA should revise the combustion efficiency requirements to apply only to steam-assisted flares used as Refinery MACT control devices during periods of time that the flares are controlling Refinery MACT regulated streams. One commenter suggested that the EPA misused the TCEQ data in proposing the NHVcz metric and that the proposed limits are overly conservative. The commenter requested that the EPA work with stakeholders to conduct additional testing to determine what, if any, operating parameters are appropriate and necessary to achieve an adequate destruction efficiency for nonsteam-assisted flares. Response: We disagree with the commenters that the combustion efficiency requirements should apply only to steam-assisted flares. The available data (for runs where steam assist is turned off) as well as the available combustion theories suggest that the combustion zone net heating value minimum limit, which is the vent gas net heating value for unassisted or perimeter air-assisted flares, is necessary to ensure proper flare performance. While we agree that additional data on air-assisted flares would allow for a more robust analysis, the data we do have strongly indicate that air-assisted flares can be overassisted and that the combustion efficiency of air-assisted flares that are VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 over-assisted is below 98-percent control efficiency. Comment: A few commenters suggested that the proposed flare regulations should not apply to part 63, subpart R (gasoline loading) and subpart Y (marine vessel loading) facilities, and to part 61, subpart FF (benzene waste) facilities. The commenters recommended that flares associated with gasoline loading, marine vessel loading and wastewater treatment emissions need to comply only with the General Provisions for flares. Some of these commenters argued that these sources are more consistent in flow and composition than other refinery sources, so the new requirements are not necessary to ensure good combustion for these ‘‘dedicated’’ flares. Some commenters suggested that operators of flares with consistent flow and composition be allowed to use process knowledge or engineering judgment rather than be required to install continuous monitors or be subject to ongoing grab sampling requirements. Some commenters noted that the required control efficiency for some refinery emissions sources subject to subpart CC sources is 95-percent. One commenter also requested that the EPA provide overlap provisions so flares used to control sources from different MACT sources would not have duplicative requirements. Response: The regulatory revisions that we are finalizing apply to petroleum refinery sources subject to part 63, subparts CC and UUU. Gasoline loading, marine vessel loading and wastewater treatment operations that are part of the refinery affected source as defined at 40 CFR 63.640 are subject to subpart CC. Gasoline loading, marine vessel loading and wastewater treatment operations located at non-refinery source categories are not subject to part 63, subpart CC and, thus, would not be subject to the revisions to subpart CC being finalized in this action. To the extent that the commenters are requesting that the EPA establish flare requirements that would apply to flares that are not part of the refinery affected source, that request is beyond the scope of this rulemaking, which only addresses revisions to Refinery MACT 1 and 2. When we issue rules addressing requirements for other sources with flares, we will consider issues similar to those we considered in this action and determine at that time whether revisions to those other flare requirements are necessary. The commenters note that some subpart CC emissions sources have only a control efficiency requirement of 95percent. While this may be true, where PO 00000 Frm 00036 Fmt 4701 Sfmt 4700 the owner or operator chooses to control these sources through the use of a flare, operation of that flare was subject to operational requirements in the General Provisions at 40 CFR 63.11 and the best performing flares were achieving 98percent control at the time the General Provisions were promulgated. At the time the General Provisions were promulgated, we received no comments that the EPA should set different operational limits for flares that are controlling emissions from sources where the standard may vary by level of control efficiency and we see no basis to do so now. The purpose of the revisions to the flare operating requirements is to ensure that flares are operating consistent with the MACT floor requirements for any and all sources that may use flares as a control device (79 FR 36905, June 30, 2014). As the MACT floor control requirements of certain refinery sources that allow the use of a flare as a control device is 98percent, we established operational limits to ensure flares used as control devices meet this MACT requirement. To the extent that the commenters are requesting that the EPA establish an alternative monitoring approach for flares in dedicated service that have consistent composition and flow, we agree that these types of flares, which have limited flare vent gas streams, do not need to have the same type of ongoing monitoring requirements as those with more variable waste streams. Thus, we are establishing an option that refinery owners or operators can use to demonstrate compliance with the operating requirements for flares that are in dedicated service to a specific emission source, such as a wastewater treatment operation. Refinery owners or operators will need to submit an application for the use of this alternative. The application must include a description of the system, characterization of the vent gases that could be routed to the flare based on a minimum of 7 grab samples (14 daily grab samples for continuously operated flares) and specification of the net heating value that will be used for all flaring events (based on the minimum net heating value of the grab samples). We are also allowing engineering estimates to characterize the amount of gas flared and the amount of assist gas introduced into the system. For example, the use of fan curves to estimate air assist rates is acceptable. Flare owners or operators would use the net heating value determined from the initial sampling phase and measured or estimated flare vent gas and assist gas E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 flow rates, if applicable, to demonstrate compliance with the standards. Comment: A few commenters suggested that the EPA’s proposed work practice and monitoring standards for flares are CAA section 112(d) ‘‘developments’’ required by law and supported by the evidence, and reflect best practices at many refineries today. One commenter suggested that the EPA must allow companies with consent decrees to meet their consent decree requirements as an alternative compliance approach and in lieu of the proposed requirements. Response: We proposed the enhanced monitoring requirements and operating limits under authority of CAA sections 112(d)(2) and (d)(3) to ensure that flares used to control regulated Refinery MACT 1 or 2 gas streams are meeting the prescribed control efficiencies established at the time the MACT standard was promulgated. And, we continue to believe that these revisions are appropriate under CAA sections 112(d)(2) and (d)(3). The commenter has not suggested, and we do not believe, that the revisions promulgated would differ in substance if they were instead promulgated under CAA section 112(d)(6). In general, we expect that the NHVcz monitoring requirements that we are finalizing for flares will be consistent with the requirements in various consent decrees. However, we have not conducted a rigorous evaluation of equivalency between various requirements and therefore we are not at this time providing an allowance for flare owners or operators to comply with the NHVcz operating limits and any provisions for necessary monitoring needed in the consent decree in lieu of the NHVcz limits and monitoring requirements established in this rule. In the event that an owner or operator wishes to continue complying only with the requirements of a consent decree, the rule contains provisions by which owner or operator can seek approval for alternative limits that are at least equivalent to the performance achieved from complying with the operating limits included in the final rule. iii. Pressure Relief Devices Comment: Several commenters suggested that the EPA develop a work practice approach for atmospheric PRD rather than a prohibition on releases. One commenter recommended that the EPA establish a work practice standard for atmospheric PRDs that requires refiners to implement a base level of preventative measures including: Basic process controls, instrumented alarms, documented and verified routine VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 inspection and maintenance programs, safety-instrumented systems, disposal systems, provide redundant equipment, increase vessel design pressure and systems that reduce fire exposure on equipment. Additionally, the commenter recommended that the EPA require refiners to perform root cause analysis and implement corrective action in the event of a release. The commenter stated these requirements would be similar to the root cause analysis/corrective action requirements recently promulgated for flares under NSPS subpart Ja and provided specific regulatory language for a proposed work practice approach. (See section 2.4.1.8 in Docket item EPA–HQ–OAR–2010– 0682–0583.) One commenter requested that the EPA allow a process for companies to submit an application for case-by-case limits to be approved by the agency, either the EPA or a delegated state similar to the alternate NOX limits for process heaters provided in NSPS subpart Ja. This commenter recommended that the EPA establish reasonable work practice standards, specifically suggesting that the EPA develop work practice standards consistent with API 521. The commenter stated that the EPA should provide an implementation period for compliance that goes beyond the timeframe provided under CAA section 112(d). The commenter added that the EPA should adopt specified changes to the definition of an atmospheric pressure relief safety valve and provided suggested regulatory language for a proposed work practice standard for PRDs in EPA–HQ–OAR–2010–0682– 0549. Another commenter stated that the EPA should require, as the Bay Area Air Quality Management District (BAAQMD) does, that any refinery that has a reportable PRD event must take certain steps to prevent such releases in the future (BAAQMD Rule 8–28–304). In particular, such a refinery must create a Process Hazard Analysis, meet the Prevention Measures Procedures specified in section 8–28–405, and conduct a failure analysis of the incident, to prevent recurrence of similar incidents (Id. Reg. section 8–28– 304.1). If a second release occurs, then, within one year, the facility must vent its PRDs to a vapor recovery or disposal system that meets certain requirements (Id. Reg. section 8–28–304.2). The commenter asserted that the EPA’s prohibition on releases to the atmosphere from PRD will ensure that refineries take the necessary steps to prevent such releases, or install control devices so that any releases from PRDs PO 00000 Frm 00037 Fmt 4701 Sfmt 4700 75213 that must occur are vented through a control device to reduce the amount of toxic air pollution they emit. At a minimum, the commenter stated, the EPA must prohibit these uncontrolled emissions and require monitoring and reporting to assure compliance and ensure that the emission standards apply at all times, as required by the Act. The commenter argued that the EPA must also, however, consider requiring the additional developments that have been put into place in the BAAQMD and also require control devices to be used for all PRD, as some local air districts require. In addition, the commenter supported the EPA’s monitoring and reporting requirements for PRD releases and the proposed electronic reporting requirements, which the EPA recognized are needed to assure compliance and assist with future rulemakings and as that provision requires, the EPA also must make all information reported publicly available online promptly and in an accessible and understandable format. Response: We agree that, under the proposal, refineries would consider installing add-on controls to comply with the prohibition on atmospheric releases from PRDs. In addition, they would consider venting these control devices to existing control devices, including flares. However, it may not be feasible to vent some or all of the PRDs to existing flares if the flares are near their hydraulic load capacity based on the processes already connected to the flares. Flares have negative secondary impacts when operated at idle conditions for the vast majority of time, which could be the case if they were installed solely to address PRD releases. These secondary impacts result from GHG, CO and NOX emissions. Some PRDs may vent materials that are not compatible with flare control and would need to be vented to other controls. To estimate the impact of the proposed prohibition on venting PRDs to the atmosphere, we estimated that at least one new flare per facility would be required to handle releases from PRDs, based on the number of atmospheric PRDs reported at refineries; that 60percent of the PRDs could be piped to existing controls at minimal costs and the other 40-percent would have to be piped to new flares; and that, on average, each new flare would service 40 PRDs. Based on these assumptions, 151 new flares would be needed or approximately one new flare per refinery. At a capital cost of $2 million for each new flare, which would not include long pipe runs, if needed, to PRD that are dispersed across the plant, we estimate that the capital cost of the E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75214 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations prohibition on venting to the atmosphere would exceed $300 million. Considering the fuel needed (approximately 50,000 scf/day per flare) and a natural gas price of $4.50 per 1,000 scf, we estimate the annual operating cost for these new flares to be $12 million. PRDs are unique in that they are designed for the purpose of releasing or ‘‘popping’’ as a safety measure to address pressure build-up in various systems—pipes, tanks, reactors—at a facility. These pressure build-ups are typically a sign of a malfunction of the underlying equipment. While it would be difficult to regulate most malfunction events because they are unpredictable and can vary widely, in the case of PRDs, they are equipment installed specifically to release during malfunctions and as such, we have information on PRDs in our 2011 Refinery ICR and through the SCAAMD and BAAQ rules to establish standards for them. After reviewing these comments, we thus examined whether it would be feasible to regulate these devices under CAA section 112(d)(2) and (3). After reviewing the comments, we agree with the commenters who suggest that the BAAQMD rule, as well as a similar South Coast Air Quality Management District (SCAQMD) rule that address PRD releases (SCAQMD Rule 1173), provide work practice standards that reflect the level of control that applies to the best performers. Consequently, we developed a work practice standard for PRD based on a detailed MACT analysis considering the requirements in these rules. Our rationale for the selected MACT requirements is provided in section IV.C.4 of this preamble. The work practice standards that we are finalizing for PRDs require refiners to establish proactive measures for each affected PRD to prevent direct release of HAP to the atmosphere as a result of pressure release events. In the event of an atmospheric release, we are requiring refinery owners or operators to conduct root cause analysis to determine the cause of a PRD release event. If the root cause was due to operator error or negligence, then the release would be a deviation of the standard. For any other release (not including those caused by force majeure events), the owner or operator would have to implement corrective action. A second release due to the same root cause for the same equipment in a 3-year period would be a deviation of the work practice standard. Finally, a third release in a 3year period would be a deviation of the work practice standard, regardless of the VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 root cause. Force majeure events would not count in determining whether there has been a second or third event. With respect to defining ‘‘atmospheric pressure relief safety valve’’ as suggested by the commenter, we note that the June 30, 2014, proposed amendments in 40 CFR 63.648(j) used the term ‘‘relief valve’’ because this was a defined term in Refinery MACT 1. However, the proposed amendments included clauses such as ‘‘if the relief valve does not consist of or include a rupture disk.’’ Thus, we specifically intended to apply the pressure relief management requirements broadly to ‘‘pressure relief devices’’ and not just ‘‘valves.’’ To clarify this, we have revised the regulatory language to use the term ‘‘pressure relief device’’ rather than ‘‘relief valve’’ to clearly include rupture disks or similar types of equipment that may be used for pressure relief. 4. What is the rationale for our final approach and final decisions for the revisions pursuant to CAA section 112(d)(2) and (3)? We revised the MACT floor determination for DCU sources. CAA section 112(d)(3)(A) requires the MACT floor for existing sources to exclude ‘‘. . . those sources that have, within 18 months before the emission standard is proposed or within 30 months before such standard is promulgated, whichever is later, first achieved a level of emission rate or emission reduction which complies, or would comply if the source is not subject to such standard, with the lowest achievable emission rate (as defined by section 171) applicable to the source category and prevailing at the time, in the category or subcategory for categories and subcategories with 30 or more sources.’’ Because we have determined that a 2 psig emissions limitation is equivalent with a LAER emission limit for DCU, we revised the MACT floor analysis in order to exclude sources that first met the 2 psig limit on or after December 30, 2012. For existing sources, based on the revised MACT analysis, we concluded that the MACT floor is still 2 psig. However, because the information on which we relied was submitted in response to the 2011 Petroleum Refinery ICR which requested ‘‘typical’’ venting pressures and because providing an allowance to average across venting periods does not reduce the emissions reductions achieved, we are providing a 60-event averaging period for existing sources in response to public comments received. For new DCU sources, our revised analysis identified one DCU subject to permit emission limitations of 2.0 psig PO 00000 Frm 00038 Fmt 4701 Sfmt 4700 pressure limit prior to venting on a per event basis. Under CAA section 112(d)(3), the MACT standard for new sources cannot be less stringent than the emission control achieved in practice by the best-controlled similar source. Thus, we are finalizing a limit of 2.0 for new DCU sources. We note that as 2.0 psig limit is more stringent than a 2 psig limit because of the rounding convention of rounding to the number of significant digits for which the standard is expressed. For example, a 2.4 psig venting pressure is compliant with a 2 psig limit, while it is not compliant with a 2.0 psig limit. We evaluated the costs of requiring existing sources to meet a 2.0 psig limit as a beyond-the-MACT-floor option. We determined the incremental cost of going from a 2 psig limit with an allowance to average over 60 events to a 2.0 psig limit on a per event basis was approximately $70,000 per ton of HAP reduced considering VOC credits. Based on this high incremental costeffectiveness, we concluded that the MACT floor requirement for existing DCU sources was MACT. As discussed in detail in the proposal, we do not consider it technically feasible to meet a 1 psig pressure limit (effectively a 1.4 psig limit) on a not-to-be-exceeded basis. Thus, we rejected this beyond the floor control option for both existing and new DCU sources. See the memorandum titled ‘‘Reanalysis of MACT for Delayed Coking Unit Decoking Operations’’ in Docket ID No. EPA–HQ–OAR–2010–0682 for additional details regarding our reanalysis of MACT for DCU decoking operations. In response to comments received on the prohibition of draining prior to achieving the proposed pressure limit (see Section 7.2.1 in the ‘‘National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries— Background Information for Final Amendments: Summary of Public Comments and Responses’’ in Docket ID No. EPA–HQ–OAR–2010–0682), we are providing specific provisions to allow for draining under special conditions. The specific provision and our rationale for providing them are provided below. First, we learned that certain DCU are designed to completely fill the drum with water and allow the water to overflow in the overhead line and drain to a receiving tank in order to more effectively cool the coke bed. Owners or operators of this DCU design were concerned that the water overflow may be considered a drain and also stated that overhead temperature rather than pressure would be a better indicator of effective bed cooling. In reviewing this E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations type of DCU design, we find that this design has some unique advantages to traditional DCU to effect better cooling of the coke drum, and therefore we do not want to preclude its use. Based on saturated steam properties, we determined that an overhead temperature of 220 °F would achieve equivalent or greater emissions reductions than a 2 psig pressure limitation and an overhead temperature of 218 °F would achieve equivalent or greater emissions reductions than a 2.0 psig pressure limitation. Therefore, we are including these temperature limits as alternatives to the 2 or 2.0 psig pressure limitations for existing and new DCU affected sources, respectively. With respect to the overflow ‘‘drain,’’ we remain concerned with emissions from draining superheated water. However, if submerged fill is used in the atmospheric tank receiving the overflow water, the superheated water will be cooled by the water within the tank and emissions that occur during the conventional draining of water (from the flashing of superheated water into steam) can be prevented. Therefore, we are allowing the use of water overflow provided the overflow ‘‘drain’’ water is hard-piped to the receiving tank via a submerged fill pipe (pipe below the existing liquid level) whenever the overflow water exceeds 220 °F. Second, we received comments that, for conventional DCU (those not designed to allow water overflow), there is a limit to the maximum water level in the drum, which limits to some extent how much cooling water can be added to the coke drum. In rare cases, the coke drum does not cool sufficiently using the typical cooling steps. In this case, the common industry practice is to partially drain the coke drum and refill it with additional cooling water. This ‘‘double-quench’’ process is needed for safety reasons to sufficiently cool the coke drum contents prior to the decoking operations. Therefore, commenters requested provisions to allow double-quenching of the coke drum. We recognize the safety issues associated with coke blow-out during coke cutting if there is a portion of the coke bed that is not sufficiently cooled and we agree that double-quenching is an effective means to cool the coke drum in those rare instances that the typical cooling cycle does not sufficiently cool the coke drum contents, so we considered granting the commenters’ request. As noted previously, the primary concern with early draining of the coke drum is the emissions that are expected to occur as a result of draining superheated water. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 We recognize, however, that the water temperature near the bottom of the coke drum is typically much lower than at the top of the coke drum. If the temperature of the water drained from the bottom of the coke drum remains below 210 °F, this would minimize steam flashing and associated HAP emissions since the water drained would not be superheated. We conclude that the use of double quenching is appropriate for cases when the coke drum is not sufficiently cooled using the normal cooling procedures provided the temperature of the water drained remains below 210 °F, and it is consistent with the practices of the best performing sources. Consequently, we are finalizing provisions to allow the use of double-quenching for DCU provided the temperature of the water drained remains below 210 °F. For the CRU, we are finalizing the proposed revisions to require CRU that employ active purging to meet the MACT emissions limitations in Tables 15 and 16 in subpart UUU at all times regardless of vessel pressure. We received limited comments regarding our proposal; these comments generally concerned the costs associated with the proposed emissions limitations. As discussed in our proposal, and based on data submitted in response to the ICR, emissions using active purging are much higher than those not using active purging. In the original rule, we based the MACT floor on the best performing facilities that used sequential pressurizations and depressurizations rather than active purging. Thus, in the proposal, we concluded that allowing owners or operators to actively purge while at low pressures was inconsistent with the MACT floor emissions limitations achieved by the best performing 12-percent of sources when the MACT floor was originally established. As we are simply requiring these facilities to meet the same emission levels determined to be MACT, we do not consider costs of potential additional controls to be a viable rationale to allow these units to emit several times more HAP than the units upon which the MACT requirements were based and the emissions levels achieved in practice by the vast majority of other CRU sources. For flares, we are finalizing proposed revisions to include detailed flare monitoring and operating requirements. We are including the flaring provisions for refineries in the Refinery MACT rules and removing the cross-references to the flaring requirements in the General Provisions. The final regulatory requirements differ from the proposed requirements in several respects. First, PO 00000 Frm 00039 Fmt 4701 Sfmt 4700 75215 we are not finalizing the ban on halogenated vent streams because we did not include sufficient justification or include cost estimates for this proposed provision and we did not include any monitoring requirements to ensure compliance with this ban on halogenated vent streams. We are finalizing the proposed no visible emissions limit and the flare tip velocity limit but they will apply only when the flare vent gas flow rate is below the smokeless capacity of the flare. We received a number of comments stating that the no visible emissions limit and the flare tip velocity limit cannot be met during large malfunctions and emergency shutdown events. In response to comments, we are finalizing work practice standards for emergency flaring events using the proposed no visible emission limit and flare tip velocity limit as thresholds in the final rule to trigger root cause analysis when the flare vent gas flow rate is above the smokeless capacity of the flare. The final work practice standard includes requirements to develop a flare management plan, to implement prevention measures, and to perform root cause analysis and implement corrective action following each flaring event that exceeds the smokeless capacity of the flare. There is also a limit on the number of these flaring events that a given flare may have in the 3-year period. We are establishing these provisions because we now recognize that flares have two different design capacities: A smokeless design capacity and a hydraulic load capacity. We determined that the proposed visible emissions limit and the flare tip velocity limit for very large flow events are not the MACT floor for such events. The final work practice standards for flaring events are based on the best performing facilities and will result in emission reductions in a technically feasible manner without any negative secondary impacts. We consider it appropriate to establish a work practice standard for flares as provided in CAA section 112(h). While it is possible to monitor gaseous streams going into the flare (as we have required for the flare operating requirements) it is not possible to design and construct a conveyance to capture the emissions from a flare. While knowledge of the composition and flow of gases entering the flare provides a reasonable basis for establishing operating requirements for normal operations, we have no data on flare performance under conditions in the hydraulic load range. While smoke in the flare exhaust is an indication of incomplete combustion, it is uncertain E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75216 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations how much deterioration of HAP destruction efficiency occurs during a smoking event. We also consider that the application of a measurement methodology for flare exhaust is not practicable due to technological and economic limitations. Passive FTIR has been used to determine combustion efficiency in flare exhaust, but these are essentially manual tests, and the measurement accuracy is dependent on how well the monitor is aligned with the flare exhaust plume. Changes in wind direction require manual movement of the monitoring system. It is also unclear if these systems can accurately measure combustion efficiency during high smoking events. These systems also require very specialized expertise, and we consider that it is both technologically and economically infeasible to measure flare exhaust emissions, particularly during high load events. Consequently, for emergency flare releases, we conclude that it is appropriate to establish a work practice standard as provided in CAA section 112(h). We also received comments that the daily visible emissions observations were burdensome and unnecessary and some commenters suggested that facilities be allowed to use video surveillance cameras. We concluded that video surveillance cameras would be at least as effective as the proposed daily 5-minute visible emissions observations using Method 22. We are finalizing the proposed visible emissions monitoring requirements Method 22 and the alternative of using video surveillance cameras. We are simplifying the combustion zone gas property operating limits in response to public comments received. Specifically, we are finalizing requirements that all flares meet a minimum operating limit of 270 BTU/ scf NHVcz on a 15-minute average, and we are providing that refiners use a corrected heat content of 1,212 BTU/scf for hydrogen to demonstrate compliance with this operating limit. We determined that a corrected heat content of 1212 BTU/scf for hydrogen provided a better indication of flare performance than without the correction. We also determined that the other combustion zone parameters, which were primarily proposed to provide suitable methods for flares that had high hydrogen concentrations, were no longer necessary when a 1,212 Btu/scf net heating value is used for hydrogen. Therefore, we are not finalizing the alternative combustion zone operating limits based on lower flammability limit or combustibles concentration. We are also not finalizing separate combustion VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 zone operating limits for gases meeting the proposed hydrogen-olefin interaction criteria. In our revised analysis of the data, we analyzed all of the data together and determined the 270 Btu/scf NHVcz operating limit provided in the final rule would adequately ensure that flares achieve the desired 98-percent control efficiency regardless of the composition of gas sent to the flare. For air-assisted flares, we are finalizing the additional ‘‘dilution parameter’’ operating limit only for the net heating value dilution parameter, NHVdil. Similar to the requirements we are finalizing for the combustion zone parameters, we are finalizing requirements that flares meet a minimum operating limit of 22 BTU/ft2 NHVdil on a 15-minute average, and we are providing that refiners use a corrected heat content of 1,212 BTU/scf for hydrogen to demonstrate compliance with this operating limit. For the reasons explained above, we are not finalizing the proposed alternative dilution parameter operating limits based on lower flammability limit or combustibles concentration, and we are not finalizing separate dilution parameter operating limits for gases meeting the proposed hydrogen-olefin interaction criteria. For flares in dedicated service, we are establishing an alternative to continuous or on-going grab sample requirements for determining waste gas net heating content to reduce the burden of sampling for flare waste gases that have consistent compositions. Flares in dedicated service can use initial sampling period and process knowledge to determine a fixed net heating value of the flare vent gas to be used in the calculations of NHVcz and, if applicable, NHVdil. We are revising the definition of MPV to remove the exemption for in situ sampling systems for the reasons provided in the proposed rule. We received comments recommending that a work practice standard be adopted for PRD rather than the proposed prohibition of atmospheric PRD releases. Commenters stated that the prohibition was infeasible due to the proposed immediate timing of the requirement and impractical due to cost considerations. After reviewing these comments as well as the BAAQMD rule (Regulation 8, Rule 8–28–304) and the SCAQMD rule (Rule 1173), we have determined that the work practice standards in these rules reflect the level of control that applies to the best performers. Therefore, we proceeded to evaluate appropriate MACT PO 00000 Frm 00040 Fmt 4701 Sfmt 4700 requirements based on the provisions in these rules. The BAAQMD rule requires sources to implement a minimum of three prevention measures to limit the possibility of a release. The BAAQMD uses a ‘‘release event’’ threshold of 10 lbs/day of organic or inorganic pollutants; the SCAQMD rule effectively uses a release event threshold of 500 lbs VOC/day. When a release event occurs, both rules require that the refiner perform a root cause analysis and take corrective action (including additional prevention measures). In addition, both rules require piping the PRD to a flare if there are more than two release events (releases above a certain release size threshold) in a 5-year period. Both rules include a number of exemptions for certain types of PRD that are not expected to release significant amounts of pollutants to the air or that are not feasible to control because of pressure considerations. These include PRD associated with storage tanks, vacuum systems and equipment in heavy liquid service as well as liquid thermal relief valves that are vented to process drains. There are five refineries subject to the BAAQMD rule and seven refineries subject to the SCAQMD rule, accounting for 8-percent of refineries nationwide and representing the industry’s best performers. We consider the BAAQMD rule to be the more stringent of the two because this rule requires sources to implement a minimum of three prevention measures to limit the possibility of a release (the SCAQMD rule has no similar requirement) and uses a lower mass threshold for what is considered a ‘‘release event’’ (10 lbs/day of organic or inorganic pollutants versus the 500 lbs VOC release threshold in the SCAQMD rule). Therefore, the BAAQMD rule is considered to be the MACT floor requirement for PRDs associated with new affected sources and the SCAQMD rule is considered to be the MACT floor for PRDs associated with existing affected sources. In general, an open PRD is essentially the same as a miscellaneous process vent that is vented directly to the atmosphere. Consistent with our treatment of miscellaneous process vents and consistent with the two California rules, we believe that it is appropriate to exclude certain types of PRD that have very low potential to emit based on their type of service, size and/ or pressure. For example, PRD that have a potential to emit less than 72 pounds per day of VOC, considering the size of the valve opening, design release pressure, and equipment contents, would be considered in a similar manner as Group 2 miscellaneous E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations process vents and would not require additional control. The two California rule requirements do not apply to PRD on storage tanks and vacuum systems. Most of these PRD have a design release pressure of 2.5 psig and thus have a very limited potential to emit. It is technically infeasible to pipe these sources to a flare (or other similar control system) because the back pressure in the flare header system generally exceeds 2.5 psig. We note that some storage tanks can operate at elevated pressure (i.e., pressure tanks). Therefore, rather than follow exactly the requirements in the California rules, we determined it more practical to exclude PRD with design release pressure of less than 2.5 psig. Any release from a PRD in heavy liquid service would have a visual indication of a leak and any repairs to the valve would have to be further inspected and, if necessary, repaired under the existing equipment leak provisions. Therefore, consistent with the BAAQMD rule, we are exempting PRD in heavy liquid service from the work practice standards we are establishing in this final rule. Both the BAAQMD and SCAQMD rules exempt thermal expansion valves that are ‘‘vented to process drains or back to the pipeline.’’ We are unclear what is meant by ‘‘vented to process drains’’; however, if a liquid is released from a PRD via hard-piping to a drain system that meets the control requirements specified in Refinery MACT 1, we consider that these PRD are controlled and they would not be subject to the work practice standard established in this final rule. Similarly, all PRD in light liquid service that are hard-piped to a controlled drain system (or back to the process or pipeline) are otherwise subject to a MACT requirement and would not be subject to the work practice standard. In considering thermal relief valves not vented to process drains or back to the pipeline, we expect that releases from these thermal relief valves will be small and generally under the release event thresholds specified in the California rules. Therefore, the work practice standards do not apply to PRD that are designed solely to release due to liquid thermal expansion. The primary goal of the PRD work practice standard is to reduce the size and frequency of releases. The SCAQMD rule is targeted towards fairly large releases (compared to the direct PRD releases reported in response to the Refinery ICR), so it will reduce the frequency of large releases, but it does little to reduce the frequency of smaller releases. To more effectively reduce the VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 size and frequency of all releases, we consider it important to require the implementation of prevention measures (as required in the BAAQMD rule) and require root cause analysis and corrective action for PRD releases from all PRD subject to the work practice standard. While we recognize that if a PRD opens for a short period of time, the release might be below the release thresholds in the SCAQMD rules, we believe the release may be indicative of an important issue or design flaw. Because the potential for large emissions exist from the PRD subject to the work practice standard, we think it is reasonable to require a root cause analysis be conducted and appropriate corrective action implemented to potentially identify this issue and prevent a second release which, if the issue remains uncorrected, could be significant. Requiring that prevention measures be implemented on all PRD subject to the work practice standard and not establishing a release threshold for release events is a variation from the SCAQMD rule. However, we also considered the allowable release frequency. We believe that our adoption of this approach is balanced by our not adopting the SCAQMD provisions requiring that PRD be vented to a flare or other control system or that refiners pay a fee if there are multiple releases of a certain size within a specified timeframe.12 In place of this system, we are limiting the number of events from each PRD that can occur in a 3 year time period (2, if root causes are different), and in place of a fine, or routing to control, stating that the 3rd release in 3 years for any root cause is a deviation of the standard. Because we are not including a size threshold for release events as in the SCAQMD rule, it is natural to assume release events would occur more frequently than release events subject to the SCAQMD rules. Also, based on our Monte Carlo analysis of random rare events, we note that it is quite likely to have two or three events in a 5-year period when a long time horizon (e.g., 20 years) is considered. Therefore, considering our analysis of emergency 12 The SCAQMD rule requires PRD to be vented to a flare or other control device if there is a single release in excess of 2,000 pounds of VOC in a 24hour period or three releases in excess of 500 pounds of VOC in a 5-year period or, alternatively, pay a $350,000 fee. Thus, the SCAQMD rule would allow, for example, two releases of over 500 pounds of VOC each within a 5-year period without any penalty provided a third event did not occur. If a third event did occur, the refinery owner or operator would then have to vent the PRD to a flare or other control system or pay a fee ($350,000) for the third release over 500 pounds of VOC. PO 00000 Frm 00041 Fmt 4701 Sfmt 4700 75217 flaring events and the lack of a 500 lb/ day release threshold, we considered it reasonable to use a 3-year period rather than a 5-year period as the basis of a deviation of the work practice standard. The SCAQMD work practice standards do not apply to releases that are demonstrated to ‘‘result from natural disasters, acts of war or terrorism, or external power curtailment beyond the refinery’s control, excluding power curtailment due to an interruptible service agreement.’’ These types of events, which we are referring to as ‘‘force majeure’’ events, are beyond the control of the refinery owner or operator. We are providing that these events should not be included in the event count, but that they would be subject to the root cause analysis in order to confirm whether the release was caused by a force majeure event. Consistent with the requirements in the SCAQMD rule, we are requiring refinery owners or operators to conduct a root cause analysis for a PRD release event. If the root cause was due to operator error or negligence, then the release would be a deviation of the standard. For any other release (not including those caused by force majeure events), the owner or operator would have to implement corrective action. We consider that a second release due to the same root cause for the same equipment in a 3-year period would be a deviation of the work practice standard. This provision will help ensure that root cause/corrective action are conducted effectively. Finally, a third release in a 3-year period (not including those caused by force majeure events) would be a deviation of the work practice standard, regardless of the root cause. While we are using a 3-year interval rather than the 5-year interval provided in the SCAQMD, we consider that the requirements as included in this final rule (i.e., the inclusion of prevention measure requirements and no thresholds for release events) will achieve equivalent if not greater emissions reductions than the SCAQMD rule. We also consider that, given the prevention measure requirements and a 3-year period, there is less likelihood of unusual random events that happen over a short period of time that may cause refinery owners or operators to feel compelled to vent the PRD to a flare to eliminate concerns regarding potential non-compliance. Thus, we project that the requirements that we have included in the final rule will achieve emissions reductions commensurate to or exceeding the requirements in the SCAQMD rule (that serves as the MACT floor for existing sources) but will achieve those E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75218 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations reductions in a more cost-effective manner. We also considered requiring all PRD to be vented through a closed vent system to a control device as an alternative beyond-the-MACT floor requirement. While this requirement would provide additional emission reductions beyond those we are establishing as the MACT floor, these reduction come at significant costs. Capital costs for requiring control of all atmospheric PRD is estimated to be approximately $300 million compared to $11 million for the requirements described above. The total annualized cost for requiring control of all atmospheric PRD is estimated to be approximately $41 million/year compared to $3.3 million/year for the requirements described above. We estimate that the incremental costeffectiveness of requiring control of all atmospheric PRD compared to the requirements described above exceeds $1 million per ton of HAP reduced. Consequently, we conclude that this is not a cost-effective option for existing sources. The final requirements that we have developed for PRD achieve equal or greater emission reductions than those achieved by the SCAQMD rule (MACT floor). To the extent those requirements are more stringent that the SCAQMD, they are cost-effective. We could not identify an alternative requirement that provided further emission reductions in a cost-effective manner. Thus, we conclude that the work practice standards described above represent MACT for existing sources. The BAAQMD rule, which represents the requirements applicable to the best performing sources, is the basis for new source MACT for PRD. Based on the specific provisions for PRD in the BAAQMD rule, we conclude that the MACT floor requirement is to have all PRD in HAP service associated with a new affected source vented through a closed vent system to a control device. As with existing sources, the PRD WPS would also contain the same exclusions (e.g., heavy liquid service PRDs, thermal expansion valves, liquid PRDs that are hard-piped to controlled drains, PRD with release pressures of less than 2.5 psig, PRD with emission potential of less than 72 lbs/day, and PRD on mobile equipment). These provisions are similar to the applicability provisions of the BAAQMD rule. Thus, we retain the same applicability of the work practice standard for PRDs on new or existing equipment, but all affected PRD on a new source would be required to be controlled. This is essentially equivalent to the proposed requirement of no VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 atmospheric releases. We could not identify a control option more stringent than the BAAQMD rule as applied to new sources. Therefore, we conclude that venting all PRD in HAP service through a closed vent system to a flare or similar control system is MACT for PRD associated with new affected sources. We consider it appropriate to establish a work practice standard for PRD as provided in CAA section 112(h). While it may be possible to design and construct a conveyance for PRD releases, we consider that the application of a measurement methodology for PRDs is not practicable due to technological and economic limitations. First, it is not practicable to use a measurement methodology for PRD releases. The venting time can be very short and may vary widely in composition and flow rate. The oftenshort duration of an event makes it infeasible to collect a grab sample of the gases when a release occurs, and a single grab sample would not account for potential variation in vent gas composition. It would be economically prohibitive to construct an appropriate conveyance and install and operate continuous monitoring systems for each individual PRD in order to attempt to quantitatively measure a release event that may occur only a few times in a 3year period. Additionally, we have not identified an available, technically feasible continuous emission monitoring systems that can determine a mass VOC or HAP release quantity accurately given the flow, composition and composition variability of potential PRD releases from refineries. Consequently, we conclude that it is appropriate to establish a work practice standard for PRD releases as provided in CAA section 112(h). D. NESHAP Amendments Addressing Emissions During Periods of SSM 1. What amendments did we propose to address emissions during periods of SSM? We proposed to eliminate the SSM exemption in 40 CFR part 63, subparts CC and UUU. Consistent with Sierra Club v. EPA, we proposed standards in these rules that apply at all times. We also proposed several revisions to Table 6 of subpart CC of 40 CFR part 63 and to Table 44 to subpart UUU of 40 CFR part 63 (the General Provisions Applicability tables for each subpart), including eliminating the incorporation of the General Provisions’ requirement that the source develop an SSM plan, and eliminating and revising certain recordkeeping and reporting PO 00000 Frm 00042 Fmt 4701 Sfmt 4700 requirements related to the SSM exemption. For Refinery MACT 1, we proposed that the use of a bypass at any time to divert a Group 1 miscellaneous process vent to the atmosphere is a deviation of the emission standard, and specified that refiners install, maintain and operate a continuous parameter monitoring system (CPMS) for flow that is capable of recording the volume of gas that bypasses the APCD. We also proposed to revise the definition of MPV to remove the exclusion for ‘‘Episodic or non-routine releases such as those associated with startup, shutdown, malfunction, maintenance, depressuring and catalyst transfer operations.’’ We also proposed that the control requirements for Group 1 MPV apply at all times, including startup and shutdowns. For Refinery MACT 2, we proposed alternate standards for three emission sources for periods of startup or shutdown. We proposed PM standards for startup of FCCU controlled with an ESP under Refinery MACT 2 because of safety concerns associated with operating an ESP during an FCCU startup. For FCCU controlled by an ESP, we proposed a 30-percent opacity limit (on a 6-minute rolling average basis) during the period that torch oil is used during FCCU startup. For startup of FCCU without a post-combustion device under Refinery MACT 2, we proposed a CO standard based on an excess oxygen concentration of 1 volume percent (dry basis) based on a 1-hour average. For periods of SRU shutdown, we proposed to allow diverting the SRU purge gases to a flare meeting the design and operating requirements in 40 CFR 63.670 (or, for a limited transitional time period, 40 CFR 63.11) or to a thermal oxidizer operated at a minimum temperature of 1,200 °F and a minimum outlet oxygen concentration of 2 volume percent (dry basis). For other emission sources in Refinery MACT 2, we proposed that the requirements that apply during normal operations should apply during startup and shutdown. 2. How did the SSM provisions change since proposal? a. Refinery MACT 1 We proposed that when process equipment is opened to the atmosphere (e.g., for maintenance), the existing MPV emissions limits apply. In this final rule, we are instead finalizing startup and shutdown provisions that apply to these venting events. These startup and shutdown provisions are work practice standards that allow refinery owners or operators to open process equipment E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations during startup and shutdown provided that the equipment is drained and purged to a closed system until the hydrocarbon content is less than or equal to 10-percent of the LEL. For those situations where 10-percent LEL cannot be demonstrated (no direct measurement location), the equipment may be opened and vented to the atmosphere if the pressure is less than or equal to 5 psig. Active purging of the equipment is only allowed after the 10percent LEL level is achieved, regardless of the pressure of the equipment/vessel. We are establishing a separate requirement for very small process equipment, defined as equipment where it is physically impossible to release more than 72 lbs VOC per equipment opening based on the size and contents of the equipment. This definition is consistent with the Group 1 applicability cutoff for control of miscellaneous process vents. We also developed requirements specific to catalyst changeout activities where pyrophoric catalyst (e.g., hydrotreater or hydrocracker catalysts) must be purged using recovered hydrogen. These provisions include: Documenting the procedures for equipment openings and procedures for verifying that events meet the specific conditions above using site procedures used to de-inventory equipment for safety purposes (i.e., hot work or vessel entry procedures) and documenting any deviations from the work practice standard requirements. b. Refinery MACT 2 tkelley on DSK3SPTVN1PROD with RULES2 We are expanding the proposed 1percent minimum oxygen operating limit alternative for organic HAP to apply for all FCCU startup and shutdown events (rather than only partial burn FCCU with CO boilers during startup). We are replacing the proposed opacity limit alternative to the metal HAP standard with a minimum cyclone face velocity limit and we are extending that alternative limit to all FCCU (regardless of control device) for both startup and shutdown in this final rule. We are extending the proposed alternative for SRU to monitor incinerator temperature and excess oxygen limits during SRU shutdowns to also apply during periods of startup. 3. What key comments did we receive on the SSM revisions and what are our responses? a. Refinery MACT 1 Comment: Many commenters stated that the proposed extension of the MPV definition to episodic maintenance startup and shutdown vents and VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 elimination of the SSM exception for storage tanks would create hundreds or thousands of new vents per refinery per year and generate massive on-going burdens. The commenters argued that the EPA has not included in the record any analysis of the potential environmental benefits, costs or operational and compliance feasibility and impacts associated with this requirement and that many of these requirements will result in delayed and extended equipment and process outages. One commenter asserted that the EPA has articulated no justification for applying emission standards to these events, nor any analysis consistent with CAA section 112 for a determination that MACT standards are appropriately applied to these emission events under the criteria in CAA section 112(d). Many commenters stated that every time a vessel is opened for inspection or maintenance each vent point will have to be evaluated as a potential MPV or storage tank vent. If a particular vent point (e.g., bleeder) used for maintenance, startup or shutdown handles material that is initially greater than 20 ppm HAP, then it is a MPV. If there is a potential to emit greater than or equal 72 lbs/day of VOC, then it is a Group 1 MPV and must be controlled. If there is a potential of less than 72 lb/ day VOC release, then it is a Group 2 MPV and subject to recordkeeping requirements. Commenters stated that in a refinery there would be tens or more such activities per day associated with normal maintenance and inspection; during turnarounds, there could be hundreds of such MPVs. Commenters added that these MPVs may then need to be individually accounted for and permitted creating an unnecessary permitting and recordkeeping burden for these periodic emissions. Commenters recommended a general set of work practice requirements for maintenance, startup and shutdown of vents, based on state requirements, that do not impose the permitting, notice and evaluation requirements associated with identifying these vents individually. Commenters explained that states have dealt with these episodic vents by establishing them as a special class of process vent with limited recordkeeping requirements and subject to a work practice standard, rather than the normal MPV requirements. A key element of these work practices is clear identification of the criteria for releasing these vents to the atmosphere and for routing these vents to control after hydrocarbon is reintroduced, which the commenters asserted the current rule does not provide. Commenters proposed that a PO 00000 Frm 00043 Fmt 4701 Sfmt 4700 75219 work practice standard could include removing process liquids to the extent practical and depressuring smaller volume equipment until a pressure of <5 psig is achieved and/or purging and depressuring to a control device until the vent has a hydrocarbon concentration of less than 10-percent of the LEL. The commenters suggested that these standards should provide clear easily monitored criteria for when this equipment can be vented to the atmosphere, and should not impose the permitting, notice and evaluation requirements associated with identifying these vents as individual MPVs. One commenter provided draft regulatory language for a work practice requirement. Response: We proposed to eliminate the episodic and non-routine emission exclusion in order to ensure that the MACT includes emission limits that apply at all times consistent with the holding in Sierra Club. At the time of the proposal, we expected that essentially all SSM event emissions would be routed to flares that are subject to the MACT standards and, thus, would serve to control these emissions. However, we recognize that maintenance activities that require equipment openings are a separate class of startup/shutdown emissions because there must be a point in time when the vessel can be opened and any emissions vented to the atmosphere. We acknowledge that it would require a significant effort to identify and characterize each of these potential release points for permitting purposes. In considering these comments and whether we should establish a separate limit that would apply to these equipment openings, we reviewed state permit requirements and the practices employed by the best performing sources. We found that some state or local agencies required depressuring to 5 psig prior to atmospheric releases while others required the gases to have organic concentrations at or below 10percent of LEL prior to atmospheric venting. In the final rule, we are establishing a requirement that prior to opening process equipment to the atmosphere, the equipment must first be drained and purged to a closed system so that the hydrocarbon content is less than or equal to 10-percent of the LEL. For those situations where 10-percent LEL cannot be demonstrated, the equipment may be opened and vented to the atmosphere if the pressure is less than or equal to 5 psig, provided there is no active purging of the equipment to the atmosphere until the LEL criterion is met. For equipment where it is not technically possible to depressurize to a E:\FR\FM\01DER2.SGM 01DER2 75220 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 control system, we allow venting to the atmosphere where there is no more than 72 lbs VOC per day potential, consistent with our Group 1 applicability cutoff for control of process vents. For catalyst changeout activities where hydrotreater pyrophoric catalyst must be purged we have provided limited allowances for direct venting. Provisions to demonstrate compliance with this work practice include documenting the procedures for equipment openings and procedures for verifying that events meet the specific conditions above using site procedures used to de-inventory equipment for safety purposes (i.e., hot work or vessel entry procedures). b. Refinery MACT 2 Comment: Several commenters noted that there was a proposed specific alternative metal HAP/PM standard for startup of an FCCU controlled with an ESP, but took issue with the fact that no alternative PM limits were proposed for startup of FCCU equipped with other types of PM controls, or for any FCCU during periods of shutdown or hot standby. Regarding the proposed alternative for startup, which would provide an alternative in the form of an opacity limit when torch oil is in use, commenters stated that there are serious process safety concerns which prevent most FCCU ESPs from being operated when torch oil is in the regenerator, that is, during periods of startup, shutdown and hot standby. To avoid the possibility of a fire and explosion, the commenters claimed ESPs are usually de-energized and bypassed during these periods and, consequently, these FCCUs are generally unable to meet the proposed 30-percent opacity limit. Several commenters stated that the EPA’s limits on FCCU opacity during SSM are unreasonable and ignore the technical requirements for transitional operations of those units. The commenters indicated that they have ESPs located downstream of the CO boiler and claimed that for safety reasons the CO boiler cannot operate during startup, shutdown or hot standby. Further, a commenter indicated that the ESP cannot operate if the CO boiler is not operating and thus both the CO boiler and the ESP must be bypassed during startup, shutdown, and hot standby operations. Another commenter stated that the EPA offers no data to support the achievability of this requirement in practice and discusses information for 26 startup/shutdown events that found that none complied with a 30-percent opacity requirement. Several commenters also noted that experience has shown that the 30-percent opacity VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 limit is unachievable during these periods for FCCUs controlled with tertiary cyclones, when regenerator gas flow is below cyclone minimum design flow. Several commenters suggested that the EPA establish a standard based on the operation of FCCU catalyst regenerators’ internal cyclones that function to retain the catalyst in the regenerators and thereby minimize catalyst and metal HAP emissions from the regenerators. Additional control to meet the Refinery MACT 2 emission limit of not more than 1.0 lb PM/1,000 lbs coke burn-off is provided by a bag house, wet gas scrubber (WGS), ESP or tertiary (external) cyclone. The efficiency of a cyclone is a function of the inlet gas velocity. Assuring adequate velocity to the internal cyclones ensures that the catalyst sent to these additional controls is minimized and ensures that they are operating as effectively as possible. Similarly, even if the FCCU cannot meet the normal opacity limits during startup, shutdown or hot standby (e.g. due to the ESP being off-line for safety reasons or the tertiary cyclones or WGS operating at non-routine conditions), assuring adequate velocity to the internal regenerator cyclones will control and minimize particulate emissions. Several commenters stated support for another commenter’s position that all FCCUs should be allowed the option of complying with a 20 feet/second minimum inlet velocity to the primary regenerator cyclones during periods of startup and shutdown, including hot standby, and these commenters provided additional technical explanations in their comments. On the other hand, some commenters seemed to support the proposed opacity limits, but suggested minor revisions. One commenter noted that the SCAQMD has granted Valero’s request for variances from visible emission standards during startup of the FCCU of up to 65-percent opacity for up to five minutes, in aggregate, during any 1-hour period, and 30-percent as an hourly average for the remaining period, during startup events. The application of this variance reflects the unavailability and/ or ineffectiveness of the ESP during the startup condition. Another commenter recommended that either the opacity standard should be raised or the time period for averaging should be extended so FCCUs can be operated safely during SSM events and still remain in compliance. Response: We have reviewed the data submitted by the commenters to support their assertion that the 30-percent opacity limit (determined on a 6-minute PO 00000 Frm 00044 Fmt 4701 Sfmt 4700 average basis) is not achievable during startup and shutdown events. While the data are limited, and it is unclear if the data provided are indicative of the performance achieved by the best performing sources, we do not have adequate data to refute the assertion that the 30-percent opacity limit (determined on a 6-minute average basis) is not achievable during startup and shutdown events. We considered the two options suggested by the commenters, the minimum velocity for the internal FCCU regenerator cyclones and the 30-percent hourly average opacity limit excluding 5 minutes not exceeding 65-percent opacity. Again, due to the limited data available during startup and shutdown events, we are not able to determine which requirement would provide greater HAP emissions reduction. However, we note that some facilities may not be required to have an opacity monitoring system in place and opacity monitoring is not applicable for FCCU controlled with wet scrubbers. Therefore, we find that the minimum internal cyclone inlet velocity requirement is more broadly applicable than the opacity limit. Also, based on the data provided by the commenters, the minimum internal cyclone inlet velocity requirement will provide PM (and therefore metal HAP) emissions reductions during startup and shutdown periods. Therefore, considering the available data, we conclude that MACT for FCCU startup and shutdown events is maintaining the minimum internal cyclone inlet velocity of 20 feet/second. Comment: Several commenters stated that the EPA should provide alternate standards for startups of FCCU equipped with CO boilers and for any FCCU during periods of shutdown and hot standby. The commenters stated that the EPA incorrectly assumes that refiners are able to safely and reliably start up their FCCU with flue gas boilers in service and meet the normal operating limit of 500 ppm CO. They claimed that most refiners are unable to reliably start up their FCCU with flue gas boilers in service due to the design of the boiler and the fact that many boilers are not able to safely and reliably handle the transient FCCU operations that can occur during startup, shutdown, and hot standby. One commenter stated that FCCU built with CO boilers experience issues with flame stability due to fluctuating flue gas compositions and rates when starting up and shutting down. Accordingly, the commenter stated, startup and shutdown activities at FCCU using a boiler as an APCD are not currently meeting the Refinery MACT 2 standard E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations of 500 ppm CO on a 1-hour basis, and this level of control does not qualify as the MACT floor. The commenter gave examples of facilities where FCCU, including those equipped with postcombustion control systems, do not consistently demonstrate compliance with a 500 ppm CO concentration standard during all startup and shutdown events. Commenters stated that reliable boiler operation is critical to the overall refinery steam system and refineries must avoid jeopardizing boiler operation to prevent major upsets of process operations. A major upset or site-wide shutdown could result in flaring and emissions of HAP far in excess of that emitted while bypassing the CO boiler. Commenters stated that combustion of torch oil in the FCCU regenerator during startup is one of the primary reasons the CO limit cannot be met during these operations. Torch oil is also used during shutdown to control the cooling rate (and potential equipment damage) and during hot standby and, thus, the normal CO standard cannot be met at these times either. Hot standby is used to hold an FCCU regenerator at operating temperature for outages where a regenerator shutdown is not needed and to avoid full FCCU shutdowns. Full cold shutdown also increases personnel exposures associated with removing catalyst and securing equipment. Additionally, this can produce additional emissions over maintaining the unit in hot standby. Commenters claimed that because of the variability of CO during torch oil operations, it is not possible for the EPA to establish a CAA section 112(d) standard for startup and shutdown activities at FCCU because refineries cannot measure a constant level of emissions reductions. The commenters recommended expansion of the proposed standard of greater than 1-percent hourly average excess regenerator oxygen to all FCCU, including units with fired boilers. These commenters suggested that maintaining an adequate level of excess oxygen for the combustion of fuel in the regenerator is the best way to minimize CO and organic HAP emissions from FCCU during these periods. Response: After reviewing the comments and discussing CO boiler operations with facility operators, we agree that the 1-percent minimum oxygen limit should be more broadly applicable to FCCU startup and shutdown regardless of the control device configuration and have revised the final rule accordingly. Comment: Several commenters stated that the proposed alternative standards VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 for SRP shutdowns should be extended to startups as well since the normal SRP emission limitation cannot always be achieved during SRP startups. Several commenters gave examples of startup activities where this relief is needed, and noted there may be other startup activities that also need this relief. Response: For the control of sulfur HAP, we determined that incineration effectively controls these HAP. We were not aware that there would be unusual sulfur loads in the SRU tail gas during startup. We agree that the alternative standard we proposed for periods of shutdown is also the MACT floor for periods of startup because incineration meeting the limits proposed will achieve the MACT control requirements for sulfur HAP during periods of either startup or shutdown even though sulfur loadings during these periods may be elevated. For many SRU configurations, compliance during normal operations is demonstrated by monitoring SO2 emissions. However, during startup and shutdown, high sulfur loadings in the SRU tail gas entering the incinerator will cause high SO2 emissions even though sulfur HAP emissions are well controlled. Consequently, the proposed incinerator operating limits provide a better indication of sulfur HAP control during startup and shutdown than SO2 emissions. Owners or operators that use incinerators or thermal oxidizers during normal operations may meet the sitespecific temperature and excess oxygen operating limits that were determined based on their performance test during periods of startup and shutdown. 4. What is the rationale for our final approach and final decisions to address emissions during periods of SSM? a. Refinery MACT 1 We did not receive comments regarding the proposed amendments to Table 6 of subpart CC of 40 CFR part 63; therefore, for the reasons provided in the preamble to the proposed rule, we finalizing these amendments as proposed. We determined that it was overly burdensome and in most cases technically infeasible to consider every potential equipment or vessel opening and classify these ‘‘openings’’ (newly classified as MPV in the proposal) as either Group 1 or Group 2 MPV. We also determined that it is not always technically feasible, depending on the opening, to demonstrate compliance with the MPV emissions limitations. After considering the public comments, we determined it was appropriate to establish separate startup and shutdown provisions for MPV associated with PO 00000 Frm 00045 Fmt 4701 Sfmt 4700 75221 process equipment openings. We reviewed state and local requirements and based the final rule requirements on the emissions limitations required to be followed by the best performing sources. Therefore, we are finalizing requirements for refinery owners or operators to open process equipment during these startup and shutdown events without directly permitting these ‘‘vents’’ as Group 1 or Group 2 MPV provided that the equipment is drained and purged to a closed system until the hydrocarbon content is less than or equal to 10-percent of the LEL. As described in further detail previously in this section, we have provided provisions for special cases where the 10-percent LEL limit cannot be demonstrated and provisions for less significant equipment openings, consistent with the practices used by the best performing facilities. b. Refinery MACT 2 We did not receive significant comments regarding the proposed amendments to Table 44 to subpart UUU of 40 CFR part 63; therefore, we finalizing these amendments as proposed. In response to comments, we determined that the limited provisions that were provided for startup only or for shutdown only were too limited and we have expanded the proposed provisions to both startup and shutdown regardless of control device used. For the FCCU organic HAP emissions limit, we are finalizing an alternative limit for periods of startup of no less than 1-percent oxygen in the exhaust gas as proposed, but we are extending that alternative limit to shutdown and to all FCCU in this final rule. For the FCCU metal HAP emissions limit, we proposed a specific startup limit for FCCU controlled be an ESP of 30-percent opacity. We received comments along with limited data suggesting that this limit was not achievable. Commenters suggested that the best performing units maintain a minimum face velocity of at least 20 feet/second to minimize catalyst PM losses during startup and shutdowns. Operators of wet scrubbers also noted that they cannot maintain pressure drops and that one cannot meet the PM emissions limit normalized by coke burn-off rate when the coke burn-off rate approaches zero. Consequently, commenters stated that the alternative limits should be provided for startup and shutdown regardless of control device. Upon consideration of the comments, we determined that it was necessary to revise the proposed E:\FR\FM\01DER2.SGM 01DER2 75222 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations alternative to be based on minimum inlet face velocity to the FCCU regenerator internal cyclones and provide the alternative for both startup and shutdown. We also expanded this limit to all FCCU; however, we also required FCCU with wet scrubbers to meet only the liquid to gas ratio operating limit during periods of startup and shutdown to allow wet scrubbers to use a consistent compliance method at all times. For SRU, we are finalizing an alternative standard during periods of startup and shutdown to use a flare that meets the operating limits included in the final rule or a thermal oxidizer or incinerator operated at a minimum hourly average temperature of 1,200 °F and a minimum hourly average outlet oxygen concentration of 2 volume percent (dry basis). We proposed these alternatives for periods of shutdown only, but based on comments received regarding startup issues, we determined that high sulfur loadings can occur during periods of startup and that the alternative limit proposed was appropriate for both startup and shutdown. E. Technical Amendments to Refinery MACT 1 and 2 tkelley on DSK3SPTVN1PROD with RULES2 1. What other amendments did we propose for Refinery MACT 1 and 2? We proposed a number of amendments to Refinery MACT 1 and 2 to address technical issues such as rule language clarifications and reference corrections. First, we proposed to amend Refinery MACT 1 to clarify what is meant by ‘‘seal’’ for open-ended valves and lines that are ‘‘sealed’’ by the cap, blind flange, plug, or second valve by stating that sealed means when there are no detectable emissions from the open-ended valve or line at or above an instrument reading of 500 ppm. Second, we also proposed electronic reporting requirements where owners or operators of petroleum refineries must submit electronic copies of required performance test and performance evaluation reports for compliance with Refinery MACT 1 and 2 by direct computer-to-computer electronic transfer using EPA-provided software. Third, we proposed to update the General Provisions Tables 6 (for Refinery MACT 1) and 44 (for Refinery MACT 2) to correct cross references and to incorporate additional sections of the General Provisions that are necessary to implement these rules. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 2. How did the other amendments for Refinery MACT 1 and 2 change since proposal? We are not finalizing the definition of ‘‘seal’’ for open-ended lines as proposed. We are finalizing changes to update the General Provisions crossreference tables as proposed, with one minor change to provide an option for the administrator to issue guidance on performance test reporting timeframes in order to address issues relating to submittal of data to the ERT. 3. What key comments did we receive on the other amendments for Refinery MACT 1 and 2 and what are our responses? Comment: Numerous commenters objected to the proposal to clarify the meaning of ‘‘seal’’ as it relates to openended line (OEL) standards. Commenters contend that there is no basis for the EPA to assert that the proposed definition merely ‘‘clarifies’’ an established interpretation of the term ‘‘seal’’ and stated that the proposed revision constitutes an illegal change in the requirements for OELs, and the clarification should not be finalized. One commenter stated that none of the MACT standards in place before this proposal have stated or suggested that a ‘‘sealed’’ OEL is one with detectable emissions below 500 ppm. This commenter added this unique interpretation of the requirement to ‘‘seal’’ an OEL with a cap or plug is incompatible with the historical interpretation of this requirement by affected facilities and by the EPA, and the EPA has not issued any sort of definitive guidance or interpretation setting out this position. The commenter detailed numerous references to considerations the EPA has made relative to OEL requirements in LDAR programs. In addition to the examples cited, the commenter noted that in 2006, the EPA proposed to add a ‘‘no detectible emissions’’ limit and monitoring requirement for OELs to NSPS VV (71 FR 65317, November 7, 2006). Two commenters noted that the proposed monitoring was not finalized in either NSPS VV or VVa (72 FR 64860, November 16, 2007) because it was not considered BDT due to the low emission reductions and the cost effectiveness of the requirement. Another commenter agreed that there is no explanation provided for why this information could now support the need for a new OEL seal standard that requires monitoring to ensure compliance when it was deemed to be unjustified previously. In addition, the commenter collected OEL monitoring data and submitted it to PO 00000 Frm 00046 Fmt 4701 Sfmt 4700 the EPA (see Docket Item No. EPA–HQ– OAR–2010–0869–0058). Based on these data, the commenter asserted that the existence of leaks from OELs that are not properly sealed is extremely low. The commenter noted that the EPA is claiming this change is only a clarification of current requirements, allowing the EPA to bypass the need to cite a CAA authorization for this change to the existing CAA section 112(d)(2) standard or meet the process requirements associated with such a change, including providing emission reduction, cost and burden estimates in the record and the associated PRA Information Collection Request (ICR). Several commenters claimed that this clarification would result in retroactive impact and also addressed the implication of the proposed change on other fugitive emissions standards. One commenter stated that the EPA cannot retroactively reinterpret the OEL requirements or define the word ‘‘seal’’ and added that the EPA should account for the thousands of additional monitoring events per year per refinery that this new requirement would add to LDAR programs and provide proper cost justification under CAA sections 112(d)(6) or 112(f)(2). Several commenters also stated that the proposed definition will effectively change all equipment leak rules in parts 40 CFR parts 60, 61 and 63 and the change should not be finalized. One commenter added that by claiming this change is only a clarification of current requirements, the EPA would set a precedent applicable to all OELs in all industries subject to any similar OEL equipment leak requirement. Response: We have decided not to finalize the proposed clarification of the term ‘‘seal’’ for OELs at this time. The fenceline monitoring requirements we are finalizing will detect any significant leaks from a cap, blind flange, plug or second valve that does not properly seal an OEL, as well as significant leaks from numerous other types of fugitive emission sources. Comment: A few commenters stated that the proposed use of the ERT is not appropriate because the costs and burdens imposed are additive to the costs of producing and submitting the written report, and there is no benefit that justifies the additional cost. One commenter also stated that the EPA has not developed or articulated a reasonable approach to using information that would be uploaded to the ERT. The commenters recommended that the EPA remove this portion of the proposal until the ERT is demonstrated to handle all the information from refinery performance E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tests (rather than only portions), thereby eliminating the need for both written and electronic reporting and until the Agency demonstrates that it is using the electronic data to develop improved air quality emission factors. Other commenters stated that the ERT requirement does not supersede or replace any state reporting requirements and thus the regulated industry will be subject to dual reporting requirements. These commenters disagreed with the preamble claim that eliminating the recordkeeping requirements for performance test reports is a burden savings, and stated that it may duplicate burdens already borne by the regulated community. The commenters expressed further concern that duplicative reporting requirements will strain the regulated industry to comply with deadlines established by rule for report submittals. One commenter stated that there is no mechanism for obtaining extensions for special circumstances. Under proposed 40 CFR 63.655(h)(9)(i), all reports are due in 60 days. The commenter claimed that by not referencing reporting requirements to the General Provisions in 40 CFR 63.10(d)(2), there is no allowance for obtaining additional time due to unforeseen circumstances or due to the difficulties involved with completing particularly complex reports. One commenter stated that the primary performance test method (Method 18) required for determining compliance is not currently included in the list of methods supported by the ERT. The commenter stated that the regulated community’s experience with Method 18 is that it is a very broad methodology and can be exceptionally complex to execute and to report. The commenter stated that the EPA is aware that Method 18 reporting is complex, that it may be difficult to incorporate into the ERT, and that no time schedule has been defined for development or implementation for this method. The commenter also stated that without formal notice of changes to the ERT, the regulated community is at risk of non-compliance. The only way for the regulated community to know that changes have occurred in the ERT is to monitor the Web site directly because the EPA does not formally announce changes to the ERT in the Federal Register. As such, it would be possible for a regulated entity to be unaware of changes made such as the incorporation of Method 18. The commenter expressed concern that the proposal language is an open-ended commitment subject to change without notice. The commenter stated that the EPA should VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 clearly indicate when facilities would be required to use the ERT when new test methods are included in the ERT. Response: We disagree that use of the ERT for completing stack test reports is an added cost and burden. While the requirement to report the results of stack tests with the ERT does not supersede state reporting requirements, we are aware of several states that already require the use of the ERT, and we are aware of more states that are considering requiring its use. We note that where states will not accept an electronic ERT submittal, the ERT provides an option to print the report, and the printed report can be mailed to the state agency. We have no reason to believe that the time savings in the ability to reuse data elements within reports does not, at a minimum, offset the cost incurred by printing out and mailing a copy of the report and the commenters have provided no support for their cost claims. Furthermore, based on the analysis performed for the Electronic Reporting and Recordkeeping Requirements for the New Source Performance Standards Rulemaking (ERRRNSPS) (80 FR 15100), electronic reporting results in an overall cost savings to industry when annualized over a 20-year period. The cost savings is achieved through means such as standardization of data, embedded quality assurance checks, automatic calculation routines and reduced data entry through the ability to reuse data in files instead of starting from scratch with each test. As outlined in the ERRRNSPS, there are many benefits to electronic reporting. These benefits span all users of the data—the EPA, state and local regulators, the regulated entities and the public. We note that in the preamble to this proposed rule we provided a number of reasons why the use of the ERT will provide benefit going forward and that most of the benefits we outlined were longer-term benefits (e.g., reducing burden of future information collection requests). Additionally, we note that in 2011, in response to Executive Order 13563, the EPA developed a plan 13 to periodically review its regulations to determine if they should be modified, streamlined, expanded or repealed in an effort to make regulations more effective and less burdensome. The plan includes replacing outdated paper reporting with electronic reporting. In keeping with this plan and the White House’s Digital 13 EPA’s ‘‘Final Plan for Periodic Retrospective Reviews,’’ August 2011. Available at: https://www. epa.gov/regdarrt/retrospective/documents/ eparetroreviewplan-aug2011.pdf. PO 00000 Frm 00047 Fmt 4701 Sfmt 4700 75223 Government Strategy, 14 in 2013 the EPA issued an agency-wide policy specifying that new regulations will require reports to be electronic to the maximum extent possible. By requiring electronic submission of stack test reports in this rule, we are taking steps to implement this policy. We also disagree that we have not developed or articulated a reasonable approach to using information that would be uploaded to the ERT. To the contrary, we have discussed at length our plans for the use of stack test data collected via the ERT. In 2009, we published an advanced notice of proposed rulemaking (74 FR 52723) for the Emissions Factors Program Improvements. In that notice, we first outlined our intended approach for revising our emissions factors development procedures. This approach included using stack test data collected with the ERT. We reiterated this position in our ‘‘Recommended Procedures for the Development of Emissions Factors and Use of the WebFIRE Database’’ (https://www.epa. gov/ttn/chief/efpac/procedures/ procedures81213.pdf), which was subject to public notice and comment before being finalized in 2013. Finally, we discussed uses of these data in the preamble to the proposed rule and at length in the preamble to the ERRRNSPS. We think that it is a circular argument to say that the agency should eliminate the use of the ERT until it demonstrates that it is using the electronic data. It would be impossible for the agency to use data that it does not have. We can only use electronic data once we have electronic data. We do note that we are nearing completion of programming the WebFIRE database with our new emissions factor development procedures and anticipate running the routines on existing data sets in the near future. We continue to improve and upgrade the ERT on an ongoing basis. The current version of the ERT supports 41 methods, including EPA Methods 1–4, 5, 5B, 5F, 25A 26, and 26A. We note that the ERT does not currently support EPA Method 18, and for performance tests using Method 18, the source will still have to produce a paper report. However, we are aware of the need to add Method 18 to the ERT, and we are currently looking at developing this capability. As noted in the ERRRNSPS, when new methods are added to the 14 Digital Government: Building a 21st Century Platform to Better Serve the American People, May 2012. Available at: https://www.whitehouse.gov/ sites/default/files/omb/egov/digital-government/ digital-government-strategy.pdf. E:\FR\FM\01DER2.SGM 01DER2 75224 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations ERT, we will not only post them to the Web site; we will also send out a listserv notice to the Clearinghouse for Inventories and Emissions Factors (CHIEF) listserv. Information on joining the CHIEF listserv can be found at https://www.epa.gov/ttn/chief/ listserv.html#chief. We are requiring the use of the ERT if the method is supported by the ERT, as listed on the ERT Web site (https://www.epa.gov/ttn/ chief/ert/ert_info.html) at the time of the test. We do not agree that it is overly burdensome to check a Web site for updates prior to conducting a performance test. We did revise the MACT 1 and 2 tables referencing reporting requirements to the general provisions (Table 6 for Refinery MACT 1 and Table 44 for Refinery MACT 2) to provide flexibility in the 60-day reporting timeline to accommodate unforeseen circumstances or difficulties involved with completing particularly complex reports. 4. What is the rationale for our final approach and final decisions for the other amendments for Refinery MACT 1 and 2? We are not finalizing the definition of seal, as proposed. The fenceline monitoring work practice standard will detect any significant leaks from a cap, blind flange, plug or second valve that does not properly seal an OEL, as well as significant leaks from numerous other types of fugitive emission sources. We are finalizing requirements for electronic reporting, as proposed, with a minor clarification. Specifically, we are revising Tables 6 in subpart CC and 44 in subpart UUU, which cross-reference the applicable provisions in the General Provisions to provide flexibility in the ERT 60-day reporting timeline. Refiners can seek approval from the EPA or a delegated state additional time for submittal of data due to unforeseen circumstances or due to the difficulties involved with completing particularly complex reports. F. Technical Amendments to Refinery NSPS Subparts J and Ja tkelley on DSK3SPTVN1PROD with RULES2 1. What amendments did we propose for Refinery NSPS Subparts J and Ja? We proposed a number of amendments to Refinery NSPS subparts J and Ja to address reconsideration issues and minor technical clarifications. First, we proposed revisions to 40 CFR 60.100a(b) to include a provision that sources subject to Refinery NSPS subpart J could elect to comply instead with the provisions of Refinery NSPS subpart Ja. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Second, we proposed a series of amendments to the requirements for SRP in 40 CFR 60.102a, to clarify the applicable emission limits for different types of SRP based on whether oxygen enrichment is used. The amendments proposed also clarified that emissions averaging across a group of emission points within a given SRP is allowed for each of the different types of SRP, and that emissions averaging is specific to the SO2 or reduced sulfur standards (and not to the 10 ppmv hydrogen sulfide (H2S) limit). We also proposed a series of corresponding amendments in 40 CFR 60.106a to clarify the monitoring requirements, particularly when oxygen enrichment or emissions averaging is used. We also proposed clarifications in 40 CFR 60.106a to consistently use the term ‘‘reduced sulfur compounds’’ when referring to the emission limits and monitoring devices needed to comply with the reduced sulfur compound emission limits for sulfur recovery plants with reduction control systems not followed by incineration. Third, we proposed amendments to 40 CFR 60.102a(g)(1) to clarify that CO boilers, while part of the FCCU affected facility, can also be FGCD. Fourth, we proposed several revisions to 40 CFR 60.104a to clarify the performance testing requirements. We proposed revision to 40 CFR 60.104a(a) to clarify that an initial compliance demonstration is needed for the H2S concentration limit in 40 CFR 60.103a(h). We proposed revisions to the annual PM testing requirement in 40 CFR 60.104a(b) to clarify that annually means once per calendar year, with an interval of at least 8 months but no more than 16 months between annual tests. We also proposed to amend 40 CFR 60.104a(f) to clarify that the provisions of that paragraph are specific to owners or operators of an FCCU or FCU that use a cyclone to comply with the PM emissions limit in 40 CFR 60.102a(b)(1) and not to facilities electing to comply with the PM emissions limit using a PM CEMS. We also proposed to amend 40 CFR 60.104a(j) to delete the requirements to measure flow for the H2S concentration limit for fuel gas. Fifth, we proposed several amendments to clarify the requirements for control device operating parameters in 40 CFR 60.105a. Specifically, we proposed amendments to 40 CFR 60.105a(b)(1)(ii)(A) to require corrective action be completed to repair faulty (leaking or plugged) air or water lines within 12 hours of identification of an abnormal pressure reading during the daily checks. We also proposed revisions to 40 CFR 60.105a(i) to specify that periods when abnormal pressure PO 00000 Frm 00048 Fmt 4701 Sfmt 4700 readings for a jet ejector-type wet scrubber (or other type of wet scrubber equipped with atomizing spray nozzles) are not corrected within 12 hours of identification and periods when a bag leak detection system alarm (for a fabric filter) is not alleviated within the time period specified in the rule are considered to be periods of excess emissions. We also proposed amendments to 40 CFR 60.105(b)(1)(iv) and 60.107a(b)(1)(iv) to provide flexibility in span range to accommodate different manufacturers of the length-of-stain tubes. We also proposed to delete the last sentence in 40 CFR 60.105(b)(3)(iii). Finally, we proposed clarification to the performance test requirements for the H2S concentration limit for affected flares in 40 CFR 60.107a(e)(1)(ii) and (e)(2)(ii) to remove the distinction between flares with or without routine flow. 2. How did the amendments to Refinery NSPS Subparts J and Ja change since proposal? We are making very few changes to the amendments proposed for Refinery NSPS subparts J and Ja. In response to comments, we are revising the NSPS requirements to replace the ‘‘measurement sensitivity’’ requirements with accuracy requirements consistent with those used in Refinery MACT 1 and 2. Specifically, we are revising 40 CFR 60.106a(a)(6)(i)(B) and (7)(i)(B) to require use of a flow sensor meeting an accuracy requirement of ±5-percent over the normal range of flow measured or 10-cubic-feet-per-minute, whichever is greater. We are also revising the flare accuracy requirements in 40 CFR 60.107a(f)(1)(ii) to require use of a flow sensor meeting an accuracy requirement of ±20-percent of the flow rate at velocities ranging from 0.1 to 1 feet per second and an accuracy of ±5-percent of the flow rate for velocities greater than 1-feet-per-second. Finally, we are revising 40 CFR 60.101a(b) to correct an inadvertent error where the phrase ‘‘and delayed coking units’’ was not included in the proposed sentence revision. 3. What key comments did we receive on the amendments to Refinery NSPS Subparts J and Ja and what are our responses? Comment: Two commenters noted concern with the term ‘‘measurement sensitivity’’ in proposed 40 CFR 60.106a(a)(6)(i)(B) and (a)(7)(i)(B) for sulfur recovery unit monitoring alternatives and in existing regulations 40 CFR 60.107a(f)(1)(ii) for flares because ‘‘sensitivity’’ is not a term E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 found on typical monitoring system data sheets. Typical flow meter characteristics include terms such as accuracy and resolution and the commenters requested that the EPA revise the terminology to match the wording found in 40 CFR part 63, subpart CC, Table 13 for flow meters (i.e., accuracy requirements). Additionally, several commenters suggested that the EPA flow monitor accuracy specifications are inconsistent with those in the SCAQMD Flare Rule and many refinery consent decrees. The commenters recommended revising both the flare flow meter sensitivity specification and accuracy specification in Refinery MACT 1 Table 13 and in Refinery NSPS subpart Ja to be consistent with the accuracy specification from the Shell Deer Park Consent Decree, Appendix 1.10, which specifies the required flare flow meter accuracy as ‘‘±20% of reading over the velocity range of 0.1–1 feet per second (ft/s) and ±5% of reading over the velocity range of 1–250 ft/s.’’ Response: We proposed the term ‘‘measurement sensitivity’’ in proposed 40 CFR 60.106a(a)(6)(i)(B) and (a)(7)(i)(B) to be internally consistent within Refinery NSPS subpart Ja [i.e., consistent with the existing language in § 60.107a(f)(1)(ii)]. However, we agree with the commenters that this term may be unclear. This term is not defined in Refinery NSPS subpart Ja and it is not commonly used in the flow monitoring system’s technical specification sheets. Therefore, to be consistent with the terminology used by instrument vendors and used in Refinery MACT 1 and 2, we are revising these sections to replace the term ‘‘measurement sensitivity’’ with ‘‘accuracy.’’ We are also revising the flow rate accuracy provisions specific for flares to provide an accuracy requirement of ±20-percent over the velocity range of 0.1–1 ft/s and ±5% for velocities exceeding 1 ft/s in 40 CFR 60.107a(f)(1)(ii) and in Table 13 of subpart CC. We are providing this provision specifically for flares because they commonly operate at high turndown ratios. For other flow measurements, we are retaining the 10cubic-foot-per-minute accuracy requirement. We are also clarifying that the ±5-percent accuracy requirement for the SRU alternatives apply to the ‘‘the normal range of flow measured’’ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 consistent with the requirements in Refinery MACT 1 and 2. Comment: One commenter stated that in the proposed revisions to 40 CFR 60.100a, (79 FR 36956), the EPA proposes to remove the phrase ‘‘and delayed coker units’’ from 40 CFR 60.100a(b). However, we state the compliance date for both flares and delayed coker units separately in the same paragraph. The commenter believes the EPA should explain the reason for and implications of the removal of this phrase. Response: The removal of the phrase ‘‘and delayed coking units’’ from the first sentence in 40 CFR 60.100a(b) was an inadvertent error. The only revision that we intended to make in 40 CFR 60.100a was to allow owners or operators subject to subpart J to elect to comply with the requirements in subpart Ja. In the final amendments, we have included the phrase ‘‘and delayed coking units’’ in the first sentence in 40 CFR 60.100a(b). 4. What is the rationale for our final approach and final decisions for the amendments to Refinery NSPS Subparts J and Ja? We are finalizing amendments for Refinery NSPS subparts J and Ja as proposed with minor revisions. In response to comments, we are revising the ‘‘measurement sensitivity’’ requirements to be an ‘‘accuracy’’ requirement. This change will make the requirements more clear and consistent between the flow meter requirements in the NSPS and the MACT standards since the same flow meter will be subject to each of these requirements. We are also providing a dual accuracy requirement for flare flow meters. This accuracy requirement is necessary because flares, which can have large diameters to accommodate high flows, are commonly operated at low flow rates. Together, this makes it technically infeasible for many flares to meet the lower flow 10 cfm accuracy requirement. Therefore, we are providing specific accuracy requirements for flares of ±20-percent over the velocity range of 0.1–1 ft/s and ±5-percent for velocities exceeding 1 ft/ s, consistent with recent consent decrees and equipment vendor specifications. Finally, we are revising the introductory phrase in the first sentence PO 00000 Frm 00049 Fmt 4701 Sfmt 4700 75225 in 40 CFR 60.101a(b) to read ‘‘Except for flares and delayed coking units . . .’’ to correct an inadvertent error. We intended to revise this sentence only to include the proposed provision to allow sources subject to Refinery NSPS subpart J to comply with Refinery NSPS subpart Ja. The redline text posted on our Web site showed no revisions to this introductory phrase, but the amendatory text did not include the words ‘‘and delayed coking units’’ in this phrase. This was an inadvertent error, which we are correcting in the final rule. V. Summary of Cost, Environmental and Economic Impacts and Additional Analyses Conducted A. What are the affected facilities, the air quality impacts and cost impacts? The sources affected by significant amendments to the petroleum refinery standards include flares, storage vessels, pressure relief devices, fugitive emissions and DCU. The amendments for other sources subject to one or more of the petroleum refinery standards are expected to have minimal air quality and cost impacts. The total capital investment cost of the final amendments and standards is estimated at $283 million, $112 million from the final amendments for storage vessels, DCU and fenceline monitoring and $171 million from standards to ensure compliance. We estimate annualized costs of the final amendments for storage vessels, DCU and fenceline monitoring to be approximately $13.0 million, which includes an estimated $11.0 million for recovery of lost product and the annualized cost of capital. We also estimated annualized costs of the final standards to ensure compliance to be approximately $50.2 million. The final amendments for storage vessels, DCU and fenceline monitoring would achieve a nationwide HAP emission reduction of 1,323 tpy, with a concurrent reduction in VOC emissions of 16,660 tpy and a reduction in methane emissions of 8,700 metric tonnes per year. Table 2 of this preamble summarizes the cost and emission reduction impacts of the final amendments, and Table 3 of this preamble summarizes the costs of the final standards to ensure compliance. E:\FR\FM\01DER2.SGM 01DER2 75226 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 2—NATIONWIDE IMPACTS OF FINAL AMENDMENTS (2010$) Affected source Total capital investment (million $) Total annualized cost without credit (million $/yr) Product recovery credit (million $/yr) Total annualized costs (million $/yr) Methane emission reductions (metric tpy) VOC emission reductions (tpy) Cost effectiveness ($/ton VOC) HAP emission reductions (tpy) Cost effectiveness ($/ton HAP) Storage Vessels ........................ Delayed Coking Units ............... Fugitive Emissions (Fenceline Monitoring) ............................. 18.5 81 3.13 14.5 (8.16) (2.80) (5.03) 11.7 .................... 8,700 14,600 2,060 (345) 5,680 910 413 (5,530) 28,330 12.5 6.36 .................... 6.36 .................... .................... .................... .................... .................... Total ................................... 112 24.0 (11.0) 13.0 8,700 16,660 780 1,323 9,830 TABLE 3—NATIONWIDE COSTS OF FINAL AMENDMENTS TO ENSURE COMPLIANCE (2010$) Total annualized cost without credit (million $/yr) Product recovery credit (million $/yr) Total annualized costs (million $/yr) Affected Source Total capital investment (million $) Relief Device Monitoring .................................................................................. Flare Monitoring ............................................................................................... FCCU Testing .................................................................................................. 11.1 160 ........................ 3.3 46.5 0.4 ........................ ........................ ........................ 3.3 46.5 0.4 Total .......................................................................................................... 171 50.2 ........................ 50.2 The impacts shown in Table 2 do not include costs, product recovery credits, or emissions reductions associated with any root cause analysis or corrective action taken in response to the final amendments for fenceline monitoring. The impacts shown in Table 3 do not include (i) the costs or emissions reductions associated with any root cause analysis and corrective action taken in response to the final source performance testing at the FCCUs, or (ii) emissions reductions associated with corrective action taken in response to pressure relief device or (iii) emissions reductions associated with the flare operating and monitoring provisions. The operational and monitoring requirements for flares at refineries have the potential to reduce excess emissions from flares by up to approximately 3,900 tpy of HAP and 33,000 tpy of VOC. The operational and monitoring requirements for flares also have the potential to reduce methane emissions by 25,800 metric tonnes per year while increasing emissions of carbon dioxide (CO2) and nitrous oxide by 267,000 metric tonnes per year and 2 metric tonnes per year, respectively, yielding a net reduction in GHG emissions of 377,000 metric tonnes per year of CO2 equivalents (CO2e). tkelley on DSK3SPTVN1PROD with RULES2 B. What are the economic impacts? We performed a national economic impact analysis for petroleum product producers. All petroleum product refiners will incur annual compliance costs of less than 1-percent of their sales. For all firms, the minimum costto-sales ratio is <0.01-percent; the VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 maximum cost-to-sales ratio is 0.87percent; and the mean cost-to-sales ratio is 0.03-percent. Therefore, the overall economic impact of this proposed rule should be minimal for the refining industry and its consumers. In addition, the EPA performed a screening analysis for impacts on small businesses by comparing estimated annualized engineering compliance costs at the firm-level to firm sales. The screening analysis found that the ratio of compliance cost to firm revenue falls below 1-percent for the 28 small companies likely to be affected by the proposal. For small firms, the minimum cost-to-sales ratio is <0.01-percent; the maximum cost-to-sales ratio is 0.62percent; and the mean cost-to-sales ratio is 0.07-percent. More information and details of this analysis is provided in the technical document ‘‘Economic Impact Analysis for Petroleum Refineries Proposed Amendments to the National Emissions Standards for Hazardous Air Pollutants’’, which is available in the docket for this rule (Docket ID No. EPA– HQ–OAR–2010–0682). C. What are the benefits? The final rule is anticipated to result in a reduction of 1,323 tpy of HAP (based on allowable emissions under the MACT standards) and 16,660 tpy of VOC, not including potential emission reductions that may occur as a result of the operating and monitoring requirements for flares and fugitive emission sources via fenceline monitoring. These avoided emissions will result in improvements in air PO 00000 Frm 00050 Fmt 4701 Sfmt 4700 quality and reduced negative health effects associated with exposure to air pollution of these emissions; however, we have not quantified or monetized the benefits of reducing these emissions for this rulemaking. D. Impacts of This Rulemaking on Environmental Justice Populations To examine the potential impacts on vulnerable populations (minority, lowincome and indigenous communities) that might be associated with the Petroleum Refinery source categories addressed in this final rule, we evaluated the percentages of various social, demographic and economic groups in the at-risk populations living near the facilities where these sources are located and compared them to national averages. Our analysis of the demographics of the population with estimated risks greater than 1-in-1 million indicates potential disparities in risks between demographic groups including the African American, Other and Multiracial, Hispanic, Below the Poverty Level, and Over 25 without a High School Diploma when compared to the nationwide percentages of those groups. These groups will benefit the most from the emission reductions achieved by this final rulemaking, which is projected to result in 1 million fewer people exposed to risks greater than 1-in-1 million. Additionally, these communities will benefit from this rulemaking, as this rulemaking for the first time ever requires fenceline monitoring, and reporting of fenceline data. The agency during the pre-proposal period and E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations during the comment period received feedback from communities on the importance of having fenceline monitoring in their communities and the importance of communities having access to this data. The EPA believes that vulnerable communities will benefit from this data and the requirements that EPA has put in place in this rulemaking to manage fugitive emissions. E. Impacts of This Rulemaking on Children’s Health Under Executive Order 13045 the EPA must evaluate the effects of the planned regulation on children’s health and safety. This action’s health and risk assessments are contained in section IV.A of this preamble. We believe we have adequately estimated risk for children, and we do not believe that the environmental health risks addressed by this action present a disproportionate risk to children. When the EPA derives exposure reference concentrations and unit risk estimates (URE) for HAP, it also considers the most sensitive populations identified (i.e., children) in the available literature, and importantly, these are the values used in our risk assessments. With regard to children’s potentially greater susceptibility to noncancer toxicants, the assessments rely on the EPA (or comparable) hazard identification and dose-response values which have been developed to be protective for all subgroups of the general population, including children. With respect to cancer, the EPA uses the age-dependent adjustment factor approach, and applies these factors to carcinogenic pollutants that are known to act via mutagenic mode of action. Further details are provided in the ‘‘Final Residual Risk Assessment for the Petroleum Refining Source Sector’’, Docket ID No. EPA–HQ–OAR–2010– 0682. tkelley on DSK3SPTVN1PROD with RULES2 VI. Statutory and Executive Order Reviews A. Executive Orders 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review This action is an economically significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, ‘‘Economic Impact Analysis: Petroleum Refineries—Final Amendments to the National Emissions VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Standards for Hazardous Air Pollutants and New Source Performance Standards’’ is available in Docket ID Number EPA–HQ–OAR–2010–0682. B. Paperwork Reduction Act (PRA) The information collection requirements in this 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 se. The information collection requirements are not enforceable until OMB approves them. Adequate recordkeeping and reporting are necessary to ensure compliance with these standards as required by the CAA. The ICR information collected from recordkeeping and reporting requirements is also used for prioritizing inspections and is of sufficient quality to be used as evidence in court. The ICR document prepared by the EPA for the amendments to the Petroleum Refinery MACT standards for 40 CFR part 63, subpart CC has been assigned the EPA ICR number 1692.08. Burden changes associated with these amendments would result from new monitoring, recordkeeping and reporting requirements. The estimated annual increase in recordkeeping and reporting burden hours is 99,722 hours; the frequency of response is quarterly and semiannual for reports for all respondents that must comply with the rule’s reporting requirements; and the estimated average number of likely respondents per year is 95 (this is the average in the second year). The cost burden to respondents resulting from the collection of information includes the total capital cost annualized over the equipment’s expected useful life (about $18 million, which includes monitoring equipment for fenceline monitoring, pressure relief devices, and flares), a total operation and maintenance component (about $21 million per year for fenceline and flare monitoring), and a labor cost component (about $8.3 million per year, the cost of the additional 99,722 labor hours). Burden is defined at 5 CFR 1320.3(b). The ICR document prepared by the EPA for the amendments to the Petroleum Refinery MACT standards for 40 CFR part 63, subpart UUU has been assigned the EPA ICR number 1844.06. Burden changes associated with these amendments would result from new testing, recordkeeping and reporting requirements being finalized with this action. The estimated average burden per response is 25 hours; the frequency of response ranges from annually up to every 5 years for respondents that have PO 00000 Frm 00051 Fmt 4701 Sfmt 4700 75227 FCCU, and the estimated average number of likely respondents per year is 67. The cost burden to respondents resulting from the collection of information includes the performance testing costs (approximately $778,000 per year over the first 3 years for the initial PM and one-time HCN performance tests and $235,000 per year starting in the fourth year), and a labor cost component (approximately $410,000 per year for 4,940 additional labor hours). 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 EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in this final rule. C. Regulatory Flexibility Act (RFA) I certify that this action will not have a significant economic impact on a substantial number of small entities (SISNOSE) under the RFA. The small entities subject to the requirements of this action are small businesses, small organizations and small governmental jurisdictions. For purposes of assessing the impacts of this rule on small entities, a small entity is defined as: (1) A small business in the petroleum refining industry having 1,500 or fewer employees (Small Business Administration (SBA), 2011); (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. Details of this analysis are presented in the economic impact analysis which can be found in the docket for this rule (Docket ID No. EPA–HQ–OAR–2010–0682). D. Unfunded Mandates Reform Act (UMRA) This action does not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531–1538, and does not significantly or uniquely affect small governments. As discussed earlier in this preamble, these amendments result in nationwide costs of $63.2 million per year for the private sector. Additionally, the rule contains no requirements that apply to small E:\FR\FM\01DER2.SGM 01DER2 75228 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations governments and does not impose obligations upon them. 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. F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments This action does not have tribal implications, as specified in Executive Order 13175. The final amendments impose no requirements on tribal governments. Thus, Executive Order 13175 does not apply to this action. Consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA consulted with tribal officials during the development of the proposed rule and specifically solicited comment on the proposed amendments from tribal officials. G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks This action is not subject to Executive Order 13045 because the EPA does not believe the environmental health or safety risks addressed by this action present a disproportionate risk to children. This action’s health and risk assessments are contained in section IV.A of this preamble. tkelley on DSK3SPTVN1PROD with RULES2 H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution or Use This action is not a ‘‘significant energy action’’ because it is not likely to have a significant adverse effect on the supply, distribution or use of energy. The overall economic impact of this final rule should be minimal for the refining industry and its consumers. I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR Part 51 This rulemaking involves technical standards. Therefore, the EPA conducted searches for the Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards through the Enhanced National Standards Systems Network (NSSN) Database managed by the American National Standards Institute (ANSI). We also contacted voluntary consensus standards (VCS) organizations and accessed and VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 searched their databases. We conducted searches for EPA Methods 18, 22, 320, 325A, and 325B of 40 CFR parts 60 and 63, appendix A. No applicable VCS were identified for EPA Method 22. The following voluntary consensus standards were identified as acceptable alternatives to the EPA test methods for the purpose of this rule. The voluntary consensus standard ISO 16017–2:2003(E) ‘‘Air quality— Sampling and analysis of volatile organic compounds in ambient air, indoor air and workplace air by sorbent tube/thermal desorption/capillary gas chromatography. Part 2: Diffusive sampling’’ is an acceptable alternative to Method 325A, Sections 1.2, 6.1 and 6.5 and Method 325B Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 12.2.4, 13.0, A.1.1, and A.2. This voluntary consensus standard gives general guidance for the sampling and analysis of volatile organic compounds in air. It is applicable to indoor, ambient and workplace air. This standard is available at International Organization for Standardization, ISO Central Secretariat, Chemin de Blandonnet 8, CP 401, 1214 Vernier, Geneva, Switzerland. See https://www.iso.org. The voluntary consensus standard BS EN 14662–4:2005 ‘‘Ambient Air Quality: Standard Method for the Measurement of Benzene Concentrations—Part 4: Diffusive Sampling Followed By Thermal Desorption and Gas Chromatography’’ is an acceptable alternative to Method 325A, Section 1.2 and Method 325B, Sections 1.3, 7.1.3, 7.1.4, 12.2.4, 13.0, A.1.1, and A.2. This voluntary consensus standard gives general guidance for the sampling and analysis of benzene in air by diffusive sampling, thermal desorption and capillary gas chromatography. This standard is available the European Committee for Standardization, Avenue Marnix 17—B–1000 Brussels. See https://www.cen.eu. The voluntary consensus standard ASTM D6420–99 (2010) ‘‘Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/Mass Spectrometry’’ is an acceptable alternative to EPA Method 18. This voluntary consensus standard employs a direct interface gas chromatography/mass spectrometer (GCMS) to identify and quantify a list of 36 volatile organic compounds (the compounds are listed in the method). The voluntary consensus standard ASTM D6196–03 (Reapproved 2009) ‘‘Standard Practice for Selection of Sorbents, Sampling, and Thermal Desorption Analysis Procedures for Volatile Organic Compounds in Air’’ is an acceptable alternative to Method 325A, Sections 1.2 and 6.1, and Method PO 00000 Frm 00052 Fmt 4701 Sfmt 4700 325B, Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 13.0, A.1.1, and A.2. This voluntary consensus standard is intended to assist in the selection of sorbents and procedures for the sampling and analysis of ambient, indoor, and workplace atmospheres for a variety of common volatile organic compounds. The voluntary consensus standards ASTM D1945–03 and later revision ASTM D1945–14 ‘‘Standard Test Method for Analysis of Natural Gas by Gas Chromatography’’ are acceptable for natural gas analysis. This voluntary consensus standard covers the determination of the chemical composition of natural gases and similar gaseous mixtures. This test method may be abbreviated for the analysis of lean natural gases containing negligible amounts of hexanes and higher hydrocarbons, or for the determination of one or more components, as required. The voluntary consensus standard ASTM UOP539–12 ‘‘Refinery Gas Analysis by GC’’ is acceptable for refinery gas analysis. This voluntary consensus standard is for determining the composition of refinery gas streams or vaporized liquefied petroleum gas using a preconfigured, commercially available gas chromatograph. The voluntary consensus standard ASTM D6348–03 (Reapproved 2010) including Annexes A1 through A8, ‘‘Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy’’ is an acceptable alternative to EPA Method 320. This voluntary consensus standard is a field test method that employs an extractive sampling system to direct stationary source effluent to an FTIR spectrometer for the identification and quantification of gaseous compounds. This field test method provides near real time analysis of extracted gas samples from stationary sources. The voluntary consensus standard ASTM D6348–12e1 ‘‘Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy’’ is an acceptable alternative to EPA Method 320 with the following two caveats: (1) The test plan preparation and implementation in the Annexes to ASTM D 6348–03 (Reapproved 2010), Sections A1 through A8 are mandatory; and (2) In ASTM D6348–03 (Reapproved 2010) Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (Equation A5.5). In order for the test data to be acceptable for a compound, %R must be 70% ≥ R ≤ 130%. If the %R value does not meet this criterion for a target compound, the test data is not acceptable for that compound and the test must be repeated E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations for that analyte (i.e., the sampling and/ or analytical procedure should be adjusted before a retest). The %R value for each compound must be reported in the test report, and all field measurements must be corrected with the calculated %R value for that compound by using the following equation: Reported Result = (Measured Concentration in the Stack × 100)/ % R. This voluntary consensus standard is a field test method that employs an extractive sampling system to direct stationary source effluent to an FTIR spectrometer for the identification and quantification of gaseous compounds. This field test method provides near real time analysis of extracted gas samples from stationary sources. The EPA solicited comments on VCS and invited the public to identify potentially-applicable VCS; however, we did not receive comments regarding this aspect of 40 CFR part 60, subparts J and Ja, and part 63, subparts CC, UUU, and Y. Under 40 CFR 63.7(f) and 63.8(f), a source may apply to the EPA for permission to use alternative test methods or alternative monitoring requirements in place of any required testing methods, performance specifications, or procedures in this final rule. tkelley on DSK3SPTVN1PROD with RULES2 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 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 U.S. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin or income with respect to the development, implementation and enforcement of environmental laws, regulations and policies. The EPA has this goal for all communities and persons by working to ensure that everyone enjoys the same degree of protection from environmental and health hazards and equal access to the decision-making process to have a VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 healthy environment in which to live, learn and work. The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations. As discussed in section V.D. of this preamble, the EPA conducted an analysis of the characteristics of the population with greater than 1-in-1 million risk living within 50 km of the 142 refineries affected by this rulemaking and determined that there are more AfricanAmericans, Other and multiracial groups, Hispanics, low-income individuals, individuals with less than a high school diploma compared to national averages. Therefore, these populations are expected to experience the benefits of the risk reductions associated with this rule. The results of this evaluation are contained in two technical reports, ‘‘Risk and Technology Review—Analysis of Socio-Economic Factors for Populations Living Near Petroleum Refineries’’, available in the docket for this action (See Docket ID Nos. EPA–HQ–OAR–2010–0682–0226 and -0227). Additionally, a discussion of the final risk analysis is included in Sections IV.A and V.D of this preamble. The EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because it maintains or increases the level of environmental protection for all affected populations without having any disproportionately high and adverse human health or environmental effects on any population, including any minority, low-income or indigenous populations. Further, the EPA believes that implementation of this rule will provide an ample margin of safety to protect public health of all demographic groups. K. Congressional Review Act (CRA) This action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is a ‘‘major rule’’ as defined by 5 U.S.C. 804(2). List of Subjects 40 CFR Part 60 Environmental protection, Administrative practice and procedures, Air pollution control, Hazardous substances, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements. PO 00000 Frm 00053 Fmt 4701 Sfmt 4700 75229 40 CFR Part 63 Environmental protection, Administrative practice and procedures, Air pollution control, Hazardous substances, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements. Dated: September 29, 2015. Gina McCarthy, Administrator. For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is amended as follows: PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 1. The authority citation for part 60 continues to read as follows: ■ Authority: 42 U.S.C. 7401 et seq. Subpart J—Standards of Performance for Petroleum Refineries 2. Section 60.105 is amended by revising paragraphs (b)(1)(iv) and (b)(3)(iii) to read as follows: ■ § 60.105 Monitoring of emissions and operations. * * * * * (b) * * * (1) * * * (iv) The supporting test results from sampling the requested fuel gas stream/ system demonstrating that the sulfur content is less than 5 ppmv. Sampling data must include, at minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas streams/systems; for infrequently operated fuel gas streams/systems, seven grab samples must be collected unless other additional information would support reduced sampling. The owner or operator shall use detector tubes (‘‘length-of-stain tube’’ type measurement) following the ‘‘Gas Processors Association Standard 2377– 86 (incorporated by reference—see § 60.17), using tubes with a maximum span between 10 and 40 ppmv inclusive when 1≤N≤10, where N = number of pump strokes, to test the applicant fuel gas stream for H2S; and * * * * * (3) * * * (iii) If the operation change results in a sulfur content that is outside the range of concentrations included in the original application and the owner or operator chooses not to submit new information to support an exemption, the owner or operator must begin H2S monitoring using daily stain sampling to demonstrate compliance using length-of E:\FR\FM\01DER2.SGM 01DER2 75230 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Subpart Ja—Standards of Performance for Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007 3. Section 60.100a is amended by revising the first sentence of paragraph (b) to read as follows: ■ * * * * * (b) Except for flares and delayed coking units, the provisions of this subpart apply only to affected facilities under paragraph (a) of this section which either commence construction, modification or reconstruction after May 14, 2007, or elect to comply with the provisions of this subpart in lieu of complying with the provisions in subpart J of this part. * * * * * * * * ■ 4. Section 60.101a is amended by: ■ a. Revising the definition of ‘‘Corrective action’’; and ■ b. Adding, in alphabetical order, a definition for ‘‘Sour water’’. The revision and addition read as follows: tkelley on DSK3SPTVN1PROD with RULES2 Definitions. * * * * * Where: ELS = Emission limit for large sulfur recovery plant, ppmv (as SO2, dry basis at zero percent excess air); k1 = Constant factor for emission limit conversion: k1 = 1 for converting to the SO2 limit for a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration and k1 = 1.2 for converting to the reduced sulfur compounds limit for a sulfur recovery plant with a reduction control system not followed by incineration; and %O2 = O2 concentration of the air/oxygen mixture supplied to the Claus burner, percent by volume (dry basis). If only VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 § 60.102a Emissions limitations. * § 60.100a Applicability, designation of affected facility, and reconstruction. § 60.101a Corrective action means the design, operation and maintenance changes that one takes consistent with good engineering practice to reduce or eliminate the likelihood of the recurrence of the primary cause and any other contributing cause(s) of an event identified by a root cause analysis as having resulted in a discharge of gases from an affected facility in excess of specified thresholds. * * * * * Sour water means water that contains sulfur compounds (usually H2S) at concentrations of 10 parts per million by weight or more. * * * * * ■ 5. Section 60.102a is amended by revising paragraphs (b)(1)(i) and (iii), (f), and (g)(1) introductory text to read as follows: * * * * (b) * * * (1) * * * (i) 1.0 gram per kilogram (g/kg) (1 pound (lb) per 1,000 lb) coke burn-off or, if a PM continuous emission monitoring system (CEMS) is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each modified or reconstructed FCCU. * * * * * (iii) 1.0 g/kg (1 lb/1,000 lb) coke burnoff or, if a PM CEMS is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air for each affected FCU. * * * * * (f) Except as provided in paragraph (f)(3) of this section, each owner or operator of an affected sulfur recovery plant shall comply with the applicable emission limits in paragraph (f)(1) or (2) of this section. ambient air is used for the Claus burner or if the owner or operator elects not to monitor O2 concentration of the air/ oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, use 20.9% for %O2. (ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing reduced sulfur compounds in excess of the emission limit calculated using Equation 1 of this section. For Claus units that use only PO 00000 Frm 00054 Fmt 4701 Sfmt 4700 (1) For a sulfur recovery plant with a design production capacity greater than 20 long tons per day (LTD), the owner or operator shall comply with the applicable emission limit in paragraph (f)(1)(i) or (ii) of this section. If the sulfur recovery plant consists of multiple process trains or release points, the owner or operator shall comply with the applicable emission limit for each process train or release point individually or comply with the applicable emission limit in paragraph (f)(1)(i) or (ii) as a flow rate weighted average for a group of release points from the sulfur recovery plant provided that flow is monitored as specified in § 60.106a(a)(7); if flow is not monitored as specified in § 60.106a(a)(7), the owner or operator shall comply with the applicable emission limit in paragraph (f)(1)(i) or (ii) for each process train or release point individually. For a sulfur recovery plant with a design production capacity greater than 20 long LTD and a reduction control system not followed by incineration, the owner or operator shall also comply with the H2S emission limit in paragraph (f)(1)(iii) of this section for each individual release point. (i) For a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere (SO2) in excess of the emission limit calculated using Equation 1 of this section. For Claus units that use only ambient air in the Claus burner or that elect not to monitor O2 concentration of the air/ oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, this SO2 emissions limit is 250 ppmv (dry basis) at zero percent excess air. ambient air in the Claus burner or for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit is 300 ppmv calculated as ppmv SO2 (dry basis) at 0-percent excess air. (iii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing hydrogen sulfide (H2S) in excess of 10 ppmv calculated as ppmv SO2 (dry basis) at zero percent excess air. E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.000</GPH> stain tubes with a maximum span between 200 and 400 ppmv inclusive when 1≤N≤5, where N = number of pump strokes. The owner or operator must begin monitoring according to the requirements in paragraph (a)(1) or (2) of this section as soon as practicable but in no case later than 180 days after the operation change. During daily stain tube sampling, a daily sample exceeding 162 ppmv is an exceedance of the 3hour H2S concentration limit. * * * * * Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75231 control system followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing SO2 in excess of the emission limit calculated using Equation 2 of this section. For Claus units that use only ambient air in the Claus burner or that elect not to monitor O2 concentration of the air/oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, this SO2 emission limit is 2,500 ppmv (dry basis) at zero percent excess air. the sulfur pit, which shall not exceed 240 hours per year. The owner or operator must document the time periods during which the sulfur pit vents were not controlled and measures taken to minimize emissions during these periods. Examples of these measures include not adding fresh sulfur or shutting off vent fans. (g) * * * (1) Except as provided in (g)(1)(iii) of this section, for each fuel gas combustion device, the owner or operator shall comply with either the emission limit in paragraph (g)(1)(i) of this section or the fuel gas concentration limit in paragraph (g)(1)(ii) of this section. For CO boilers or furnaces that are part of a fluid catalytic cracking unit or fluid coking unit affected facility, the owner or operator shall comply with the fuel gas concentration limit in paragraph (g)(1)(ii) for all fuel gas streams combusted in these units. * * * * * ■ 6. Section 60.104a is amended by: ■ a. Revising the first sentence of paragraph (a) and paragraphs (b), (f) introductory text, and (h) introductory text; ■ b. Adding paragraph (h)(6); and ■ c. Removing and reserving paragraphs (j)(1) through (3). The revisions and additions read as follows: requirement in § 60.103a(h) according to the requirements of § 60.8. * * * (b) The owner or operator of a FCCU or FCU that elects to monitor control device operating parameters according to the requirements in § 60.105a(b), to use bag leak detectors according to the requirements in § 60.105a(c), or to use COMS according to the requirements in § 60.105a(e) shall conduct a PM performance test at least annually (i.e., once per calendar year, with an interval of at least 8 months but no more than 16 months between annual tests) and furnish the Administrator a written report of the results of each test. * * * * * (f) The owner or operator of an FCCU or FCU that uses cyclones to comply with the PM per coke burn-off emissions limit in § 60.102a(b)(1) shall establish a site-specific opacity operating limit according to the procedures in paragraphs (f)(1) through (3) of this section. * * * * * (h) The owner or operator shall determine compliance with the SO2 emissions limits for sulfur recovery plants in § 60.102a(f)(1)(i) and (f)(2)(i) and the reduced sulfur compounds and H2S emissions limits for sulfur recovery plants in § 60.102a(f)(1)(ii), (f)(1)(iii), (f)(2)(ii), and (f)(2)(iii) using the following methods and procedures: * * * * * (6) If oxygen or oxygen-enriched air is used in the Claus burner and either Equation 1 or 2 of this subpart is used to determine the applicable emissions limit, determine the average O2 concentration of the air/oxygen mixture supplied to the Claus burner, in percent by volume (dry basis), for the performance test using all hourly average O2 concentrations determined (ii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing reduced sulfur compounds in excess of the emission limit calculated using Equation 2 of this section. For Claus units that use only ambient air in the Claus burner or for non-Claus sulfur recovery plants, this reduced sulfur compounds emission limit is 3,000 ppmv calculated as ppmv SO2 (dry basis) at zero percent excess air. (iii) For a sulfur recovery plant with a reduction control system not followed by incineration, the owner or operator shall not discharge or cause the discharge of any gases into the atmosphere containing H2S in excess of 100 ppmv calculated as ppmv SO2 (dry basis) at zero percent excess air. (3) The emission limits in paragraphs (f)(1) and (2) of this section shall not apply during periods of maintenance of VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 § 60.104a Performance tests. (a) The owner or operator shall conduct a performance test for each FCCU, FCU, sulfur recovery plant and fuel gas combustion device to demonstrate initial compliance with each applicable emissions limit in § 60.102a and conduct a performance test for each flare to demonstrate initial compliance with the H2S concentration PO 00000 Frm 00055 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.001</GPH> § 60.106a(a)(7); if flow is not monitored as specified in § 60.106a(a)(7), the owner or operator shall comply with the applicable emission limit in paragraph (f)(2)(i) or (ii) for each process train or release point individually. For a sulfur recovery plant with a design production capacity of 20 LTD or less and a reduction control system not followed by incineration, the owner or operator shall also comply with the H2S emission limit in paragraph (f)(2)(iii) of this section for each individual release point. (i) For a sulfur recovery plant with an oxidation control system or a reduction Where: ESS = Emission limit for small sulfur recovery plant, ppmv (as SO2, dry basis at zero percent excess air); k1 = Constant factor for emission limit conversion: k1 = 1 for converting to the SO2 limit for a sulfur recovery plant with an oxidation control system or a reduction control system followed by incineration and k1 = 1.2 for converting to the reduced sulfur compounds limit for a sulfur recovery plant with a reduction control system not followed by incineration; and %O2 = O2 concentration of the air/oxygen mixture supplied to the Claus burner, percent by volume (dry basis). If only ambient air is used in the Claus burner or if the owner or operator elects not to monitor O2 concentration of the air/ oxygen mixture used in the Claus burner or for non-Claus sulfur recovery plants, use 20.9% for %O2. tkelley on DSK3SPTVN1PROD with RULES2 (2) For a sulfur recovery plant with a design production capacity of 20 LTD or less, the owner or operator shall comply with the applicable emission limit in paragraph (f)(2)(i) or (ii) of this section. If the sulfur recovery plant consists of multiple process trains or release points, the owner or operator may comply with the applicable emission limit for each process train or release point individually or comply with the applicable emission limit in paragraph (f)(2)(i) or (ii) as a flow rate weighted average for a group of release points from the sulfur recovery plant provided that flow is monitored as specified in 75232 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations during the test runs using the procedures in § 60.106a(a)(5) or (6). * * * * * ■ 7. Section 60.105a is amended by: ■ a. Revising paragraphs (b)(1)(i), (b)(1)(ii)(A), (b)(2), (h)(1), (h)(3)(i), and (i)(1); ■ b. Redesignating paragraphs (i)(2) through (6) as (i)(3) through (7); ■ c. Adding paragraph (i)(2); and ■ d. Revising newly redesignated paragraph (i)(7). The revisions and additions read as follows: § 60.105a Monitoring of emissions and operations for fluid catalytic cracking units (FCCU) and fluid coking units (FCU). tkelley on DSK3SPTVN1PROD with RULES2 * * * * * (b) * * * (1) * * * (i) For units controlled using an electrostatic precipitator, the owner or operator shall use CPMS to measure and record the hourly average total power input and secondary current to the entire system. (ii) * * * (A) As an alternative to pressure drop, the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles must conduct a daily check of the air or water pressure to the spray nozzles and record the results of each check. Faulty (e.g., leaking or plugged) air or water lines must be repaired within 12 hours of identification of an abnormal pressure reading. * * * * * (2) For use in determining the coke burn-off rate for an FCCU or FCU, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring the concentrations of CO2, O2 (dry basis), and if needed, CO in the exhaust gases prior to any control or energy recovery system that burns auxiliary fuels. A CO monitor is not required for determining coke burn-off rate when no auxiliary fuel is burned and a continuous CO monitor is not required in accordance with paragraph (h)(3) of this section. (i) The owner or operator shall install, operate, and maintain each CO2 and O2 monitor according to Performance Specification 3 of appendix B to this part. (ii) The owner or operator shall conduct performance evaluations of each CO2 and O2 monitor according to the requirements in § 60.13(c) and Performance Specification 3 of appendix B to this part. The owner or operator shall use Method 3 of appendix A–3 to this part for conducting the relative accuracy evaluations. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (iii) If a CO monitor is required, the owner or operator shall install, operate, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to this part. If this CO monitor also serves to demonstrate compliance with the CO emissions limit in § 60.102a(b)(4), the span value for this instrument is 1,000 ppm; otherwise, the span value for this instrument should be set at approximately 2 times the typical CO concentration expected in the FCCU of FCU flue gas prior to any emission control or energy recovery system that burns auxiliary fuels. (iv) If a CO monitor is required, the owner or operator shall conduct performance evaluations of each CO monitor according to the requirements in § 60.13(c) and Performance Specification 4 of appendix B to this part. The owner or operator shall use Method 10, 10A, or 10B of appendix A– 3 to this part for conducting the relative accuracy evaluations. (v) The owner or operator shall comply with the quality assurance requirements of procedure 1 of appendix F to this part, including quarterly accuracy determinations for CO2 and CO monitors, annual accuracy determinations for O2 monitors, and daily calibration drift tests. * * * * * (h) * * * (1) The owner or operator shall install, operate, and maintain each CO monitor according to Performance Specification 4 or 4A of appendix B to this part. The span value for this instrument is 1,000 ppmv CO. * * * * * (3) * * * (i) The demonstration shall consist of continuously monitoring CO emissions for 30 days using an instrument that meets the requirements of Performance Specification 4 or 4A of appendix B to this part. The span value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative accuracy limit shall be 10 percent of the average CO emissions or 5 ppmv CO, whichever is greater. For instruments that are identical to Method 10 of appendix A–4 to this part and employ the sample conditioning system of Method 10A of appendix A–4 to this part, the alternative relative accuracy test procedure in section 10.1 of Performance Specification 2 of appendix B to this part may be used in place of the relative accuracy test. * * * * * (i) * * * (1) If a CPMS is used according to paragraph (b)(1) of this section, all 3hour periods during which the average PM control device operating PO 00000 Frm 00056 Fmt 4701 Sfmt 4700 characteristics, as measured by the continuous monitoring systems under paragraph (b)(1), fall below the levels established during the performance test. If the alternative to pressure drop CPMS is used for the owner or operator of a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, each day in which abnormal pressure readings are not corrected within 12 hours of identification. (2) If a bag leak detection system is used according to paragraph (c) of this section, each day in which the cause of an alarm is not alleviated within the time period specified in paragraph (c)(3) of this section. * * * * * (7) All 1-hour periods during which the average CO concentration as measured by the CO continuous monitoring system under paragraph (h) of this section exceeds 500 ppmv or, if applicable, all 1-hour periods during which the average temperature and O2 concentration as measured by the continuous monitoring systems under paragraph (h)(4) of this section fall below the operating limits established during the performance test. ■ 8. Section 60.106a is amended by: ■ a. Revising paragraph (a)(1)(i); ■ b. Adding paragraphs (a)(1)(iv) through (vii); ■ c. Revising paragraphs (a)(2) introductory text, (a)(2)(i) and (ii), and the first sentence of paragraph (a)(2)(iii); ■ d. Removing paragraphs (a)(2)(iv) and (v); ■ e. Redesignating paragraphs (a)(2)(vi) through (ix) as (a)(2)(iv) through (vii); ■ f. Revising the first sentence of paragraph (a)(3) introductory text and paragraph (a)(3)(i); ■ g. Adding paragraphs (a)(4) through (7); and ■ h. Revising paragraphs (b)(2) and (3). The revisions and additions read as follows: § 60.106a Monitoring of emissions and operations for sulfur recovery plants. (a) * * * (1) * * * (i) The span value for the SO2 monitor is two times the applicable SO2 emission limit at the highest O2 concentration in the air/oxygen stream used in the Claus burner, if applicable. * * * * * (iv) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to this part. (v) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive. E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations (vi) The owner or operator shall conduct performance evaluations for the O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of appendix B to this part. The owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A–2 to this part. (vii) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to this part for each monitor, including annual accuracy determinations for each O2 monitor, and daily calibration drift determinations. (2) For sulfur recovery plants that are subject to the reduced sulfur compounds emission limit in § 60.102a(f)(1)(ii) or (f)(2)(ii), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of reduced sulfur compounds and O2 emissions into the atmosphere. The reduced sulfur compounds emissions shall be calculated as SO2 (dry basis, zero percent excess air). (i) The span value for the reduced sulfur compounds monitor is two times the applicable reduced sulfur compounds emission limit as SO2 at the highest O2 concentration in the air/ oxygen stream used in the Claus burner, if applicable. (ii) The owner or operator shall install, operate, and maintain each reduced sulfur compounds CEMS according to Performance Specification 5 of appendix B to this part. (iii) The owner or operator shall conduct performance evaluations of each reduced sulfur compounds monitor according to the requirements in § 60.13(c) and Performance Specification 5 of appendix B to this part. * * * * * * * * (3) In place of the reduced sulfur compounds monitor required in paragraph (a)(2) of this section, the owner or operator may install, calibrate, operate, and maintain an instrument using an air or O2 dilution and oxidation system to convert any reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry basis, 0 percent excess air) of the total resultant SO2. * * * (i) The span value for this monitor is two times the applicable reduced sulfur VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 compounds emission limit as SO2 at the highest O2 concentration in the air/ oxygen stream used in the Claus burner, if applicable. * * * * * (4) For sulfur recovery plants that are subject to the H2S emission limit in § 60.102a(f)(1)(iii) or (f)(2)(iii), the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of H2S, and O2 emissions into the atmosphere. The H2S emissions shall be calculated as SO2 (dry basis, zero percent excess air). (i) The span value for this monitor is two times the applicable H2S emission limit. (ii) The owner or operator shall install, operate, and maintain each H2S CEMS according to Performance Specification 7 of appendix B to this part. (iii) The owner or operator shall conduct performance evaluations for each H2S monitor according to the requirements of § 60.13(c) and Performance Specification 7 of appendix B to this part. The owner or operator shall use Methods 11 or 15 of appendix A–5 to this part or Method 16 of appendix A–6 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A–5 to this part. (iv) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to this part. (v) The span value for the O2 monitor must be selected between 10 and 25 percent, inclusive. (vi) The owner or operator shall conduct performance evaluations for the O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of appendix B to this part. The owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A–2 to this part. (vii) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to this part for each monitor, including annual accuracy determinations for each O2 monitor, and daily calibration drift determinations. (5) For sulfur recovery plants that use oxygen or oxygen enriched air in the PO 00000 Frm 00057 Fmt 4701 Sfmt 4700 75233 Claus burner and that elects to monitor O2 concentration of the air/oxygen mixture supplied to the Claus burner, the owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the O2 concentration of the air/oxygen mixture supplied to the Claus burner in order to determine the allowable emissions limit. (i) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to this part. (ii) The span value for the O2 monitor shall be 100 percent. (iii) The owner or operator shall conduct performance evaluations for the O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of appendix B to this part. The owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A–2 to this part. (iv) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to this part for each monitor, including annual accuracy determinations for each O2 monitor, and daily calibration drift determinations. (v) The owner or operator shall use the hourly average O2 concentration from this monitor for use in Equation 1 or 2 of § 60.102a(f), as applicable, for each hour and determine the allowable emission limit as the arithmetic average of 12 contiguous 1-hour averages (i.e., the rolling 12-hour average). (6) As an alternative to the O2 monitor required in paragraph (a)(5) of this section, the owner or operator may install, calibrate, operate, and maintain a CPMS to measure and record the volumetric gas flow rate of ambient air and oxygen-enriched gas supplied to the Claus burner and calculate the hourly average O2 concentration of the air/ oxygen mixture used in the Claus burner as specified in paragraphs (a)(6)(i) through (iv) of this section in order to determine the allowable emissions limit as specified in paragraphs (a)(6)(v) of this section. (i) The owner or operator shall install, calibrate, operate and maintain each flow monitor according to the manufacturer’s procedures and specifications and the following requirements. (A) Locate the monitor in a position that provides a representative measurement of the total gas flow rate. E:\FR\FM\01DER2.SGM 01DER2 75234 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations monitor for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor. (E) Recalibrate the flow monitor in accordance with the manufacturer’s procedures and specifications biennially (every two years) or at the frequency specified by the manufacturer. (ii) The owner or operator shall use 20.9 percent as the oxygen content of the ambient air. (iii) The owner or operator shall use product specifications (e.g., as reported in material safety data sheets) for percent oxygen for purchased oxygen. For oxygen produced onsite, the percent oxygen shall be determined by periodic measurements or process knowledge. (iv) The owner or operator shall calculate the hourly average O2 concentration of the air/oxygen mixture used in the Claus burner using Equation 10 of this section: Where: %O2 = O2 concentration of the air/oxygen mixture used in the Claus burner, percent by volume (dry basis); 20.9 = O2 concentration in air, percent dry basis; Qair = Volumetric flow rate of ambient air used in the Claus burner, dscfm; %O2,oxy = O2 concentration in the enriched oxygen stream, percent dry basis; and Qoxy = Volumetric flow rate of enriched oxygen stream used in the Claus burner, dscfm. reduced sulfur compounds emission limit in § 60.102a(f)(1)(ii) or (f)(2)(ii) as a flow rate weighted average for a group of release points from the sulfur recovery plant rather than for each process train or release point individually shall install, calibrate, operate, and maintain a CPMS to measure and record the volumetric gas flow rate of each release point within the group of release points from the sulfur recovery plant as specified in paragraphs (a)(7)(i) through (iv) of this section. (i) The owner or operator shall install, calibrate, operate and maintain each flow monitor according to the manufacturer’s procedures and specifications and the following requirements. (A) Locate the monitor in a position that provides a representative measurement of the total gas flow rate. (B) Use a flow sensor meeting an accuracy requirement of ±5 percent over the normal range of flow measured or 10 cubic feet per minute, whichever is greater. (C) Use a flow monitor that is maintainable online, is able to continuously correct for temperature, pressure, and moisture content, and is able to record dry flow in standard conditions (as defined in § 60.2) over one-minute averages. (D) At least quarterly, perform a visual inspection of all components of the monitor for physical and operational integrity and all electrical connections for oxidation and galvanic corrosion if the flow monitor is not equipped with a redundant flow sensor. (E) Recalibrate the flow monitor in accordance with the manufacturer’s procedures and specifications biennially (every two years) or at the frequency specified by the manufacturer. (ii) The owner or operator shall correct the flow to 0 percent excess air using Equation 11 of this section: 20.9c = 20.9 percent O2¥0.0 percent O2 (defined O2 correction basis), percent; 20.9 = O2 concentration in air, percent; and %O2 = O2 concentration measured on a dry basis, percent. (iii) The owner or operator shall calculate the flow weighted average SO2 or reduced sulfur compounds concentration for each hour using Equation 12 of this section: (v) The owner or operator shall use the hourly average O2 concentration determined using Equation 8 of § 60.104a(d)(8) for use in Equation 1 or 2 of § 60.102a(f), as applicable, for each hour and determine the allowable emission limit as the arithmetic average of 12 contiguous 1-hour averages (i.e., the rolling 12-hour average). (7) Owners or operators of a sulfur recovery plant that elects to comply with the SO2 emission limit in § 60.102a(f)(1)(i) or (f)(2)(i) or the ER01DE15.003</GPH> VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00058 Fmt 4701 Sfmt 4725 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.002</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Where: Qadj = Volumetric flow rate adjusted to 0 percent excess air, dry standard cubic feet per minute (dscfm); Cmeas = Volumetric flow rate measured by the flow meter corrected to dry standard conditions, dscfm; ER01DE15.004</GPH> (B) Use a flow sensor meeting an accuracy requirement of ±5 percent over the normal range of flow measured or 10 cubic feet per minute, whichever is greater. (C) Use a flow monitor that is maintainable online, is able to continuously correct for temperature, pressure and, for ambient air flow monitor, moisture content, and is able to record dry flow in standard conditions (as defined in § 60.2) over one-minute averages. (D) At least quarterly, perform a visual inspection of all components of the Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 (iv) For sulfur recovery plants that use oxygen or oxygen enriched air in the Claus burner, the owner or operator shall use Equation 10 of this section and the hourly emission limits determined in paragraph (a)(5)(v) or (a)(6)(v) of this section in-place of the pollutant concentration to determine the flow weighted average hourly emission limit for each hour. The allowable emission limit shall be calculated as the arithmetic average of 12 contiguous 1hour averages (i.e., the rolling 12-hour average). (b) * * * (2) All 12-hour periods during which the average concentration of reduced sulfur compounds (as SO2) as measured by the reduced sulfur compounds continuous monitoring system required under paragraph (a)(2) or (3) of this section exceeds the applicable emission limit; or (3) All 12-hour periods during which the average concentration of H2S as measured by the H2S continuous monitoring system required under paragraph (a)(4) of this section exceeds Where: Fd = F factor on dry basis at 0% excess air, dscf/MMBtu. Xi = mole or volume fraction of each component in the fuel gas. MEVi = molar exhaust volume, dry standard cubic feet per mole (dscf/mol). MHCi = molar heat content, Btu per mole (Btu/mol). VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 the applicable emission limit (dry basis, 0 percent excess air). ■ 9. Section 60.107a is amended by revising paragraphs (a)(1)(i) and (ii), (b)(1)(iv), the first sentence of paragraph (b)(3)(iii), (d)(3), (e)(1) introductory text, (e)(1)(ii), (e)(2) introductory text, (e)(2)(ii), (e)(2)(vi)(C), (e)(3), (f)(1)(ii), and (h)(5) to read as follows: § 60.107a Monitoring of emissions and operations for fuel gas combustion devices and flares. (a) * * * (1) * * * (i) The owner or operator shall install, operate, and maintain each SO2 monitor according to Performance Specification 2 of appendix B to this part. The span value for the SO2 monitor is 50 ppmv SO2. (ii) The owner or operator shall conduct performance evaluations for the SO2 monitor according to the requirements of § 60.13(c) and Performance Specification 2 of appendix B to this part. The owner or operator shall use Methods 6, 6A, or 6C of appendix A–4 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A–4 to this part. Samples taken by Method 6 of appendix A–4 to this part shall be taken at a flow rate of approximately 2 liters/min for at least 30 minutes. The relative accuracy limit shall be 20 percent or 4 ppmv, whichever is greater, and the calibration drift limit shall be 5 percent of the established span value. * * * * * (b) * * * (1) * * * (iv) The supporting test results from sampling the requested fuel gas stream/ system demonstrating that the sulfur content is less than 5 ppmv H2S. Sampling data must include, at 1,000,000 = unit conversion, Btu per MMBtu. * * * * * (e) * * * (1) Total reduced sulfur monitoring requirements. The owner or operator shall install, operate, calibrate and maintain an instrument or instruments for continuously monitoring and recording the concentration of total PO 00000 Frm 00059 Fmt 4701 Sfmt 4700 minimum, 2 weeks of daily monitoring (14 grab samples) for frequently operated fuel gas streams/systems; for infrequently operated fuel gas streams/ systems, seven grab samples must be collected unless other additional information would support reduced sampling. The owner or operator shall use detector tubes (‘‘length-of-stain tube’’ type measurement) following the ‘‘Gas Processors Association Standard 2377–86 (incorporated by reference— see § 60.17), using tubes with a maximum span between 10 and 40 ppmv inclusive when 1≤N≤10, where N = number of pump strokes, to test the applicant fuel gas stream for H2S; and * * * * * (3) * * * (iii) If the operation change results in a sulfur content that is outside the range of concentrations included in the original application and the owner or operator chooses not to submit new information to support an exemption, the owner or operator must begin H2S monitoring using daily stain sampling to demonstrate compliance using lengthof-stain tubes with a maximum span between 200 and 400 ppmv inclusive when 1≤N≤5, where N = number of pump strokes. * * * * * * * * (d) * * * (3) As an alternative to the requirements in paragraph (d)(2) of this section, the owner or operator of a gasfired process heater shall install, operate and maintain a gas composition analyzer and determine the average F factor of the fuel gas using the factors in Table 1 of this subpart and Equation 13 of this section. If a single fuel gas system provides fuel gas to several process heaters, the F factor may be determined at a single location in the fuel gas system provided it is representative of the fuel gas fed to the affected process heater(s). reduced sulfur in gas discharged to the flare. * * * * * (ii) The owner or operator shall conduct performance evaluations of each total reduced sulfur monitor according to the requirements in § 60.13(c) and Performance Specification 5 of appendix B to this part. The owner or operator of each total E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.005</GPH> Where: Cave = Flow weighted average concentration of the pollutant, ppmv (dry basis, zero percent excess air). The pollutant is either SO2 (if complying with the SO2 emission limit in § 60.102a(f)(1)(i) or (f)(2)(i)) or reduced sulfur compounds (if complying with the reduced sulfur compounds emission limit in § 60.102a(f)(1)(ii) or (f)(2)(ii)); N = Number of release points within the group of release points from the sulfur recovery plant for which emissions averaging is elected; Cn = Pollutant concentration in the nth release point within the group of release points from the sulfur recovery plant for which emissions averaging is elected, ppmv (dry basis, zero percent excess air); Qadj,n = Volumetric flow rate of the nth release point within the group of release points from the sulfur recovery plant for which emissions averaging is elected, dry standard cubic feet per minute (dscfm, adjusted to 0 percent excess air). 75235 75236 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations reduced sulfur monitor shall use EPA Method 15A of appendix A–5 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981 (incorporated by reference-see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A–5 to this part. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of appendix B to this part (cylinder gas audits) may be used for conducting the relative accuracy evaluations, except that it is not necessary to include as much of the sampling probe or sampling line as practical. * * * * * (2) H2S monitoring requirements. The owner or operator shall install, operate, calibrate, and maintain an instrument or instruments for continuously monitoring and recording the concentration of H2S in gas discharged to the flare according to the requirements in paragraphs (e)(2)(i) through (iii) of this section and shall collect and analyze samples of the gas and calculate total sulfur concentrations as specified in paragraphs (e)(2)(iv) through (ix) of this section. * * * * * (ii) The owner or operator shall conduct performance evaluations of each H2S monitor according to the requirements in § 60.13(c) and Performance Specification 7 of appendix B to this part. The owner or operator shall use EPA Method 11, 15 or 15A of appendix A–5 to this part for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981 (incorporated by reference—see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A–5 to this part. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of appendix B to this part (cylinder gas audits) may be used for conducting the relative accuracy evaluations, except that it is not necessary to include as much of the sampling probe or sampling line as practical. * * * * * (vi) * * * (C) Determine the acceptable range for subsequent weekly samples based on the 95-percent confidence interval for the distribution of daily ratios based on the 10 individual daily ratios using Equation 14 of this section. Where: AR = Acceptable range of subsequent ratio determinations, unitless. RatioAvg = 10-day average total sulfur-toH2S concentration ratio, unitless. 2.262 = t-distribution statistic for 95percent 2-sided confidence interval for 10 samples (9 degrees of freedom). SDev = Standard deviation of the 10 daily average total sulfur-to-H2S concentration ratios used to develop the 10-day average total sulfur-to-H2S concentration ratio, unitless. requirements in paragraph (a)(1) of this section, determine the F factor of the fuel gas at least daily according to the requirements in paragraphs (d)(2) through (4) of this section, determine the higher heating value of the fuel gas at least daily according to the requirements in paragraph (d)(7) of this section, and calculate the total sulfur content (as SO2) in the fuel gas using Equation 15 of this section. * * * * (f) * * * (1) * * * (ii) Use a flow sensor meeting an accuracy requirement of ±20 percent of the flow rate at velocities ranging from 0.1 to 1 feet per second and an accuracy of ±5 percent of the flow rate for velocities greater than 1 feet per second. * * * * * (h) * * * (5) Daily O2 limits for fuel gas combustion devices. Each day during which the concentration of O2 as measured by the O2 continuous monitoring system required under paragraph (c)(6) or (d)(8) of this section VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 exceeds the O2 operating limit or operating curve determined during the most recent biennial performance test. PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS FOR SOURCE CATEGORIES 10. The authority citation for part 63 continues to read as follows: ■ Authority: 42 U.S.C. 7401 et se. c. Revising newly redesignated paragraph (h)(78); ■ d. Adding paragraphs (h)(15), (74), (79), (85), (104) and (j)(2); ■ e. Redesignating paragraph (m)(3) through (21) as (m)(5) through (23), respectively, and paragraph (m)(2) as (m)(3). ■ f. Adding paragraphs (m)(2) and (4) and (n)(3); and ■ g. Revising paragraph (s)(1). The revisions and additions read as follows: ■ Subpart A—General Provisions § 63.14 11. Section 63.14 is amended by: a. Revising paragraph (h)(14); ■ b. Redesignating paragraphs (h)(82) through (99) as (h)(86) through (103), paragraphs (h)(77) through (81) as (h)(80) through (84), paragraphs (h)(73) through (76) as paragraphs (h)(75) through (78), and paragraphs (h)(15) through (72) as (16) through (73), respectively; * ■ ■ PO 00000 Frm 00060 Fmt 4701 Sfmt 4700 Incorporation by reference. * * * * (h) * * * (14) ASTM D1945–03 (Reapproved 2010), Standard Test Method for Analysis of Natural Gas by Gas Chromatography, Approved January 1, 2010, IBR approved for §§ 63.670(j), 63.772(h), and 63.1282(g). (15) ASTM D1945–14, Standard Test Method for Analysis of Natural Gas by Gas Chromatography, Approved E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.007</GPH> tkelley on DSK3SPTVN1PROD with RULES2 * * * * * (3) SO2 monitoring requirements. The owner or operator shall install, operate, calibrate, and maintain an instrument for continuously monitoring and recording the concentration of SO2 from a process heater or other fuel gas combustion device that is combusting gas representative of the fuel gas in the flare gas line according to the ER01DE15.006</GPH> Where: TSFG = Total sulfur concentration, as SO2, in the fuel gas, ppmv. CSO2 = Concentration of SO2 in the exhaust gas, ppmv (dry basis at 0-percent excess air). Fd = F factor gas on dry basis at 0-percent excess air, dscf/MMBtu. HHVFG = Higher heating value of the fuel gas, MMBtu/scf. * tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations November 1, 2014, IBR approved for § 63.670(j). * * * * * (74) ASTM D6196–03 (Reapproved 2009), Standard Practice for Selection of Sorbents, Sampling, and Thermal Desorption Analysis Procedures for Volatile Organic Compounds in Air, Approved March 1, 2009, IBR approved for appendix A to this part: Method 325A and Method 325B. * * * * * (78) ASTM D6348–03 (Reapproved 2010), Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1 through A8, Approved October 1, 2010, IBR approved for § 63.1571(a), tables 4 and 5 to subpart JJJJJ, tables 4 and 6 to subpart KKKKK, tables 1, 2, and 5 to subpart UUUUU and appendix B to subpart UUUUU. * * * * * (79) ASTM D6348–12e1, Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, Approved February 1, 2012, IBR approved for § 63.1571(a). * * * * * (85) ASTM D6420–99 (Reapproved 2010), Standard Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography-Mass Spectrometry, Approved October 1, 2010, IBR approved for § 63.670(j) and appendix A to this part: Method 325B. * * * * * (104) ASTM UOP539–12, Refinery Gas Analysis by GC, Copyright 2012 (to UOP), IBR approved for § 63.670(j). * * * * * (j) * * * (2) BS EN 14662–4:2005, Ambient air quality standard method for the measurement of benzene concentrations—Part 4: Diffusive sampling followed by thermal desorption and gas chromatography, Published June 27, 2005, IBR approved for appendix A to this part: Method 325A and Method 325B. * * * * * (m) * * * (2) EPA–454/B–08–002, Office of Air Quality Planning and Standards (OAQPS), Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final), March 24, 2008, IBR approved for VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 § 63.658(d) and appendix A to this part: Method 325A. * * * * * (4) EPA–454/R–99–005, Office of Air Quality Planning and Standards (OAQPS), Meteorological Monitoring Guidance for Regulatory Modeling Applications, February 2000, IBR approved for appendix A to this part: Method 325A. * * * * * (n) * * * (3) ISO 16017–2:2003(E): Indoor, ambient and workplace air—sampling and analysis of volatile organic compounds by sorbent tube/thermal desorption/capillary gas chromatography—Part 2: Diffusive sampling, May 15, 2003, IBR approved for appendix A to this part: Method 325A and Method 325B. * * * * * (s) * * * (1) ‘‘Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources,’’ Revision Number One, dated January 2003, Sampling Procedures Manual, Appendix P: Cooling Tower Monitoring, January 31, 2003, IBR approved for §§ 63.654(c) and (g), 63.655(i), and 63.11920. * * * * * Subpart Y—National Emission Standards for Marine Tank Vessel Loading Operations 12. Section 63.560 is amended by revising paragraph (a)(4) to read as follows: ■ § 63.560 Applicability and designation of affected source. (a) * * * (4) Existing sources with emissions less than 10 and 25 tons must meet the submerged fill standards of 46 CFR 153.282. * * * * * Subpart CC—National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries 13. Section 63.640 is amended by: a. Revising paragraphs (a) introductory text and (c) introductory text; ■ c. Adding paragraph (c)(9); ■ d. Revising paragraphs (d)(5), (h), (k)(1), (l) introductory text, (l)(2) introductory text, (l)(2)(i), (l)(3) introductory text, (m) introductory text, (n) introductory text, (n)(1) through (5), (n)(8) introductory text, and (n)(8)(ii); ■ e. Adding paragraphs (n)(8)(vii) and (viii); ■ f. Revising paragraph (n)(9)(i); ■ ■ PO 00000 Frm 00061 Fmt 4701 Sfmt 4700 75237 g. Adding paragraph (n)(10); h. Revising paragraph (o)(2)(i) introductory text; ■ i. Adding paragraph (o)(2)(i)(D); ■ j. Revising paragraph (o)(2)(ii) introductory text; and ■ k. Adding paragraphs (o)(2)(ii)(C) and (s). The revisions and additions read as follows: ■ ■ § 63.640 Applicability and designation of affected source. (a) This subpart applies to petroleum refining process units and to related emissions points that are specified in paragraphs (c)(1) through (9) of this section that are located at a plant site and that meet the criteria in paragraphs (a)(1) and (2) of this section: * * * * * (c) For the purposes of this subpart, the affected source shall comprise all emissions points, in combination, listed in paragraphs (c)(1) through (9) of this section that are located at a single refinery plant site. * * * * * (9) All releases associated with the decoking operations of a delayed coking unit, as defined in this subpart. (d) * * * (5) Emission points routed to a fuel gas system, as defined in § 63.641, provided that on and after January 30, 2019, any flares receiving gas from that fuel gas system are subject to § 63.670. No other testing, monitoring, recordkeeping, or reporting is required for refinery fuel gas systems or emission points routed to refinery fuel gas systems. * * * * * (h) Sources subject to this subpart are required to achieve compliance on or before the dates specified in table 11 of this subpart, except as provided in paragraphs (h)(1) through (3) of this section. (1) Marine tank vessels at existing sources shall be in compliance with this subpart, except for §§ 63.657 through 63.660, no later than August 18, 1999, unless the vessels are included in an emissions average to generate emission credits. Marine tank vessels used to generate credits in an emissions average shall be in compliance with this subpart no later than August 18, 1998, unless an extension has been granted by the Administrator as provided in § 63.6(i). (2) Existing Group 1 floating roof storage vessels meeting the applicability criteria in item 1 of the definition of Group 1 storage vessel shall be in compliance with § 63.646 at the first degassing and cleaning activity after August 18, 1998, or August 18, 2005, whichever is first. E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75238 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations (3) An owner or operator may elect to comply with the provisions of § 63.648(c) through (i) as an alternative to the provisions of § 63.648(a) and (b). In such cases, the owner or operator shall comply no later than the dates specified in paragraphs (h)(3)(i) through (iii) of this section. (i) Phase I (see table 2 of this subpart), beginning on August 18, 1998; (ii) Phase II (see table 2 of this subpart), beginning no later than August 18, 1999; and (iii) Phase III (see table 2 of this subpart), beginning no later than February 18, 2001. * * * * * (k) * * * (1) The reconstructed source, addition, or change shall be in compliance with the new source requirements in item (1), (2), or (3) of table 11 of this subpart, as applicable, upon initial startup of the reconstructed source or by August 18, 1995, whichever is later; and * * * * * (l) If an additional petroleum refining process unit is added to a plant site or if a miscellaneous process vent, storage vessel, gasoline loading rack, marine tank vessel loading operation, heat exchange system, or decoking operation that meets the criteria in paragraphs (c)(1) through (9) of this section is added to an existing petroleum refinery or if another deliberate operational process change creating an additional Group 1 emissions point(s) (as defined in § 63.641) is made to an existing petroleum refining process unit, and if the addition or process change is not subject to the new source requirements as determined according to paragraph (i) or (j) of this section, the requirements in paragraphs (l)(1) through (4) of this section shall apply. Examples of process changes include, but are not limited to, changes in production capacity, or feed or raw material where the change requires construction or physical alteration of the existing equipment or catalyst type, or whenever there is replacement, removal, or addition of recovery equipment. For purposes of this paragraph (l) and paragraph (m) of this section, process changes do not include: Process upsets, unintentional temporary process changes, and changes that are within the equipment configuration and operating conditions documented in the Notification of Compliance Status report required by § 63.655(f). * * * * * (2) The added emission point(s) and any emission point(s) within the added or changed petroleum refining process VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 unit shall be in compliance with the applicable requirements in item (4) of table 11 of this subpart by the dates specified in paragraph (l)(2)(i) or (ii) of this section. (i) If a petroleum refining process unit is added to a plant site or an emission point(s) is added to any existing petroleum refining process unit, the added emission point(s) shall be in compliance upon initial startup of any added petroleum refining process unit or emission point(s) or by the applicable compliance date in item (4) of table 11 of this subpart, whichever is later. * * * * * (3) The owner or operator of a petroleum refining process unit or of a storage vessel, miscellaneous process vent, wastewater stream, gasoline loading rack, marine tank vessel loading operation, heat exchange system, or decoking operation meeting the criteria in paragraphs (c)(1) through (9) of this section that is added to a plant site and is subject to the requirements for existing sources shall comply with the reporting and recordkeeping requirements that are applicable to existing sources including, but not limited to, the reports listed in paragraphs (l)(3)(i) through (vii) of this section. A process change to an existing petroleum refining process unit shall be subject to the reporting requirements for existing sources including, but not limited to, the reports listed in paragraphs (l)(3)(i) through (vii) of this section. The applicable reports include, but are not limited to: * * * * * (m) If a change that does not meet the criteria in paragraph (l) of this section is made to a petroleum refining process unit subject to this subpart, and the change causes a Group 2 emission point to become a Group 1 emission point (as defined in § 63.641), then the owner or operator shall comply with the applicable requirements of this subpart for existing sources, as specified in item (4) of table 11 of this subpart, for the Group 1 emission point as expeditiously as practicable, but in no event later than 3 years after the emission point becomes Group 1. * * * * * (n) Overlap of this subpart with other regulations for storage vessels. As applicable, paragraphs (n)(1), (3), (4), (6), and (7) of this section apply for Group 2 storage vessels and paragraphs (n)(2) and (5) of this section apply for Group 1 storage vessels. (1) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel that is subject to the provisions of 40 CFR part PO 00000 Frm 00062 Fmt 4701 Sfmt 4700 60, subpart Kb, is required to comply only with the requirements of 40 CFR part 60, subpart Kb, except as provided in paragraph (n)(8) of this section. After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel that is subject to the provisions of 40 CFR part 61, subpart Y, is required to comply only with the requirements of 40 CFR part 61, subpart Y, except as provided in paragraph (n)(10) of this section. (2) After the compliance dates specified in paragraph (h) of this section, a Group 1 storage vessel that is also subject to 40 CFR part 60, subpart Kb, is required to comply only with either 40 CFR part 60, subpart Kb, except as provided in paragraph (n)(8) of this section or this subpart. After the compliance dates specified in paragraph (h) of this section, a Group 1 storage vessel that is also subject to 40 CFR part 61, subpart Y, is required to comply only with either 40 CFR part 61, subpart Y, except as provided in paragraph (n)(10) of this section or this subpart. (3) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel that is part of a new source and is subject to 40 CFR 60.110b, but is not required to apply controls by 40 CFR 60.110b or 60.112b, is required to comply only with this subpart. (4) After the compliance dates specified in paragraph (h) of this section, a Group 2 storage vessel that is part of a new source and is subject to 40 CFR 61.270, but is not required to apply controls by 40 CFR 61.271, is required to comply only with this subpart. (5) After the compliance dates specified in paragraph (h) of this section, a Group 1 storage vessel that is also subject to the provisions of 40 CFR part 60, subpart K or Ka, is required to only comply with the provisions of this subpart. * * * * * (8) Storage vessels described by paragraph (n)(1) of this section are to comply with 40 CFR part 60, subpart Kb, except as provided in paragraphs (n)(8)(i) through (vi) of this section. Storage vessels described by paragraph (n)(2) electing to comply with part 60, subpart Kb of this chapter shall comply with subpart Kb except as provided in paragraphs (n)(8)(i) through (viii) of this section. * * * * * (ii) If the owner or operator determines that it is unsafe to perform the seal gap measurements required in § 60.113b(b) of this chapter or to inspect the vessel to determine compliance with E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations § 60.113b(a) of this chapter because the roof appears to be structurally unsound and poses an imminent danger to inspecting personnel, the owner or operator shall comply with the requirements in either § 63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date specified in paragraph (h) of this section for compliance with § 63.660, as applicable) or either § 63.1063(c)(2)(iv)(A) or (B) of subpart WW. * * * * * (vii) To be in compliance with § 60.112b(a)(1)(iv) or (a)(2)(ii) of this chapter, guidepoles in floating roof storage vessels must be equipped with covers and/or controls (e.g., pole float system, pole sleeve system, internal sleeve system or flexible enclosure system) as appropriate to comply with the ‘‘no visible gap’’ requirement. (viii) If a flare is used as a control device for a storage vessel, on and after January 30, 2019, the owner or operator must meet the requirements of § 63.670 instead of the requirements referenced from part 60, subpart Kb of this chapter for that flare. (9) * * * (i) If the owner or operator determines that it is unsafe to perform the seal gap measurements required in § 60.113a(a)(1) of this chapter because the floating roof appears to be structurally unsound and poses an imminent danger to inspecting personnel, the owner or operator shall comply with the requirements in either § 63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date specified in paragraph (h) of this section for compliance with § 63.660, as applicable) or either § 63.1063(c)(2)(iv)(A) or (B) of subpart WW. * * * * * (10) Storage vessels described by paragraph (n)(1) of this section are to comply with 40 CFR part 61, subpart Y, except as provided in paragraphs (n)(10)(i) through (vi) of this section. Storage vessels described by paragraph (n)(2) electing to comply with 40 CFR part 61, subpart Y, shall comply with subpart Y except as provided for in paragraphs (n)(10)(i) through (viii) of this section. (i) Storage vessels that are to comply with § 61.271(b) of this chapter are exempt from the secondary seal requirements of § 61.271(b)(2)(ii) of this chapter during the gap measurements for the primary seal required by § 61.272(b) of this chapter. (ii) If the owner or operator determines that it is unsafe to perform the seal gap measurements required in § 61.272(b) of this chapter or to inspect VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 the vessel to determine compliance with § 61.272(a) of this chapter because the roof appears to be structurally unsound and poses an imminent danger to inspecting personnel, the owner or operator shall comply with the requirements in either § 63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date specified in paragraph (h) of this section for compliance with § 63.660, as applicable) or either § 63.1063(c)(2)(iv)(A) or (B) of subpart WW. (iii) If a failure is detected during the inspections required by § 61.272(a)(2) of this chapter or during the seal gap measurements required by § 61.272(b)(1) of this chapter, and the vessel cannot be repaired within 45 days and the vessel cannot be emptied within 45 days, the owner or operator may utilize up to two extensions of up to 30 additional calendar days each. The owner or operator is not required to provide a request for the extension to the Administrator. (iv) If an extension is utilized in accordance with paragraph (n)(10)(iii) of this section, the owner or operator shall, in the next periodic report, identify the vessel, provide the information listed in § 61.272(a)(2) or (b)(4)(iii) of this chapter, and describe the nature and date of the repair made or provide the date the storage vessel was emptied. (v) Owners and operators of storage vessels complying with 40 CFR part 61, subpart Y, may submit the inspection reports required by § 61.275(a), (b)(1), and (d) of this chapter as part of the periodic reports required by this subpart, rather than within the 60-day period specified in § 61.275(a), (b)(1), and (d) of this chapter. (vi) The reports of rim seal inspections specified in § 61.275(d) of this chapter are not required if none of the measured gaps or calculated gap areas exceed the limitations specified in § 61.272(b)(4) of this chapter. Documentation of the inspections shall be recorded as specified in § 61.276(a) of this chapter. (vii) To be in compliance with § 61.271(a)(6) or (b)(3) of this chapter, guidepoles in floating roof storage vessels must be equipped with covers and/or controls (e.g., pole float system, pole sleeve system, internal sleeve system or flexible enclosure system) as appropriate to comply with the ‘‘no visible gap’’ requirement. (viii) If a flare is used as a control device for a storage vessel, on and after January 30, 2019, the owner or operator must meet the requirements of § 63.670 instead of the requirements referenced from part 61, subpart Y of this chapter for that flare. PO 00000 Frm 00063 Fmt 4701 Sfmt 4700 75239 (o) * * * (2) * * * (i) Comply with paragraphs (o)(2)(i)(A) through (D) of this section. * * * * * (D) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of 40 CFR part 61, subpart FF, and subpart G of this part, or the requirements of § 63.670. (ii) Comply with paragraphs (o)(2)(ii)(A) through (C) of this section. * * * * * (C) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of 40 CFR part 61, subpart FF, and subpart G of this part, or the requirements of § 63.670. * * * * * (s) Overlap of this subpart with other regulation for flares. On January 30, 2019, flares that are subject to the provisions of 40 CFR 60.18 or 63.11 and subject to this subpart are required to comply only with the provisions specified in this subpart. Prior to January 30, 2019, flares that are subject to the provisions of 40 CFR 60.18 or 63.11 and elect to comply with the requirements in §§ 63.670 and 63.671 are required to comply only with the provisions specified in this subpart. ■ 14. Section 63.641 is amended by: ■ a. Adding, in alphabetical order, definitions of ‘‘Assist air,’’ ‘‘Assist steam,’’ ‘‘Center steam,’’ ‘‘Closed blowdown system,’’ ‘‘Combustion zone,’’ ‘‘Combustion zone gas,’’ ‘‘Decoking operations,’’ ‘‘Delayed coking unit,’’ ‘‘Flare,’’ ‘‘Flare purge gas,’’ ‘‘Flare supplemental gas,’’ ‘‘Flare sweep gas,’’ ‘‘Flare vent gas,’’ ‘‘Flexible enclosure device,’’ ‘‘Force majeure event,’’ ‘‘Lower steam,’’ ‘‘Net heating value,’’ ‘‘Perimeter assist air,’’ ‘‘Pilot gas,’’ ‘‘Premix assist air,’’ ‘‘Regulated material,’’ ‘‘Thermal expansion relief valve,’’ ‘‘Total steam,’’ and ‘‘Upper steam’’; and ■ b. Revising the definitions of ‘‘Delayed coker vent,’’ ‘‘Emission point,’’ ‘‘Group 1 storage vessel,’’ ‘‘Miscellaneous process vent,’’ ‘‘Periodically discharged,’’ and ‘‘Reference control technology for storage vessels.’’ The revisions and additions read as follows: § 63.641 Definitions. * * * * * Assist air means all air that intentionally is introduced prior to or at E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75240 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations a flare tip through nozzles or other hardware conveyance for the purposes including, but not limited to, protecting the design of the flare tip, promoting turbulence for mixing or inducing air into the flame. Assist air includes premix assist air and perimeter assist air. Assist air does not include the surrounding ambient air. Assist steam means all steam that intentionally is introduced prior to or at a flare tip through nozzles or other hardware conveyance for the purposes including, but not limited to, protecting the design of the flare tip, promoting turbulence for mixing or inducing air into the flame. Assist steam includes, but is not necessarily limited to, center steam, lower steam and upper steam. * * * * * Center steam means the portion of assist steam introduced into the stack of a flare to reduce burnback. Closed blowdown system means a system used for depressuring process vessels that is not open to the atmosphere and is configured of piping, ductwork, connections, accumulators/ knockout drums, and, if necessary, flow inducing devices that transport gas or vapor from process vessel to a control device or back into the process. * * * * * Combustion zone means the area of the flare flame where the combustion zone gas combines for combustion. Combustion zone gas means all gases and vapors found just after a flare tip. This gas includes all flare vent gas, total steam, and premix air. * * * * * Decoking operations means the sequence of steps conducted at the end of the delayed coking unit’s cooling cycle to open the coke drum to the atmosphere in order to remove coke from the coke drum. Decoking operations begin at the end of the cooling cycle when steam released from the coke drum is no longer discharged via the unit’s blowdown system but instead is vented directly to the atmosphere. Decoking operations include atmospheric depressuring (venting), deheading, draining, and decoking (coke cutting). Delayed coker vent means a miscellaneous process vent that contains uncondensed vapors from the delayed coking unit’s blowdown system. Venting from the delayed coker vent is typically intermittent in nature, and occurs primarily during the cooling cycle of a delayed coking unit coke drum when vapor from the coke drums cannot be sent to the fractionator column for product recovery. The emissions from the decoking operations, VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 which include direct atmospheric venting, deheading, draining, or decoking (coke cutting), are not considered to be delayed coker vents. Delayed coking unit means a refinery process unit in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit includes, but is not limited to, all of the coke drums associated with a single fractionator; the fractionator, including the bottoms receiver and the overhead condenser; the coke drum cutting water and quench system, including the jet pump and coker quench water tank; and the coke drum blowdown recovery compressor system. * * * * * Emission point means an individual miscellaneous process vent, storage vessel, wastewater stream, equipment leak, decoking operation or heat exchange system associated with a petroleum refining process unit; an individual storage vessel or equipment leak associated with a bulk gasoline terminal or pipeline breakout station classified under Standard Industrial Classification code 2911; a gasoline loading rack classified under Standard Industrial Classification code 2911; or a marine tank vessel loading operation located at a petroleum refinery. * * * * * Flare means a combustion device lacking an enclosed combustion chamber that uses an uncontrolled volume of ambient air to burn gases. For the purposes of this rule, the definition of flare includes, but is not necessarily limited to, air-assisted flares, steamassisted flares and non-assisted flares. Flare purge gas means gas introduced between a flare header’s water seal and the flare tip to prevent oxygen infiltration (backflow) into the flare tip. For a flare with no water seal, the function of flare purge gas is performed by flare sweep gas and, therefore, by definition, such a flare has no flare purge gas. Flare supplemental gas means all gas introduced to the flare in order to improve the combustible characteristics of combustion zone gas. Flare sweep gas means, for a flare with a flare gas recovery system, the gas intentionally introduced into the flare header system to maintain a constant flow of gas through the flare header in order to prevent oxygen buildup in the flare header; flare sweep gas in these flares is introduced prior to and recovered by the flare gas recovery system. For a flare without a flare gas recovery system, flare sweep gas means PO 00000 Frm 00064 Fmt 4701 Sfmt 4700 the gas intentionally introduced into the flare header system to maintain a constant flow of gas through the flare header and out the flare tip in order to prevent oxygen buildup in the flare header and to prevent oxygen infiltration (backflow) into the flare tip. Flare vent gas means all gas found just prior to the flare tip. This gas includes all flare waste gas (i.e., gas from facility operations that is directed to a flare for the purpose of disposing of the gas), that portion of flare sweep gas that is not recovered, flare purge gas and flare supplemental gas, but does not include pilot gas, total steam or assist air. Flexible enclosure device means a seal made of an elastomeric fabric (or other material) which completely encloses a slotted guidepole or ladder and eliminates the vapor emission pathway from inside the storage vessel through the guidepole slots or ladder slots to the outside air. * * * * * Force majeure event means a release of HAP, either directly to the atmosphere from a relief valve or discharged via a flare, that is demonstrated to the satisfaction of the Administrator to result from an event beyond the refinery owner or operator’s control, such as natural disasters; acts of war or terrorism; loss of a utility external to the refinery (e.g., external power curtailment), excluding power curtailment due to an interruptible service agreement; and fire or explosion originating at a near or adjoining facility outside of the refinery owner or operator’s control that impacts the refinery’s ability to operate. * * * * * Group 1 storage vessel means: (1) Prior to February 1, 2016: (i) A storage vessel at an existing source that has a design capacity greater than or equal to 177 cubic meters and stored-liquid maximum true vapor pressure greater than or equal to 10.4 kilopascals and stored-liquid annual average true vapor pressure greater than or equal to 8.3 kilopascals and annual average HAP liquid concentration greater than 4 percent by weight total organic HAP; (ii) A storage vessel at a new source that has a design storage capacity greater than or equal to 151 cubic meters and stored-liquid maximum true vapor pressure greater than or equal to 3.4 kilopascals and annual average HAP liquid concentration greater than 2 percent by weight total organic HAP; or (iii) A storage vessel at a new source that has a design storage capacity greater than or equal to 76 cubic meters and less than 151 cubic meters and stored- E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations liquid maximum true vapor pressure greater than or equal to 77 kilopascals and annual average HAP liquid concentration greater than 2 percent by weight total organic HAP. (2) On and after February 1, 2016: (i) A storage vessel at an existing source that has a design capacity greater than or equal to 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than or equal to 5.2 kilopascals (0.75 pounds per square inch) and annual average HAP liquid concentration greater than 4 percent by weight total organic HAP; (ii) A storage vessel at an existing source that has a design storage capacity greater than or equal to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) and storedliquid maximum true vapor pressure greater than or equal to 13.1 kilopascals (1.9 pounds per square inch) and annual average HAP liquid concentration greater than 4 percent by weight total organic HAP; (iii) A storage vessel at a new source that has a design storage capacity greater than or equal to 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than or equal to 3.4 kilopascals (0.5 pounds per square inch) and annual average HAP liquid concentration greater than 2 percent by weight total organic HAP; or (iv) A storage vessel at a new source that has a design storage capacity greater than or equal to 76 cubic meters (20,000 gallons) and less than 151 cubic meters (40,000 gallons) and stored-liquid maximum true vapor pressure greater than or equal to 13.1 kilopascals (1.9 pounds per square inch) and annual average HAP liquid concentration greater than 2 percent by weight total organic HAP. * * * * * Lower steam means the portion of assist steam piped to an exterior annular ring near the lower part of a flare tip, which then flows through tubes to the flare tip, and ultimately exits the tubes at the flare tip. * * * * * Miscellaneous process vent means a gas stream containing greater than 20 parts per million by volume organic HAP that is continuously or periodically discharged from a petroleum refining process unit meeting the criteria specified in § 63.640(a). Miscellaneous process vents include gas streams that are discharged directly to the atmosphere, gas streams that are routed to a control device prior to discharge to the atmosphere, or gas streams that are VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 diverted through a product recovery device prior to control or discharge to the atmosphere. Miscellaneous process vents include vent streams from: Caustic wash accumulators, distillation tower condensers/accumulators, flash/ knockout drums, reactor vessels, scrubber overheads, stripper overheads, vacuum pumps, steam ejectors, hot wells, high point bleeds, wash tower overheads, water wash accumulators, blowdown condensers/accumulators, and delayed coker vents. Miscellaneous process vents do not include: (1) Gaseous streams routed to a fuel gas system, provided that on and after January 30, 2019, any flares receiving gas from the fuel gas system are in compliance with § 63.670; (2) Pressure relief device discharges; (3) Leaks from equipment regulated under § 63.648; (4) [Reserved] (5) In situ sampling systems (onstream analyzers) until January 30, 2019. After this date, these sampling systems will be included in the definition of miscellaneous process vents; (6) Catalytic cracking unit catalyst regeneration vents; (7) Catalytic reformer regeneration vents; (8) Sulfur plant vents; (9) Vents from control devices such as scrubbers, boilers, incinerators, and electrostatic precipitators applied to catalytic cracking unit catalyst regeneration vents, catalytic reformer regeneration vents, and sulfur plant vents; (10) Vents from any stripping operations applied to comply with the wastewater provisions of this subpart, subpart G of this part, or 40 CFR part 61, subpart FF; (11) Emissions associated with delayed coking unit decoking operations; (12) Vents from storage vessels; (13) Emissions from wastewater collection and conveyance systems including, but not limited to, wastewater drains, sewer vents, and sump drains; and (14) Hydrogen production plant vents through which carbon dioxide is removed from process streams or through which steam condensate produced or treated within the hydrogen plant is degassed or deaerated. Net heating value means the energy released as heat when a compound undergoes complete combustion with oxygen to form gaseous carbon dioxide and gaseous water (also referred to as lower heating value). * * * * * Perimeter assist air means the portion of assist air introduced at the perimeter PO 00000 Frm 00065 Fmt 4701 Sfmt 4700 75241 of the flare tip or above the flare tip. Perimeter assist air includes air intentionally entrained in lower and upper steam. Perimeter assist air includes all assist air except premix assist air. Periodically discharged means discharges that are intermittent and associated with routine operations, maintenance activities, startups, shutdowns, malfunctions, or process upsets. * * * * * Pilot gas means gas introduced into a flare tip that provides a flame to ignite the flare vent gas. * * * * * Premix assist air means the portion of assist air that is introduced to the flare vent gas, whether injected or induced, prior to the flare tip. Premix assist air also includes any air intentionally entrained in center steam. * * * * * Reference control technology for storage vessels means either: (1) For Group 1 storage vessels complying with § 63.660: (i) An internal floating roof, including an external floating roof converted to an internal floating roof, meeting the specifications of § 63.1063(a)(1)(i) and (b); (ii) An external floating roof meeting the specifications of § 63.1063(a)(1)(ii), (a)(2), and (b); or (iii) [Reserved] (iv) A closed-vent system to a control device that reduces organic HAP emissions by 95 percent, or to an outlet concentration of 20 parts per million by volume (ppmv). (v) For purposes of emissions averaging, these four technologies are considered equivalent. (2) For all other storage vessels: (i) An internal floating roof meeting the specifications of § 63.119(b) of subpart G except for § 63.119(b)(5) and (6); (ii) An external floating roof meeting the specifications of § 63.119(c) of subpart G except for § 63.119(c)(2); (iii) An external floating roof converted to an internal floating roof meeting the specifications of § 63.119(d) of subpart G except for § 63.119(d)(2); or (iv) A closed-vent system to a control device that reduces organic HAP emissions by 95 percent, or to an outlet concentration of 20 parts per million by volume. (v) For purposes of emissions averaging, these four technologies are considered equivalent. * * * * * Regulated material means any stream associated with emission sources listed E:\FR\FM\01DER2.SGM 01DER2 75242 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations in § 63.640(c) required to meet control requirements under this subpart as well as any stream for which this subpart or a cross-referencing subpart specifies that the requirements for flare control devices in § 63.670 must be met. * * * * * Thermal expansion relief valve means a pressure relief valve designed to protect equipment from excess pressure due to thermal expansion of blocked liquid-filled equipment or piping due to ambient heating or heat from a heat tracing system. Pressure relief valves designed to protect equipment from excess pressure due to blockage against a pump or compressor or due to fire contingency are not thermal expansion relief valves. * * * * * Total steam means the total of all steam that is supplied to a flare and includes, but is not limited to, lower steam, center steam and upper steam. Upper steam means the portion of assist steam introduced via nozzles located on the exterior perimeter of the upper end of the flare tip. * * * * * ■ 15. Section 63.642 is amended by: ■ a. Adding paragraph (b); ■ b. Revising paragraphs (d)(3), (e), (i), (k) introductory text, (k)(1), (l) introductory text, and (l)(2); and ■ c. Adding paragraph (n). The revisions and additions read as follows: § 63.642 General standards. tkelley on DSK3SPTVN1PROD with RULES2 * * * * * (b) The emission standards set forth in this subpart shall apply at all times. * * * * * (d) * * * (3) Performance tests shall be conducted according to the provisions of § 63.7(e) except that performance tests shall be conducted at maximum representative operating capacity for the process. During the performance test, an owner or operator shall operate the control device at either maximum or minimum representative operating conditions for monitored control device parameters, whichever results in lower emission reduction. An owner or operator shall not conduct a performance test during startup, shutdown, periods when the control device is bypassed or periods when the process, monitoring equipment or control device is not operating properly. The owner/operator may not conduct performance tests during periods of malfunction. The owner or operator must record the process information that is necessary to document operating conditions during the test and include VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 in such record an explanation to support that the test was conducted at maximum representative operating capacity. Upon request, the owner or operator shall make available to the Administrator such records as may be necessary to determine the conditions of performance tests. * * * * * (e) All applicable records shall be maintained as specified in § 63.655(i). * * * * * (i) The owner or operator of an existing source shall demonstrate compliance with the emission standard in paragraph (g) of this section by following the procedures specified in paragraph (k) of this section for all emission points, or by following the emissions averaging compliance approach specified in paragraph (l) of this section for specified emission points and the procedures specified in paragraph (k)(1) of this section. * * * * * (k) The owner or operator of an existing source may comply, and the owner or operator of a new source shall comply, with the applicable provisions in §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as specified in § 63.640(h). (1) The owner or operator using this compliance approach shall also comply with the requirements of §§ 63.648 and/ or 63.649, 63.654, 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable. * * * * * (l) The owner or operator of an existing source may elect to control some of the emission points within the source to different levels than specified under §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable according to § 63.640(h), by using an emissions averaging compliance approach as long as the overall emissions for the source do not exceed the emission level specified in paragraph (g) of this section. The owner or operator using emissions averaging shall meet the requirements in paragraphs (l)(1) and (2) of this section. * * * * * (2) Comply with the requirements of §§ 63.648 and/or 63.649, 63.654, 63.652, 63.653, 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable. * * * * * (n) At all times, the owner or operator must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for PO 00000 Frm 00066 Fmt 4701 Sfmt 4700 minimizing emissions. The general duty to minimize emissions does not require the owner operator to make any further efforts to reduce emissions if levels required by the applicable standard have been achieved. Determination of whether a source is operating in compliance with operation and maintenance requirements will be based on information available to the Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source. ■ 16. Section 63.643 is amended by revising paragraphs (a) introductory text and (a)(1) and adding paragraph (c) to read as follows: § 63.643 Miscellaneous process vent provisions. (a) The owner or operator of a Group 1 miscellaneous process vent as defined in § 63.641 shall comply with the requirements of either paragraph (a)(1) or (2) of this section or, if applicable, paragraph (c) of this section. The owner or operator of a miscellaneous process vent that meets the conditions in paragraph (c) of this section is only required to comply with the requirements of paragraph (c) of this section and § 63.655(g)(13) and (i)(12) for that vent. (1) Reduce emissions of organic HAP’s using a flare. On and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the requirements of § 63.11(b) of subpart A or the requirements of § 63.670. * * * * * (c) An owner or operator may designate a process vent as a maintenance vent if the vent is only used as a result of startup, shutdown, maintenance, or inspection of equipment where equipment is emptied, depressurized, degassed or placed into service. The owner of operator does not need to designate a maintenance vent as a Group 1 or Group 2 miscellaneous process vent. The owner or operator must comply with the applicable requirements in paragraphs (c)(1) through (3) of this section for each maintenance vent. (1) Prior to venting to the atmosphere, process liquids are removed from the equipment as much as practical and the equipment is depressured to a control device, fuel gas system, or back to the process until one of the following conditions, as applicable, is met. (i) The vapor in the equipment served by the maintenance vent has a lower E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations explosive limit (LEL) of less than 10 percent. (ii) If there is no ability to measure the LEL of the vapor in the equipment based on the design of the equipment, the pressure in the equipment served by the maintenance vent is reduced to 5 psig or less. Upon opening the maintenance vent, active purging of the equipment cannot be used until the LEL of the vapors in the maintenance vent (or inside the equipment if the maintenance is a hatch or similar type of opening) equipment is less than 10 percent. (iii) The equipment served by the maintenance vent contains less than 72 pounds of VOC. (iv) If the maintenance vent is associated with equipment containing pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers) at refineries that do not have a pure hydrogen supply, the LEL of the vapor in the equipment must be less than 20 percent, except for one event per year not to exceed 35 percent. (2) Except for maintenance vents complying with the alternative in paragraph (c)(1)(iii) of this section, the owner or operator must determine the LEL or, if applicable, equipment pressure using process instrumentation or portable measurement devices and follow procedures for calibration and maintenance according to manufacturer’s specifications. (3) For maintenance vents complying with the alternative in paragraph (c)(1)(iii) of this section, the owner or operator shall determine mass of VOC in the equipment served by the maintenance vent based on the equipment size and contents after considering any contents drained or purged from the equipment. Equipment size may be determined from equipment design specifications. Equipment contents may be determined using process knowledge. ■ 17. Section 63.644 is amended by revising paragraphs (a) introductory text, (a)(2), and (c) to read as follows: tkelley on DSK3SPTVN1PROD with RULES2 § 63.644 Monitoring provisions for miscellaneous process vents. (a) Except as provided in paragraph (b) of this section, each owner or operator of a Group 1 miscellaneous process vent that uses a combustion device to comply with the requirements in § 63.643(a) shall install the monitoring equipment specified in paragraph (a)(1), (2), (3), or (4) of this section, depending on the type of combustion device used. All monitoring equipment shall be installed, calibrated, maintained, and operated according to manufacturer’s specifications or other written procedures that provide adequate assurance that the equipment VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 will monitor accurately and, except for CPMS installed for pilot flame monitoring, must meet the applicable minimum accuracy, calibration and quality control requirements specified in table 13 of this subpart. * * * * * (2) Where a flare is used prior to January 30, 2019, a device (including but not limited to a thermocouple, an ultraviolet beam sensor, or an infrared sensor) capable of continuously detecting the presence of a pilot flame is required, or the requirements of § 63.670 shall be met. Where a flare is used on and after January 30, 2019, the requirements of § 63.670 shall be met. * * * * * (c) The owner or operator of a Group 1 miscellaneous process vent using a vent system that contains bypass lines that could divert a vent stream away from the control device used to comply with paragraph (a) of this section either directly to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a) shall comply with either paragraph (c)(1) or (2) of this section. Use of the bypass at any time to divert a Group 1 miscellaneous process vent stream to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a) is an emissions standards violation. Equipment such as low leg drains and equipment subject to § 63.648 are not subject to this paragraph (c). (1) Install, calibrate and maintain a flow indicator that determines whether a vent stream flow is present at least once every hour. A manual block valve equipped with a valve position indicator may be used in lieu of a flow indicator, as long as the valve position indicator is monitored continuously. Records shall be generated as specified in § 63.655(h) and (i). The flow indicator shall be installed at the entrance to any bypass line that could divert the vent stream away from the control device to the atmosphere; or (2) Secure the bypass line valve in the non-diverting position with a car-seal or a lock-and-key type configuration. A visual inspection of the seal or closure mechanism shall be performed at least once every month to ensure that the valve is maintained in the non-diverting position and that the vent stream is not diverted through the bypass line. * * * * * 18. Section 63.645 is amended by revising paragraphs (e)(1) and (f)(2) to read as follows: ■ PO 00000 Frm 00067 Fmt 4701 Sfmt 4700 75243 § 63.645 Test methods and procedures for miscellaneous process vents. * * * * * (e) * * * (1) Methods 1 or 1A of 40 CFR part 60, appendix A–1, as appropriate, shall be used for selection of the sampling site. For vents smaller than 0.10 meter in diameter, sample at the center of the vent. * * * * * (f) * * * (2) The gas volumetric flow rate shall be determined using Methods 2, 2A, 2C, 2D, or 2F of 40 CFR part 60, appendix A–1 or Method 2G of 40 CFR part 60, appendix A–2, as appropriate. * * * * * ■ 19. Section 63.646 is amended by adding introductory text and revising paragraph (b)(2) to read as follows: § 63.646 Storage vessel provisions. Upon a demonstration of compliance with the standards in § 63.660 by the compliance dates specified in § 63.640(h), the standards in this section shall no longer apply. * * * * * (b) * * * (2) When an owner or operator and the Administrator do not agree on whether the annual average weight percent organic HAP in the stored liquid is above or below 4 percent for a storage vessel at an existing source or above or below 2 percent for a storage vessel at a new source, an appropriate method (based on the type of liquid stored) as published by EPA or a consensus-based standards organization shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–B2959, (800) 262– 1373, https://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street NW., 6th floor, Washington, DC 20036, (202) 293–8020, https://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street NW., 4th Floor, Washington, DC 20001, (202) 824–7000, https:// www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016– 5990, (800) 843–2763, https:// www.asme.org), the American Petroleum Institute (API, 1220 L Street NW., Washington, DC 20005–4070, (202) 682–8000, https://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356–0060, https://www.naesb.org). * * * * * E:\FR\FM\01DER2.SGM 01DER2 75244 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 20. Section 63.647 is amended by: a. Revising paragraph (a); b. Redesignating paragraph (c) as paragraph (d); and ■ c. Adding paragraph (c). The revisions and additions read as follows: ■ ■ ■ § 63.647 Wastewater provisions. (a) Except as provided in paragraphs (b) and (c) of this section, each owner or operator of a Group 1 wastewater stream shall comply with the requirements of §§ 61.340 through 61.355 of this chapter for each process wastewater stream that meets the definition in § 63.641. * * * * * (c) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of part 61, subpart FF of this chapter, or the requirements of § 63.670. * * * * * ■ 21. Section 63.648 is amended by: ■ a. Adding paragraph (a)(3); ■ b. Revising paragraph (c) introductory text; and ■ c. Adding paragraphs (c)(11) and (12) and (j). The revisions and additions read as follows: tkelley on DSK3SPTVN1PROD with RULES2 § 63.648 Equipment leak standards. (a) * * * (3) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of part 60, subpart VV of this chapter, or the requirements of § 63.670. * * * * * (c) In lieu of complying with the existing source provisions of paragraph (a) in this section, an owner or operator may elect to comply with the requirements of §§ 63.161 through 63.169, 63.171, 63.172, 63.175, 63.176, 63.177, 63.179, and 63.180 of subpart H except as provided in paragraphs (c)(1) through (12) and (e) through (i) of this section. * * * * * (11) [Reserved] (12) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of §§ 63.172 and 63.180, or the requirements of § 63.670. * * * * * (j) Except as specified in paragraph (j)(4) of this section, the owner or VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 operator must comply with the requirements specified in paragraphs (j)(1) and (2) of this section for pressure relief devices, such as relief valves or rupture disks, in organic HAP gas or vapor service instead of the pressure relief device requirements of § 60.482–4 or § 63.165, as applicable. Except as specified in paragraphs (j)(4) and (5) of this section, the owner or operator must also comply with the requirements specified in paragraph (j)(3) of this section for all pressure relief devices. (1) Operating requirements. Except during a pressure release, operate each pressure relief device in organic HAP gas or vapor service with an instrument reading of less than 500 ppm above background as detected by Method 21 of 40 CFR part 60, appendix A–7. (2) Pressure release requirements. For pressure relief devices in organic HAP gas or vapor service, the owner or operator must comply with the applicable requirements in paragraphs (j)(2)(i) through (iii) of this section following a pressure release. (i) If the pressure relief device does not consist of or include a rupture disk, conduct instrument monitoring, as specified in § 60.485(b) or § 63.180(c), as applicable, no later than 5 calendar days after the pressure relief device returns to organic HAP gas or vapor service following a pressure release to verify that the pressure relief device is operating with an instrument reading of less than 500 ppm. (ii) If the pressure relief device includes a rupture disk, either comply with the requirements in paragraph (j)(2)(i) of this section (not replacing the rupture disk) or install a replacement disk as soon as practicable after a pressure release, but no later than 5 calendar days after the pressure release. The owner or operator must conduct instrument monitoring, as specified in § 60.485(b) or § 63.180(c), as applicable, no later than 5 calendar days after the pressure relief device returns to organic HAP gas or vapor service following a pressure release to verify that the pressure relief device is operating with an instrument reading of less than 500 ppm. (iii) If the pressure relief device consists only of a rupture disk, install a replacement disk as soon as practicable after a pressure release, but no later than 5 calendar days after the pressure release. The owner or operator may not initiate startup of the equipment served by the rupture disk until the rupture disc is replaced. The owner or operator must conduct instrument monitoring, as specified in § 60.485(b) or § 63.180(c), as applicable, no later than 5 calendar days after the pressure relief device returns to PO 00000 Frm 00068 Fmt 4701 Sfmt 4700 organic HAP gas or vapor service following a pressure release to verify that the pressure relief device is operating with an instrument reading of less than 500 ppm. (3) Pressure release management. Except as specified in paragraphs (j)(4) and (5) of this section, the owner or operator shall comply with the requirements specified in paragraphs (j)(3)(i) through (v) of this section for all pressure relief devices in organic HAP service no later than January 30, 2019. (i) The owner or operator must equip each affected pressure relief device with a device(s) or use a monitoring system that is capable of: (A) Identifying the pressure release; (B) Recording the time and duration of each pressure release; and (C) Notifying operators immediately that a pressure release is occurring. The device or monitoring system may be either specific to the pressure relief device itself or may be associated with the process system or piping, sufficient to indicate a pressure release to the atmosphere. Examples of these types of devices and systems include, but are not limited to, a rupture disk indicator, magnetic sensor, motion detector on the pressure relief valve stem, flow monitor, or pressure monitor. (ii) The owner or operator must apply at least three redundant prevention measures to each affected pressure relief device and document these measures. Examples of prevention measures include: (A) Flow, temperature, level and pressure indicators with deadman switches, monitors, or automatic actuators. (B) Documented routine inspection and maintenance programs and/or operator training (maintenance programs and operator training may count as only one redundant prevention measure). (C) Inherently safer designs or safety instrumentation systems. (D) Deluge systems. (E) Staged relief system where initial pressure relief valve (with lower set release pressure) discharges to a flare or other closed vent system and control device. (iii) If any affected pressure relief device releases to atmosphere as a result of a pressure release event, the owner or operator must perform root cause analysis and corrective action analysis according to the requirement in paragraph (j)(6) of this section and implement corrective actions according to the requirements in paragraph (j)(7) of this section. The owner or operator must also calculate the quantity of organic HAP released during each pressure E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations release event and report this quantity as required in § 63.655(g)(10)(iii). Calculations may be based on data from the pressure relief device monitoring alone or in combination with process parameter monitoring data and process knowledge. (iv) The owner or operator shall determine the total number of release events occurred during the calendar year for each affected pressure relief device separately. The owner or operator shall also determine the total number of release events for each pressure relief device for which the root cause analysis concluded that the root cause was a force majeureevent, as defined in this subpart. (v) Except for pressure relief devices described in paragraphs (j)(4) and (5) of this section, the following release events are a violation of the pressure release management work practice standards. (A) Any release event for which the root cause of the event was determined to be operator error or poor maintenance. (B) A second release event not including force majeure events from a single pressure relief device in a 3 calendar year period for the same root cause for the same equipment. (C) A third release event not including force majeure events from a single pressure relief device in a 3 calendar year period for any reason. (4) Pressure relief devices routed to a control device. If all releases and potential leaks from a pressure relief device are routed through a closed vent system to a control device, back into the process or to the fuel gas system, the owner or operator is not required to comply with paragraph (j)(1), (2), or (3) (if applicable) of this section. Both the closed vent system and control device (if applicable) must meet the requirements of § 63.644. When complying with this paragraph (j)(4), all references to ‘‘Group 1 miscellaneous process vent’’ in § 63.644 mean ‘‘pressure relief device.’’ If a pressure relief device complying with this paragraph (j)(4) is routed to the fuel gas system, then on and after January 30, 2019, any flares receiving gas from that fuel gas system must be in compliance with § 63.670. (5) Pressure relief devices exempted from pressure release management requirements. The following types of pressure relief devices are not subject to the pressure release management requirements in paragraph (j)(3) of this section. (i) Pressure relief devices in heavy liquid service, as defined in § 63.641. (ii) Pressure relief devices that only release material that is liquid at VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 standard conditions (1 atmosphere and 68 degrees Fahrenheit) and that are hard-piped to a controlled drain system (i.e., a drain system meeting the requirements for Group 1 wastewater streams in § 63.647(a)) or piped back to the process or pipeline. (iii) Thermal expansion relief valves. (iv) Pressure relief devices designed with a set relief pressure of less than 2.5 psig. (v) Pressure relief devices that do not have the potential to emit 72 lbs/day or more of VOC based on the valve diameter, the set release pressure, and the equipment contents. (vi) Pressure relief devices on mobile equipment. (6) Root cause analysis and corrective action analysis. A root cause analysis and corrective action analysis must be completed as soon as possible, but no later than 45 days after a release event. Special circumstances affecting the number of root cause analyses and/or corrective action analyses are provided in paragraphs (j)(6)(i) through (iv) of this section. (i) You may conduct a single root cause analysis and corrective action analysis for a single emergency event that causes two or more pressure relief devices installed on the same equipment to release. (ii) You may conduct a single root cause analysis and corrective action analysis for a single emergency event that causes two or more pressure relief devices to release, regardless of the equipment served, if the root cause is reasonably expected to be a force majeure event, as defined in this subpart. (iii) Except as provided in paragraphs (j)(6)(i) and (ii) of this section, if more than one pressure relief device has a release during the same time period, an initial root cause analysis shall be conducted separately for each pressure relief device that had a release. If the initial root cause analysis indicates that the release events have the same root cause(s), the initially separate root cause analyses may be recorded as a single root cause analysis and a single corrective action analysis may be conducted. (7) Corrective action implementation. Each owner or operator required to conduct a root cause analysis and corrective action analysis as specified in paragraphs (j)(3)(iii) and (j)(6) of this section shall implement the corrective action(s) identified in the corrective action analysis in accordance with the applicable requirements in paragraphs (j)(7)(i) through (iii) of this section. (i) All corrective action(s) must be implemented within 45 days of the PO 00000 Frm 00069 Fmt 4701 Sfmt 4700 75245 event for which the root cause and corrective action analyses were required or as soon thereafter as practicable. If an owner or operator concludes that no corrective action should be implemented, the owner or operator shall record and explain the basis for that conclusion no later than 45 days following the event. (ii) For corrective actions that cannot be fully implemented within 45 days following the event for which the root cause and corrective action analyses were required, the owner or operator shall develop an implementation schedule to complete the corrective action(s) as soon as practicable. (iii) No later than 45 days following the event for which a root cause and corrective action analyses were required, the owner or operator shall record the corrective action(s) completed to date, and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates. ■ 22. Section 63.649 is amended by revising definition of Cc term in the equation in paragraph (c)(6)(i) to read as follows: § 63.649 Alternative means of emission limitation: Connectors in gas/vapor service and light liquid service. * * (c) * * (6) * * (i) * * * * * * * * Cc = Optional credit for removed connectors = 0.67 × net number (i.e., the total number of connectors removed minus the total added) of connectors in organic HAP service removed from the process unit after the applicability date set forth in § 63.640(h)(3)(iii) for existing process units, and after the date of start-up for new process units. If credits are not taken, then Cc = 0. * * * * * 23. Section 63.650 is amended by revising paragraph (a) and adding paragraph (d) to read as follows: ■ § 63.650 Gasoline loading rack provisions. (a) Except as provided in paragraphs (b) through (d) of this section, each owner or operator of a Group 1 gasoline loading rack classified under Standard Industrial Classification code 2911 located within a contiguous area and under common control with a petroleum refinery shall comply with subpart R of this part, §§ 63.421, 63.422(a) through (c) and (e), 63.425(a) through (c) and (e) through (i), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3), and (k). * * * * * E:\FR\FM\01DER2.SGM 01DER2 75246 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations (d) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of subpart R of this part, or the requirements of § 63.670. ■ 24. Section 63.651 is amended by revising paragraphs (a) and (d) and adding paragraph (e) to read as follows: § 63.651 Marine tank vessel loading operation provisions. (a) Except as provided in paragraphs (b) through (e) of this section, each owner or operator of a marine tank vessel loading operation located at a petroleum refinery shall comply with the requirements of §§ 63.560 through 63.568. * * * * * (d) The compliance time of 4 years after promulgation of 40 CFR part 63, subpart Y, does not apply. The compliance time is specified in § 63.640(h)(1). (e) If a flare is used as a control device, on and after January 30, 2019, the flare shall meet the requirements of § 63.670. Prior to January 30, 2019, the flare shall meet the applicable requirements of subpart Y of this part, or the requirements of § 63.670. ■ 25. Section 63.652 is amended by: ■ a. Revising paragraph (a); ■ b. Removing and reserving paragraph (f)(2); and ■ c. Revising paragraphs (g)(2)(iii)(B)(1), (h)(3), (k) introductory text, and (k)(3). The revisions and additions read as follows: tkelley on DSK3SPTVN1PROD with RULES2 § 63.652 Emissions averaging provisions. (a) This section applies to owners or operators of existing sources who seek to comply with the emission standard in § 63.642(g) by using emissions averaging according to § 63.642(l) rather than following the provisions of §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651. Existing marine tank vessel loading operations located at the Valdez Marine Terminal source may not comply with the standard by using emissions averaging. * * * * * (g) * * * (2) * * * (iii) * * * (B) * * * (1) The percent reduction shall be measured according to the procedures in § 63.116 of subpart G if a combustion control device is used. For a flare meeting the criteria in § 63.116(a) of subpart G or § 63.670, as applicable, or a boiler or process heater meeting the criteria in § 63.645(d) or § 63.116(b) of VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 subpart G, the percentage of reduction shall be 98 percent. If a noncombustion control device is used, percentage of reduction shall be demonstrated by a performance test at the inlet and outlet of the device, or, if testing is not feasible, by a control design evaluation and documented engineering calculations. * * * * * (h) * * * (3) Emissions from storage vessels shall be determined as specified in § 63.150(h)(3) of subpart G, except as follows: (i) For storage vessels complying with § 63.646: (A) All references to § 63.119(b) in § 63.150(h)(3) of subpart G shall be replaced with: § 63.119(b) or § 63.119(b) except for § 63.119(b)(5) and (6). (B) All references to § 63.119(c) in § 63.150(h)(3) of subpart G shall be replaced with: § 63.119(c) or § 63.119(c) except for § 63.119(c)(2). (C) All references to § 63.119(d) in § 63.150(h)(3) of subpart G shall be replaced with: § 63.119(d) or § 63.119(d) except for § 63.119(d)(2). (ii) For storage vessels complying with § 63.660: (A) Section 63.1063(a)(1)(i), (a)(2), and (b) or § 63.1063(a)(1)(i) and (b) shall apply instead of § 63.119(b) in § 63.150(h)(3) of subpart G. (B) Section 63.1063(a)(1)(ii), (a)(2), and (b) shall apply instead of § 63.119(c) in § 63.150(h)(3) of subpart G. (C) Section 63.1063(a)(1)(i), (a)(2), and (b) or § 63.1063(a)(1)(i) and (b) shall apply instead of § 63.119(d) in § 63.150(h)(3) of subpart G. * * * * * (k) The owner or operator shall demonstrate that the emissions from the emission points proposed to be included in the average will not result in greater hazard or, at the option of the State or local permitting authority, greater risk to human health or the environment than if the emission points were controlled according to the provisions in §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable. * * * * * (3) An emissions averaging plan that does not demonstrate an equivalent or lower hazard or risk to the satisfaction of the State or local permitting authority shall not be approved. The State or local permitting authority may require such adjustments to the emissions averaging plan as are necessary in order to ensure that the average will not result in greater hazard or risk to human health or the environment than would result if the emission points were controlled PO 00000 Frm 00070 Fmt 4701 Sfmt 4700 according to §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable. * * * * * ■ 26. Section 63.653 is amended by revising paragraphs (a) introductory text, (a)(3)(i) and (ii), and (a)(7) to read as follows: § 63.653 Monitoring, recordkeeping, and implementation plan for emissions averaging. (a) For each emission point included in an emissions average, the owner or operator shall perform testing, monitoring, recordkeeping, and reporting equivalent to that required for Group 1 emission points complying with §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable. The specific requirements for miscellaneous process vents, storage vessels, wastewater, gasoline loading racks, and marine tank vessels are identified in paragraphs (a)(1) through (7) of this section. * * * * * (3) * * * (i) Perform the monitoring or inspection procedures in § 63.646 and either § 63.120 of subpart G or § 63.1063 of subpart WW, as applicable; and (ii) For closed vent systems with control devices, conduct an initial design evaluation as specified in § 63.646 and either § 63.120(d) of subpart G or § 63.985(b) of subpart SS, as applicable. * * * * * (7) If an emission point in an emissions average is controlled using a pollution prevention measure or a device or technique for which no monitoring parameters or inspection procedures are specified in §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable, the owner or operator shall establish a site-specific monitoring parameter and shall submit the information specified in § 63.655(h)(4) in the Implementation Plan. * * * * * ■ 27. Section 63.655 is amended by: ■ a. Revising paragraphs (f) introductory text, (f)(1) introductory text, (f)(1)(i)(A) introductory text, (f)(1)(i)(A)(2) and (3), (f)(1)(i)(B) introductory text, (f)(1)(i)(B)(2), (f)(1)(i)(D)(2), (f)(1)(iv) introductory text, and (f)(1)(iv)(A); ■ b. Adding paragraphs (f)(1)(vii) and (viii); ■ c. Revising paragraphs (f)(2) introductory text, (f)(3) introductory text, the first sentence of (f)(6), (g) introductory text, (g)(1) through (5), (g)(6)(i)(D), (g)(6)(iii), and (g)(7)(i); E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations d. Adding paragraphs (g)(10) through (14); ■ e. Removing and reserving paragraph (h)(1); ■ f. Revising paragraphs (h)(2) introductory text, (h)(2)(i)(B), (h)(2)(ii), and (h)(5)(iii); ■ g. Adding paragraphs (h)(8) and (9) and (i) introductory text; ■ h. Revising paragraph (i)(1) introductory text and paragraph (i)(1)(ii); ■ i. Adding paragraphs (i)(1)(v) and (vi); ■ j. Redesignating paragraphs (i)(4) and (5) as paragraphs (i)(5) and (6), respectively; ■ k. Adding paragraph (i)(4); ■ l. Revising newly redesignated paragraph (i)(5) introductory text; and ■ m. Adding paragraphs (i)(7) through (12). The revisions and additions read as follows: ■ § 63.655 Reporting and recordkeeping requirements. tkelley on DSK3SPTVN1PROD with RULES2 * * * * * (f) Each owner or operator of a source subject to this subpart shall submit a Notification of Compliance Status report within 150 days after the compliance dates specified in § 63.640(h) with the exception of Notification of Compliance Status reports submitted to comply with § 63.640(l)(3) and for storage vessels subject to the compliance schedule specified in § 63.640(h)(2). Notification of Compliance Status reports required by § 63.640(l)(3) and for storage vessels subject to the compliance dates specified in § 63.640(h)(2) shall be submitted according to paragraph (f)(6) of this section. This information may be submitted in an operating permit application, in an amendment to an operating permit application, in a separate submittal, or in any combination of the three. If the required information has been submitted before the date 150 days after the compliance date specified in § 63.640(h), a separate Notification of Compliance Status report is not required within 150 days after the compliance dates specified in § 63.640(h). If an owner or operator submits the information specified in paragraphs (f)(1) through (5) of this section at different times, and/or in different submittals, later submittals may refer to earlier submittals instead of duplicating and resubmitting the previously submitted information. Each owner or operator of a gasoline loading rack classified under Standard Industrial Classification Code 2911 located within a contiguous area and under common control with a petroleum refinery subject to the standards of this subpart shall submit VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 the Notification of Compliance Status report required by subpart R of this part within 150 days after the compliance dates specified in § 63.640(h). (1) The Notification of Compliance Status report shall include the information specified in paragraphs (f)(1)(i) through (viii) of this section. (i) * * * (A) Identification of each storage vessel subject to this subpart, and for each Group 1 storage vessel subject to this subpart, the information specified in paragraphs (f)(1)(i)(A)(1) through (3) of this section. This information is to be revised each time a Notification of Compliance Status report is submitted for a storage vessel subject to the compliance schedule specified in § 63.640(h)(2) or to comply with § 63.640(l)(3). * * * * * (2) For storage vessels subject to the compliance schedule specified in § 63.640(h)(2) that are not complying with § 63.646, the anticipated compliance date. (3) For storage vessels subject to the compliance schedule specified in § 63.640(h)(2) that are complying with § 63.646 and the Group 1 storage vessels described in § 63.640(l), the actual compliance date. (B) If a closed vent system and a control device other than a flare is used to comply with § 63.646 or § 63.660, the owner or operator shall submit: * * * * * (2) The design evaluation documentation specified in § 63.120(d)(1)(i) of subpart G or § 63.985(b)(1)(i) of subpart SS (as applicable), if the owner or operator elects to prepare a design evaluation; or * * * * * (D) * * * (2) All visible emission readings, heat content determinations, flow rate measurements, and exit velocity determinations made during the compliance determination required by § 63.120(e) of subpart G or § 63.987(b) of subpart SS or § 63.670(h), as applicable; and * * * * * (iv) For miscellaneous process vents controlled by flares, initial compliance test results including the information in paragraphs (f)(1)(iv)(A) and (B) of this section. (A) All visible emission readings, heat content determinations, flow rate measurements, and exit velocity determinations made during the compliance determination required by §§ 63.645 and 63.116(a) of subpart G or § 63.670(h), as applicable; and * * * * * PO 00000 Frm 00071 Fmt 4701 Sfmt 4700 75247 (vii) For pressure relief devices in organic HAP service subject to the requirements in § 63.648(j)(3)(i) and (ii), this report shall include the information specified in paragraphs (f)(1)(vii)(A) and (B) of this section. (A) A description of the monitoring system to be implemented, including the relief devices and process parameters to be monitored, and a description of the alarms or other methods by which operators will be notified of a pressure release. (B) A description of the prevention measures to be implemented for each affected pressure relief device. (viii) For each delayed coking unit, identification of whether the unit is an existing affected source or a new affected source and whether monitoring will be conducted as specified in § 63.657(b) or (c). (2) If initial performance tests are required by §§ 63.643 through 63.653, the Notification of Compliance Status report shall include one complete test report for each test method used for a particular source. On and after February 1, 2016, performance tests shall be submitted according to paragraph (h)(9) of this section. * * * * * (3) For each monitored parameter for which a range is required to be established under § 63.120(d) of subpart G or § 63.985(b) of subpart SS for storage vessels or § 63.644 for miscellaneous process vents, the Notification of Compliance Status report shall include the information in paragraphs (f)(3)(i) through (iii) of this section. * * * * * (6) Notification of Compliance Status reports required by § 63.640(l)(3) and for storage vessels subject to the compliance dates specified in § 63.640(h)(2) shall be submitted no later than 60 days after the end of the 6-month period during which the change or addition was made that resulted in the Group 1 emission point or the existing Group 1 storage vessel was brought into compliance, and may be combined with the periodic report. * * * (g) The owner or operator of a source subject to this subpart shall submit Periodic Reports no later than 60 days after the end of each 6-month period when any of the information specified in paragraphs (g)(1) through (7) of this section or paragraphs (g)(9) through (14) of this section is collected. The first 6month period shall begin on the date the Notification of Compliance Status report is required to be submitted. A Periodic Report is not required if none of the events identified in paragraphs (g)(1) E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75248 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations through (7) of this section or paragraphs (g)(9) through (14) of this section occurred during the 6-month period unless emissions averaging is utilized. Quarterly reports must be submitted for emission points included in emission averages, as provided in paragraph (g)(8) of this section. An owner or operator may submit reports required by other regulations in place of or as part of the Periodic Report required by this paragraph (g) if the reports contain the information required by paragraphs (g)(1) through (14) of this section. (1) For storage vessels, Periodic Reports shall include the information specified for Periodic Reports in paragraphs (g)(2) through (5) of this section. Information related to gaskets, slotted membranes, and sleeve seals is not required for storage vessels that are part of an existing source complying with § 63.646. (2) Internal floating roofs. (i) An owner or operator who elects to comply with § 63.646 by using a fixed roof and an internal floating roof or by using an external floating roof converted to an internal floating roof shall submit the results of each inspection conducted in accordance with § 63.120(a) of subpart G in which a failure is detected in the control equipment. (A) For vessels for which annual inspections are required under § 63.120(a)(2)(i) or (a)(3)(ii) of subpart G, the specifications and requirements listed in paragraphs (g)(2)(i)(A)(1) through (3) of this section apply. (1) A failure is defined as any time in which the internal floating roof is not resting on the surface of the liquid inside the storage vessel and is not resting on the leg supports; or there is liquid on the floating roof; or the seal is detached from the internal floating roof; or there are holes, tears, or other openings in the seal or seal fabric; or there are visible gaps between the seal and the wall of the storage vessel. (2) Except as provided in paragraph (g)(2)(i)(A)(3) of this section, each Periodic Report shall include the date of the inspection, identification of each storage vessel in which a failure was detected, and a description of the failure. The Periodic Report shall also describe the nature of and date the repair was made or the date the storage vessel was emptied. (3) If an extension is utilized in accordance with § 63.120(a)(4) of subpart G, the owner or operator shall, in the next Periodic Report, identify the vessel; include the documentation specified in § 63.120(a)(4) of subpart G; and describe the date the storage vessel was emptied and the nature of and date the repair was made. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (B) For vessels for which inspections are required under § 63.120(a)(2)(ii), (a)(3)(i), or (a)(3)(iii) of subpart G (i.e., internal inspections), the specifications and requirements listed in paragraphs (g)(2)(i)(B)(1) and (2) of this section apply. (1) A failure is defined as any time in which the internal floating roof has defects; or the primary seal has holes, tears, or other openings in the seal or the seal fabric; or the secondary seal (if one has been installed) has holes, tears, or other openings in the seal or the seal fabric; or, for a storage vessel that is part of a new source, the gaskets no longer close off the liquid surface from the atmosphere; or, for a storage vessel that is part of a new source, the slotted membrane has more than a 10 percent open. (2) Each Periodic Report shall include the date of the inspection, identification of each storage vessel in which a failure was detected, and a description of the failure. The Periodic Report shall also describe the nature of and date the repair was made. (ii) An owner or operator who elects to comply with § 63.660 by using a fixed roof and an internal floating roof shall submit the results of each inspection conducted in accordance with § 63.1063(c)(1), (d)(1), and (d)(2) of subpart WW in which a failure is detected in the control equipment. For vessels for which inspections are required under § 63.1063(c) and (d), the specifications and requirements listed in paragraphs (g)(2)(ii)(A) through (C) of this section apply. (A) A failure is defined in § 63.1063(d)(1) of subpart WW. (B) Each Periodic Report shall include a copy of the inspection record required by § 63.1065(b) of subpart WW when a failure occurs. (C) An owner or operator who elects to use an extension in accordance with § 63.1063(e)(2) of subpart WW shall, in the next Periodic Report, submit the documentation required by § 63.1063(e)(2). (3) External floating roofs. (i) An owner or operator who elects to comply with § 63.646 by using an external floating roof shall meet the periodic reporting requirements specified in paragraphs (g)(3)(i)(A) through (C) of this section. (A) The owner or operator shall submit, as part of the Periodic Report, documentation of the results of each seal gap measurement made in accordance with § 63.120(b) of subpart G in which the seal and seal gap requirements of § 63.120(b)(3), (4), (5), or (6) of subpart G are not met. This documentation shall include the PO 00000 Frm 00072 Fmt 4701 Sfmt 4700 information specified in paragraphs (g)(3)(i)(A)(1) through (4) of this section. (1) The date of the seal gap measurement. (2) The raw data obtained in the seal gap measurement and the calculations described in § 63.120(b)(3) and (4) of subpart G. (3) A description of any seal condition specified in § 63.120(b)(5) or (6) of subpart G that is not met. (4) A description of the nature of and date the repair was made, or the date the storage vessel was emptied. (B) If an extension is utilized in accordance with § 63.120(b)(7)(ii) or (b)(8) of subpart G, the owner or operator shall, in the next Periodic Report, identify the vessel; include the documentation specified in § 63.120(b)(7)(ii) or (b)(8) of subpart G, as applicable; and describe the date the vessel was emptied and the nature of and date the repair was made. (C) The owner or operator shall submit, as part of the Periodic Report, documentation of any failures that are identified during visual inspections required by § 63.120(b)(10) of subpart G. This documentation shall meet the specifications and requirements in paragraphs (g)(3)(i)(C)(1) and (2) of this section. (1) A failure is defined as any time in which the external floating roof has defects; or the primary seal has holes or other openings in the seal or the seal fabric; or the secondary seal has holes, tears, or other openings in the seal or the seal fabric; or, for a storage vessel that is part of a new source, the gaskets no longer close off the liquid surface from the atmosphere; or, for a storage vessel that is part of a new source, the slotted membrane has more than 10 percent open area. (2) Each Periodic Report shall include the date of the inspection, identification of each storage vessel in which a failure was detected, and a description of the failure. The Periodic Report shall also describe the nature of and date the repair was made. (ii) An owner or operator who elects to comply with § 63.660 by using an external floating roof shall meet the periodic reporting requirements specified in paragraphs (g)(3)(ii)(A) and (B) of this section. (A) For vessels for which inspections are required under § 63.1063(c)(2), (d)(1), and (d)(3) of subpart WW, the owner or operator shall submit, as part of the Periodic Report, a copy of the inspection record required by § 63.1065(b) of subpart WW when a failure occurs. A failure is defined in § 63.1063(d)(1). E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations (B) An owner or operator who elects to use an extension in accordance with § 63.1063(e)(2) or (c)(2)(iv)(B) of subpart WW shall, in the next Periodic Report, submit the documentation required by those paragraphs. (4) [Reserved] (5) An owner or operator who elects to comply with § 63.646 or § 63.660 by installing a closed vent system and control device shall submit, as part of the next Periodic Report, the information specified in paragraphs (g)(5)(i) through (v) of this section, as applicable. (i) The Periodic Report shall include the information specified in paragraphs (g)(5)(i)(A) and (B) of this section for those planned routine maintenance operations that would require the control device not to meet the requirements of either § 63.119(e)(1) or (2) of subpart G, § 63.985(a) and (b) of subpart SS, or § 63.670, as applicable. (A) A description of the planned routine maintenance that is anticipated to be performed for the control device during the next 6 months. This description shall include the type of maintenance necessary, planned frequency of maintenance, and lengths of maintenance periods. (B) A description of the planned routine maintenance that was performed for the control device during the previous 6 months. This description shall include the type of maintenance performed and the total number of hours during those 6 months that the control device did not meet the requirements of either § 63.119(e)(1) or (2) of subpart G, § 63.985(a) and (b) of subpart SS, or § 63.670, as applicable, due to planned routine maintenance. (ii) If a control device other than a flare is used, the Periodic Report shall describe each occurrence when the monitored parameters were outside of the parameter ranges documented in the Notification of Compliance Status report. The description shall include: Identification of the control device for which the measured parameters were outside of the established ranges, and causes for the measured parameters to be outside of the established ranges. (iii) If a flare is used prior to January 30, 2019 and prior to electing to comply with the requirements in § 63.670, the Periodic Report shall describe each occurrence when the flare does not meet the general control device requirements specified in § 63.11(b) of subpart A and shall include: Identification of the flare that does not meet the general requirements specified in § 63.11(b) of subpart A, and reasons the flare did not meet the general requirements specified in § 63.11(b) of subpart A. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (iv) If a flare is used on or after the date for which compliance with the requirements in § 63.670 is elected, which can be no later than January 30, 2019, the Periodic Report shall include the items specified in paragraph (g)(11) of this section. (v) An owner or operator who elects to comply with § 63.660 by installing an alternate control device as described in § 63.1064 of subpart WW shall submit, as part of the next Periodic Report, a written application as described in § 63.1066(b)(3) of subpart WW. (6) * * * (i) * * * (D) For data compression systems under paragraph (h)(5)(iii) of this section, an operating day when the monitor operated for less than 75 percent of the operating hours or a day when less than 18 monitoring values were recorded. * * * * * (iii) For periods in closed vent systems when a Group 1 miscellaneous process vent stream was detected in the bypass line or diverted from the control device and either directly to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a), report the date, time, duration, estimate of the volume of gas, the concentration of organic HAP in the gas and the resulting mass emissions of organic HAP that bypassed the control device. For periods when the flow indicator is not operating, report the date, time, and duration. (7) * * * (i) Results of the performance test shall include the identification of the source tested, the date of the test, the percentage of emissions reduction or outlet pollutant concentration reduction (whichever is needed to determine compliance) for each run and for the average of all runs, and the values of the monitored operating parameters. * * * * * (10) For pressure relief devices subject to the requirements § 63.648(j), Periodic Reports must include the information specified in paragraphs (g)(10)(i) through (iii) of this section. (i) For pressure relief devices in organic HAP gas or vapor service, pursuant to § 63.648(j)(1), report any instrument reading of 500 ppm or greater. (ii) For pressure relief devices in organic HAP gas or vapor service subject to § 63.648(j)(2), report confirmation that any monitoring required to be done during the reporting period to show compliance was conducted. (iii) For pressure relief devices in organic HAP service subject to PO 00000 Frm 00073 Fmt 4701 Sfmt 4700 75249 § 63.648(j)(3), report each pressure release to the atmosphere, including duration of the pressure release and estimate of the mass quantity of each organic HAP released, and the results of any root cause analysis and corrective action analysis completed during the reporting period, including the corrective actions implemented during the reporting period and, if applicable, the implementation schedule for planned corrective actions to be implemented subsequent to the reporting period. (11) For flares subject to § 63.670, Periodic Reports must include the information specified in paragraphs (g)(11)(i) through (iv) of this section. (i) Records as specified in paragraph (i)(9)(i) of this section for each 15minute block during which there was at least one minute when regulated material is routed to a flare and no pilot flame is present. (ii) Visible emission records as specified in paragraph (i)(9)(ii)(C) of this section for each period of 2 consecutive hours during which visible emissions exceeded a total of 5 minutes. (iii) The 15-minute block periods for which the applicable operating limits specified in § 63.670(d) through (f) are not met. Indicate the date and time for the period, the net heating value operating parameter(s) determined following the methods in § 63.670(k) through (n) as applicable. (iv) For flaring events meeting the criteria in § 63.670(o)(3): (A) The start and stop time and date of the flaring event. (B) The length of time for which emissions were visible from the flare during the event. (C) The periods of time that the flare tip velocity exceeds the maximum flare tip velocity determined using the methods in § 63.670(d)(2) and the maximum 15-minute block average flare tip velocity recorded during the event. (D) Results of the root cause and corrective actions analysis completed during the reporting period, including the corrective actions implemented during the reporting period and, if applicable, the implementation schedule for planned corrective actions to be implemented subsequent to the reporting period. (12) For delayed coking units, the Periodic Report must include the information specified in paragraphs (g)(12)(i) through (iv) of this section. (i) For existing source delayed coking units, any 60-cycle average exceeding the applicable limit in § 63.657(a)(1). (ii) For new source delayed coking units, any direct venting event E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75250 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations exceeding the applicable limit in § 63.657(a)(2). (iii) The total number of double quenching events performed during the reporting period. (iv) For each double quenching draining event when the drain water temperature exceeded 210 °F, report the drum, date, time, the coke drum vessel pressure or temperature, as applicable, when pre-vent draining was initiated, and the maximum drain water temperature during the pre-vent draining period. (13) For maintenance vents subject to the requirements in § 63.643(c), Periodic Reports must include the information specified in paragraphs (g)(13)(i) through (iv) of this section for any release exceeding the applicable limits in § 63.643(c)(1). For the purposes of this reporting requirement, owners or operators complying with § 63.643(c)(1)(iv) must report each venting event for which the lower explosive limit is 20 percent or greater. (i) Identification of the maintenance vent and the equipment served by the maintenance vent. (ii) The date and time the maintenance vent was opened to the atmosphere. (iii) The lower explosive limit, vessel pressure, or mass of VOC in the equipment, as applicable, at the start of atmospheric venting. If the 5 psig vessel pressure option in § 63.643(c)(1)(ii) was used and active purging was initiated while the lower explosive limit was 10 percent or greater, also include the lower explosive limit of the vapors at the time active purging was initiated. (iv) An estimate of the mass of organic HAP released during the entire atmospheric venting event. (14) Any changes in the information provided in a previous Notification of Compliance Status report. (h) * * * (2) For storage vessels, notifications of inspections as specified in paragraphs (h)(2)(i) and (ii) of this section. (i) * * * (B) Except as provided in paragraph (h)(2)(i)(C) of this section, if the internal inspection required by § 63.120(a)(2), (a)(3), or (b)(10) of subpart G or § 63.1063(d)(1) of subpart WW is not planned and the owner or operator could not have known about the inspection 30 calendar days in advance of refilling the vessel with organic HAP, the owner or operator shall notify the Administrator at least 7 calendar days prior to refilling of the storage vessel. Notification may be made by telephone and immediately followed by written documentation demonstrating why the inspection was unplanned. This VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 notification, including the written documentation, may also be made in writing and sent so that it is received by the Administrator at least 7 calendar days prior to the refilling. * * * * * (ii) In order to afford the Administrator the opportunity to have an observer present, the owner or operator of a storage vessel equipped with an external floating roof shall notify the Administrator of any seal gap measurements. The notification shall be made in writing at least 30 calendar days in advance of any gap measurements required by § 63.120(b)(1) or (2) of subpart G or § 63.1062(d)(3) of subpart WW. The State or local permitting authority can waive this notification requirement for all or some storage vessels subject to the rule or can allow less than 30 calendar days’ notice. * * * * * (5) * * * (iii) An owner or operator may use an automated data compression recording system that does not record monitored operating parameter values at a set frequency (for example, once every hour) but records all values that meet set criteria for variation from previously recorded values. (A) The system shall be designed to: (1) Measure the operating parameter value at least once every hour. (2) Record at least 24 values each day during periods of operation. (3) Record the date and time when monitors are turned off or on. (4) Recognize unchanging data that may indicate the monitor is not functioning properly, alert the operator, and record the incident. (5) Compute daily average values of the monitored operating parameter based on recorded data. (B) You must maintain a record of the description of the monitoring system and data compression recording system including the criteria used to determine which monitored values are recorded and retained, the method for calculating daily averages, and a demonstrations that they system meets all criteria of paragraph (h)(5)(iii)(A) of this section. * * * * * (8) For fenceline monitoring systems subject to § 63.658, within 45 calendar days after the end of each quarterly reporting period covered by the periodic report, each owner or operator shall submit the following information to the EPA’s Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA’s Central Data Exchange (CDX) (https:// cdx.epa.gov/). The owner or operator need not transmit this data prior to obtaining 12 months of data. PO 00000 Frm 00074 Fmt 4701 Sfmt 4700 (i) Individual sample results for each monitor for each sampling period during the quarterly reporting period. For the first reporting period and for any period in which a passive monitor is added or moved, the owner or operator shall report the coordinates of all of the passive monitor locations. The owner or operator shall determine the coordinates using an instrument with an accuracy of at least 3 meters. Coordinates shall be in decimal degrees with at least five decimal places. (ii) The biweekly annual average concentration difference (Dc) values for benzene for the quarterly reporting period. (iii) Notation for each biweekly value that indicates whether background correction was used, all measurements in the sampling period were below detection, or whether an outlier was removed from the sampling period data set. (9) On and after February 1, 2016, if required to submit the results of a performance test or CEMS performance evaluation, the owner or operator shall submit the results according to the procedures in paragraphs (h)(9)(i) and (ii) of this section. (i) Within 60 days after the date of completing each performance test as required by this subpart, the owner or operator shall submit the results of the performance tests following the procedure specified in either paragraph (h)(9)(i)(A) or (B) of this section. (A) For data collected using test methods supported by the EPA’s Electronic Reporting Tool (ERT) as listed on the EPA’s ERT Web site (https://www.epa.gov/ttn/chief/ert/ index.html) at the time of the test, the owner or operator must submit the results of the performance test to the EPA via the CEDRI. (CEDRI can be accessed through the EPA’s CDX.) Performance test data must be submitted in a file format generated through the use of the EPA’s ERT or an alternate electronic file format consistent with the extensible markup language (XML) schema listed on the EPA’s ERT Web site. If an owner or operator claims that some of the performance test information being submitted is confidential business information (CBI), the owner or operator must submit a complete file generated through the use of the EPA’s ERT or an alternate electronic file consistent with the XML schema listed on the EPA’s ERT Web site, including information claimed to be CBI, on a compact disc, flash drive or other commonly used electronic storage media to the EPA. The electronic storage media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/ E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404–02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA’s CDX as described earlier in this paragraph (h)(9)(i)(A). (B) For data collected using test methods that are not supported by the EPA’s ERT as listed on the EPA’s ERT Web site at the time of the test, the owner or operator must submit the results of the performance test to the Administrator at the appropriate address listed in § 63.13. (ii) Within 60 days after the date of completing each CEMS performance evaluation as required by this subpart, the owner or operator must submit the results of the performance evaluation following the procedure specified in either paragraph (h)(9)(ii)(A) or (B) of this section. (A) For performance evaluations of continuous monitoring systems measuring relative accuracy test audit (RATA) pollutants that are supported by the EPA’s ERT as listed on the EPA’s ERT Web site at the time of the evaluation, the owner or operator must submit the results of the performance evaluation to the EPA via the CEDRI. (CEDRI can be accessed through the EPA’s CDX.) Performance evaluation data must be submitted in a file format generated through the use of the EPA’s ERT or an alternate file format consistent with the XML schema listed on the EPA’s ERT Web site. If an owner or operator claims that some of the performance evaluation information being submitted is CBI, the owner or operator must submit a complete file generated through the use of the EPA’s ERT or an alternate electronic file consistent with the XML schema listed on the EPA’s ERT Web site, including information claimed to be CBI, on a compact disc, flash drive or other commonly used electronic storage media to the EPA. The electronic storage media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404– 02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA’s CDX as described earlier in this paragraph (h)(9)(ii)(A). (B) For any performance evaluations of continuous monitoring systems measuring RATA pollutants that are not supported by the EPA’s ERT as listed on the EPA’s ERT Web site at the time of the evaluation, the owner or operator must submit the results of the VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 performance evaluation to the Administrator at the appropriate address listed in § 63.13. (i) Recordkeeping. Each owner or operator of a source subject to this subpart shall keep copies of all applicable reports and records required by this subpart for at least 5 years except as otherwise specified in paragraphs (i)(1) through (12) of this section. All applicable records shall be maintained in such a manner that they can be readily accessed within 24 hours. Records may be maintained in hard copy or computer-readable form including, but not limited to, on paper, microfilm, computer, flash drive, floppy disk, magnetic tape, or microfiche. (1) Each owner or operator subject to the storage vessel provisions in § 63.646 shall keep the records specified in § 63.123 of subpart G except as specified in paragraphs (i)(1)(i) through (iv) of this section. Each owner or operator subject to the storage vessel provisions in § 63.660 shall keep records as specified in paragraphs (i)(1)(v) and (vi) of this section. * * * * * (ii) All references to § 63.122 in § 63.123 of subpart G shall be replaced with § 63.655(e). * * * * * (v) Each owner or operator of a Group 1 storage vessel subject to the provisions in § 63.660 shall keep records as specified in § 63.1065 or § 63.998, as applicable. (vi) Each owner or operator of a Group 2 storage vessel shall keep the records specified in § 63.1065(a) of subpart WW. If a storage vessel is determined to be Group 2 because the weight percent total organic HAP of the stored liquid is less than or equal to 4 percent for existing sources or 2 percent for new sources, a record of any data, assumptions, and procedures used to make this determination shall be retained. * * * * * (4) For each closed vent system that contains bypass lines that could divert a vent stream away from the control device and either directly to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a), the owner or operator shall keep a record of the information specified in either paragraph (i)(4)(i) or (ii) of this section, as applicable. (i) The owner or operator shall maintain records of periods when flow was detected in the bypass line, including the date and time and the duration of the flow in the bypass line. For each flow event, the owner or operator shall maintain records PO 00000 Frm 00075 Fmt 4701 Sfmt 4700 75251 sufficient to determine whether or not the detected flow included flow of a Group 1 miscellaneous process vent stream requiring control. For periods when the Group 1 miscellaneous process vent stream requiring control is diverted from the control device and released either directly to the atmosphere or to a control device that does not comply with the requirements in § 63.643(a), the owner or operator shall include an estimate of the volume of gas, the concentration of organic HAP in the gas and the resulting emissions of organic HAP that bypassed the control device using process knowledge and engineering estimates. (ii) Where a seal mechanism is used to comply with § 63.644(c)(2), hourly records of flow are not required. In such cases, the owner or operator shall record the date that the monthly visual inspection of the seals or closure mechanisms is completed. The owner or operator shall also record the occurrence of all periods when the seal or closure mechanism is broken, the bypass line valve position has changed or the key for a lock-and-key type lock has been checked out. The owner or operator shall include an estimate of the volume of gas, the concentration of organic HAP in the gas and the resulting mass emissions of organic HAP from the Group 1 miscellaneous process vent stream requiring control that bypassed the control device or records sufficient to demonstrate that there was no flow of a Group 1 miscellaneous process vent stream requiring control during the period. (5) The owner or operator of a heat exchange system subject to this subpart shall comply with the recordkeeping requirements in paragraphs (i)(5)(i) through (v) of this section and retain these records for 5 years. * * * * * (7) Each owner or operator subject to the delayed coking unit decoking operations provisions in § 63.657 must maintain records specified in paragraphs (i)(7)(i) through (iii) of this section. (i) The average pressure or temperature, as applicable, for the 5minute period prior to venting to the atmosphere, draining, or deheading the coke drum for each cooling cycle for each coke drum. (ii) If complying with the 60-cycle rolling average, each 60-cycle rolling average pressure or temperature, as applicable, considering all coke drum venting events in the existing affected source. (iii) For double-quench cooling cycles: E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75252 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations (A) The date, time and duration of each pre-vent draining event. (B) The pressure or temperature of the coke drum vessel, as applicable, for the 15 minute period prior to the pre-vent draining. (C) The drain water temperature at 1minute intervals from the start of prevent draining to the complete closure of the drain valve. (8) For fenceline monitoring systems subject to § 63.658, each owner or operator shall keep the records specified in paragraphs (i)(8)(i) through (x) of this section on an ongoing basis. (i) Coordinates of all passive monitors, including replicate samplers and field blanks, and if applicable, the meteorological station. The owner or operator shall determine the coordinates using an instrument with an accuracy of at least 3 meters. The coordinates shall be in decimal degrees with at least five decimal places. (ii) The start and stop times and dates for each sample, as well as the tube identifying information. (iii) Sampling period average temperature and barometric pressure measurements. (iv) For each outlier determined in accordance with Section 9.2 of Method 325A of appendix A of this part, the sampler location of and the concentration of the outlier and the evidence used to conclude that the result is an outlier. (v) For samples that will be adjusted for a background, the location of and the concentration measured simultaneously by the background sampler, and the perimeter samplers to which it applies. (vi) Individual sample results, the calculated Dc for benzene for each sampling period and the two samples used to determine it, whether background correction was used, and the annual average Dc calculated after each sampling period. (vii) Method detection limit for each sample, including co-located samples and blanks. (viii) Documentation of corrective action taken each time the action level was exceeded. (ix) Other records as required by Methods 325A and 325B of appendix A of this part. (x) If a near-field source correction is used as provided in § 63.658(i), records of hourly meteorological data, including temperature, barometric pressure, wind speed and wind direction, calculated daily unit vector wind direction and daily sigma theta, and other records specified in the site-specific monitoring plan. (9) For each flare subject to § 63.670, each owner or operator shall keep the VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 records specified in paragraphs (i)(9)(i) through (xii) of this section up-to-date and readily accessible, as applicable. (i) Retain records of the output of the monitoring device used to detect the presence of a pilot flame as required in § 63.670(b) for a minimum of 2 years. Retain records of each 15-minute block during which there was at least one minute that no pilot flame is present when regulated material is routed to a flare for a minimum of 5 years. (ii) Retain records of daily visible emissions observations or video surveillance images required in § 63.670(h) as specified in the paragraphs (i)(9)(ii)(A) through (C), as applicable, for a minimum of 3 years. (A) If visible emissions observations are performed using Method 22 at 40 CFR part 60, appendix A–7, the record must identify whether the visible emissions observation was performed, the results of each observation, total duration of observed visible emissions, and whether it was a 5-minute or 2-hour observation. If the owner or operator performs visible emissions observations more than one time during a day, the record must also identify the date and time of day each visible emissions observation was performed. (B) If video surveillance camera is used, the record must include all video surveillance images recorded, with time and date stamps. (C) For each 2 hour period for which visible emissions are observed for more than 5 minutes in 2 consecutive hours, the record must include the date and time of the 2 hour period and an estimate of the cumulative number of minutes in the 2 hour period for which emissions were visible. (iii) The 15-minute block average cumulative flows for flare vent gas and, if applicable, total steam, perimeter assist air, and premix assist air specified to be monitored under § 63.670(i), along with the date and time interval for the 15-minute block. If multiple monitoring locations are used to determine cumulative vent gas flow, total steam, perimeter assist air, and premix assist air, retain records of the 15-minute block average flows for each monitoring location for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If pressure and temperature monitoring is used, retain records of the 15-minute block average temperature, pressure and molecular weight of the flare vent gas or assist gas stream for each measurement location used to determine the 15-minute block average cumulative flows for a minimum of 2 years, and retain the 15-minute block PO 00000 Frm 00076 Fmt 4701 Sfmt 4700 average cumulative flows that are used in subsequent calculations for a minimum of 5 years. (iv) The flare vent gas compositions specified to be monitored under § 63.670(j). Retain records of individual component concentrations from each compositional analyses for a minimum of 2 years. If NHVvg analyzer is used, retain records of the 15-minute block average values for a minimum of 5 years. (v) Each 15-minute block average operating parameter calculated following the methods specified in § 63.670(k) through (n), as applicable. (vi) [Reserved] (vii) All periods during which operating values are outside of the applicable operating limits specified in § 63.670(d) through (f) when regulated material is being routed to the flare. (viii) All periods during which the owner or operator does not perform flare monitoring according to the procedures in § 63.670(g) through (j). (ix) Records of periods when there is flow of vent gas to the flare, but when there is no flow of regulated material to the flare, including the start and stop time and dates of periods of no regulated material flow. (x) Records when the flow of vent gas exceeds the smokeless capacity of the flare, including start and stop time and dates of the flaring event. (xi) Records of the root cause analysis and corrective action analysis conducted as required in § 63.670(o)(3), including an identification of the affected facility, the date and duration of the event, a statement noting whether the event resulted from the same root cause(s) identified in a previous analysis and either a description of the recommended corrective action(s) or an explanation of why corrective action is not necessary under § 63.670(o)(5)(i). (xii) For any corrective action analysis for which implementation of corrective actions are required in § 63.670(o)(5), a description of the corrective action(s) completed within the first 45 days following the discharge and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates. (10) [Reserved] (11) For each pressure relief device subject to the pressure release management work practice standards in § 63.648(j)(3), the owner or operator shall keep the records specified in paragraphs (i)(11)(i) through (iii) of this section. (i) Records of the prevention measures implemented as required in § 63.648(j)(3)(ii), if applicable. E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations (ii) Records of the number of releases during each calendar year and the number of those releases for which the root cause was determined to be a force majeure event. Keep these records for the current calendar year and the past five calendar years. (iii) For each release to the atmosphere, the owner or operator shall keep the records specified in paragraphs (i)(11)(iii)(A) through (D) of this section. (A) The start and end time and date of each pressure release to the atmosphere. (B) Records of any data, assumptions, and calculations used to estimate of the mass quantity of each organic HAP released during the event. (C) Records of the root cause analysis and corrective action analysis conducted as required in § 63.648(j)(3)(iii), including an identification of the affected facility, the date and duration of the event, a statement noting whether the event resulted from the same root cause(s) identified in a previous analysis and either a description of the recommended corrective action(s) or an explanation of why corrective action is not necessary under § 63.648(j)(7)(i). (D) For any corrective action analysis for which implementation of corrective actions are required in § 63.648(j)(7), a description of the corrective action(s) completed within the first 45 days following the discharge and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates. (12) For each maintenance vent opening subject to the requirements in § 63.643(c), the owner or operator shall keep the applicable records specified in (i)(12)(i) through (v) of this section. (i) The owner or operator shall maintain standard site procedures used to deinventory equipment for safety purposes (e.g., hot work or vessel entry procedures) to document the procedures used to meet the requirements in § 63.643(c). The current copy of the procedures shall be retained and available on-site at all times. Previous versions of the standard site procedures, is applicable, shall be retained for five years. (ii) If complying with the requirements of § 63.643(c)(1)(i) and the lower explosive limit at the time of the vessel opening exceeds 10 percent, identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, and the lower explosive limit at the time of the vessel opening. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (iii) If complying with the requirements of § 63.643(c)(1)(ii) and either the vessel pressure at the time of the vessel opening exceeds 5 psig or the lower explosive limit at the time of the active purging was initiated exceeds 10 percent, identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, the pressure of the vessel or equipment at the time of discharge to the atmosphere and, if applicable, the lower explosive limit of the vapors in the equipment when active purging was initiated. (iv) If complying with the requirements of § 63.643(c)(1)(iii), identification of the maintenance vent, the process units or equipment associated with the maintenance vent, the date of maintenance vent opening, and records used to estimate the total quantity of VOC in the equipment at the time the maintenance vent was opened to the atmosphere for each applicable maintenance vent opening. (v) If complying with the requirements of § 63.643(c)(1)(iv), identification of the maintenance vent, the process units or equipment associated with the maintenance vent, records documenting the lack of a pure hydrogen supply, the date of maintenance vent opening, and the lower explosive limit of the vapors in the equipment at the time of discharge to the atmosphere for each applicable maintenance vent opening. 28. Section 63.656 is amended by revising paragraph (c)(1) to read as follows: ■ § 63.656 Implementation and enforcement. * * * * * (c) * * * (1) Approval of alternatives to the requirements in §§ 63.640, 63.642(g) through (l), 63.643, 63.646 through 63.652, 63.654, 63.657 through 63.660, and 63.670. Where these standards reference another subpart, the cited provisions will be delegated according to the delegation provisions of the referenced subpart. Where these standards reference another subpart and modify the requirements, the requirements shall be modified as described in this subpart. Delegation of the modified requirements will also occur according to the delegation provisions of the referenced subpart. * * * * * 29. Section 63.657 is added to read as follows: ■ PO 00000 Frm 00077 Fmt 4701 Sfmt 4700 75253 § 63.657 Delayed coking unit decoking operation standards. (a) Except as provided in paragraphs (e) and (f) of this section, each owner or operator of a delayed coking unit shall depressure each coke drum to a closed blowdown system until the coke drum vessel pressure or temperature measured at the top of the coke drum or in the overhead line of the coke drum as near as practical to the coke drum meets the applicable limits specified in paragraph (a)(1) or (2) of this section prior to venting to the atmosphere, draining or deheading the coke drum at the end of the cooling cycle. (1) For delayed coking units at an existing affected source, meet either: (i) An average vessel pressure of 2 psig determined on a rolling 60-event average; or (ii) An average vessel temperature of 220 degrees Fahrenheit determined on a rolling 60-event average. (2) For delayed coking units at a new affected source, meet either: (i) A vessel pressure of 2.0 psig for each decoking event; or (ii) A vessel temperature of 218 degrees Fahrenheit for each decoking event. (b) Each owner or operator of a delayed coking unit complying with the pressure limits in paragraph (a)(1)(i) or (a)(2)(i) of this section shall install, operate, calibrate, and maintain a monitoring system, as specified in paragraphs (b)(1) through (5) of this section, to determine the coke drum vessel pressure. (1) The pressure monitoring system must be in a representative location (at the top of the coke drum or in the overhead line as near as practical to the coke drum) that minimizes or eliminates pulsating pressure, vibration, and, to the extent practical, internal and external corrosion. (2) The pressure monitoring system must be capable of measuring a pressure of 2.0 psig within ±0.5 psig. (3) The pressure monitoring system must be verified annually or at the frequency recommended by the instrument manufacturer. The pressure monitoring system must be verified following any period of more than 24 hours throughout which the pressure exceeded the maximum rated pressure of the sensor, or the data recorder was off scale. (4) All components of the pressure monitoring system must be visually inspected for integrity, oxidation and galvanic corrosion every 3 months, unless the system has a redundant pressure sensor. (5) The output of the pressure monitoring system must be reviewed E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75254 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations daily to ensure that the pressure readings fluctuate as expected between operating and cooling/decoking cycles to verify the pressure taps are not plugged. Plugged pressure taps must be unplugged or otherwise repaired prior to the next operating cycle. (c) Each owner or operator of a delayed coking unit complying with the temperature limits in paragraph (a)(1)(ii) or (a)(2)(ii) of this section shall install, operate, calibrate, and maintain a continuous parameter monitoring system to measure the coke drum vessel temperature (at the top of the coke drum or in the overhead line as near as practical to the coke drum) according to the requirements specified in table 13 of this subpart. (d) The owner or operator of a delayed coking unit shall determine the coke drum vessel pressure or temperature, as applicable, on a 5-minute rolling average basis while the coke drum is vented to the closed blowdown system and shall use the last complete 5-minute rolling average pressure or temperature just prior to initiating steps to isolate the coke drum prior to venting, draining or deheading to demonstrate compliance with the requirements in paragraph (a) of this section. Pressure or temperature readings after initiating steps to isolate the coke drum from the closed blowdown system just prior to atmospheric venting, draining, or deheading the coke drum shall not be used in determining the average coke drum vessel pressure or temperature for the purpose of compliance with the requirements in paragraph (a) of this section. (e) The owner or operator of a delayed coking unit using the ‘‘water overflow’’ method of coke cooling must hardpipe the overflow water or otherwise prevent exposure of the overflow water to the atmosphere when transferring the overflow water to the overflow water storage tank whenever the coke drum vessel temperature exceeds 220 degrees Fahrenheit. The overflow water storage tank may be an open or fixed-roof tank provided that a submerged fill pipe (pipe outlet below existing liquid level in the tank) is used to transfer overflow water to the tank. The owner or operator of a delayed coking unit using the ‘‘water overflow’’ method of coke cooling shall determine the coke drum vessel temperature as specified in paragraphs (c) and (d) of this section regardless of the compliance method used to demonstrate compliance with the requirements in paragraph (a) of this section. (f) The owner or operator of a delayed coking unit may partially drain a coke drum prior to achieving the applicable VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 limits in paragraph (a) of this section in order to double-quench a coke drum that did not cool adequately using the normal cooling process steps provided that the owner or operator meets the conditions in paragraphs (f)(1) and (2) of this section. (1) The owner or operator shall install, operate, calibrate, and maintain a continuous parameter monitoring system to measure the drain water temperature at the bottom of the coke drum or in the drain line as near as practical to the coke drum according to the requirements specified in table 13 of this subpart. (2) The owner or operator must maintain the drain water temperature below 210 degrees Fahrenheit during the partial drain associated with the double-quench event. ■ 30. Section 63.658 is added to read as follows: § 63.658 Fenceline monitoring provisions. (a) The owner or operator shall conduct sampling along the facility property boundary and analyze the samples in accordance with Methods 325A and 325B of appendix A of this part and paragraphs (b) through (k) of this section. (b) The target analyte is benzene. (c) The owner or operator shall determine passive monitor locations in accordance with Section 8.2 of Method 325A of appendix A of this part. (1) As it pertains to this subpart, known sources of VOCs, as used in Section 8.2.1.3 in Method 325A of appendix A of this part for siting passive monitors means a wastewater treatment unit, process unit, or any emission source requiring control according to the requirements of this subpart, including marine vessel loading operations. For marine loading operations that are located offshore, one passive monitor should be sited on the shoreline adjacent to the dock. (2) The owner or operator may collect one or more background samples if the owner or operator believes that an offsite upwind source or an onsite source excluded under § 63.640(g) may influence the sampler measurements. If the owner or operator elects to collect one or more background samples, the owner of operator must develop and submit a site-specific monitoring plan for approval according to the requirements in paragraph (i) of this section. Upon approval of the sitespecific monitoring plan, the background sampler(s) should be operated co-currently with the routine samplers. (3) The owner or operator shall collect at least one co-located duplicate sample PO 00000 Frm 00078 Fmt 4701 Sfmt 4700 for every 10 field samples per sampling period and at least two field blanks per sampling period, as described in Section 9.3 in Method 325A of appendix A of this part. The co-located duplicates may be collected at any one of the perimeter sampling locations. (4) The owner or operator shall follow the procedure in Section 9.6 of Method 325B of appendix A of this part to determine the detection limit of benzene for each sampler used to collect samples, background samples (if the owner or operator elects to do so), colocated samples and blanks. (d) The owner or operator shall collect and record meteorological data according to the applicable requirements in paragraphs (d)(1) through (3) of this section. (1) If a near-field source correction is used as provided in paragraph (i)(1) of this section or if an alternative test method is used that provides timeresolved measurements, the owner or operator shall: (i) Use an on-site meteorological station in accordance with Section 8.3 of Method 325A of appendix A of this part. (ii) Collect and record hourly average meteorological data, including temperature, barometric pressure, wind speed and wind direction and calculate daily unit vector wind direction and daily sigma theta. (2) For cases other than those specified in paragraph (d)(1) of this section, the owner or operator shall collect and record sampling period average temperature and barometric pressure using either an on-site meteorological station in accordance with Section 8.3 of Method 325A of appendix A of this part or, alternatively, using data from a United States Weather Service (USWS) meteorological station provided the USWS meteorological station is within 40 kilometers (25 miles) of the refinery. (3) If an on-site meteorological station is used, the owner or operator shall follow the calibration and standardization procedures for meteorological measurements in EPA– 454/B–08–002 (incorporated by reference—see § 63.14). (e) The owner of operator shall use a sampling period and sampling frequency as specified in paragraphs (e)(1) through (3) of this section. (1) Sampling period. A 14-day sampling period shall be used, unless a shorter sampling period is determined to be necessary under paragraph (g) or (i) of this section. A sampling period is defined as the period during which sampling tube is deployed at a specific sampling location with the diffusive E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations sampling end cap in-place and does not include the time required to analyze the sample. For the purpose of this subpart, a 14-day sampling period may be no shorter than 13 calendar days and no longer than 15 calendar days, but the routine sampling period shall be 14 calendar days. (2) Base sampling frequency. Except as provided in paragraph (e)(3) of this section, the frequency of sample collection shall be once each contiguous 14-day sampling period, such that the beginning of the next 14-day sampling period begins immediately upon the completion of the previous 14-day sampling period. (3) Alternative sampling frequency for burden reduction. When an individual monitor consistently achieves results at or below 0.9 mg/m3, the owner or operator may elect to use the applicable minimum sampling frequency specified in paragraphs (e)(3)(i) through (v) of this section for that monitoring site. When calculating Dc for the monitoring period when using this alternative for burden reduction, zero shall be substituted for the sample result for the monitoring site for any period where a sample is not taken. (i) If every sample at a monitoring site is at or below 0.9 mg/m3 for 2 years (52 consecutive samples), every other sampling period can be skipped for that monitoring site, i.e., sampling will occur approximately once per month. (ii) If every sample at a monitoring site that is monitored at the frequency specified in paragraph (e)(3)(i) of this section is at or below 0.9 mg/m3 for 2 years (i.e., 26 consecutive ‘‘monthly’’ samples), five 14-day sampling periods can be skipped for that monitoring site following each period of sampling, i.e., sampling will occur approximately once per quarter. (iii) If every sample at a monitoring site that is monitored at the frequency specified in paragraph (e)(3)(ii) of this section is at or below 0.9 mg/m3 for 2 years (i.e., 8 consecutive quarterly samples), twelve 14-day sampling periods can be skipped for that monitoring site following each period of sampling, i.e., sampling will occur twice a year. (iv) If every sample at a monitoring site that is monitored at the frequency specified in paragraph (e)(3)(iii) of this section is at or below 0.9 mg/m3 for an 2 years (i.e., 4 consecutive semi-annual samples), only one sample per year is required for that monitoring site. For yearly sampling, samples shall occur at least 10 months but no more than 14 months apart. (v) If at any time a sample for a monitoring site that is monitored at the VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 frequency specified in paragraphs (e)(3)(i) through (iv) of this section returns a result that is above 0.9 mg/m3, the sampling site must return to the original sampling requirements of contiguous 14-day sampling periods with no skip periods for one quarter (six 14-day sampling periods). If every sample collected during this quarter is at or below 0.9 mg/m3 , the owner or operator may revert back to the reduced monitoring schedule applicable for that monitoring site prior to the sample reading exceeding 0.9 mg/m3 If any sample collected during this quarter is above 0.9 mg/m3, that monitoring site must return to the original sampling requirements of contiguous 14-day sampling periods with no skip periods for a minimum of two years. The burden reduction requirements can be used again for that monitoring site once the requirements of paragraph (e)(3)(i) of this section are met again, i.e., after 52 contiguous 14-day samples with no results above 0.9 mg/m3 . (f) Within 45 days of completion of each sampling period, the owner or operator shall determine whether the results are above or below the action level as follows: (1) The owner or operator shall determine the facility impact on the benzene concentration (Dc) for each 14day sampling period according to either paragraph (f)(1)(i) or (ii) of this section, as applicable. (i) Except when near-field source correction is used as provided in paragraph (i) of this section, the owner or operator shall determine the highest and lowest sample results for benzene concentrations from the sample pool and calculate Dc as the difference in these concentrations. The owner or operator shall adhere to the following procedures when one or more samples for the sampling period are below the method detection limit for benzene: (A) If the lowest detected value of benzene is below detection, the owner or operator shall use zero as the lowest sample result when calculating Dc. (B) If all sample results are below the method detection limit, the owner or operator shall use the method detection limit as the highest sample result. (ii) When near-field source correction is used as provided in paragraph (i) of this section, the owner or operator shall determine Dc using the calculation protocols outlined in the approved sitespecific monitoring plan and in paragraph (i) of this section. (2) The owner or operator shall calculate the annual average Dc based on the average of the 26 most recent 14day sampling periods. The owner or operator shall update this annual PO 00000 Frm 00079 Fmt 4701 Sfmt 4700 75255 average value after receiving the results of each subsequent 14-day sampling period. (3) The action level for benzene is 9 micrograms per cubic meter (mg/m3) on an annual average basis. If the annual average Dc value for benzene is less than or equal to 9 mg/m3, the concentration is below the action level. If the annual average Dc value for benzene is greater than 9 mg/m3, the concentration is above the action level, and the owner or operator shall conduct a root cause analysis and corrective action in accordance with paragraph (g) of this section. (g) Within 5 days of determining that the action level has been exceeded for any annual average Dc and no longer than 50 days after completion of the sampling period, the owner or operator shall initiate a root cause analysis to determine the cause of such exceedance and to determine appropriate corrective action, such as those described in paragraphs (g)(1) through (4) of this section. The root cause analysis and initial corrective action analysis shall be completed and initial corrective actions taken no later than 45 days after determining there is an exceedance. Root cause analysis and corrective action may include, but is not limited to: (1) Leak inspection using Method 21 of part 60, appendix A–7 of this chapter and repairing any leaks found. (2) Leak inspection using optical gas imaging and repairing any leaks found. (3) Visual inspection to determine the cause of the high benzene emissions and implementing repairs to reduce the level of emissions. (4) Employing progressively more frequent sampling, analysis and meteorology (e.g., using shorter sampling periods for Methods 325A and 325B of appendix A of this part, or using active sampling techniques). (h) If, upon completion of the corrective action analysis and corrective actions such as those described in paragraph (g) of this section, the Dc value for the next 14-day sampling period for which the sampling start time begins after the completion of the corrective actions is greater than 9 mg/ m3 or if all corrective action measures identified require more than 45 days to implement, the owner or operator shall develop a corrective action plan that describes the corrective action(s) completed to date, additional measures that the owner or operator proposes to employ to reduce fenceline concentrations below the action level, and a schedule for completion of these measures. The owner or operator shall submit the corrective action plan to the E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75256 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Administrator within 60 days after receiving the analytical results indicating that the Dc value for the 14day sampling period following the completion of the initial corrective action is greater than 9 mg/m3 or, if no initial corrective actions were identified, no later than 60 days following the completion of the corrective action analysis required in paragraph (g) of this section. (i) An owner or operator may request approval from the Administrator for a site-specific monitoring plan to account for offsite upwind sources or onsite sources excluded under § 63.640(g) according to the requirements in paragraphs (i)(1) through (4) of this section. (1) The owner or operator shall prepare and submit a site-specific monitoring plan and receive approval of the site-specific monitoring plan prior to using the near-field source alternative calculation for determining Dc provided in paragraph (i)(2) of this section. The site-specific monitoring plan shall include, at a minimum, the elements specified in paragraphs (i)(1)(i) through (v) of this section. The procedures in Section 12 of Method 325A of appendix A of this part are not required, but may be used, if applicable, when determining near-field source contributions. (i) Identification of the near-field source or sources. For onsite sources, documentation that the onsite source is excluded under § 63.640(g) and identification of the specific provision in § 63.640(g) that applies to the source. (ii) Location of the additional monitoring stations that shall be used to determine the uniform background concentration and the near-field source concentration contribution. (iii) Identification of the fenceline monitoring locations impacted by the near-field source. If more than one nearfield source is present, identify the nearfield source or sources that are expected to contribute to the concentration at that monitoring location. (iv) A description of (including sample calculations illustrating) the planned data reduction and calculations to determine the near-field source concentration contribution for each monitoring location. (v) If more frequent monitoring or a monitoring station other than a passive diffusive tube monitoring station is proposed, provide a detailed description of the measurement methods, measurement frequency, and recording frequency for determining the uniform background or near-field source concentration contribution. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (2) When an approved site-specific monitoring plan is used, the owner or operator shall determine Dc for comparison with the 9 mg/m3 action level using the requirements specified in paragraphs (i)(2)(i) through (iii) of this section. (i) For each monitoring location, calculate Dci using the following equation. Dci = MFCi ¥ NFSi ¥ UB Where: Dci = The fenceline concentration, corrected for background, at measurement location i, micrograms per cubic meter (mg/m3). MFCi = The measured fenceline concentration at measurement location i, mg/m3. NFSi = The near-field source contributing concentration at measurement location i determined using the additional measurements and calculation procedures included in the site-specific monitoring plan, mg/m3. For monitoring locations that are not included in the site-specific monitoring plan as impacted by a near-field source, use NFSi = 0 mg/ m3. UB = The uniform background concentration determined using the additional measurements included in the sitespecific monitoring plan, mg/m3. If no additional measurements are specified in the site-specific monitoring plan for determining the uniform background concentration, use UB = 0 mg/m3. (ii) When one or more samples for the sampling period are below the method detection limit for benzene, adhere to the following procedures: (A) If the benzene concentration at the monitoring location used for the uniform background concentration is below the method detection limit, the owner or operator shall use zero for UB for that monitoring period. (B) If the benzene concentration at the monitoring location(s) used to determine the near-field source contributing concentration is below the method detection limit, the owner or operator shall use zero for the monitoring location concentration when calculating NFSi for that monitoring period. (C) If a fenceline monitoring location sample result is below the method detection limit, the owner or operator shall use the method detection limit as the sample result. (iii) Determine Dc for the monitoring period as the maximum value of Dci from all of the fenceline monitoring locations for that monitoring period. (3) The site-specific monitoring plan shall be submitted and approved as described in paragraphs (i)(3)(i) through (iv) of this section. PO 00000 Frm 00080 Fmt 4701 Sfmt 4700 (i) The site-specific monitoring plan must be submitted to the Administrator for approval. (ii) The site-specific monitoring plan shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143–01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refineryrtr@ epa.gov. (iii) The Administrator shall approve or disapprove the plan in 90 days. The plan shall be considered approved if the Administrator either approves the plan in writing, or fails to disapprove the plan in writing. The 90-day period shall begin when the Administrator receives the plan. (iv) If the Administrator finds any deficiencies in the site-specific monitoring plan and disapproves the plan in writing, the owner or operator may revise and resubmit the sitespecific monitoring plan following the requirements in paragraphs (i)(3)(i) and (ii) of this section. The 90-day period starts over with the resubmission of the revised monitoring plan. (4) The approval by the Administrator of a site-specific monitoring plan will be based on the completeness, accuracy and reasonableness of the request for a site-specific monitoring plan. Factors that the Administrator will consider in reviewing the request for a site-specific monitoring plan include, but are not limited to, those described in paragraphs (i)(4)(i) through (v) of this section. (i) The identification of the near-field source or sources. For onsite sources, the documentation provided that the onsite source is excluded under § 63.640(g). (ii) The monitoring location selected to determine the uniform background concentration or an indication that no uniform background concentration monitor will be used. (iii) The location(s) selected for additional monitoring to determine the near-field source concentration contribution. (iv) The identification of the fenceline monitoring locations impacted by the near-field source or sources. (v) The appropriateness of the planned data reduction and calculations to determine the near-field source concentration contribution for each monitoring location. (vi) If more frequent monitoring is proposed, the adequacy of the description of the measurement and E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations recording frequency proposed and the adequacy of the rationale for using the alternative monitoring frequency. (j) The owner or operator shall comply with the applicable recordkeeping and reporting requirements in § 63.655(h) and (i). (k) As outlined in § 63.7(f), the owner or operator may submit a request for an alternative test method. At a minimum, the request must follow the requirements outlined in paragraphs (k)(1) through (7) of this section. (1) The alternative method may be used in lieu of all or a partial number of passive samplers required in Method 325A of appendix A of this part. (2) The alternative method must be validated according to Method 301 in appendix A of this part or contain performance based procedures and indicators to ensure self-validation. (3) The method detection limit must nominally be at least an order of magnitude below the action level, i.e., 0.9 mg/m3 benzene. The alternate test method must describe the procedures used to provide field verification of the detection limit. (4) The spatial coverage must be equal to or better than the spatial coverage provided in Method 325A of appendix A of this part. (i) For path average concentration open-path instruments, the physical path length of the measurement shall be no more than a passive sample footprint (the spacing that would be provided by the sorbent traps when following Method 325A). For example, if Method 325A requires spacing monitors A and B 610 meters (2000 feet) apart, then the physical path length limit for the measurement at that portion of the fenceline shall be no more than 610 meters (2000 feet). (ii) For range resolved open-path instrument or approach, the instrument or approach must be able to resolve an average concentration over each passive sampler footprint within the path length of the instrument. (iii) The extra samplers required in Sections 8.2.1.3 of Method 325A may be omitted when they fall within the path length of an open-path instrument. (5) At a minimum, non-integrating alternative test methods must provide a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15minute period. (6) For alternative test methods capable of real time measurements (less than a 5 minute sampling and analysis cycle), the alternative test method may allow for elimination of data points corresponding to outside emission sources for purpose of calculation of the VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 high point for the two week average. The alternative test method approach must have wind speed, direction and stability class of the same time resolution and within the footprint of the instrument. (7) For purposes of averaging data points to determine the Dc for the 14day average high sample result, all results measured under the method detection limit must use the method detection limit. For purposes of averaging data points for the 14-day average low sample result, all results measured under the method detection limit must use zero. ■ 31. Section 63.660 is added to read as follows: § 63.660 Storage vessel provisions. On and after the applicable compliance date for a Group 1 storage vessel located at a new or existing source as specified in § 63.640(h), the owner or operator of a Group 1 storage vessel that is part of a new or existing source shall comply with the requirements in subpart WW or SS of this part according to the requirements in paragraphs (a) through (i) of this section. (a) As used in this section, all terms not defined in § 63.641 shall have the meaning given them in subpart A, WW, or SS of this part. The definitions of ‘‘Group 1 storage vessel’’ (paragraph (2)) and ‘‘Storage vessel’’ in § 63.641 shall apply in lieu of the definition of ‘‘Storage vessel’’ in § 63.1061. (1) An owner or operator may use good engineering judgment or test results to determine the stored liquid weight percent total organic HAP for purposes of group determination. Data, assumptions, and procedures used in the determination shall be documented. (2) When an owner or operator and the Administrator do not agree on whether the annual average weight percent organic HAP in the stored liquid is above or below 4 percent for a storage vessel at an existing source or above or below 2 percent for a storage vessel at a new source, an appropriate method (based on the type of liquid stored) as published by EPA or a consensus-based standards organization shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–B2959, (800) 262– 1373, https://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street NW., 6th Floor, Washington, DC 20036, (202) 293–8020, https://www.ansi.org), the American Gas Association (AGA, 400 North Capitol PO 00000 Frm 00081 Fmt 4701 Sfmt 4700 75257 Street NW., 4th Floor, Washington, DC 20001, (202) 824–7000, https:// www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016– 5990, (800) 843–2763, https:// www.asme.org), the American Petroleum Institute (API, 1220 L Street NW., Washington, DC 20005–4070, (202) 682–8000, https://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356–0060, https://www.naesb.org). (b) A floating roof storage vessel complying with the requirements of subpart WW of this part may comply with the control option specified in paragraph (b)(1) of this section and, if equipped with a ladder having at least one slotted leg, shall comply with one of the control options as described in paragraph (b)(2) of this section. (1) In addition to the options presented in §§ 63.1063(a)(2)(viii)(A) and (B) and 63.1064, a floating roof storage vessel may comply with § 63.1063(a)(2)(vii) using a flexible enclosure device and either a gasketed or welded cap on the top of the guidepole. (2) Each opening through a floating roof for a ladder having at least one slotted leg shall be equipped with one of the configurations specified in paragraphs (b)(2)(i) through (iii) of this section. (i) A pole float in the slotted leg and pole wipers for both legs. The wiper or seal of the pole float must be at or above the height of the pole wiper. (ii) A ladder sleeve and pole wipers for both legs of the ladder. (iii) A flexible enclosure device and either a gasketed or welded cap on the top of the slotted leg. (c) For the purposes of this subpart, references shall apply as specified in paragraphs (c)(1) through (6) of this section. (1) All references to ‘‘the proposal date for a referencing subpart’’ and ‘‘the proposal date of the referencing subpart’’ in subpart WW of this part mean June 30, 2014. (2) All references to ‘‘promulgation of the referencing subpart’’ and ‘‘the promulgation date of the referencing subpart’’ in subpart WW of this part mean February 1, 2016. (3) All references to ‘‘promulgation date of standards for an affected source or affected facility under a referencing subpart’’ in subpart SS of this part mean February 1, 2016. (4) All references to ‘‘the proposal date of the relevant standard established pursuant to CAA section 112(f)’’ in E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations subpart SS of this part mean June 30, 2014. (5) All references to ‘‘the proposal date of a relevant standard established pursuant to CAA section 112(d)’’ in subpart SS of this part mean July 14, 1994. (6) All references to the ‘‘required control efficiency’’ in subpart SS of this part mean reduction of organic HAP emissions by 95 percent or to an outlet concentration of 20 ppmv. (d) For an uncontrolled fixed roof storage vessel that commenced construction on or before June 30, 2014, and that meets the definition of ‘‘Group 1 storage vessel’’, paragraph (2), in § 63.641 but not the definition of ‘‘Group 1 storage vessel’’, paragraph (1), in § 63.641, the requirements of § 63.982 and/or § 63.1062 do not apply until the next time the storage vessel is completely emptied and degassed, or January 30, 2026, whichever occurs first. (e) Failure to perform inspections and monitoring required by this section shall constitute a violation of the applicable standard of this subpart. (f) References in § 63.1066(a) to initial startup notification requirements do not apply. (g) References to the Notification of Compliance Status in § 63.999(b) mean the Notification of Compliance Status required by § 63.655(f). (h) References to the Periodic Reports in §§ 63.1066(b) and 63.999(c) mean the Periodic Report required by § 63.655(g). (i) Owners or operators electing to comply with the requirements in subpart SS of this part for a Group 1 storage vessel must comply with the requirements in paragraphs (i)(1) through (3) of this section. (1) If a flare is used as a control device, the flare shall meet the requirements of § 63.670 instead of the flare requirements in § 63.987. (2) If a closed vent system contains a bypass line, the owner or operator shall comply with the provisions of either § 63.983(a)(3)(i) or (ii) for each closed vent system that contains bypass lines that could divert a vent stream either directly to the atmosphere or to a control device that does not comply with the requirements in subpart SS of this part. Except as provided in paragraphs (i)(2)(i) and (ii) of this section, use of the bypass at any time to divert a Group 1 storage vessel to either directly to the atmosphere or to a control device that does not comply with the requirements in subpart SS of this part is an emissions standards violation. Equipment such as low leg drains and equipment subject to VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 § 63.648 are not subject to this paragraph (i)(2). (i) If planned routine maintenance of the control device cannot be performed during periods that storage vessel emissions are vented to the control device or when the storage vessel is taken out of service for inspections or other planned maintenance reasons, the owner or operator may bypass the control device. (ii) Periods for which storage vessel control device may be bypassed for planned routine maintenance of the control device shall not exceed 240 hours per calendar year. (3) If storage vessel emissions are routed to a fuel gas system or process, the fuel gas system or process shall be operating at all times when regulated emissions are routed to it. The exception in § 63.984(a)(1) does not apply. ■ 32. Section 63.670 is added to read as follows: § 63.670 Requirements for flare control devices. On or before January 30, 2019, the owner or operator of a flare used as a control device for an emission point subject to this subpart shall meet the applicable requirements for flares as specified in paragraphs (a) through (q) of this section and the applicable requirements in § 63.671. The owner or operator may elect to comply with the requirements of paragraph (r) of this section in lieu of the requirements in paragraphs (d) through (f) of this section, as applicable. (a) [Reserved] (b) Pilot flame presence. The owner or operator shall operate each flare with a pilot flame present at all times when regulated material is routed to the flare. Each 15-minute block during which there is at least one minute where no pilot flame is present when regulated material is routed to the flare is a deviation of the standard. Deviations in different 15-minute blocks from the same event are considered separate deviations. The owner or operator shall monitor for the presence of a pilot flame as specified in paragraph (g) of this section. (c) Visible emissions. The owner or operator shall specify the smokeless design capacity of each flare and operate with no visible emissions, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours, when regulated material is routed to the flare and the flare vent gas flow rate is less than the smokeless design capacity of the flare. The owner or operator shall monitor for visible PO 00000 Frm 00082 Fmt 4701 Sfmt 4700 emissions from the flare as specified in paragraph (h) of this section. (d) Flare tip velocity. For each flare, the owner or operator shall comply with either paragraph (d)(1) or (2) of this section, provided the appropriate monitoring systems are in-place, whenever regulated material is routed to the flare for at least 15-minutes and the flare vent gas flow rate is less than the smokeless design capacity of the flare. (1) Except as provided in paragraph (d)(2) of this section, the actual flare tip velocity (Vtip) must be less than 60 feet per second. The owner or operator shall monitor Vtipusing the procedures specified in paragraphs (i) and (k) of this section. (2) Vtip must be less than 400 feet per second and also less than the maximum allowed flare tip velocity (Vmax) as calculated according to the following equation. The owner or operator shall monitor Vtip using the procedures specified in paragraphs (i) and (k) of this section and monitor gas composition and determine NHVvg using the procedures specified in paragraphs (j) and (l) of this section. Where: Vmax = Maximum allowed flare tip velocity, ft/sec. NHVvg = Net heating value of flare vent gas, as determined by paragraph (l)(4) of this section, Btu/scf. 1,212 = Constant. 850 = Constant. (e) Combustion zone operating limits. For each flare, the owner or operator shall operate the flare to maintain the net heating value of flare combustion zone gas (NHVcz) at or above 270 British thermal units per standard cubic feet (Btu/scf) determined on a 15-minute block period basis when regulated material is routed to the flare for at least 15-minutes. The owner or operator shall monitor and calculate NHVcz as specified in paragraph (m) of this section. (f) Dilution operating limits for flares with perimeter assist air. For each flare actively receiving perimeter assist air, the owner or operator shall operate the flare to maintain the net heating value dilution parameter (NHVdil) at or above 22 British thermal units per square foot (Btu/ft2) determined on a 15-minute block period basis when regulated material is being routed to the flare for at least 15-minutes. The owner or operator shall monitor and calculate NHVdil as specified in paragraph (n) of this section. E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.008</GPH> tkelley on DSK3SPTVN1PROD with RULES2 75258 (g) Pilot flame monitoring. The owner or operator shall continuously monitor the presence of the pilot flame(s) using a device (including, but not limited to, a thermocouple, ultraviolet beam sensor, or infrared sensor) capable of detecting that the pilot flame(s) is present. (h) Visible emissions monitoring. The owner or operator shall monitor visible emissions while regulated materials are vented to the flare. An initial visible emissions demonstration must be conducted using an observation period of 2 hours using Method 22 at 40 CFR part 60, appendix A–7. Subsequent visible emissions observations must be conducted using either the methods in paragraph (h)(1) of this section or, alternatively, the methods in paragraph (h)(2) of this section. The owner or operator must record and report any instances where visible emissions are observed for more than 5 minutes during any 2 consecutive hours as specified in § 63.655(g)(11)(ii). (1) At least once per day, conduct visible emissions observations using an observation period of 5 minutes using Method 22 at 40 CFR part 60, appendix A–7. If at any time the owner or operator sees visible emissions, even if the minimum required daily visible emission monitoring has already been performed, the owner or operator shall immediately begin an observation period of 5 minutes using Method 22 at 40 CFR part 60, appendix A–7. If visible emissions are observed for more than one continuous minute during any 5minute observation period, the observation period using Method 22 at 40 CFR part 60, appendix A–7 must be extended to 2 hours or until 5-minutes of visible emissions are observed. (2) Use a video surveillance camera to continuously record (at least one frame every 15 seconds with time and date stamps) images of the flare flame and a reasonable distance above the flare flame at an angle suitable for visual emissions observations. The owner or operator must provide real-time video surveillance camera output to the control room or other continuously manned location where the camera images may be viewed at any time. (i) Flare vent gas, steam assist and air assist flow rate monitoring. The owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording the volumetric flow rate in the flare header or headers that feed the flare as well as any supplemental natural gas used. Different flow monitoring methods may be used to measure different gaseous streams that make up VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 the flare vent gas provided that the flow rates of all gas streams that contribute to the flare vent gas are determined. If assist air or assist steam is used, the owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording the volumetric flow rate of assist air and/or assist steam used with the flare. If pre-mix assist air and perimeter assist are both used, the owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of separately measuring, calculating, and recording the volumetric flow rate of premix assist air and perimeter assist air used with the flare. Continuously monitoring fan speed or power and using fan curves is an acceptable method for continuously monitoring assist air flow rates. (1) The flow rate monitoring systems must be able to correct for the temperature and pressure of the system and output parameters in standard conditions (i.e., a temperature of 20 °C (68 °F) and a pressure of 1 atmosphere). (2) Mass flow monitors may be used for determining volumetric flow rate of flare vent gas provided the molecular weight of the flare vent gas is determined using compositional analysis as specified in paragraph (j) of this section so that the mass flow rate can be converted to volumetric flow at standard conditions using the following equation. Where: Qvol = Volumetric flow rate, standard cubic feet per second. Qmass = Mass flow rate, pounds per second. 385.3 = Conversion factor, standard cubic feet per pound-mole. MWt = Molecular weight of the gas at the flow monitoring location, pounds per pound-mole. (3) Mass flow monitors may be used for determining volumetric flow rate of assist air or assist steam. Use equation in paragraph (i)(2) of this section to convert mass flow rates to volumetric flow rates. Use a molecular weight of 18 pounds per pound-mole for assist steam and use a molecular weight of 29 pounds per pound-mole for assist air. (4) Continuous pressure/temperature monitoring system(s) and appropriate engineering calculations may be used in lieu of a continuous volumetric flow monitoring systems provided the molecular weight of the gas is known. For assist steam, use a molecular weight of 18 pounds per pound-mole. For assist air, use a molecular weight of 29 pounds PO 00000 Frm 00083 Fmt 4701 Sfmt 4700 75259 per pound-mole. For flare vent gas, molecular weight must be determined using compositional analysis as specified in paragraph (j) of this section. (j) Flare vent gas composition monitoring. The owner or operator shall determine the concentration of individual components in the flare vent gas using either the methods provided in paragraph (j)(1) or (2) of this section, to assess compliance with the operating limits in paragraph (e) of this section and, if applicable, paragraphs (d) and (f) of this section. Alternatively, the owner or operator may elect to directly monitor the net heating value of the flare vent gas following the methods provided in paragraphs (j)(3) of this section and, if desired, may directly measure the hydrogen concentration in the flare vent gas following the methods provided in paragraphs (j)(4) of this section. The owner or operator may elect to use different monitoring methods for different gaseous streams that make up the flare vent gas using different methods provided the composition or net heating value of all gas streams that contribute to the flare vent gas are determined. (1) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring (i.e., at least once every 15minutes), calculating, and recording the individual component concentrations present in the flare vent gas. (2) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator shall install, operate, and maintain a grab sampling system capable of collecting an evacuated canister sample for subsequent compositional analysis at least once every eight hours while there is flow of regulated material to the flare. Subsequent compositional analysis of the samples must be performed according to Method 18 of 40 CFR part 60, appendix A–6, ASTM D6420–99 (Reapproved 2010), ASTM D1945–03 (Reapproved 2010), ASTM D1945–14 or ASTM UOP539–12 (all incorporated by reference—see § 63.14). (3) Except as provided in paragraphs (j)(5) and (6) of this section, the owner or operator shall install, operate, calibrate, and maintain a calorimeter capable of continuously measuring, calculating, and recording NHVvg at standard conditions. (4) If the owner or operator uses a continuous net heating value monitor according to paragraph (j)(3) of this section, the owner or operator may, at their discretion, install, operate, calibrate, and maintain a monitoring E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.009</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 75260 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations system capable of continuously measuring, calculating, and recording the hydrogen concentration in the flare vent gas. (5) Direct compositional or net heating value monitoring is not required for purchased (‘‘pipeline quality’’) natural gas streams. The net heating value of purchased natural gas streams may be determined using annual or more frequent grab sampling at any one representative location. Alternatively, the net heating value of any purchased natural gas stream can be assumed to be 920 Btu/scf. (6) Direct compositional or net heating value monitoring is not required for gas streams that have been demonstrated to have consistent composition (or a fixed minimum net heating value) according to the methods in paragraphs (j)(6)(i) through (v) of this section. (i) The owner or operator shall submit to the Administrator a written application for an exemption from monitoring. The application must contain the following information: (A) A description of the flare gas stream/system to be considered, including submission of a portion of the appropriate piping diagrams indicating the boundaries of the flare gas stream/ system and the affected flare(s) to be considered; (B) A statement that there are no crossover or entry points to be introduced into the flare gas stream/ system (this should be shown in the piping diagrams) prior to the point where the flow rate of the gas streams is measured; (C) An explanation of the conditions that ensure that the flare gas net heating value is consistent and, if flare gas net heating value is expected to vary (e.g., due to product loading of different material), the conditions expected to produce the flare gas with the lowest net heating value; (D) The supporting test results from sampling the requested flare gas stream/ system for the net heating value. Sampling data must include, at minimum, 2 weeks of daily measurement values (14 grab samples) for frequently operated flare gas streams/systems; for infrequently operated flare gas streams/systems, seven grab samples must be collected unless other additional information would support reduced sampling. If the flare gas stream composition can vary, samples must be taken during those conditions expected to result in lowest net heating value identified in paragraph (j)(6)(i)(C) of this section. The owner or operator shall determine net heating value for the gas stream using VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 either gas composition analysis or net heating value monitor (with optional hydrogen concentration analyzer) according to the method provided in paragraph (l) of this section; and (E) A description of how the 2 weeks (or seven samples for infrequently operated flare gas streams/systems) of monitoring results compares to the typical range of net heating values expected for the flare gas stream/system going to the affected flare (e.g., ‘‘the samples are representative of typical operating conditions of the flare gas stream going to the loading rack flare’’ or ‘‘the samples are representative of conditions expected to yield the lowest net heating value of the flare gas stream going to the loading rack flare’’). (F) The net heating value to be used for all flows of the flare vent gas from the flare gas stream/system covered in the application. A single net heating value must be assigned to the flare vent gas either by selecting the lowest net heating value measured in the sampling program or by determining the 95th percent confidence interval on the mean value of all samples collected using the t-distribution statistic (which is 1.943 for 7 grab samples or 1.771 for 14 grab samples). (ii) The effective date of the exemption is the date of submission of the information required in paragraph (j)(6)(i) of this section. (iii) No further action is required unless refinery operating conditions change in such a way that affects the exempt fuel gas stream/system (e.g., the stream composition changes). If such a change occurs, the owner or operator shall follow the procedures in paragraph (j)(6)(iii)(A), (B), or (C) of this section. (A) If the operation change results in a flare vent gas net heating value that is still within the range of net heating values included in the original application, the owner or operator shall determine the net heating value on a grab sample and record the results as proof that the net heating value assigned to the vent gas stream in the original application is still appropriate. (B) If the operation change results in a flare vent gas net heating value that is lower than the net heating value assigned to the vent gas stream in the original application, the owner or operator may submit new information following the procedures of paragraph (j)(6)(i) of this section within 60 days (or within 30 days after the seventh grab sample is tested for infrequently operated process units). (C) If the operation change results in a flare vent gas net heating value has greater variability in the flare gas stream/system such the owner or PO 00000 Frm 00084 Fmt 4701 Sfmt 4700 operator chooses not to submit new information to support an exemption, the owner or operator must begin monitoring the composition or net heat content of the flare vent gas stream using the methods in this section (i.e., grab samples every 8 hours until such time a continuous monitor, if elected, is installed). (k) Calculation methods for cumulative flow rates and determining compliance with Vtip operating limits. The owner or operator shall determine Vtip on a 15-minute block average basis according to the following requirements. (1) The owner or operator shall use design and engineering principles to determine the unobstructed cross sectional area of the flare tip. The unobstructed cross sectional area of the flare tip is the total tip area that vent gas can pass through. This area does not include any stability tabs, stability rings, and upper steam or air tubes because flare vent gas does not exit through them. (2) The owner or operator shall determine the cumulative volumetric flow of flare vent gas for each 15-minute block average period using the data from the continuous flow monitoring system required in paragraph (i) of this section according to the following requirements, as applicable. If desired, the cumulative flow rate for a 15-minute block period only needs to include flow during those periods when regulated material is sent to the flare, but owners or operators may elect to calculate the cumulative flow rates across the entire 15-minute block period for any 15-minute block period where there is regulated material flow to the flare. (i) Use set 15-minute time periods starting at 12 midnight to 12:15 a.m., 12:15 a.m. to 12:30 a.m. and so on concluding at 11:45 p.m. to midnight when calculating 15-minute block average flow volumes. (ii) If continuous pressure/ temperature monitoring system(s) and engineering calculations are used as allowed under paragraph (i)(4) of this section, the owner or operator shall, at a minimum, determine the 15-minute block average temperature and pressure from the monitoring system and use those values to perform the engineering calculations to determine the cumulative flow over the 15-minute block average period. Alternatively, the owner or operator may divide the 15minute block average period into equal duration subperiods (e.g., three 5minute periods) and determine the average temperature and pressure for each subperiod, perform engineering calculations to determine the flow for each subperiod, then add the volumetric E:\FR\FM\01DER2.SGM 01DER2 Where: Vtip = Flare tip velocity, feet per second. Qcum = Cumulative volumetric flow over 15minute block average period, actual cubic feet. Area = Unobstructed area of the flare tip, square feet. 900 = Conversion factor, seconds per 15minute block average. tkelley on DSK3SPTVN1PROD with RULES2 (4) If the owner or operator chooses to comply with paragraph (d)(2) of this section, the owner or operator shall also determine the net heating value of the flare vent gas following the requirements in paragraphs (j) and (l) of this section and calculate Vmax using the equation in paragraph (d)(2) of this section in order to compare Vtip to Vmax on a 15-minute block average basis. (l) Calculation methods for determining flare vent gas net heating value. The owner or operator shall determine the net heating value of the flare vent gas (NHVvg) based on the composition monitoring data on a 15minute block average basis according to the following requirements. (1) If compositional analysis data are collected as provided in paragraph (j)(1) or (2) of this section, the owner or operator shall determine NHVvg of a specific sample by using the following equation. Where: NHVvg = Net heating value of flare vent gas, Btu/scf. i = Individual component in flare vent gas. n = Number of components in flare vent gas. xi = Concentration of component i in flare vent gas, volume fraction. NHVi = Net heating value of component i according to table 12 of this subpart, Btu/ scf. If the component is not specified in table 12 of this subpart, the heats of combustion may be determined using any published values where the net enthalpy per mole of offgas is based on combustion at 25 °C and 1 atmosphere (or constant pressure) with offgas water in the gaseous state, but the standard temperature for determining the volume corresponding to one mole of vent gas is 20 °C. (2) If direct net heating value monitoring data are collected as provided in paragraph (j)(3) of this VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 section but a hydrogen concentration monitor is not used, the owner or operator shall use the direct output of the monitoring system(s) (in Btu/scf) to determine the NHVvg for the sample. (3) If direct net heating value monitoring data are collected as provided in paragraph (j)(3) of this section and hydrogen concentration monitoring data are collected as provided in paragraph (j)(4) of this section, the owner or operator shall use the following equation to determine NHVvg for each sample measured via the net heating value monitoring system. NHVvg = NHVmeasured + 938xH2 Where: NHVvg = Net heating value of flare vent gas, Btu/scf. NHVmeasured = Net heating value of flare vent gas stream as measured by the continuous net heating value monitoring system, Btu/scf. xH2 = Concentration of hydrogen in flare vent gas at the time the sample was input into the net heating value monitoring system, volume fraction. 938 = Net correction for the measured heating value of hydrogen (1,212 ¥ 274), Btu/scf. (4) Use set 15-minute time periods starting at 12 midnight to 12:15 a.m., 12:15 a.m. to 12:30 a.m. and so on concluding at 11:45 p.m. to midnight when calculating 15-minute block averages. (5) When a continuous monitoring system is used as provided in paragraph (j)(1) or (3) of this section and, if applicable, paragraph (j)(4) of this section, the owner or operator may elect to determine the 15-minute block average NHVvg using either the calculation methods in paragraph (l)(5)(i) of this section or the calculation methods in paragraph (l)(5)(ii) of this section. The owner or operator may choose to comply using the calculation methods in paragraph (l)(5)(i) of this section for some flares at the petroleum refinery and comply using the calculation methods (l)(5)(ii) of this section for other flares. However, for each flare, the owner or operator must elect one calculation method that will apply at all times, and use that method for all continuously monitored flare vent streams associated with that flare. If the owner or operator intends to change the calculation method that applies to a flare, the owner or operator must notify the Administrator 30 days in advance of such a change. (i) Feed-forward calculation method. When calculating NHVvg for a specific 15-minute block: (A) Use the results from the first sample collected during an event, (for PO 00000 Frm 00085 Fmt 4701 Sfmt 4700 periodic flare vent gas flow events) for the first 15-minute block associated with that event. (B) If the results from the first sample collected during an event (for periodic flare vent gas flow events) are not available until after the second 15minute block starts, use the results from the first sample collected during an event for the second 15-minute block associated with that event. (C) For all other cases, use the results that are available from the most recent sample prior to the 15-minute block period for that 15-minute block period for all flare vent gas steams. For the purpose of this requirement, use the time that the results become available rather than the time the sample was collected. For example, if a sample is collected at 12:25 a.m. and the analysis is completed at 12:38 a.m., the results are available at 12:38 a.m. and these results would be used to determine compliance during the 15-minute block period from 12:45 a.m. to 1:00 a.m. (ii) Direct calculation method. When calculating NHVvg for a specific 15minute block: (A) If the results from the first sample collected during an event (for periodic flare vent gas flow events) are not available until after the second 15minute block starts, use the results from the first sample collected during an event for the first 15-minute block associated with that event. (B) For all other cases, use the arithmetic average of all NHVvg measurement data results that become available during a 15-minute block to calculate the 15-minute block average for that period. For the purpose of this requirement, use the time that the results become available rather than the time the sample was collected. For example, if a sample is collected at 12:25 a.m. and the analysis is completed at 12:38 a.m., the results are available at 12:38 a.m. and these results would be used to determine compliance during the 15-minute block period from 12:30 a.m. to 12:45 a.m. (6) When grab samples are used to determine flare vent gas composition: (i) Use the analytical results from the first grab sample collected for an event for all 15-minute periods from the start of the event through the 15-minute block prior to the 15-minute block in which a subsequent grab sample is collected. (ii) Use the results from subsequent grab sampling events for all 15 minute periods starting with the 15-minute block in which the sample was collected and ending with the 15-minute block prior to the 15-minute block in which the next grab sample is collected. For E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.011</GPH> flows for the subperiods to determine the cumulative volumetric flow of vent gas for the 15-minute block average period. (3) The 15-minute block average Vtip shall be calculated using the following equation. 75261 ER01DE15.010</GPH> Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75262 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations (6) of this section and a flow-weighted average of the gas stream net heating values shall be used to determine the 15-minute block average net heating value of the cumulative flare vent gas. (m) Calculation methods for determining combustion zone net heating value. The owner or operator shall determine the net heating value of the combustion zone gas (NHVcz) as specified in paragraph (m)(1) or (2) of this section, as applicable. (1) Except as specified in paragraph (m)(2) of this section, determine the 15minute block average NHVcz based on the 15-minute block average vent gas and assist gas flow rates using the following equation. For periods when there is no assist steam flow or premix assist air flow, NHVcz = NHVvg. Where: NHVcz = Net heating value of combustion zone gas, Btu/scf. NHVvg = Net heating value of flare vent gas for the 15-minute block period, Btu/scf. Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block period, scf. this section and that monitor gas composition or net heating value in a location representative of the cumulative vent gas stream and that directly monitor supplemental natural gas flow additions to the flare must determine the 15-minute block average NHVcz using the following equation. Where: NHVcz = Net heating value of combustion zone gas, Btu/scf. NHVvg = Net heating value of flare vent gas for the 15-minute block period, Btu/scf. Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. QNG2 = Cumulative volumetric flow of supplemental natural gas to the flare during the 15-minute block period, scf. QNG1 = Cumulative volumetric flow of supplemental natural gas to the flare during the previous 15-minute block period, scf. For the first 15-minute block period of an event, use the volumetric flow value for the current 15-minute block period, i.e., QNG1=QNG2. NHVNG = Net heating value of supplemental natural gas to the flare for the 15-minute block period determined according to the requirements in paragraph (j)(5) of this section, Btu/scf. Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block period, scf. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (2) Owners or operators of flares that use the feed-forward calculation PO 00000 Frm 00086 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.015</GPH> Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block period, scf. Qa,perimeter = Cumulative volumetric flow of perimeter assist air during the 15-minute block period, scf. methodology in paragraph (l)(5)(i) of this section and that monitor gas composition or net heating value in a location representative of the cumulative vent gas stream and that directly monitor supplemental natural gas flow additions to the flare must determine the 15-minute block average NHVdil using the following equation only during periods when perimeter assist air is used. For 15-minute block periods when there is no cumulative ER01DE15.014</GPH> (n) Calculation methods for determining the net heating value dilution parameter. The owner or operator shall determine the net heating value dilution parameter (NHVdil) as specified in paragraph (n)(1) or (2) of this section, as applicable. (1) Except as specified in paragraph (n)(2) of this section, determine the 15minute block average NHVdil based on the 15-minute block average vent gas and perimeter assist air flow rates using the following equation only during periods when perimeter assist air is used. For 15-minute block periods when there is no cumulative volumetric flow of perimeter assist air, the 15-minute block average NHVdil parameter does not need to be calculated. ER01DE15.013</GPH> Where: NHVdil = Net heating value dilution parameter, Btu/ft2. NHVvg = Net heating value of flare vent gas determined for the 15-minute block period, Btu/scf. Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. Diam = Effective diameter of the unobstructed area of the flare tip for flare vent gas flow, ft. Use the area as determined in paragraph (k)(1) of this section and determine the diameter as (2) Owners or operators of flares that use the feed-forward calculation methodology in paragraph (l)(5)(i) of ER01DE15.012</GPH> tkelley on DSK3SPTVN1PROD with RULES2 the purpose of this requirement, use the time the sample was collected rather than the time the analytical results become available. (7) If the owner or operator monitors separate gas streams that combine to comprise the total flare vent gas flow, the 15-minute block average net heating value shall be determined separately for each measurement location according to the methods in paragraphs (l)(1) through Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Where: NHVdil = Net heating value dilution parameter, Btu/ft2. NHVvg = Net heating value of flare vent gas determined for the 15-minute block period, Btu/scf. Qvg = Cumulative volumetric flow of flare vent gas during the 15-minute block period, scf. QNG2 = Cumulative volumetric flow of supplemental natural gas to the flare during the 15-minute block period, scf. QNG1 = Cumulative volumetric flow of supplemental natural gas to the flare during the previous 15-minute block period, scf. For the first 15-minute block period of an event, use the volumetric flow value for the current 15-minute block period, i.e., QNG1 =QNG2. NHVNG = Net heating value of supplemental natural gas to the flare for the 15-minute block period determined according to the requirements in paragraph (j)(5) of this section, Btu/scf. Diam = Effective diameter of the unobstructed area of the flare tip for flare vent gas flow, ft. Use the area as determined in paragraph (k)(1) of this section and determine the diameter as prevented during periods of startup, shutdown, or emergency releases. The flare minimization assessment must (at a minimum) consider the items in paragraphs (o)(1)(ii)(A) through (C) of this section. The assessment must provide clear rationale in terms of costs (capital and annual operating), natural gas offset credits (if applicable), technical feasibility, secondary environmental impacts and safety considerations for the selected minimization alternative(s) or a statement, with justifications, that flow reduction could not be achieved. Based upon the assessment, each owner or operator of an affected flare shall identify the minimization alternatives that it has implemented by the due date of the flare management plan and shall include a schedule for the prompt implementation of any selected measures that cannot reasonably be completed as of that date. (A) Modification in startup and shutdown procedures to reduce the quantity of process gas discharge to the flare. (B) Implementation of prevention measures listed for pressure relief devices in § 63.648(j)(5) for each pressure relief valve that can discharge to the flare. (C) Installation of a flare gas recovery system or, for facilities that are fuel gas rich, a flare gas recovery system and a co-generation unit or combined heat and power unit. (iii) A description of each affected flare containing the information in paragraphs (o)(1)(iii)(A) through (G) of this section. (A) A general description of the flare, including whether it is a ground flare or elevated (including height), the type of assist system (e.g., air, steam, pressure, non-assisted), whether the flare is used on a routine basis or if it is only used during periods of startup, shutdown or emergency release, and whether the flare is equipped with a flare gas recovery system. (B) The smokeless capacity of the flare based on design conditions. Note: A single value must be provided for the smokeless capacity of the flare. (C) The maximum vent gas flow rate (hydraulic load capacity). (D) The maximum supplemental gas flow rate. tkelley on DSK3SPTVN1PROD with RULES2 Qs = Cumulative volumetric flow of total steam during the 15-minute block period, scf. Qa,premix = Cumulative volumetric flow of premix assist air during the 15-minute block period, scf. Qa,perimeter = Cumulative volumetric flow of perimeter assist air during the 15-minute block period, scf. (o) Emergency flaring provisions. The owner or operator of a flare that has the potential to operate above its smokeless capacity under any circumstance shall comply with the provisions in paragraphs (o)(1) through (8) of this section. (1) Develop a flare management plan to minimize flaring during periods of startup, shutdown, or emergency releases. The flare management plan must include the information described in paragraphs (o)(1)(i) through (vii) of this section. (i) A listing of all refinery process units, ancillary equipment, and fuel gas systems connected to the flare for each affected flare. (ii) An assessment of whether discharges to affected flares from these process units, ancillary equipment and fuel gas systems can be minimized or VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00087 Fmt 4701 Sfmt 4700 (E) For flares that receive assist steam, the minimum total steam rate and the maximum total steam rate. (F) For flares that receive assist air, an indication of whether the fan/blower is single speed, multi-fixed speed (e.g., high, medium, and low speeds), or variable speeds. For fans/blowers with fixed speeds, provide the estimated assist air flow rate at each fixed speed. For variable speeds, provide the design fan curve (e.g., air flow rate as a function of power input). (G) Simple process flow diagram showing the locations of the flare following components of the flare: Flare tip (date installed, manufacturer, nominal and effective tip diameter, tip drawing); knockout or surge drum(s) or pot(s) (including dimensions and design capacities); flare header(s) and subheader(s); assist system; and ignition system. (iv) Description and simple process flow diagram showing all gas lines (including flare waste gas, purge or sweep gas (as applicable), supplemental gas) that are associated with the flare. For purge, sweep, supplemental gas, identify the type of gas used. Designate which lines are exempt from composition or net heating value monitoring and why (e.g., natural gas, gas streams that have been demonstrated to have consistent composition, pilot gas). Designate which lines are monitored and identify on the process flow diagram the location and type of each monitor. Designate the pressure relief devices that are vented to the flare. (v) For each flow rate, gas composition, net heating value or hydrogen concentration monitor identified in paragraph (o)(1)(iv) of this section, provide a detailed description of the manufacturer’s specifications, including, but not limited to, make, model, type, range, precision, accuracy, calibration, maintenance and quality assurance procedures. (vi) For each pressure relief valve vented to the flare identified in paragraph (o)(1)(iv) of this section, provide a detailed description of each pressure release valve, including type of relief device (rupture disc, valve type) diameter of the relief valve, set pressure of the relief valve and listing of the prevention measures implemented. This E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.017</GPH> parameter does not need to be calculated. ER01DE15.016</GPH> volumetric flow of perimeter assist air, the 15-minute block average NHVdil 75263 tkelley on DSK3SPTVN1PROD with RULES2 75264 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations information may be maintained in an electronic database on-site and does not need to be submitted as part of the flare management plan unless requested to do so by the Administrator. (vii) Procedures to minimize or eliminate discharges to the flare during the planned startup and shutdown of the refinery process units and ancillary equipment that are connected to the affected flare, together with a schedule for the prompt implementation of any procedures that cannot reasonably be implemented as of the date of the submission of the flare management plan. (2) Each owner or operator required to develop and implement a written flare management plan as described in paragraph (o)(1) of this section must submit the plan to the Administrator as described in paragraphs (o)(2)(i) through (iii) of this section. (i) The owner or operator must develop and implement the flare management plan no later than January 30, 2019 or at startup for a new flare that commenced construction on or after February 1, 2016. (ii) The owner or operator must comply with the plan as submitted by the date specified in paragraph (o)(2)(i) of this section. The plan should be updated periodically to account for changes in the operation of the flare, such as new connections to the flare or the installation of a flare gas recovery system, but the plan need be resubmitted to the Administrator only if the owner or operator alters the design smokeless capacity of the flare. The owner or operator must comply with the updated plan as submitted. (iii) All versions of the plan submitted to the Administrator shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143–01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refineryRTR@epa.gov. (3) The owner or operator of a flare subject to this subpart shall conduct a root cause analysis and a corrective action analysis for each flow event that contains regulated material and that meets either the criteria in paragraph (o)(3)(i) or (ii) of this section. (i) The vent gas flow rate exceeds the smokeless capacity of the flare and visible emissions are present from the flare for more than 5 minutes during any 2 consecutive hours during the release event. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (ii) The vent gas flow rate exceeds the smokeless capacity of the flare and the 15-minute block average flare tip velocity exceeds the maximum flare tip velocity determined using the methods in paragraph (d)(2) of this section. (4) A root cause analysis and corrective action analysis must be completed as soon as possible, but no later than 45 days after a flare flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this section. Special circumstances affecting the number of root cause analyses and/or corrective action analyses are provided in paragraphs (o)(4)(i) through (v) of this section. (i) You may conduct a single root cause analysis and corrective action analysis for a single continuous flare flow event that meets both of the criteria in paragraphs (o)(3)(i) and (ii) of this section. (ii) You may conduct a single root cause analysis and corrective action analysis for a single continuous flare flow event regardless of the number of 15-minute block periods in which the flare tip velocity was exceeded or the number of 2 hour periods that contain more the 5 minutes of visible emissions. (iii) You may conduct a single root cause analysis and corrective action analysis for a single event that causes two or more flares that are operated in series (i.e., cascaded flare systems) to have a flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this section. (iv) You may conduct a single root cause analysis and corrective action analysis for a single event that causes two or more flares to have a flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this section, regardless of the configuration of the flares, if the root cause is reasonably expected to be a force majeure event, as defined in this subpart. (v) Except as provided in paragraphs (o)(4)(iii) and (iv) of this section, if more than one flare has a flow event that meets the criteria in paragraph (o)(3)(i) or (ii) of this section during the same time period, an initial root cause analysis shall be conducted separately for each flare that has a flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this section. If the initial root cause analysis indicates that the flow events have the same root cause(s), the initially separate root cause analyses may be recorded as a single root cause analysis and a single corrective action analysis may be conducted. (5) Each owner or operator of a flare required to conduct a root cause analysis and corrective action analysis as specified in paragraphs (o)(3) and (4) PO 00000 Frm 00088 Fmt 4701 Sfmt 4700 of this section shall implement the corrective action(s) identified in the corrective action analysis in accordance with the applicable requirements in paragraphs (o)(5)(i) through (iii) of this section. (i) All corrective action(s) must be implemented within 45 days of the event for which the root cause and corrective action analyses were required or as soon thereafter as practicable. If an owner or operator concludes that no corrective action should be implemented, the owner or operator shall record and explain the basis for that conclusion no later than 45 days following the event. (ii) For corrective actions that cannot be fully implemented within 45 days following the event for which the root cause and corrective action analyses were required, the owner or operator shall develop an implementation schedule to complete the corrective action(s) as soon as practicable. (iii) No later than 45 days following the event for which a root cause and corrective action analyses were required, the owner or operator shall record the corrective action(s) completed to date, and, for action(s) not already completed, a schedule for implementation, including proposed commencement and completion dates. (6) The owner or operator shall determine the total number of events for which a root cause and corrective action analyses was required during the calendar year for each affected flare separately for events meeting the criteria in paragraph (o)(3)(i) of this section and those meeting the criteria in paragraph (o)(3)(ii) of this section. For the purpose of this requirement, a single root cause analysis conducted for an event that met both of the criteria in paragraphs (o)(3)(i) and (ii) of this section would be counted as an event under each of the separate criteria counts for that flare. Additionally, if a single root cause analysis was conducted for an event that caused multiple flares to meet the criteria in paragraph (o)(3)(i) or (ii) of this section, that event would count as an event for each of the flares for each criteria in paragraph (o)(3) of this section that was met during that event. The owner or operator shall also determine the total number of events for which a root cause and correct action analyses was required and the analyses concluded that the root cause was a force majeure event, as defined in this subpart. (7) The following events would be a violation of this emergency flaring work practice standard. (i) Any flow event for which a root cause analysis was required and the root E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations cause was determined to be operator error or poor maintenance. (ii) Two visible emissions exceedance events meeting the criteria in paragraph (o)(3)(i) of this section that were not caused by a force majeure event from a single flare in a 3 calendar year period for the same root cause for the same equipment. (iii) Two flare tip velocity exceedance events meeting the criteria in paragraph (o)(3)(ii) of this section that were not caused by a force majeure event from a single flare in a 3 calendar year period for the same root cause for the same equipment. (iv) Three visible emissions exceedance events meeting the criteria in paragraph (o)(3)(i) of this section that were not caused by a force majeure event from a single flare in a 3 calendar year period for any reason. (v) Three flare tip velocity exceedance events meeting the criteria in paragraph (o)(3)(ii) of this section that were not caused by a force majeure event from a single flare in a 3 calendar year period for any reason. (p) Flare monitoring records. The owner or operator shall keep the records specified in § 63.655(i)(9). (q) Reporting. The owner or operator shall comply with the reporting requirements specified in § 63.655(g)(11). (r) Alternative means of emissions limitation. An owner or operator may request approval from the Administrator for site-specific operating limits that shall apply specifically to a selected flare. Site-specific operating limits include alternative threshold values for the parameters specified in paragraphs (d) through (f) of this section as well as threshold values for operating parameters other than those specified in paragraphs (d) through (f) of this section. The owner or operator must demonstrate that the flare achieves 96.5 percent combustion efficiency (or 98 percent destruction efficiency) using the site-specific operating limits based on a performance evaluation as described in paragraph (r)(1) of this section. The request shall include information as described in paragraph (r)(2) of this section. The request shall be submitted and followed as described in paragraph (r)(3) of this section. (1) The owner or operator shall prepare and submit a site-specific test plan and receive approval of the sitespecific performance evaluation plan prior to conducting any flare performance evaluation test runs intended for use in developing sitespecific operating limits. The sitespecific performance evaluation plan shall include, at a minimum, the VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 elements specified in paragraphs (r)(1)(i) through (ix) of this section. Upon approval of the site-specific performance evaluation plan, the owner or operator shall conduct performance evaluation test runs for the flare following the procedures described in the site-specific performance evaluation plan. (i) The design and dimensions of the flare, flare type (air-assisted only, steamassisted only, air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being flared, including quantity of gas flared, frequency of flaring events (if periodic), expected net heating value of flare vent gas, minimum total steam assist rate. (ii) The operating conditions (vent gas compositions, vent gas flow rates and assist flow rates, if applicable) likely to be encountered by the flare during normal operations and the operating conditions for the test period. (iii) A description of (including sample calculations illustrating) the planned data reduction and calculations to determine the flare combustion or destruction efficiency. (iv) Site-specific operating parameters to be monitored continuously during the flare performance evaluation. These parameters may include but are not limited to vent gas flow rate, steam and/ or air assist flow rates, and flare vent gas composition. If new operating parameters are proposed for use other than those specified in paragraphs (d) through (f) of this section, an explanation of the relevance of the proposed operating parameter(s) as an indicator of flare combustion performance and why the alternative operating parameter(s) can adequately ensure that the flare achieves the required combustion efficiency. (v) A detailed description of the measurement methods, monitored pollutant(s), measurement locations, measurement frequency, and recording frequency proposed for both emission measurements and flare operating parameters. (vi) A description of (including sample calculations illustrating) the planned data reduction and calculations to determine the flare operating parameters. (vii) The minimum number and length of test runs and range of operating values to be evaluated during the performance evaluation. A sufficient number of test runs shall be conducted to identify the point at which the combustion/destruction efficiency of the flare deteriorates. (viii) [Reserved] (ix) Test schedule. PO 00000 Frm 00089 Fmt 4701 Sfmt 4700 75265 (2) The request for flare-specific operating limits shall include sufficient and appropriate data, as determined by the Administrator, to allow the Administrator to confirm that the selected site-specific operating limit(s) adequately ensures that the flare destruction efficiency is 98 percent or greater or that the flare combustion efficiency is 96.5 percent or greater at all times. At a minimum, the request shall contain the information described in paragraphs (r)(2)(i) through (iv) of this section. (i) The design and dimensions of the flare, flare type (air-assisted only, steamassisted only, air- and steam-assisted, pressure-assisted, or non-assisted), and description of gas being flared, including quantity of gas flared, frequency of flaring events (if periodic), expected net heating value of flare vent gas, minimum total steam assist rate. (ii) Results of each performance evaluation test run conducted, including, at a minimum: (A) The measured combustion/ destruction efficiency. (B) The measured or calculated operating parameters for each test run. If operating parameters are calculated, the raw data from which the parameters are calculated must be included in the test report. (C) Measurement location descriptions for both emission measurements and flare operating parameters. (D) Description of sampling and analysis procedures (including number and length of test runs) and any modifications to standard procedures. If there were deviations from the approved test plan, a detailed description of the deviations and rationale why the test results or calculation procedures used are appropriate. (E) Operating conditions (e.g., vent gas composition, assist rates, etc.) that occurred during the test. (F) Quality assurance procedures. (G) Records of calibrations. (H) Raw data sheets for field sampling. (I) Raw data sheets for field and laboratory analyses. (J) Documentation of calculations. (iii) The selected flare-specific operating limit values based on the performance evaluation test results, including the averaging time for the operating limit(s), and rationale why the selected values and averaging times are sufficiently stringent to ensure proper flare performance. If new operating parameters or averaging times are proposed for use other than those specified in paragraphs (d) through (f) of this section, an explanation of why the E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 75266 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations alternative operating parameter(s) or averaging time(s) adequately ensures the flare achieves the required combustion efficiency. (iv) The means by which the owner or operator will document on-going, continuous compliance with the selected flare-specific operating limit(s), including the specific measurement location and frequencies, calculation procedures, and records to be maintained. (3) The request shall be submitted as described in paragraphs (r)(3)(i) through (iv) of this section. (i) The owner or operator may request approval from the Administrator at any time upon completion of a performance evaluation conducted following the methods in an approved site-specific performance evaluation plan for an operating limit(s) that shall apply specifically to that flare. (ii) The request must be submitted to the Administrator for approval. The owner or operator must continue to comply with the applicable standards for flares in this subpart until the requirements in § 63.6(g)(1) are met and a notice is published in the Federal Register allowing use of such an alternative means of emission limitation. (iii) The request shall also be submitted to the following address: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom (E143–01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic copies in lieu of hard copies may also be submitted to refineryrtr@epa.gov. (iv) If the Administrator finds any deficiencies in the request, the request must be revised to address the deficiencies and be re-submitted for approval within 45 days of receipt of the notice of deficiencies. The owner or operator must comply with the revised request as submitted until it is approved. (4) The approval process for a request for a flare-specific operating limit(s) is described in paragraphs (r)(4)(i) through (iii) of this section. (i) Approval by the Administrator of a flare-specific operating limit(s) request will be based on the completeness, accuracy and reasonableness of the request. Factors that the EPA will consider in reviewing the request for approval include, but are not limited to, those described in paragraphs (r)(4)(i)(A) through (C) of this section. (A) The description of the flare design and operating characteristics. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (B) If a new operating parameter(s) other than those specified in paragraphs (d) through (f) of this section is proposed, the explanation of how the proposed operating parameter(s) serves a good indicator(s) of flare combustion performance. (C) The results of the flare performance evaluation test runs and the establishment of operating limits that ensures that the flare destruction efficiency is 98 percent or greater or that the flare combustion efficiency is 96.5 percent or greater at all times. (D) The completeness of the flare performance evaluation test report. (ii) If the request is approved by the Administrator, a flare-specific operating limit(s) will be established at the level(s) demonstrated in the approved request. (iii) If the Administrator finds any deficiencies in the request, the request must be revised to address the deficiencies and be re-submitted for approval. ■ 33. Section 63.671 is added to read as follows: § 63.671 Requirements for flare monitoring systems. (a) Operation of CPMS. For each CPMS installed to comply with applicable provisions in § 63.670, the owner or operator shall install, operate, calibrate, and maintain the CPMS as specified in paragraphs (a)(1) through (8) of this section. (1) Except for CPMS installed for pilot flame monitoring, all monitoring equipment must meet the applicable minimum accuracy, calibration and quality control requirements specified in table 13 of this subpart. (2) The owner or operator shall ensure the readout (that portion of the CPMS that provides a visual display or record) or other indication of the monitored operating parameter from any CPMS required for compliance is readily accessible onsite for operational control or inspection by the operator of the source. (3) All CPMS must complete a minimum of one cycle of operation (sampling, analyzing and data recording) for each successive 15minute period. (4) Except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions and required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments), the owner or operator shall operate all CPMS and collect data continuously at all times when regulated emissions are routed to the flare. PO 00000 Frm 00090 Fmt 4701 Sfmt 4700 (5) The owner or operator shall operate, maintain, and calibrate each CPMS according to the CPMS monitoring plan specified in paragraph (b) of this section. (6) For each CPMS except for CPMS installed for pilot flame monitoring, the owner or operator shall comply with the out-of-control procedures described in paragraph (c) of this section. (7) The owner or operator shall reduce data from a CPMS as specified in paragraph (d) of this section. (8) The CPMS must be capable of measuring the appropriate parameter over the range of values expected for that measurement location. The data recording system associated with each CPMS must have a resolution that is equal to or better than the required system accuracy. (b) CPMS monitoring plan. The owner or operator shall develop and implement a CPMS quality control program documented in a CPMS monitoring plan that covers each flare subject to the provisions in § 63.670 and each CPMS installed to comply with applicable provisions in § 63.670. The owner or operator shall have the CPMS monitoring plan readily available onsite at all times and shall submit a copy of the CPMS monitoring plan to the Administrator upon request by the Administrator. The CPMS monitoring plan must contain the information listed in paragraphs (b)(1) through (5) of this section. (1) Identification of the specific flare being monitored and the flare type (airassisted only, steam-assisted only, airand steam-assisted, pressure-assisted, or non-assisted). (2) Identification of the parameter to be monitored by the CPMS and the expected parameter range, including worst case and normal operation. (3) Description of the monitoring equipment, including the information specified in paragraphs (b)(3)(i) through (vii) of this section. (i) Manufacturer and model number for all monitoring equipment components installed to comply with applicable provisions in § 63.670. (ii) Performance specifications, as provided by the manufacturer, and any differences expected for this installation and operation. (iii) The location of the CPMS sampling probe or other interface and a justification of how the location meets the requirements of paragraph (a)(1) of this section. (iv) Placement of the CPMS readout, or other indication of parameter values, indicating how the location meets the requirements of paragraph (a)(2) of this section. E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations (v) Span of the CPMS. The span of the CPMS sensor and analyzer must encompass the full range of all expected values. (vi) How data outside of the span of the CPMS will be handled and the corrective action that will be taken to reduce and eliminate such occurrences in the future. (vii) Identification of the parameter detected by the parametric signal analyzer and the algorithm used to convert these values into the operating parameter monitored to demonstrate compliance, if the parameter detected is different from the operating parameter monitored. (4) Description of the data collection and reduction systems, including the information specified in paragraphs (b)(4)(i) through (iii) of this section. (i) A copy of the data acquisition system algorithm used to reduce the measured data into the reportable form of the standard and to calculate the applicable averages. (ii) Identification of whether the algorithm excludes data collected during CPMS breakdowns, out-ofcontrol periods, repairs, maintenance periods, instrument adjustments or checks to maintain precision and accuracy, calibration checks, and zero (low-level), mid-level (if applicable) and high-level adjustments. (iii) If the data acquisition algorithm does not exclude data collected during CPMS breakdowns, out-of-control periods, repairs, maintenance periods, instrument adjustments or checks to maintain precision and accuracy, calibration checks, and zero (low-level), mid-level (if applicable) and high-level adjustments, a description of the procedure for excluding this data when the averages calculated as specified in paragraph (e) of this section are determined. (5) Routine quality control and assurance procedures, including descriptions of the procedures listed in paragraphs (b)(5)(i) through (vi) of this section and a schedule for conducting these procedures. The routine procedures must provide an assessment of CPMS performance. (i) Initial and subsequent calibration of the CPMS and acceptance criteria. (ii) Determination and adjustment of the calibration drift of the CPMS. (iii) Daily checks for indications that the system is responding. If the CPMS system includes an internal system check, the owner or operator may use the results to verify the system is responding, as long as the system provides an alarm to the owner or operator or the owner or operator checks the internal system results daily for VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 proper operation and the results are recorded. (iv) Preventive maintenance of the CPMS, including spare parts inventory. (v) Data recording, calculations and reporting. (vi) Program of corrective action for a CPMS that is not operating properly. (c) Out-of-control periods. For each CPMS installed to comply with applicable provisions in § 63.670 except for CPMS installed for pilot flame monitoring, the owner or operator shall comply with the out-of-control procedures described in paragraphs (c)(1) and (2) of this section. (1) A CPMS is out-of-control if the zero (low-level), mid-level (if applicable) or high-level calibration drift exceeds two times the accuracy requirement of table 13 of this subpart. (2) When the CPMS is out of control, the owner or operator shall take the necessary corrective action and repeat all necessary tests that indicate the system is out of control. The owner or operator shall take corrective action and conduct retesting until the performance requirements are below the applicable limits. The beginning of the out-ofcontrol period is the hour a performance check (e.g., calibration drift) that indicates an exceedance of the performance requirements established in this section is conducted. The end of the out-of-control period is the hour following the completion of corrective action and successful demonstration that the system is within the allowable limits. The owner or operator shall not use data recorded during periods the CPMS is out of control in data averages and calculations, used to report emissions or operating levels, as specified in paragraph (d)(3) of this section. (d) CPMS data reduction. The owner or operator shall reduce data from a CPMS installed to comply with applicable provisions in § 63.670 as specified in paragraphs (d)(1) through (3) of this section. (1) The owner or operator may round the data to the same number of significant digits used in that operating limit. (2) Periods of non-operation of the process unit (or portion thereof) resulting in cessation of the emissions to which the monitoring applies must not be included in the 15-minute block averages. (3) Periods when the CPMS is out of control must not be included in the 15minute block averages. (e) Additional requirements for gas chromatographs. For monitors used to determine compositional analysis for net heating value per § 63.670(j)(1), the PO 00000 Frm 00091 Fmt 4701 Sfmt 4700 75267 gas chromatograph must also meet the requirements of paragraphs (e)(1) through (3) of this section. (1) The quality assurance requirements are in table 13 of this subpart. (2) The calibration gases must meet one of the following options: (i) The owner or operator must use a calibration gas or multiple gases that include all of compounds listed in paragraphs (e)(2)(i)(A) through (K) of this section that may be reasonably expected to exist in the flare gas stream and optionally include any of the compounds listed in paragraphs (e)(2)(i)(L) through (O) of this section. All of the calibration gases may be combined in one cylinder. If multiple calibration gases are necessary to cover all compounds, the owner or operator must calibrate the instrument on all of the gases. (A) Hydrogen. (B) Methane. (C) Ethane. (D) Ethylene. (E) Propane. (F) Propylene. (G) n-Butane. (H) iso-Butane. (I) Butene (general). It is not necessary to separately speciate butene isomers, but the net heating value of trans-butene must be used for co-eluting butene isomers. (J) 1,3-Butadiene. It is not necessary to separately speciate butadiene isomers, but you must use the response factor and net heating value of 1,3-butadiene for co-eluting butadiene isomers. (K) n-Pentane. Use the response factor for n-pentane to quantify all C5+ hydrocarbons. (L) Acetylene (optional). (M) Carbon monoxide (optional). (N) Propadiene (optional). (O) Hydrogen sulfide (optional). (ii) The owner or operator must use a surrogate calibration gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All of the calibration gases may be combined in one cylinder. If multiple calibration gases are necessary to cover all compounds, the owner or operator must calibrate the instrument on all of the gases. (3) If the owner or operator chooses to use a surrogate calibration gas under paragraph (e)(2)(ii) of this section, the owner or operator must comply with paragraphs (e)(3)(i) and (ii) of this section. (i) Use the response factor for the nearest normal hydrocarbon (i.e., nalkane) in the calibration mixture to quantify unknown components detected in the analysis. (ii) Use the response factor for npentane to quantify unknown E:\FR\FM\01DER2.SGM 01DER2 75268 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations components detected in the analysis that elute after n-pentane. ■ 34. The appendix to subpart CC is amended in table 6 by: ■ a. Revising the entries ‘‘63.5(d)(1)(ii)’’ and ‘‘63.5(f)’’; ■ b. Removing the entry ‘‘63.6(e)(1)’’; ■ c. Adding, in numerical order, the entries ‘‘63.6(e)(1)(i) and (ii)’’ and ‘‘63.6(e)(1)(iii)’’; ■ d. Revising the entries ‘‘63.6(e)(3)(i),’’ ‘‘63.6(e)(3)(iii)–63.6(e)(3)(ix),’’ and ‘‘63.6(f)(1)’’; ■ e. Removing the entry ‘‘63.6(f)(2) and (3)’’; ■ f. Adding, in numerical order, the entries ‘‘63.6(f)(2)’’ and ‘‘63.6(f)(3)’’; ■ g. Removing the entry ‘‘63.6(h)(1) and 63.6(h)(2)’’; h. Adding, in numerical order, the entries ‘‘63.6(h)(1)’’ and ‘‘63.6(h)(2)’’; ■ i. Revising the entries ‘‘63.7(b)’’ and ‘‘63.7(e)(1)’’; ■ j. Removing the entry ‘‘63.8(a)’’; ■ k. Adding, in numerical order, the entries ‘‘63.8(a)(1) and (2),’’ ‘‘63.8(a)(3),’’ and ‘‘63.8(a)(4)’’; ■ l. Revising the entry ‘‘63.8(c)(1)’’; ■ m. Adding, in numerical order, the entries ‘‘63.8(c)(1)(i)’’ and ‘‘63.8(c)(1)(iii)’’; ■ n. Revising the entries ‘‘63.8(c)(4),’’ ‘‘63.8(c)(5)–63.8(c)(8),’’ ‘‘63.8(d),’’ ‘‘63.8(e),’’ ‘‘63.8(g),’’ ‘‘63.10(b)(2)(i),’’ ‘‘63.10(b)(2)(ii),’’ ‘‘63.10(b)(2)(iv),’’ ‘‘63.10(b)(2)(v),’’ and ‘‘63.10(b)(2)(vii)’’; ■ o. Removing the entry ‘‘63.10(c)(9)– 63.10(c)(15)’’; ■ p. Adding, in numerical order, the entries ‘‘63.10(c)(9),’’ ‘‘63.10(c)(10)– 63.10(c)(11),’’ and ‘‘63.10(c)(12)– 63.10(c)(15)’’; ■ q. Revising the entry ‘‘63.10(d)(2)’’; ■ r. Removing the entries ‘‘63.10(d)(5)(i)’’ and ‘‘63.10(d)(5)(ii)’’; ■ s. Adding, in numerical order, the entry ‘‘63.10(d)(5)’’; ■ t. Removing the entry ‘‘63.11–63.16’’; ■ u. Adding, in numerical order, the entries ‘‘63.11’’ and ‘‘63.12–63.16’’; ■ v. Revising footnote a. ■ w. Removing footnote b. The revisions and additions read as follows: ■ Appendix to Subpart CC of Part 63— Tables * * TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART * * * CC a Applies to subpart CC Comment * * 63.5(d)(1)(ii) ............................................. * Yes ................... * * * * Except that for affected sources subject to this subpart, emission estimates specified in § 63.5(d)(1)(ii)(H) are not required, and § 63.5(d)(1)(ii)(G) and (I) are Reserved and do not apply. * * 63.5(f) ....................................................... * Yes ................... * * * * Except that the cross-reference in § 63.5(f)(2) to § 63.9(b)(2) does not apply. * * 63.6(e)(1)(i) and (ii) .................................. 63.6(e)(1)(iii) ............................................. * No ..................... Yes. * * See § 63.642(n) for general duty requirement. * * 63.6(e)(3)(i) .............................................. * * No. * * 63.6(e)(3)(iii)–63.6(e)(3)(ix) ...................... 63.6(f)(1) .................................................. 63.6(f)(2) .................................................. * No. No. Yes ................... * 63.6(f)(3) .................................................. Yes ................... * * 63.6(h)(1) ................................................. 63.6(h)(2) ................................................. * No. Yes ................... * * 63.7(b) ...................................................... * Yes ................... * * * * Except this subpart requires notification of performance test at least 30 days (rather than 60 days) prior to the performance test. * * 63.7(e)(1) ................................................. tkelley on DSK3SPTVN1PROD with RULES2 Reference * No ..................... * See § 63.642(d)(3). * * * * * 63.8(a)(1) and (2) ..................................... 63.8(a)(3) ................................................. 63.8(a)(4) ................................................. * Yes. No ..................... Yes ................... * * * * * * 63.8(c)(1) .................................................. 63.8(c)(1)(i) .............................................. 63.8(c)(1)(iii) ............................................. * Yes ................... No ..................... No. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00092 * * * * * * * * Except the phrase ‘‘as specified in § 63.7(c)’’ in § 63.6(f)(2)(iii)(D) does not apply because this subpart does not require a site-specific test plan. Except the cross-references to § 63.6(f)(1) and (e)(1)(i) are changed to § 63.642(n). * * * * Except § 63.6(h)(2)(ii), which is reserved. Reserved. Except that for a flare complying with § 63.670, the cross-reference to § 63.11 in this paragraph does not include § 63.11(b). * * Except § 63.8(c)(1)(i) and (iii). See § 63.642(n). Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM * 01DER2 * 75269 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART CC a—Continued Reference Applies to subpart CC Comment * * 63.8(c)(4) .................................................. * Yes ................... 63.8(c)(5)–63.8(c)(8) ................................ 63.8(d) ...................................................... No ..................... No ..................... * * * * Except that for sources other than flares, this subpart specifies the monitoring cycle frequency specified in § 63.8(c)(4)(ii) is ‘‘once every hour’’ rather than ‘‘for each successive 15-minute period.’’ This subpart specifies continuous monitoring system requirements. This subpart specifies quality control procedures for continuous monitoring systems. 63.8(e) ...................................................... Yes. * * 63.8(g) ...................................................... * No ..................... * * 63.10(b)(2)(i) ............................................ 63.10(b)(2)(ii) ........................................... * No. No ..................... * * 63.10(b)(2)(iv) .......................................... 63.10(b)(2)(v) ........................................... No. No. * * 63.10(b)(2)(vii) .......................................... * No ..................... * * * * § 63.655(i) specifies records to be kept for parameters measured with continuous monitors. * * 63.10(c)(9) ................................................ 63.10(c)(10)–63.10(c)(11) ........................ 63.10(c)(12)–63.10(c)(15) ........................ * No ..................... No ..................... No. * * * Reserved. § 63.655(i) specifies the records that must be kept. * * 63.10(d)(2) ............................................... * No ..................... * * * * Although § 63.655(f) specifies performance test reporting, EPA may approve other timeframes for submittal of performance test data. * * 63.10(d)(5) ............................................... * No ..................... * * § 63.655(g) specifies the reporting requirements. * * 63.11 ........................................................ * Yes ................... * * * * Except that flares complying with § 63.670 are not subject to the requirements of § 63.11(b). 63.12–63.16 ............................................. Yes. * * * * This subpart specifies data reduction procedures in §§ 63.655(i)(3) and 63.671(d). * * * * * * § 63.655(i) specifies the records that must be kept. * * * * * * a Wherever subpart A of this part specifies ‘‘postmark’’ dates, submittals may be sent by methods other than the U.S. Mail (e.g., by fax or courier). Submittals shall be sent by the specified dates, but a postmark is not required. 35. The appendix to subpart CC is amended in table 10 by: ■ a. Redesignating the entry ‘‘Flare’’ as ‘‘Flare (if meeting the requirements of §§ 63.643 and 63.644)’’; ■ b. Adding the entry ‘‘Flare (if meeting the requirements of §§ 63.670 and ■ 63.671)’’ after newly redesignated entry ‘‘Flare (if meeting the requirements of §§ 63.643 and 63.644)’’; ■ c. Revising the entry ‘‘All control devices’’; and ■ d. Revising footnote i. The revisions and additions read as follows: Appendix to Subpart CC of Part 63— Tables * * * * * TABLE 10—MISCELLANEOUS PROCESS VENTS—MONITORING, RECORDKEEPING AND REPORTING REQUIREMENTS FOR COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL ORGANIC HAP EMISSIONS OR A LIMIT OF 20 PARTS PER MILLION BY VOLUME tkelley on DSK3SPTVN1PROD with RULES2 Control device Parameters to be monitored a Recordkeeping and reporting requirements for monitored parameters * * Flare (if meeting the requirements of §§ 63.670 and 63.671). All control devices .......................... * * The parameters specified in § 63.670. Presence of flow diverted to the atmosphere from the control device (§ 63.644(c)(1)) or * * * 1. Records as specified in § 63.655(i)(9). 2. Report information as specified in § 63.655(g)(11)—PR.g 1. Hourly records of whether the flow indicator was operating and whether flow was detected at any time during each hour. Record and report the times and durations of all periods when the vent stream is diverted through a bypass line or the monitor is not operating—PR.g VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00093 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75270 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 10—MISCELLANEOUS PROCESS VENTS—MONITORING, RECORDKEEPING AND REPORTING REQUIREMENTS FOR COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL ORGANIC HAP EMISSIONS OR A LIMIT OF 20 PARTS PER MILLION BY VOLUME—Continued Parameters to be monitored a Control device Monthly inspections of valves (§ 63.644(c)(2)). sealed Recordkeeping and reporting requirements for monitored parameters 1. Records that monthly inspections were performed. 2. Record and report all monthly inspections that show the valves are not closed or the seal has been changed—PR.g a Regulatory citations are listed in parentheses. * * * * * * * g PR = Periodic Reports described in § 63.655(g). * * * * * * * i Process vents that are routed to refinery fuel gas systems are not regulated under this subpart provided that on and after January 30, 2019, any flares receiving gas from that fuel gas system are in compliance with § 63.670. No monitoring, recordkeeping, or reporting is required for boilers and process heaters that combust refinery fuel gas. 36. The appendix to subpart CC is amended by adding table 11 to read as follows: ■ Appendix to Subpart CC of Part 63— Tables * * * * * TABLE 11—COMPLIANCE DATES AND REQUIREMENTS If the construction/reconstruction date a is . . . Then the owner or operator must comply with . . . And the owner or operator must achieve compliance . . . Except as provided in . . . (1) After June 30, 2014 ................. (i) Requirements for new sources in §§ 63.640 through 63.642, 63.647, 63.650 through 63.653, and 63.656 through 63.660. (ii) The new source requirements in § 63.654 for heat exchange systems. (i) Requirements for new sources in §§ 63.640 through 63.653 and 63.656 b c. (ii) Requirements for new sources in §§ 63.640 through 63.645, §§ 63.647 through 63.653, and §§ 63.656 and 63.657 b. (iii) Requirements for existing sources in § 63.658. (iv) Requirements for new sources in § 63.660 c. (v) The new source requirements in § 63.654 for heat exchange systems. (i) Requirements for new sources in §§ 63.640 through 63.653 and 63.656 d e. (ii) Requirements for new sources in §§ 63.640 through 63.645, 63.647 through 63.653, and 63.656 and 63.657 d. (iii) Requirements for existing sources in § 63.658. (iv) Requirements for new sources in § 63.660 e. (v) The existing source requirements in § 63.654 for heat exchange systems. (i) Requirements for existing sources in §§ 63.640 through 63.653 and 63.656 f g. Upon initial startup or February 1, 2016, whichever is later. § 63.640(k), (l) and (m). Upon initial startup or October 28, 2009, whichever is later. § 63.640(k), (l) and (m). Upon initial startup ........................ § 63.640(k), (l) and (m). On or before January 30, 2019 .... § 63.640(k), (l) and (m). On or before January 30, 2018 .... § 63.640(k), (l) and (m). On or before April 29, 2016 ......... § 63.640(k), (l) and (m). Upon initial startup or October 28, 2009, whichever is later. § 63.640(k), (l) and (m). Upon initial startup or August 18, 1995, whichever is later. § 63.640(k), (l) and (m). On or before January 30, 2019 .... § 63.640(k), (l) and (m). On or before January 30, 2018 .... § 63.640(k), (l) and (m). On or before April 29, 2016 ......... § 63.640(k), (l) and (m). On or before October 29, 2012 .... § 63.640(k), (l) and (m). (a) On or before August 18, 1998 (1) § 63.640(k), (l) and (m). (2) § 63.6(c)(5) of subpart A of this part or unless an extension has been granted by the Administrator as provided in § 63.6(i) of subpart A of this part. § 63.640(k), (l) and (m). (2) After September 4, 2007 but on or before June 30, 2014. (3) After July 14, 1994 but on or before September 4, 2007. tkelley on DSK3SPTVN1PROD with RULES2 (4) On or before July 14, 1994 ...... (ii) Requirements for existing sources in §§ 63.640 through 63.645, 63.647 through 63.653, and 63.656 and 63.657 f. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00094 Fmt 4701 On or before January 30, 2019 .... Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75271 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 11—COMPLIANCE DATES AND REQUIREMENTS—Continued If the construction/reconstruction date a is . . . Then the owner or operator must comply with . . . (v) The existing source requirements in § 63.654 for heat exchange systems And the owner or operator must achieve compliance . . . Except as provided in . . . (iii) Requirements for existing sources in § 63.658. (iv) Requirements for existing sources in § 63.660 g. On or before October 29, 2012 .... On or before January 30, 2018 .... § 63.640(k), (l) and (m). On or before April 29, 2016 ......... § 63.640(k), (l) and (m). § 63.640(k), (l) and (m). a For purposes of this table, the construction/reconstruction date means the date of construction or reconstruction of an entire affected source or the date of a process unit addition or change meeting the criteria in § 63.640(i) or (j). If a process unit addition or change does not meet the criteria in § 63.640(i) or (j), the process unit shall comply with the applicable requirements for existing sources. b Between the compliance dates in items (2)(i) and (2)(ii) of this table, the owner or operator may elect to comply with either the requirements in item (2)(i) or item (2)(ii) of this table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(ii) of this table. c Between the compliance dates in items (2)(i) and (2)(iv) of this table, the owner or operator may elect to comply with either the requirements in item (2)(i) or item (2)(iv) of this table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(iv) of this table. d Between the compliance dates in items (3)(i) and (3)(ii) of this table, the owner or operator may elect to comply with either the requirements in item (3)(i) or item (3)(ii) of this table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(ii) of this table. e Between the compliance dates in items (3)(i) and (3)(iv) of this table, the owner or operator may elect to comply with either the requirements in item (3)(i) or item (3)(iv) of this table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(iv) of this table. f Between the compliance dates in items (4)(i) and (4)(ii) of this table, the owner or operator may elect to comply with either the requirements in item (4)(i) or item (4)(ii) of this table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(ii) of this table. g Between the compliance dates in items (4)(i) and (4)(iv) of this table, the owner or operator may elect to comply with either the requirements in item (4)(i) or item (4)(iv) of this table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(iv) of this table. 37. The appendix to subpart CC is amended by adding table 12 to read as follows: ■ Appendix to Subpart CC of Part 63— Tables * * * * * TABLE 12—INDIVIDUAL COMPONENT PROPERTIES MWi (pounds per pound-mole) tkelley on DSK3SPTVN1PROD with RULES2 Component Molecular formula Acetylene ............................................................................. Benzene ............................................................................... 1,2-Butadiene ...................................................................... 1,3-Butadiene ...................................................................... iso-Butane ............................................................................ n-Butane .............................................................................. cis-Butene ............................................................................ iso-Butene ............................................................................ trans-Butene ........................................................................ Carbon Dioxide .................................................................... Carbon Monoxide ................................................................ Cyclopropane ....................................................................... Ethane ................................................................................. Ethylene ............................................................................... Hydrogen ............................................................................. Hydrogen Sulfide ................................................................. Methane ............................................................................... Methyl-Acetylene ................................................................. Nitrogen ............................................................................... Oxygen ................................................................................ Pentane+ (C5+) ................................................................... Propadiene .......................................................................... Propane ............................................................................... Propylene ............................................................................. Water ................................................................................... C2H2 ............... C6H6 ............... C4H6 ............... C4H6 ............... C4H10 ............. C4H10 ............. C4H8 ............... C4H8 ............... C4H8 ............... CO2 ................ CO ................. C3H6 ............... C2H6 ............... C2H4 ............... H2 ................... H2S ................ CH4 ................ C3H4 ............... N2 ................... O2 ................... C5H12 ............. C3H4 ............... C3H8 ............... C3H6 ............... H2O ................ NHVi (British thermal units per standard cubic foot) CMNi (mole per mole) 26.04 78.11 54.09 54.09 58.12 58.12 56.11 56.11 56.11 44.01 28.01 42.08 30.07 28.05 2.02 34.08 16.04 40.06 28.01 32.00 72.15 40.06 44.10 42.08 18.02 2 6 4 4 4 4 4 4 4 1 1 3 2 2 0 0 1 3 0 0 5 3 3 3 0 1,404 3,591 2,794 2,690 2,957 2,968 2,830 2,928 2,826 0 316 2,185 1,595 1,477 1,212a 587 896 2,088 0 0 3,655 2,066 2,281 2,150 0 LFLi (volume %) 2.5 1.3 2.0 2.0 1.8 1.8 1.6 1.8 1.7 ∞ 12.5 2.4 3.0 2.7 4.0 4.0 5.0 1.7 ∞ ∞ 1.4 2.16 2.1 2.4 ∞ a The theoretical net heating value for hydrogen is 274 Btu/scf, but for the purposes of the flare requirement in this subpart, a net heating value of 1,212 Btu/scf shall be used. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00095 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75272 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 38. The appendix to subpart CC is amended by adding table 13 to read as follows: ■ Appendix to Subpart CC of Part 63— Tables * * * * * TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS Parameter Minimum accuracy requirements Calibration requirements Temperature .................................... ±1 percent over the normal range of temperature measured, expressed in degrees Celsius (C), or 2.8 degrees C, whichever is greater. Flow Rate for All Flows Other Than Flare Vent Gas. ±5 percent over the normal range of flow measured or 1.9 liters per minute (0.5 gallons per minute), whichever is greater, for liquid flow. ±5 percent over the normal range of flow measured or 280 liters per minute (10 cubic feet per minute), whichever is greater, for gas flow. ±5 percent over the normal range measured for mass flow. Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours throughout which the temperature exceeded the manufacturer’s specified maximum rated temperature or install a new temperature sensor. At least quarterly, inspect all components for integrity and all electrical connections for continuity, oxidation, and galvanic corrosion, unless the CPMS has a redundant temperature sensor. Record the results of each calibration check and inspection. Locate the temperature sensor in a position that provides a representative temperature; shield the temperature sensor system from electromagnetic interference and chemical contaminants. Conduct a flow sensor calibration check at least biennially (every two years); conduct a calibration check following any period of more than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow rate or install a new flow sensor. At least quarterly, inspect all components for leakage, unless the CPMS has a redundant flow sensor. ±20 percent of flow rate at velocities ranging from 0.03 to 0.3 meters per second (0.1 to 1 feet per second). ±5 percent of flow rate at velocities greater than 0.3 meters per second (1 feet per second). Pressure .......................................... ±5 percent over the normal operating range or 0.12 kilopascals (0.5 inches of water column), whichever is greater. Net Heating Value by Calorimeter .. tkelley on DSK3SPTVN1PROD with RULES2 Flare Vent Gas Flow Rate .............. ±2 percent of span ........................ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00096 Fmt 4701 Record the results of each calibration check and inspection. Locate the flow sensor(s) and other necessary equipment (such as straightening vanes) in a position that provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances. Conduct a flow sensor calibration check at least biennially (every two years); conduct a calibration check following any period of more than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow rate or install a new flow sensor. At least quarterly, inspect all components for leakage, unless the CPMS has a redundant flow sensor. Record the results of each calibration check and inspection. Locate the flow sensor(s) and other necessary equipment (such as straightening vanes) in a position that provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances. Review pressure sensor readings at least once a week for straightline (unchanging) pressure and perform corrective action to ensure proper pressure sensor operation if blockage is indicated. Using an instrument recommended by the sensor’s manufacturer, check gauge calibration and transducer calibration annually; conduct calibration checks following any period of more than 24 hours throughout which the pressure exceeded the manufacturer’s specified maximum rated pressure or install a new pressure sensor. At least quarterly, inspect all components for integrity, all electrical connections for continuity, and all mechanical connections for leakage, unless the CPMS has a redundant pressure sensor. Record the results of each calibration check and inspection. Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure and minimizes or eliminates pulsating pressure, vibration, and internal and external corrosion. Specify calibration requirements in your site specific CPMS monitoring plan. Calibration requirements should follow manufacturer’s recommendations at a minimum. Temperature control (heated and/or cooled as necessary) the sampling system to ensure proper year-round operation. Where feasible, select a sampling location at least two equivalent diameters downstream from and 0.5 equivalent diameters upstream from the nearest disturbance. Select the sampling location at least two equivalent duct diameters from the nearest control device, point of pollutant generation, air in-leakages, or other point at which a change in the pollutant concentration or emission rate occurs. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75273 TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS—Continued Parameter Minimum accuracy requirements Calibration requirements Net Heating Value by Gas Chromatograph. As specified in Performance Specification 9 of 40 CFR part 60, appendix B Hydrogen analyzer .......................... ±2 percent over the concentration measured or 0.1 volume percent, whichever is greater. Follow the procedure in Performance Specification 9 of 40 CFR part 60, appendix B, except that a single daily mid-level calibration check can be used (rather than triplicate analysis), the multi-point calibration can be conducted quarterly (rather than monthly), and the sampling line temperature must be maintained at a minimum temperature of 60 °C (rather than 120 °C). Specify calibration requirements in your site specific CPMS monitoring plan. Calibration requirements should follow manufacturer’s recommendations at a minimum. Select the sampling location at least two equivalent duct diameters from the nearest control device, point of pollutant generation, air inleakages, or other point at which a change in the pollutant concentration occurs. 39. Section 63.1562 is amended by revising paragraphs (b)(3) and (f)(5) to read as follows: ■ § 63.1562 What parts of my plant are covered by this subpart? * * * * * (b) * * * (3) The process vent or group of process vents on Claus or other types of sulfur recovery plant units or the tail gas treatment units serving sulfur recovery plants that are associated with sulfur recovery. * * * * * (f) * * * (5) Gaseous streams routed to a fuel gas system, provided that on and after January 30, 2019, any flares receiving gas from the fuel gas system are subject to § 63.670. ■ 40. Section 63.1564 is amended by: ■ a. Revising paragraphs (a)(1) and (2); ■ b. Adding paragraph (a)(5); ■ c. Removing the equation following paragraph (b)(4)(ii) and adding it after paragraph (b)(4)(iii) introductory text; ■ d. Revising paragraphs (b)(2), (b)(4)(i) and (ii), and (b)(4)(iv); and ■ e. Adding paragraph (c)(5). The revisions and additions read as follows: § 63.1564 What are my requirements for metal HAP emissions from catalytic cracking units? tkelley on DSK3SPTVN1PROD with RULES2 (a) * * * Where: Rc = Coke burn-off rate, kg/hr (lb/hr); VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (1) Except as provided in paragraph (a)(5) of this section, meet each emission limitation in Table 1 of this subpart that applies to you. If your catalytic cracking unit is subject to the NSPS for PM in § 60.102 of this chapter or is subject to § 60.102a(b)(1) of this chapter, you must meet the emission limitations for NSPS units. If your catalytic cracking unit is not subject to the NSPS for PM, you can choose from the four options in paragraphs (a)(1)(i) through (vi) of this section: (i) You can elect to comply with the NSPS for PM in § 60.102 of this chapter (Option 1a); (ii) You can elect to comply with the NSPS for PM coke burn-off emission limit in § 60.102a(b)(1) of this chapter (Option 1b); (iii) You can elect to comply with the NSPS for PM concentration limit in § 60.102a(b)(1) of this chapter (Option 1c); (iv) You can elect to comply with the PM per coke burn-off emission limit in § 60.102a(b)(1) of this chapter (Option 2); (v) You can elect to comply with the Nickel (Ni) lb/hr emission limit (Option 3); or (vi) You can elect to comply with the Ni per coke burn-off emission limit (Option 4). (2) Comply with each operating limit in Table 2 of this subpart that applies to you. When a specific control device may be monitored using more than one continuous parameter monitoring system, you may select the parameter with which you will comply. You must provide notice to the Administrator (or Qr = Volumetric flow rate of exhaust gas from catalyst regenerator before adding air or PO 00000 Frm 00097 Fmt 4701 Sfmt 4700 other designated authority) if you elect to change the monitoring option. * * * * * (5) During periods of startup, shutdown and hot standby, you can choose from the two options in paragraphs (a)(5)(i) and (ii) of this section: (i) You can elect to comply with the requirements in paragraphs (a)(1) and (2) of this section, except catalytic cracking units controlled using a wet scrubber must maintain only the liquid to gas ratio operating limit (the pressure drop operating limit does not apply); or (ii) You can elect to maintain the inlet velocity to the primary internal cyclones of the catalytic cracking unit catalyst regenerator at or above 20 feet per second. (b) * * * (2) Conduct a performance test for each catalytic cracking unit according to the requirements in § 63.1571 and under the conditions specified in Table 4 of this subpart. * * * * * (4) * * * (i) If you elect Option 1b or Option 2 in paragraph (a)(1)(ii) or (iv) of this section, compute the PM emission rate (lb/1,000 lb of coke burn-off) for each run using Equations 1, 2, and 3 (if applicable) of this section and the sitespecific opacity limit, if applicable, using Equation 4 of this section as follows: gas streams. Example: You may measure upstream or downstream of an E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.018</GPH> Subpart UUU-—National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units 75274 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Qsd = Volumetric flow rate of the catalytic cracking unit catalyst regenerator flue gas as measured by Method 2 in appendix A–1 to part 60 of this chapter, dscm/hr (dscf/hr); Rc = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr); and K = Conversion factor, 1.0 (kg2/g)/(1,000 kg) (1,000 lb/(1,000 lb)). Where: Es = Emission rate of PM allowed, kg/1,000 kg (1b/1,000 lb) of coke burn-off in catalyst regenerator; 1.0 = Emission limitation, kg coke/1,000 kg (lb coke/1,000 lb); A = Allowable incremental rate of PM emissions. Before August 1, 2017, A = 0.18 g/million cal (0.10 lb/million Btu). On or after August 1, 2017, A = 0 g/ million cal (0 lb/million Btu); H = Heat input rate from solid or liquid fossil fuel, million cal/hr (million Btu/hr). Make sure your permitting authority approves procedures for determining the heat input rate; Rc = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr) determined using Equation 1 of this section; and K′ = Conversion factor to units to standard, 1.0 (kg2/g)/(1,000 kg) (103 lb/(1,000 lb)). Where: Opacity Limit = Maximum permissible hourly average opacity, percent, or 10 percent, whichever is greater; Opacityst = Hourly average opacity measured during the source test, percent; and PMEmRst = PM emission rate measured during the source test, lb/1,000 lb coke burn. (ii) If you elect Option 1c in paragraph (a)(1)(iii) of this section, the PM concentration emission limit, determine the average PM concentration from the initial performance test used to certify your PM CEMS. * * * * * (iv) If you elect Option 4 in paragraph (a)(1)(vi) of this section, the Ni per coke burn-off emission limit, compute your Ni emission rate using Equations 1 and 8 of this section and your site-specific Ni operating limit (if you use a continuous opacity monitoring system) using Equations 9 and 10 of this section as follows: Where: ENi2 = Normalized mass emission rate of Ni, mg/kg coke (lb/1,000 lb coke). ER01DE15.023</GPH> Qoxy = Volumetric flow rate of oxygenenriched air stream to regenerator, as determined from instruments in the catalytic cracking unit control room, dscm/min (dscf/min); and %Oxy = Oxygen concentration in oxygenenriched air stream, percent by volume (dry basis). VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00098 Fmt 4701 Sfmt 4725 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.019</GPH> ER01DE15.020</GPH> ER01DE15.021</GPH> ER01DE15.022</GPH> %CO = Carbon monoxide concentration in regenerator exhaust, percent by volume (dry basis); %O2 = Oxygen concentration in regenerator exhaust, percent by volume (dry basis); K1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dscm-%) (0.0186 (lbmin)/(hr-dscf-%)); K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) (0.1303 (lbmin)/(hr-dscf)); K3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm-%) (0.0062 (lbmin)/(hr-dscf-%)); Where: E = Emission rate of PM, kg/1,000 kg (lb/ 1,000 lb) of coke burn-off; Cs = Concentration of PM, g/dscm (lb/dscf); tkelley on DSK3SPTVN1PROD with RULES2 electrostatic precipitator, but you must measure upstream of a carbon monoxide boiler, dscm/min (dscf/min). You may use the alternative in either § 63.1573(a)(1) or (2), as applicable, to calculate Qr; Qa = Volumetric flow rate of air to catalytic cracking unit catalyst regenerator, as determined from instruments in the catalytic cracking unit control room, dscm/min (dscf/min); %CO2 = Carbon dioxide concentration in regenerator exhaust, percent by volume (dry basis); Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations NiEmR2st = Average Ni emission rate calculated as the arithmetic average Ni emission rate using Equation 8 of this Where: Ni Operating Limit2 = Maximum permissible hourly average Ni operating limit, percent-ppmw-acfm-hr/kg coke, i.e., your site-specific Ni operating limit; and Rc,st = Coke burn rate from Equation 1 of this section, as measured during the initial performance test, kg coke/hr. § 63.1565 What are my requirements for organic HAP emissions from catalytic cracking units? tkelley on DSK3SPTVN1PROD with RULES2 * * * * * (c) * * * (5) If you elect to comply with the alternative limit in paragraph (a)(5)(ii) of this section during periods of startup, shutdown, and hot standby, demonstrate continuous compliance by: (i) Collecting the volumetric flow rate from the catalyst regenerator (in acfm) and determining the average flow rate for each hour. For events lasting less than one hour, determine the average flow rate during the event. (ii) Determining the cumulative crosssectional area of the primary internal cyclone inlets in square feet (ft2) using design drawings of the primary (firststage) internal cyclones to determine the inlet cross-sectional area of each primary internal cyclone and summing the cross-sectional areas for all primary internal cyclones in the catalyst regenerator or, if primary cyclones. If all primary internal cyclones are identical, you may alternatively determine the inlet cross-sectional area of one primary internal cyclone using design drawings and multiply that area by the total number of primary internal cyclones in the catalyst regenerator. (iii) Calculating the inlet velocity to the primary internal cyclones in square feet per second (ft2/sec) by dividing the average volumetric flow rate (acfm) by the cumulative cross-sectional area of the primary internal cyclone inlets (ft2) and by 60 seconds/minute (for unit conversion). (iv) Maintaining the inlet velocity to the primary internal cyclones at or above 20 feet per second for each hour during the startup, shutdown, or hot standby event or, for events lasting less than 1 hour, for the duration of the event. ■ 41. Section 63.1565 is amended by revising paragraph (a)(1) introductory text and adding paragraph (a)(5) to read as follows: VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 (a) * * * (1) Except as provided in paragraph (a)(5) of this section, meet each emission limitation in Table 8 of this subpart that applies to you. If your catalytic cracking unit is subject to the NSPS for carbon monoxide (CO) in § 60.103 of this chapter or is subject to § 60.102a(b)(4) of this chapter, you must meet the emission limitations for NSPS units. If your catalytic cracking unit is not subject to the NSPS for CO, you can choose from the two options in paragraphs (a)(1)(i) through (ii) of this section: * * * * * (5) During periods of startup, shutdown and hot standby, you can choose from the two options in paragraphs (a)(5)(i) and (ii) of this section: (i) You can elect to comply with the requirements in paragraphs (a)(1) and (2) of this section; or (ii) You can elect to maintain the oxygen (O2) concentration in the exhaust gas from your catalyst regenerator at or above 1 volume percent (dry basis). * * * * * ■ 42. Section 63.1566 is amended by revising paragraphs (a)(1) introductory text, (a)(1)(i), and (a)(4) to read as follows: § 63.1566 What are my requirements for organic HAP emissions from catalytic reforming units? (a) * * * (1) Meet each emission limitation in Table 15 of this subpart that applies to you. You can choose from the two options in paragraphs (a)(1)(i) and (ii) of this section. (i) You can elect to vent emissions of total organic compounds (TOC) to a flare (Option 1). On and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must meet the control device requirements in § 63.11(b) or the requirements of § 63.670. * * * * * PO 00000 Frm 00099 Fmt 4701 Sfmt 4700 section for each of the performance test runs, mg/kg coke. (4) The emission limitations in Tables 15 and 16 of this subpart do not apply to emissions from process vents during passive depressuring when the reactor vent pressure is 5 pounds per square inch gauge (psig) or less. The emission limitations in Tables 15 and 16 of this subpart do apply to emissions from process vents during active purging operations (when nitrogen or other purge gas is actively introduced to the reactor vessel) or active depressuring (using a vacuum pump, ejector system, or similar device) regardless of the reactor vent pressure. * * * * * ■ 43. Section 63.1568 is amended by revising paragraphs (a)(1) introductory text and (a)(1)(i) and adding paragraph (a)(4) to read as follows: § 63.1568 What are my requirements for HAP emissions from sulfur recovery units? (a) * * * (1) Meet each emission limitation in Table 29 of this subpart that applies to you. If your sulfur recovery unit is subject to the NSPS for sulfur oxides in § 60.104 or § 60.102a(f)(1) of this chapter, you must meet the emission limitations for NSPS units. If your sulfur recovery unit is not subject to one of these NSPS for sulfur oxides, you can choose from the options in paragraphs (a)(1)(i) through (ii) of this section: (i) You can elect to meet the NSPS requirements in § 60.104(a)(2) or § 60.102a(f)(1) of this chapter (Option 1); or * * * * * (4) During periods of startup and shutdown, you can choose from the three options in paragraphs (a)(4)(i) through (iii) of this section. (i) You can elect to comply with the requirements in paragraphs (a)(1) and (2) of this section. (ii) You can elect to send any startup or shutdown purge gases to a flare. On and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must meet the design and operating requirements in § 63.11(b) or the requirements of § 63.670. (iii) You can elect to send any startup or shutdown purge gases to a thermal oxidizer or incinerator operated at a E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.024</GPH> Where: Opacity2 = Opacity value for use in Equation 10 of this section, percent, or 10 percent, whichever is greater; and 75275 75276 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations minimum hourly average temperature of 1,200 degrees Fahrenheit in the firebox and a minimum hourly average outlet oxygen (O2) concentration of 2 volume percent (dry basis). * * * * * 44. Section 63.1570 is amended by revising paragraphs (a) through (d) and removing paragraph (g) to read as follows: ■ § 63.1570 What are my general requirements for complying with this subpart? (a) You must be in compliance with all of the non-opacity standards in this subpart at all times. (b) You must be in compliance with the opacity and visible emission limits in this subpart at all times. (c) At all times, you must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. The general duty to minimize emissions does not require you to make any further efforts to reduce emissions if levels required by the applicable standard have been achieved. Determination of whether a source is operating in compliance with operation and maintenance requirements will be based on information available to the Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source. (d) During the period between the compliance date specified for your affected source and the date upon which continuous monitoring systems have been installed and validated and any applicable operating limits have been set, you must maintain a log that documents the procedures used to minimize emissions from process and emissions control equipment according to the general duty in paragraph (c) of this section. * * * * * 45. Section 63.1571 is amended by: a. Adding paragraphs (a)(5) and (6); ■ b. Revising paragraph (b)(1); ■ c. Removing paragraph (b)(4); ■ d. Redesignating paragraph (b)(5) as paragraph (b)(4); and ■ e. Revising the first sentence of paragraph (d)(2) and paragraph (d)(4). The revisions and additions read as follows: ■ tkelley on DSK3SPTVN1PROD with RULES2 ■ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 § 63.1571 How and when do I conduct a performance test or other initial compliance demonstration? (a) * * * (5) Periodic performance testing for PM or Ni. Except as provided in paragraphs (a)(5)(i) and (ii) of this section, conduct a periodic performance test for PM or Ni for each catalytic cracking unit at least once every 5 years according to the requirements in Table 4 of this subpart. You must conduct the first periodic performance test no later than August 1, 2017. (i) Catalytic cracking units monitoring PM concentration with a PM CEMS are not required to conduct a periodic PM performance test. (ii) Conduct a performance test annually if you comply with the emission limits in Item 1 (NSPS subpart J) or Item 4 (Option 1a) in Table 1 of this subpart and the PM emissions measured during the most recent performance source test are greater than 0.80 g/kg coke burn-off. (6) One-time performance testing for HCN. Conduct a performance test for HCN from each catalytic cracking unit no later than August 1, 2017 according to the applicable requirements in paragraphs (a)(6)(i) and (ii) of this section. (i) If you conducted a performance test for HCN for a specific catalytic cracking unit between March 31, 2011 and February 1, 2016, you may submit a request to the Administrator to use the previously conducted performance test results to fulfill the one-time performance test requirement for HCN for each of the catalytic cracking units tested according to the requirements in paragraphs (a)(6)(i)(A) through (D) of this section. (A) The request must include a copy of the complete source test report, the date(s) of the performance test and the test methods used. If available, you must also indicate whether the catalytic cracking unit catalyst regenerator was operated in partial or complete combustion mode during the test, the control device configuration, including whether platinum or palladium combustion promoters were used during the test, and the CO concentration (measured using CO CEMS or manual test method) for each test run. (B) You must submit a separate request for each catalytic cracking unit tested and you must submit each request to the Administrator no later than March 30, 2016. (C) The Administrator will evaluate each request with respect to the completeness of the request, the completeness of the submitted test report and the appropriateness of the PO 00000 Frm 00100 Fmt 4701 Sfmt 4700 test methods used. The Administrator will notify the facility within 60 days of receipt of the request if it is approved or denied. If the Administrator fails to respond to the facility within 60 days of receipt of the request, the request will be automatically approved. (D) If the request is approved, you do not need to conduct an additional HCN performance test. If the request is denied, you must conduct an additional HCN performance test following the requirements in (a)(6)(ii) of this section. (ii) Unless you receive approval to use a previously conducted performance test to fulfill the one-time performance test requirement for HCN for your catalytic cracking unit as provided in paragraph (a)(6)(i) of this section, conduct a performance test for HCN for each catalytic cracking unit no later than August 1, 2017 according to following requirements: (A) Select sampling port location, determine volumetric flow rate, conduct gas molecular weight analysis and measure moisture content as specified in either Item 1 of Table 4 of this subpart or Item 1 of Table 11 of this subpart. (B) Measure HCN concentration using Method 320 of appendix A of this part. The method ASTM D6348–03 (Reapproved 2010) including Annexes A1 through A8 (incorporated by reference—see § 63.14) is an acceptable alternative to EPA Method 320 of appendix A of this part. The method ASTM D6348–12e1 (incorporated by reference—see § 63.14) is an acceptable alternative to EPA Method 320 of appendix A of this part with the following two caveats: (1) The test plan preparation and implementation in the Annexes to ASTM D6348–03 (Reapproved 2010), Sections A1 through A8 are mandatory; and (2) In ASTM D6348–03 (Reapproved 2010) Annex A5 (Analyte Spiking Technique), the percent (%) R must be determined for each target analyte (Equation A5.5). In order for the test data to be acceptable for a compound, %R must be 70% ≥ R ≤ 130%. If the %R value does not meet this criterion for a target compound, the test data is not acceptable for that compound and the test must be repeated for that analyte (i.e., the sampling and/or analytical procedure should be adjusted before a retest). The %R value for each compound must be reported in the test report, and all field measurements must be corrected with the calculated %R value for that compound by using the following equation: E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Reported Result = (Measured Concentration in the Stack × 100÷/ % R. (C) Measure CO concentration as specified in either Item 2 or 3a of Table 11 of this subpart. (D) Record and include in the test report an indication of whether the catalytic cracking unit catalyst regenerator was operated in partial or complete combustion mode and the control device configuration, including whether platinum or palladium combustion promoters were used during the test. (b) * * * (1) Performance tests shall be conducted according to the provisions of § 63.7(e) except that performance tests shall be conducted at maximum representative operating capacity for the process. During the performance test, you must operate the control device at either maximum or minimum representative operating conditions for monitored control device parameters, whichever results in lower emission reduction. You must not conduct a performance test during startup, shutdown, periods when the control device is bypassed or periods when the process, monitoring equipment or control device is not operating properly. You may not conduct performance tests during periods of malfunction. You must record the process information that is necessary to document operating conditions during the test and include in such record an explanation to support that the test was conducted at maximum representative operating capacity. Upon request, you must make available to the Administrator such records as may be necessary to determine the conditions of performance tests. * * * * * (d) * * * (2) If you must meet the HAP metal emission limitations in § 63.1564, you elect the option in paragraph (a)(1)(iv) in § 63.1564 (Ni per coke burn-off), and you use continuous parameter monitoring systems, you must establish an operating limit for the equilibrium catalyst Ni concentration based on the laboratory analysis of the equilibrium catalyst Ni concentration from the initial performance test. * * * * * * * * (4) Except as specified in paragraph (d)(3) of this section, if you use continuous parameter monitoring systems, you may adjust one of your monitored operating parameters (flow rate, total power and secondary current, pressure drop, liquid-to-gas ratio) from the average of measured values during VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 the performance test to the maximum value (or minimum value, if applicable) representative of worst-case operating conditions, if necessary. This adjustment of measured values may be done using control device design specifications, manufacturer recommendations, or other applicable information. You must provide supporting documentation and rationale in your Notification of Compliance Status, demonstrating to the satisfaction of your permitting authority, that your affected source complies with the applicable emission limit at the operating limit based on adjusted values. * * * * * ■ 46. Section 63.1572 is amended by revising paragraphs (c) introductory text, (c)(1), (3), and (4) and (d)(1) and (2) to read as follows: § 63.1572 What are my monitoring installation, operation, and maintenance requirements? * * * * * (c) Except for flare monitoring systems, you must install, operate, and maintain each continuous parameter monitoring system according to the requirements in paragraphs (c)(1) through (5) of this section. For flares, on and after January 30, 2019, you must install, operate, calibrate, and maintain monitoring systems as specified in §§ 63.670 and 63.671. Prior to January 30, 2019, you must either meet the monitoring system requirements in paragraphs (c)(1) through (5) of this section or meet the requirements in §§ 63.670 and 63.671. (1) You must install, operate, and maintain each continuous parameter monitoring system according to the requirements in Table 41 of this subpart. You must also meet the equipment specifications in Table 41 of this subpart if pH strips or colormetric tube sampling systems are used. You must install, operate, and maintain each continuous parameter monitoring system according to the requirements in Table 41 of this subpart. You must meet the requirements in Table 41 of this subpart for BLD systems. Alternatively, before August 1, 2017, you may install, operate, and maintain each continuous parameter monitoring system in a manner consistent with the manufacturer’s specifications or other written procedures that provide adequate assurance that the equipment will monitor accurately. * * * * * (3) Each continuous parameter monitoring system must have valid hourly average data from at least 75 PO 00000 Frm 00101 Fmt 4701 Sfmt 4700 75277 percent of the hours during which the process operated, except for BLD systems. (4) Each continuous parameter monitoring system must determine and record the hourly average of all recorded readings and if applicable, the daily average of all recorded readings for each operating day, except for BLD systems. The daily average must cover a 24-hour period if operation is continuous or the number of hours of operation per day if operation is not continuous, except for BLD systems. * * * * * (d) * * * (1) You must conduct all monitoring in continuous operation (or collect data at all required intervals) at all times the affected source is operating. (2) You may not use data recorded during required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments) for purposes of this regulation, including data averages and calculations, for fulfilling a minimum data availability requirement, if applicable. You must use all the data collected during all other periods in assessing the operation of the control device and associated control system. ■ 47. Section 63.1573 is amended by: ■ a. Redesignating paragraphs (b), (c), (d), (e), and (f) as paragraphs (c), (d), (e), (f), and (g); ■ b. Adding paragraph (b); and ■ c. Revising newly redesignated paragraphs (c) introductory text, (d) introductory text, (f) introductory text, and (g)(1) introductory text. The revisions and additions read as follows: § 63.1573 What are my monitoring alternatives? * * * * * (b) What is the approved alternative for monitoring pressure drop? You may use this alternative to a continuous parameter monitoring system for pressure drop if you operate a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles. You shall: (1) Conduct a daily check of the air or water pressure to the spray nozzles; (2) Maintain records of the results of each daily check; and (3) Repair or replace faulty (e.g., leaking or plugged) air or water lines within 12 hours of identification of an abnormal pressure reading. (c) What is the approved alternative for monitoring pH or alkalinity levels? You may use the alternative in E:\FR\FM\01DER2.SGM 01DER2 75278 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations paragraph (c)(1) or (2) of this section for a catalytic reforming unit. * * * * * (d) Can I use another type of monitoring system? You may use an automated data compression system. An automated data compression system does not record monitored operating parameter values at a set frequency (e.g., once every hour) but records all values that meet set criteria for variation from previously recorded values. You must maintain a record of the description of the monitoring system and data recording system, including the criteria used to determine which monitored values are recorded and retained, the method for calculating daily averages, and a demonstration that the system meets all of the criteria in paragraphs (d)(1) through (5) of this section: * * * * * (f) How do I request to monitor alternative parameters? You must submit a request for review and approval or disapproval to the Administrator. The request must include the information in paragraphs (f)(1) through (5) of this section. * * * * * (g) * * * (1) You may request alternative monitoring requirements according to the procedures in this paragraph if you meet each of the conditions in paragraphs (g)(1)(i) through (iii) of this section: * * * * * ■ 48. Section 63.1574 is amended by revising paragraphs (a)(3) introductory text and (f)(1) to read as follows: tkelley on DSK3SPTVN1PROD with RULES2 § 63.1574 What notifications must I submit and when? (a) * * * (3) If you are required to conduct an initial performance test, performance evaluation, design evaluation, opacity observation, visible emission observation, or other initial compliance demonstration, you must submit a notification of compliance status according to § 63.9(h)(2)(ii). You can submit this information in an operating permit application, in an amendment to an operating permit application, in a separate submission, or in any combination. In a State with an approved operating permit program where delegation of authority under section 112(l) of the CAA has not been requested or approved, you must provide a duplicate notification to the applicable Regional Administrator. If the required information has been submitted previously, you do not have to provide a separate notification of compliance status. Just refer to the VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 earlier submissions instead of duplicating and resubmitting the previously submitted information. * * * * * (f) * * * (1) You must submit the plan to your permitting authority for review and approval along with your notification of compliance status. While you do not have to include the entire plan in your permit under part 70 or 71 of this chapter, you must include the duty to prepare and implement the plan as an applicable requirement in your part 70 or 71 operating permit. You must submit any changes to your permitting authority for review and approval and comply with the plan as submitted until the change is approved. * * * * * ■ 49. Section 63.1575 is amended by: ■ a. Revising paragraphs (d) introductory text and (d)(1) and (2); ■ b. Adding paragraph (d)(4); ■ c. Revising paragraph (e) introductory text; ■ d. Removing and reserving paragraph (e)(1); ■ e. Revising paragraphs (e)(4) and (6) and (f)(1) and (2); ■ f. Removing and reserving paragraph (h); and ■ g. Adding paragraph (k). The revisions and additions read as follows: § 63.1575 when? What reports must I submit and * * * * * (d) For each deviation from an emission limitation and for each deviation from the requirements for work practice standards that occurs at an affected source where you are not using a continuous opacity monitoring system or a continuous emission monitoring system to comply with the emission limitation or work practice standard in this subpart, the semiannual compliance report must contain the information in paragraphs (c)(1) through (3) of this section and the information in paragraphs (d)(1) through (4) of this section. (1) The total operating time of each affected source during the reporting period and identification of the sources for which there was a deviation. (2) Information on the number, date, time, duration, and cause of deviations (including unknown cause, if applicable). * * * * * (4) The applicable operating limit or work practice standard from which you deviated and either the parameter monitor reading during the deviation or a description of how you deviated from the work practice standard. PO 00000 Frm 00102 Fmt 4701 Sfmt 4700 (e) For each deviation from an emission limitation occurring at an affected source where you are using a continuous opacity monitoring system or a continuous emission monitoring system to comply with the emission limitation, you must include the information in paragraphs (c)(1) through (3) of this section, in paragraphs (d)(1) through (3) of this section, and in paragraphs (e)(2) through (13) of this section. * * * * * (4) An estimate of the quantity of each regulated pollutant emitted over the emission limit during the deviation, and a description of the method used to estimate the emissions. * * * * * (6) A breakdown of the total duration of the deviations during the reporting period and into those that are due to control equipment problems, process problems, other known causes, and other unknown causes. * * * * * (f) * * * (1) You must include the information in paragraph (f)(1)(i) or (ii) of this section, if applicable. (i) If you are complying with paragraph (k)(1) of this section, a summary of the results of any performance test done during the reporting period on any affected unit. Results of the performance test include the identification of the source tested, the date of the test, the percentage of emissions reduction or outlet pollutant concentration reduction (whichever is needed to determine compliance) for each run and for the average of all runs, and the values of the monitored operating parameters. (ii) If you are not complying with paragraph (k)(1) of this section, a copy of any performance test done during the reporting period on any affected unit. The report may be included in the next semiannual compliance report. The copy must include a complete report for each test method used for a particular kind of emission point tested. For additional tests performed for a similar emission point using the same method, you must submit the results and any other information required, but a complete test report is not required. A complete test report contains a brief process description; a simplified flow diagram showing affected processes, control equipment, and sampling point locations; sampling site data; description of sampling and analysis procedures and any modifications to standard procedures; quality assurance procedures; record of operating conditions during the test; record of E:\FR\FM\01DER2.SGM 01DER2 tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations preparation of standards; record of calibrations; raw data sheets for field sampling; raw data sheets for field and laboratory analyses; documentation of calculations; and any other information required by the test method. (2) Any requested change in the applicability of an emission standard (e.g., you want to change from the PM standard to the Ni standard for catalytic cracking units or from the HCl concentration standard to percent reduction for catalytic reforming units) in your compliance report. You must include all information and data necessary to demonstrate compliance with the new emission standard selected and any other associated requirements. * * * * * (k) Electronic submittal of performance test and CEMS performance evaluation data. For performance tests or CEMS performance evaluations conducted on and after February 1, 2016, if required to submit the results of a performance test or CEMS performance evaluation, you must submit the results according to the procedures in paragraphs (k)(1) and (2) of this section. (1) Within 60 days after the date of completing each performance test as required by this subpart, you must submit the results of the performance tests following the procedure specified in either paragraph (k)(1)(i) or (ii) of this section. (i) For data collected using test methods supported by the EPA’s Electronic Reporting Tool (ERT) as listed on the EPA’s ERT Web site (https://www.epa.gov/ttn/chief/ert/ index.html) at the time of the test, you must submit the results of the performance test to the EPA via the Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA’s Central Data Exchange (CDX) (https:// cdx.epa.gov/).) Performance test data must be submitted in a file format generated through use of the EPA’s ERT or an alternate electronic file format consistent with the extensible markup language (XML) schema listed on the EPA’s ERT Web site. If you claim that some of the performance test information being submitted is confidential business information (CBI), you must submit a complete file generated through the use of the EPA’s ERT or an alternate electronic file consistent with the XML schema listed on the EPA’s ERT Web site, including information claimed to be CBI, on a compact disc, flash drive or other commonly used electronic storage VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 media to the EPA. The electronic storage media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404– 02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA’s CDX as described earlier in this paragraph (k)(1)(i). (ii) For data collected using test methods that are not supported by the EPA’s ERT as listed on the EPA’s ERT Web site at the time of the test, you must submit the results of the performance test to the Administrator at the appropriate address listed in § 63.13. (2) Within 60 days after the date of completing each CEMS performance evaluation required by § 63.1571(a) and (b), you must submit the results of the performance evaluation following the procedure specified in either paragraph (k)(2)(i) or (ii) of this section. (i) For performance evaluations of continuous monitoring systems measuring relative accuracy test audit (RATA) pollutants that are supported by the EPA’s ERT as listed on the EPA’s ERT Web site at the time of the evaluation, you must submit the results of the performance evaluation to the EPA via the CEDRI. (CEDRI is accessed through the EPA’s CDX.) Performance evaluation data must be submitted in a file format generated through the use of the EPA’s ERT or an alternate file format consistent with the XML schema listed on the EPA’s ERT Web site. If you claim that some of the performance evaluation information being submitted is CBI, you must submit a complete file generated through the use of the EPA’s ERT or an alternate electronic file consistent with the XML schema listed on the EPA’s ERT Web site, including information claimed to be CBI, on a compact disc, flash drive or other commonly used electronic storage media to the EPA. The electronic storage media must be clearly marked as CBI and mailed to U.S. EPA/ OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404–02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI omitted must be submitted to the EPA via the EPA’s CDX as described earlier in this paragraph (k)(2)(i). (ii) For any performance evaluations of continuous monitoring systems measuring RATA pollutants that are not supported by the EPA’s ERT as listed on the EPA’s ERT Web site at the time of the evaluation, you must submit the results of the performance evaluation to the Administrator at the appropriate address listed in § 63.13. PO 00000 Frm 00103 Fmt 4701 Sfmt 4700 75279 50. Section 63.1576 is amended by revising paragraphs (a)(2) and (b)(3) and (5) to read as follows: ■ § 63.1576 What records must I keep, in what form, and for how long? (a) * * * (2) The records specified in paragraphs (a)(2)(i) through (iv) of this section. (i) Record the date, time, and duration of each startup and/or shutdown period, recording the periods when the affected source was subject to the standard applicable to startup and shutdown. (ii) In the event that an affected unit fails to meet an applicable standard, record the number of failures. For each failure record the date, time and duration of each failure. (iii) For each failure to meet an applicable standard, record and retain a list of the affected sources or equipment, an estimate of the volume of each regulated pollutant emitted over any emission limit and a description of the method used to estimate the emissions. (iv) Record actions taken to minimize emissions in accordance with § 63.1570(c) and any corrective actions taken to return the affected unit to its normal or usual manner of operation. * * * * * (b) * * * (3) The performance evaluation plan as described in § 63.8(d)(2) for the life of the affected source or until the affected source is no longer subject to the provisions of this part, to be made available for inspection, upon request, by the Administrator. If the performance evaluation plan is revised, you must keep previous (i.e., superseded) versions of the performance evaluation plan on record to be made available for inspection, upon request, by the Administrator, for a period of 5 years after each revision to the plan. The program of corrective action should be included in the plan required under § 63.8(d)(2). * * * * * (5) Records of the date and time that each deviation started and stopped. * * * * * ■ 51. Section 63.1579 is amended by: ■ a. Revising the introductory text; ■ b. Adding, in alphabetical order, a new definition of ‘‘Hot standby’’; and ■ c. Revising the definitions of ‘‘Deviation’’ and ‘‘PM’’. The revisions read as follows: § 63.1579 subpart? What definitions apply to this Terms used in this subpart are defined in the Clean Air Act (CAA), in 40 CFR 63.2, the General Provisions of E:\FR\FM\01DER2.SGM 01DER2 75280 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations this part (§§ 63.1 through 63.15), and in this section as listed. If the same term is defined in subpart A of this part and in this section, it shall have the meaning given in this section for purposes of this subpart. * * * * * Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a source: (1) Fails to meet any requirement or obligation established by this subpart, including but not limited to any emission limit, operating limit, or work practice standard; or (2) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit. * * * * * Hot standby means periods when the catalytic cracking unit is not receiving fresh or recycled feed oil but the catalytic cracking unit is maintained at elevated temperatures, typically using torch oil in the catalyst regenerator and recirculating catalyst, to prevent a complete shutdown and cold restart of the catalytic cracking unit. * * * * * PM means, for the purposes of this subpart, emissions of particulate matter that serve as a surrogate measure of the total emissions of particulate matter and metal HAP contained in the particulate matter, including but not limited to: Antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium as measured by Methods 5, 5B or 5F in appendix A–3 to part 60 of this chapter or by an approved alternative method. * * * * * 52. Table 1 to subpart UUU of part 63 is revised to read as follows: As stated in § 63.1564(a)(1), you shall meet each emission limitation in the following table that applies to you. ■ TABLE 1 TO SUBPART UUU OF PART 63—METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS For each new or existing catalytic cracking unit . . . You shall meet the following emission limits for each catalyst regenerator vent . . . 1. Subject to new source performance standard (NSPS) for PM in 40 CFR 60.102 and not electing § 60.100(e). PM emissions must not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/ 1,000 lb) of coke burn-off, and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in any 1-hour period. Before August 1, 2017, if the discharged gases pass through an incinerator or waste heat boiler in which you burn auxiliary or in supplemental liquid or solid fossil fuel, the incremental rate of PM emissions must not exceed 43.0 grams per Gigajoule (g/ GJ) or 0.10 pounds per million British thermal units (lb/million Btu) of heat input attributable to the liquid or solid fossil fuel; and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in any 1-hour period. PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1,000 lb) of coke burn-off or, if a PM CEMS is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air. PM emissions must not exceed 0.5 g/kg coke burn-off (0.5 lb/1000 lb coke burn-off) or, if a PM CEMS is used, 0.020 gr/dscf corrected to 0 percent excess air. PM emissions must not exceed the limits specified in Item 1 of this table. 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i); or 40 CFR 60.102 and electing § 60.100(e). 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii) .......................... 4. Option 1a: Elect NSPS subpart J requirements for PM per coke burn limit and 30% opacity, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 5. Option 1b: Elect NSPS subpart Ja requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 6. Option 1c: Elect NSPS subpart Ja requirements for PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 7. Option 2: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 8. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 9. Option 4: Ni per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 53. Table 2 to subpart UUU of part 63 is revised to read as follows: ■ PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1000 lb) of coke burn-off. PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent excess air. PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1000 lb) of coke burn-off in the catalyst regenerator. Nickel (Ni) emissions must not exceed 13,000 milligrams per hour (mg/ hr) (0.029 lb/hr). Ni emissions must not exceed 1.0 mg/kg (0.001 lb/1,000 lb) of coke burn-off in the catalyst regenerator. As stated in § 63.1564(a)(2), you shall meet each operating limit in the following table that applies to you. tkelley on DSK3SPTVN1PROD with RULES2 TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS For each new or existing catalytic cracking unit . . . For this type of continuous monitoring system . . . For this type of control device . . . You shall meet this operating limit . . . 1. Subject to the NSPS for PM in 40 CFR 60.102 and not electing § 60.100(e). Continuous system. Any ................................................ Maintain the 3-hour rolling average opacity of emissions from your catalyst regenerator vent no higher than 20 percent. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 opacity PO 00000 monitoring Frm 00104 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75281 TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . For this type of continuous monitoring system . . . For this type of control device . . . You shall meet this operating limit . . . 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i) or electing § 60.100(e). a. PM CEMS ................................. Any ................................................ Not applicable. b. Continuous opacity monitoring system used to comply with a site-specific opacity limit. Cyclone or electrostatic precipitator. c. Continuous parameter monitoring systems. Electrostatic precipitator ............... d. Continuous parameter monitoring systems. Wet scrubber ................................ e. Bag leak detection (BLD) system. Fabric filter .................................... Any ................................................ Any ................................................ Any ................................................ Any ................................................ Maintain the 3-hour rolling average opacity of emissions from your catalyst regenerator vent no higher than the site-specific opacity limit established during the performance test. i. Maintain the daily average coke burn-off rate or daily average flow rate no higher than the limit established in the performance test. ii. Maintain the 3-hour rolling average total power and secondary current above the limit established in the performance test. i. Maintain the 3-hour rolling average liquid-to-gas ratio above the limit established in the performance test. ii. Except for periods of startup, shutdown, and hot standby, maintain the 3-hour rolling average pressure drop above the limit established in the performance test.1 Maintain particulate loading below the BLD alarm set point established in the initial adjustment of the BLD system or allowable seasonal adjustments. The applicable operating limits in Item 2 of this table. See Item 1 of this table. Any ................................................ Any ................................................ The applicable operating limits in Item 2.b, 2.c, 2.d, and 2.e of this table. PM CEMS ..................................... Any ................................................ Not applicable. a. Continuous opacity monitoring system used to comply with a site-specific opacity limit. Cyclone, fabric filter, or electrostatic precipitator. b. Continuous parameter monitoring systems. i. Electrostatic precipitator ............ See Item 2.b of this table. Alternatively, before August 1, 2017, you may maintain the hourly average opacity of emissions from your catalyst generator vent no higher than the sitespecific opacity limit established during the performance test. (1) See Item 2.c.i of this table. (2) See item 2.c.ii of this table. Alternatively, before August 1, 2017, you may maintain the daily average voltage and secondary current above the limit established in the performance test. tkelley on DSK3SPTVN1PROD with RULES2 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii). 4. Option 1a: Elect NSPS subpart J requirements for PM per coke burn limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 5. Option 1b: Elect NSPS subpart Ja requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 6. Option 1c: Elect NSPS subpart Ja requirements for PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 7. Option 2: PM per coke burn-off limit not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00105 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75282 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . For this type of continuous monitoring system . . . For this type of control device . . . You shall meet this operating limit . . . ii. Wet scrubber ............................ (1) See Item 2.d.i of this table. Alternatively, before August 1, 2017, you may maintain the daily average liquid-to-gas ratio above the limit established in the performance test. (2) See Item 2.d.ii of the table. Alternatively, before August 1, 2017, you may maintain the daily average pressure drop above the limit established in the performance test (not applicable to a wet scrubber of the non-venturi jet-ejector design). See item 2.e of this table. Fabric filter .................................... b. Continuous parameter monitoring systems. 8. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 CFR 60.102. c. Bag leak detection (BLD) system. a. Continuous opacity monitoring system. i. Electrostatic precipitator ............ Cyclone, fabric filter, or electrostatic precipitator. ii. Wet scrubber ............................ tkelley on DSK3SPTVN1PROD with RULES2 c. Bag leak detection (BLD) system. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00106 Fmt 4701 Fabric filter .................................... Sfmt 4700 E:\FR\FM\01DER2.SGM Maintain the 3-hour rolling average Ni operating value no higher than the limit established during the performance test. Alternatively, before August 1, 2017, you may maintain the daily average Ni operating value no higher than the limit established during the performance test. (1) See Item 2.c.i of this table. (2) Maintain the monthly rolling average of the equilibrium catalyst Ni concentration no higher than the limit established during the performance test. (3) See Item 2.c.ii of this table. Alternatively, before August 1, 2017, you may maintain the daily average voltage and secondary current (or total power input) above the established during the performance test. (1) Maintain the monthly rolling average of the equilibrium catalyst Ni concentration no higher than the limit established during the performance test. (2) See Item 2.d.i of this table. Alternatively, before August 1, 2017, you may maintain the daily average liquid-to-gas ratio above the limit established during the performance test. (3) See Item 2.d.ii of this table. Alternatively, before August 1, 2017, you may maintain the daily average pressure drop above the limit established during the performance test (not applicable to a non-venturi wet scrubber of the jet-ejector design). See item 2.e of this table. 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75283 TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . For this type of continuous monitoring system . . . For this type of control device . . . You shall meet this operating limit . . . 9. Option 4: Ni per coke burn-off limit not subject to the NSPS for PM in 40 CFR 60.102. a. Continuous opacity monitoring system. Cyclone, fabric filter, or electrostatic precipitator. b. Continuous parameter monitoring systems. i. Electrostatic precipitator ............ Maintain the 3-hour rolling average Ni operating value no higher than Ni operating limit established during the performance test. Alternatively, before August 1, 2017, you may elect to maintain the daily average Ni operating value no higher than the Ni operating limit established during the performance test. (1) Maintain the monthly rolling average of the equilibrium catalyst Ni concentration no higher than the limit established during the performance test. (2) See Item 2.c.ii of this table. Alternatively, before August 1, 2017, you may maintain the daily average voltage and secondary current (or total power input) above the limit established during the performance test. (1) Maintain the monthly rolling average of the equilibrium catalyst Ni concentration no higher than the limit established during the performance test. (2) See Item 2.d.i of this table. Alternatively, before August 1, 2017, you may maintain the daily average liquid-to-gas ratio above the limit established during the performance test. (3) See Item 2.d.ii of this table. Alternatively, before August 1, 2017, you may maintain the daily average pressure drop above the limit established during the performance test (not applicable to a non-venturi wet scrubber of the jet-ejector design). See item 2.e of this table. ii. Wet scrubber ............................ 10. During periods of startup, shutdown, or hot standby. c. Bag leak detection (BLD) system. Any ................................................ Fabric filter .................................... Any ................................................ Meet the requirements § 63.1564(a)(5). in 1 If you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, you can use the alternative in § 63.1573(b), and comply with the daily inspections, recordkeeping, and repair provisions, instead of a continuous parameter monitoring system for pressure drop across the scrubber. 54. Table 3 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1564(b)(1), you shall meet each requirement in the following table that applies to you. tkelley on DSK3SPTVN1PROD with RULES2 TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS For each new or existing catalytic cracking unit . . . If you use this type of control device for your vent . . . You shall install, operate, and maintain a . . . 1. Subject to the NSPS for PM in 40 CFR 60.102 and not electing § 60.100(e). Any ................................................. Continuous opacity monitoring system to measure and record the opacity of emissions from each catalyst regenerator vent. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00107 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75284 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . If you use this type of control device for your vent . . . You shall install, operate, and maintain a . . . 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i); or in § 60.102 and electing § 60.100(e); electing to meet the PM per coke burn-off limit. a. Cyclone ...................................... b. Electrostatic precipitator ............ Continuous opacity monitoring system to measure and record the opacity of emissions from each catalyst regenerator vent. Continuous opacity monitoring system to measure and record the opacity of emissions from each catalyst regenerator vent; or continuous parameter monitoring systems to measure and record the coke burn-off rate or the gas flow rate entering or exiting the control device,1 the voltage, current, and secondary current to the control device. Continuous parameter monitoring system to measure and record the pressure drop across the scrubber,2 the coke burn-off rate or the gas flow rate entering or exiting the control device,3 and total liquid (or scrubbing liquor) flow rate to the control device. Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent. Continuous emission monitoring system to measure and record the concentration of PM and oxygen from each catalyst regenerator vent. c. Wet scrubber ............................. d. Fabric Filter ............................... 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i); or in § 60.102 and electing § 60.100(e); electing to meet the PM concentration limit. 4. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii) electing to meet the PM per coke burn-off limit. 5. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii) electing to meet the PM concentration limit. 6. Option 1a: Elect NSPS subpart J, PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.120a(b)(1). 7. Option 1b: Elect NSPS subpart Ja, PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.120a(b)(1). 8. Option 1c: Elect NSPS subpart Ja, PM concentration limit not subject to the NSPS for PM in 40 CFR 60.102 or 60.120a(b)(1). 9. Option 2: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.120a(b)(1). 10. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). Any ................................................. Any ................................................. The applicable continuous monitoring systems in item 2 of this table. Any ................................................. See item 3 of this table. Any ................................................. See item 1 of this table. Any ................................................. The applicable continuous monitoring systems in item 2 of this table. Any ................................................. See item 3 of this table. Any ................................................. The applicable continuous monitoring systems in item 2 of this table. a. Cyclone ...................................... Continuous opacity monitoring system to measure and record the opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the gas flow rate entering or exiting the control device.1 Continuous opacity monitoring system to measure and record the opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the gas flow rate entering or exiting the control device 1; or continuous parameter monitoring systems to measure and record the coke burn-off rate or the gas flow rate entering or exiting the control device 1 and the voltage and current (to measure the total power to the system) and secondary current to the control device. Continuous parameter monitoring system to measure and record the pressure drop across the scrubber,2 gas flow rate entering or exiting the control device,1 and total liquid (or scrubbing liquor) flow rate to the control device. Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent or the monitoring systems specified in item 10.a of this table. Continuous opacity monitoring system to measure and record the opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the coke burn-off rate and the gas flow rate entering or exiting the control device.1 b. Electrostatic precipitator ............ c. Wet scrubber ............................. tkelley on DSK3SPTVN1PROD with RULES2 d. Fabric Filter ............................... 11. Option 4: Ni per coke burn-off limit not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). VerDate Sep<11>2014 23:11 Nov 30, 2015 a. Cyclone ...................................... Jkt 238001 PO 00000 Frm 00108 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75285 TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . If you use this type of control device for your vent . . . You shall install, operate, and maintain a . . . b. Electrostatic precipitator ............ Continuous opacity monitoring system to measure and record the opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the coke burn-off rate and the gas flow rate entering or exiting the control device 1; or continuous parameter monitoring systems to measure and record the coke burn-off rate or the gas flow rate entering or exiting the control device 1 and voltage and current (to measure the total power to the system) and secondary current to the control device. Continuous parameter monitoring system to measure and record the pressure drop across the scrubber,2 gas flow rate entering or exiting the control device,1 and total liquid (or scrubbing liquor) flow rate to the control device. Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent or the monitoring systems specified in item 11.a of this table. Continuous parameter monitoring system to measure and record the gas flow rate exiting the catalyst regenerator.1 c. Wet scrubber ............................. d. Fabric Filter ............................... 12. Electing to comply with the operating limits in § 63.1566(a)(5)(iii) during periods of startup, shutdown, or hot standby. Any ................................................. 1 If applicable, you can use the alternative in § 63.1573(a)(1) instead of a continuous parameter monitoring system for gas flow rate. you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, you can use the alternative in § 63.1573(b) instead of a continuous parameter monitoring system for pressure drop across the scrubber. 2 If 55. Table 4 to subpart UUU of part 63 is revised to read as follows: ■ As stated in §§ 63.1564(b)(2) and 63.1571(a)(5), you shall meet each requirement in the following table that applies to you. TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS For each new or existing catalytic cracking unit catalyst regenerator vent . . . Using . . . According to these requirements . . . a. Select sampling port’s location and the number of traverse ports. Method 1 or 1A in appendix A–1 to part 60 of this chapter. Sampling sites must be located at the outlet of the control device or the outlet of the regenerator, as applicable, and prior to any releases to the atmosphere. b. Determine velocity and volumetric flow rate. 1. Any ............................................. You must . . . Method 2, 2A, 2C, 2D, or 2F in appendix A–1 to part 60 of this chapter, or Method 2G in appendix A–2 to part 60 of this chapter, as applicable. Method 3, 3A, or 3B in appendix A–2 to part 60 of this chapter, as applicable. Method 4 in appendix A–3 to part 60 of this chapter. tkelley on DSK3SPTVN1PROD with RULES2 c. Conduct gas molecular weight analysis. d. Measure moisture content of the stack gas. e. If you use an electrostatic precipitator, record the total number of fields in the control system and how many operated during the applicable performance test. f. If you use a wet scrubber, record the total amount (rate) of water (or scrubbing liquid) and the amount (rate) of make-up liquid to the scrubber during each test run. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00109 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75286 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit catalyst regenerator vent . . . 2. Subject to the NSPS for PM in 40 CFR 60.102 and not elect § 60.100(e). You must . . . Using . . . According to these requirements . . . a. Measure PM emissions ............ Method 5, 5B, or 5F (40 CFR part 60, appendix A–3) to determine PM emissions and associated moisture content for units without wet scrubbers. Method 5 or 5B (40 CFR part 60, appendix A–3) to determine PM emissions and associated moisture content for unit with wet scrubber. Equations 1, 2, and 3 of § 63.1564 (if applicable). You must maintain a sampling rate of at least 0.15 dry standard cubic meters per minute (dscm/min) (0.53 dry standard cubic feet per minute (dscf/ min)). Continuous system. You must collect opacity monitoring data every 10 seconds during the entire period of the Method 5, 5B, or 5F performance test and reduce the data to 6-minute averages. You must maintain a sampling rate of at least 0.15 dscm/min (0.53 dscf/min). b. Compute coke burn-off rate and PM emission rate (lb/1,000 lb of coke burn-off). c. Measure opacity of emissions .. 3. Subject to the NSPS for PM in 40 CFR 60.102a(b)(1) or elect § 60.100(e), electing the PM for coke burn-off limit. a. Measure PM emissions ............ b. Compute coke burn-off rate and PM emission rate (lb/1,000 lb of coke burn-off). c. Establish site-specific limit if you use a COMS. tkelley on DSK3SPTVN1PROD with RULES2 4. Subject to the NSPS for PM in 40 CFR 60.102a(b)(1) or elect § 60.100(e). a. Measure PM emissions ............ 5. Option 1a: Elect NSPS subpart J requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 6. Option 1b: Elect NSPS subpart Ja requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). See item 2 of this table. VerDate Sep<11>2014 23:11 Nov 30, 2015 opacity monitoring Method 5, 5B, or 5F (40 CFR part 60, appendix A–3) to determine PM emissions and associated moisture content for units without wet scrubbers. Method 5 or 5B (40 CFR part 60, appendix A–3) to determine PM emissions and associated moisture content for unit with wet scrubber. Equations 1, 2, and 3 of § 63.1564 (if applicable). Continuous system. opacity monitoring Method 5, 5B, or 5F (40 CFR part 60, appendix A–3) to determine PM emissions and associated moisture content for units without wet scrubbers. Method 5 or 5B (40 CFR part 60, appendix A–3) to determine PM emissions and associated moisture content for unit with wet scrubber. ....................................................... If you elect to comply with the site-specific opacity limit in § 63.1564(b)(4)(i), you must collect opacity monitoring data every 10 seconds during the entire period of the Method 5, 5B, or 5F performance test. For site specific opacity monitoring, reduce the data to 6-minute averages; determine and record the average opacity for each test run; and compute the sitespecific opacity limit using Equation 4 of § 63.1564. You must maintain a sampling rate of at least 0.15 dscm/min (0.53 dscf/min). See item 3 of this table. Jkt 238001 PO 00000 Frm 00110 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75287 TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit catalyst regenerator vent . . . 7. Option 1c: Elect NSPS requirements for PM concentration, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 8. Option 2: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 9. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). You must . . . According to these requirements . . . Using . . . See item 4 of this table. See item 3 of this table. a. Measure concentration of Ni .... b. Compute Ni emission rate (lb/ hr). c. Determine the equilibrium catalyst Ni concentration. Method 29 (40 CFR part 60, appendix A–8). Equation 5 of § 63.1564. XRF procedure in appendix A to this subpart1; or EPA Method 6010B or 6020 or EPA Method 7520 or 7521 in SW–8462; or an alternative to the SW–846 method satisfactory to the Administrator. d. If you use a continuous opacity monitoring system, establish your site-specific Ni operating limit. 10. Option 4: Ni per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). i. Equations 6 and 7 of § 63.1564 using data from continuous opacity monitoring system, gas flow rate, results of equilibrium catalyst Ni concentration analysis, and Ni emission rate from Method 29 test. a. Measure concentration of Ni. Method 29 (40 CFR part 60, appendix A–8). Equations 1 and 8 of § 63.1564. b. Compute Ni emission rate (lb/ 1,000 lb of coke burn-off). c. Determine the equilibrium catalyst Ni concentration. tkelley on DSK3SPTVN1PROD with RULES2 d. If you use a continuous opacity monitoring system, establish your site-specific Ni operating limit. VerDate Sep<11>2014 23:11 Nov 30, 2015 You must obtain 1 sample for each of the 3 test runs; determine and record the equilibrium catalyst Ni concentration for each of the 3 samples; and you may adjust the laboratory results to the maximum value using Equation 2 of § 63.1571. (1) You must collect opacity monitoring data every 10 seconds during the entire period of the initial Ni performance test; reduce the data to 6-minute averages; and determine and record the average opacity from all the 6-minute averages for each test run. (2) You must collect gas flow rate monitoring data every 15 minutes during the entire period of the initial Ni performance test; measure the gas flow as near as practical to the continuous opacity monitoring system; and determine and record the hourly average actual gas flow rate for each test run. Jkt 238001 PO 00000 Frm 00111 Fmt 4701 See item 6.c. of this table ............ i. Equations 9 and 10 of § 63.1564 with data from continuous opacity monitoring system, coke burn-off rate, results of equilibrium catalyst Ni concentration analysis, and Ni emission rate from Method 29 test. Sfmt 4700 E:\FR\FM\01DER2.SGM You must obtain 1 sample for each of the 3 test runs; determine and record the equilibrium catalyst Ni concentration for each of the 3 samples; and you may adjust the laboratory results to the maximum value using Equation 2 of § 63.1571. (1) You must collect opacity monitoring data every 10 seconds during the entire period of the initial Ni performance test; reduce the data to 6-minute averages; and determine and record the average opacity from all the 6-minute averages for each test run. 01DER2 75288 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit catalyst regenerator vent . . . You must . . . According to these requirements . . . Using . . . (2) You must collect gas flow rate monitoring data every 15 minutes during the entire period of the initial Ni performance test; measure the gas flow rate as near as practical to the continuous opacity monitoring system; and determine and record the hourly average actual gas flow rate for each test run. 11. If you elect item 5 Option 1b in Table 1, item 7 Option 2 in Table 1, item 8 Option 3 in Table 1, or item 9 Option 4 in Table 1 of this subpart and you use continuous parameter monitoring systems. e. Record the catalyst addition rate for each test and schedule for the 10-day period prior to the test. a. Establish each operating limit in Table 2 of this subpart that applies to you. Data from the continuous parameter monitoring systems and applicable performance test methods. VerDate Sep<11>2014 23:11 Nov 30, 2015 i. Data from the continuous parameter monitoring systems and applicable performance test methods. c. Electrostatic precipitator: Total power (voltage and current) and secondary current. tkelley on DSK3SPTVN1PROD with RULES2 b. Electrostatic precipitator or wet scrubber: Gas flow rate. i. Data from the continuous parameter monitoring systems and applicable performance test methods. Jkt 238001 PO 00000 Frm 00112 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM (1) You must collect gas flow rate monitoring data every 15 minutes during the entire period of the initial performance test; determine and record the average gas flow rate for each test run. (2) You must determine and record the 3-hr average gas flow rate from the test runs. Alternatively, before August 1, 2017, you may determine and record the maximum hourly average gas flow rate from all the readings. (1) You must collect voltage, current, and secondary current monitoring data every 15 minutes during the entire period of the performance test; and determine and record the average voltage, current, and secondary current for each test run. Alternatively, before August 1, 2017, you may collect voltage and secondary current (or total power input) monitoring data every 15 minutes during the entire period of the initial performance test. (2) You must determine and record the 3-hr average total power to the system for the test runs and the 3-hr average secondary current from the test runs. Alternatively, before August 1, 2017, you may determine and record the minimum hourly average voltage and secondary current (or total power input) from all the readings. 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75289 TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit catalyst regenerator vent . . . Results of analysis for equilibrium catalyst Ni concentration. i. Data from the continuous parameter monitoring systems and applicable performance test methods. f. Liquid-to-gas i. Data from the continuous parameter monitoring systems and applicable performance test methods. g. Alternative procedure for gas flow rate. tkelley on DSK3SPTVN1PROD with RULES2 According to these requirements . . . e. Wet scrubber: Pressure drop (not applicable to non-venturi scrubber of jet ejector design). VerDate Sep<11>2014 Using . . . d. Electrostatic precipitator or wet scrubber: Equilibrium catalyst Ni concentration. 1 Determination You must . . . i. Data from the continuous parameter monitoring systems and applicable performance test methods. You must determine and record the average equilibrium catalyst Ni concentration for the 3 runs based on the laboratory results. You may adjust the value using Equation 1 or 2 of § 63.1571 as applicable. (1) You must collect pressure drop monitoring data every 15 minutes during the entire period of the initial performance test; and determine and record the average pressure drop for each test run. (2) You must determine and record the 3-hr average pressure drop from the test runs. Alternatively, before August 1, 2017, you may determine and record the minimum hourly average pressure drop from all the readings. (1) You must collect gas flow rate and total water (or scrubbing liquid) flow rate monitoring data every 15 minutes during the entire period of the initial performance test; determine and record the average gas flow rate for each test run; and determine the average total water (or scrubbing liquid) flow for each test run. (2) You must determine and record the hourly average liquid-to-gas ratio from the test runs. Alternatively, before August 1, 2017, you may determine and record the hourly average gas flow rate and total water (or scrubbing liquid) flow rate from all the readings. (3) You must determine and record the 3-hr average liquidto-gas ratio. Alternatively, before August 1, 2017, you may determine and record the minimum liquid-to-gas ratio. (1) You must collect air flow rate monitoring data or determine the air flow rate using control room instrumentation every 15 minutes during the entire period of the initial performance test. (2) You must determine and record the 3-hr average rate of all the readings from the test runs. Alternatively, before August 1, 2017, you may determine and record the hourly average rate of all the readings. (3) You must determine and record the maximum gas flow rate using Equation 1 of § 63.1573. Wet ratio. scrubber: of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure). 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00113 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75290 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 2 EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, and EPA Method 7521, Nickel Atomic Absorption, Direct Aspiration are included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW– 846 and Updates (document number 955–001–00000–1) are available for purchase from the Superintendent of Documents, U.S. Government Publishing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building, (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington, DC. 56. Table 5 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1564(b)(5), you shall meet each requirement in the following table that applies to you. TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS For each new and existing catalytic cracking unit catalyst regenerator vent . . . For the following emission limit . . . You have demonstrated initial compliance if . . . 1. Subject to the NSPS for PM in 40 CFR 60.102 and not electing § 60.100(e). PM emissions must not exceed 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off, and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in any 1-hour period. Before August 1, 2017, if the discharged gases pass through an incinerator or waste heat boiler in which you burn auxiliary or supplemental liquid or solid fossil fuel, the incremental rate of PM must not exceed 43.0 g/GJ or 0.10 lb/million Btu of heat input attributable to the liquid or solid fossil fuel; and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in any 1-hour period. PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1,000 lb) of coke burn-off. You have already conducted a performance test to demonstrate initial compliance with the NSPS and the measured PM emission rate is less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in the catalyst regenerator. As part of the Notification of Compliance Status, you must certify that your vent meets the PM limit. You are not required to do another performance test to demonstrate initial compliance. You have already conducted a performance test to demonstrate initial compliance with the NSPS and the average hourly opacity is no more than 30 percent, except that one 6minute average in any 1-hour period can exceed 30 percent. As part of the Notification of Compliance Status, you must certify that your vent meets the 30 percent opacity limit. As part of your Notification of Compliance Status, you certify that your continuous opacity monitoring system meets the requirements in § 63.1572. 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i); or in § 60.102 and electing § 60.100(e); electing to meet the PM per coke burn-off limit. PM emissions must not exceed 0.5 g/kg (0.5 lb PM/1,000 lb) of coke burn-off). 4. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i), electing to meet the PM concentration limit. tkelley on DSK3SPTVN1PROD with RULES2 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i), electing to meet the PM per coke burn-off limit. If a PM CEMS is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00114 Fmt 4701 You have already conducted a performance test to demonstrate initial compliance with the NSPS and the measured PM emission rate is less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in the catalyst regenerator. As part of the Notification of Compliance Status, you must certify that your vent meets the PM limit. You are not required to do another performance test to demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that your BLD; CO2, O2, or CO monitor; or continuous opacity monitoring system meets the requirements in § 63.1572. You have already conducted a performance test to demonstrate initial compliance with the NSPS and the measured PM emission rate is less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in the catalyst regenerator. As part of the Notification of Compliance Status, you must certify that your vent meets the PM limit. You are not required to do another performance test to demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that your BLD; CO2, O2, or CO monitor; or continuous opacity monitoring system meets the requirements in § 63.1572. You have already conducted a performance test to demonstrate initial compliance with the NSPS and the measured PM concentration is less than or equal to 0.040 grain per dry standard cubic feet (gr/ dscf) corrected to 0 percent excess air. As part of the Notification of Compliance Status, you must certify that your vent meets the PM limit. You are not required to do another performance test to demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that your PM CEMS meets the requirements in § 63.1572. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75291 TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS—Continued For each new and existing catalytic cracking unit catalyst regenerator vent . . . For the following emission limit . . . You have demonstrated initial compliance if . . . 5. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii), electing to meet the PM concentration limit. If a PM CEMS is used, 0.020 gr/ dscf corrected to 0 percent excess air. 6. Option 1a: Elect NSPS subpart J requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). PM emissions must not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/1,000 lb) of coke burnoff, and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in any 1-hour period. Before August 1, 2017, PM emission must not exceed 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in the catalyst regenerator; if the discharged gases pass through an incinerator or waste heat boiler in which you burn auxiliary or supplemental liquid or solid fossil fuel, the incremental rate of PM must not exceed 43.0 g/GJ (0.10 lb/million Btu) of heat input attributable to the liquid or solid fossil fuel; and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in any 1-hour period. PM emissions must not exceed 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off. You have already conducted a performance test to demonstrate initial compliance with the NSPS and the measured PM concentration is less than or equal to 0.020 gr/dscf corrected to 0 percent excess air. As part of the Notification of Compliance Status, you must certify that your vent meets the PM limit. You are not required to do another performance test to demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that your PM CEMS meets the requirements in § 63.1572. The average PM emission rate, measured using EPA Method 5, 5B, or 5F (for a unit without a wet scrubber) or 5 or 5B (for a unit with a wet scrubber) (40 CFR part 60, appendix A–3), over the period of the initial performance test, is no higher than 1.0 g/kg coke burnoff (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission rate is calculated using Equations 1, 2, and 3 of § 63.1564. As part of the Notification of Compliance Status, you must certify that your vent meets the PM limit. The average hourly opacity is no more than 30 percent, except that one 6-minute average in any 1-hour period can exceed 30 percent. As part of the Notification of Compliance Status, you must certify that your vent meets the 30 percent opacity limit. If you use a continuous opacity monitoring system, your performance evaluation shows the system meets the applicable requirements in § 63.1572. 7. Option 1b: Elect NSPS subpart Ja requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent excess air. 9. Option 2: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). tkelley on DSK3SPTVN1PROD with RULES2 8. Option 1c: Elect NSPS subpart Ja requirements for PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). PM emissions must not exceed 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off. 10. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). Nickel (Ni) emissions from your catalyst regenerator vent must not exceed 13,000 mg/hr (0.029 lb/hr). VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00115 Fmt 4701 The average PM emission rate, measured using EPA Method 5, 5B, or 5F (for a unit without a wet scrubber) or 5 or 5B (for a unit with a wet scrubber) (40 CFR part 60, appendix A–3), over the period of the initial performance test, is no higher than 1.0 g/kg coke burnoff (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission rate is calculated using Equations 1, 2, and 3 of § 63.1564. If you use a BLD; CO2, O2, CO monitor; or continuous opacity monitoring system, your performance evaluation shows the system meets the applicable requirements in § 63.1572. The average PM concentration, measured using EPA Method 5, 5B, or 5F (for a unit without a wet scrubber) or Method 5 or 5B (for a unit with a wet scrubber) (40 CFR part 60, appendix A–3), over the period of the initial performance test, is less than or equal to 0.040 gr/dscf corrected to 0 percent excess air. Your performance evaluation shows your PM CEMS meets the applicable requirements in § 63.1572. The average PM emission rate, measured using EPA Method 5, 5B, or 5F (for a unit without a wet scrubber) or 5 or 5B (for a unit with a wet scrubber) (40 CFR part 60, appendix A–3), over the period of the initial performance test, is no higher than 1.0 g/kg coke burnoff (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission rate is calculated using Equations 1, 2, and 3 of § 63.1564. If you use a BLD; CO2, O2, CO monitor; or continuous opacity monitoring system, your performance evaluation shows the system meets the applicable requirements in § 63.1572. The average Ni emission rate, measured using Method 29 (40 CFR part 60, appendix A–8) over the period of the initial performance test, is not more than 13,000 mg/hr (0.029 lb/hr). The Ni emission rate is calculated using Equation 5 of § 63.1564; and if you use a BLD; CO2, O2, or CO monitor; or continuous opacity monitoring system, your performance evaluation shows the system meets the applicable requirements in § 63.1572. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75292 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS—Continued For each new and existing catalytic cracking unit catalyst regenerator vent . . . For the following emission limit . . . You have demonstrated initial compliance if . . . 11. Option 4: Ni per coke burn-off limit not subject to the NSPS for PM. Ni emissions from your catalyst regenerator vent must not exceed 1.0 mg/kg (0.001 lb/1,000 lb) of coke burn-off in the catalyst regenerator. The average Ni emission rate, measured using Method 29 (40 CFR part 60, appendix A–8) over the period of the initial performance test, is not more than 1.0 mg/kg (0.001 lb/1,000 lb) of coke burn-off in the catalyst regenerator. The Ni emission rate is calculated using Equation 8 of § 63.1564; and if you use a BLD; CO2, O2, or CO monitor; or continuous opacity monitoring system, your performance evaluation shows the system meets the applicable requirements in § 63.1572. 57. Table 6 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1564(c)(1), you shall meet each requirement in the following table that applies to you. TABLE 6 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS For each new and existing catalytic cracking unit . . . Subject to this emission limit for your catalyst regenerator vent . . . You shall demonstrate continuous compliance by . . . 1. Subject to the NSPS for PM in 40 CFR 60.102 and not electing § 60.100(e). a. PM emissions must not exceed 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off, and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in any 1-hour period. Before August 1, 2017, if the discharged gases pass through an incinerator or waste heat boiler in which you burn auxiliary or supplemental liquid or solid fossil fuel, the incremental rate of PM must not exceed 43.0 g/GJ (0.10 lb/million Btu) of heat input attributable to the liquid or solid fossil fuel; and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in any 1-hour period. i. Determining and recording each day the average coke burn-off rate (thousands of kilograms per hour) using Equation 1 in § 63.1564 and the hours of operation for each catalyst regenerator. tkelley on DSK3SPTVN1PROD with RULES2 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i), electing to meet the PM per coke burn-off limit. PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1,000 lb) of coke burn-off. 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii), electing to meet the PM per coke burn-off limit. PM emissions must not exceed 0.5 g/kg coke burn-off (0.5 lb/ 1000 lb coke burn-off). VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00116 Fmt 4701 ii. Conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit. iii. Collecting the continuous opacity monitoring data for each catalyst regenerator vent according to § 63.1572 and maintaining each 6minute average at or below 30 percent, except that one 6-minute average during a 1-hour period can exceed 30 percent. iv. Before August 1, 2017, if applicable, determining and recording each day the rate of combustion of liquid or solid fossil fuels (liters/ hour or kilograms/hour) and the hours of operation during which liquid or solid fossil-fuels are combusted in the incinerator-waste heat boiler; if applicable, maintaining the incremental rate of PM at or below 43 g/GJ (0.10 lb/million Btu) of heat input attributable to the solid or liquid fossil fuel. Determining and recording each day the average coke burn-off rate (thousands of kilograms per hour) using Equation 1 in § 63.1564 and the hours of operation for each catalyst regenerator; maintaining PM emission rate below 1.0 g/kg (1.0 lb PM/1,000 lb) of coke burn-off; and conducting a performance test once every year. Determining and recording each day the average coke burn-off rate (thousands of kilograms per hour) using Equation 1 in § 63.1564 and the hours of operation for each catalyst regenerator; maintaining PM emission rate below 0.5 g/kg (0.5 lb/1,000 lb) of coke burnoff; and conducting a performance test once every year. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75293 TABLE 6 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS—Continued For each new and existing catalytic cracking unit . . . Subject to this emission limit for your catalyst regenerator vent . . . You shall demonstrate continuous compliance by . . . 4. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i), electing to meet the PM concentration limit. If a PM CEMS is used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air. If a PM CEMS is used, 0.020 gr/ dscf corrected to 0 percent excess air. See item 1 of this table ................. Maintaining PM concentration below 0.040 gr/dscf corrected to 0 percent excess air. 5. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii), electing to meet the PM concentration limit. 6. Option 1a: Elect NSPS subpart J requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 7. Option 1b: Elect NSPS subpart Ja requirements for PM per coke burn-off limit and 30% opacity, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 8. Option 1c: Elect NSPS subpart Ja requirements for PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 9. Option 2: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). Maintaining PM concentration below 0.020 gr/dscf corrected to 0 percent excess air. See item 1 of this table. PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1,000 lb) of coke burn-off. See item 2 of this table. PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent excess air. See item 4 of this table. PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1,000 lb) of coke burn-off. Determining and recording each day the average coke burn-off rate and the hours of operation and the hours of operation for each catalyst regenerator by Equation 1 of § 63.1564 (you can use process data to determine the volumetric flow rate); maintaining PM emission rate below 1.0 g/kg (1.0 lb PM/1,000 lb) of coke burn-off; and conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit. Maintaining Ni emission rate below 13,000 mg/hr (0.029 lb/hr); and conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit. Determining and recording each day the average coke burn-off rate (thousands of kilograms per hour) and the hours of operation for each catalyst regenerator by Equation 1 of § 63.1564 (you can use process data to determine the volumetric flow rate); and maintaining Ni emission rate below 1.0 mg/kg (0.001 lb/1,000 lb) of coke burn-off in the catalyst regenerator; and conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit. 10. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). Ni emissions must not exceed 13,000 mg/hr (0.029 lb/hr). 11. Option 4: Ni per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). Ni emissions must not exceed 1.0 mg/kg (0.001 lb/1,000 lb) of coke burn-off in the catalyst regenerator. 58. Table 7 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1564(c)(1), you shall meet each requirement in the following table that applies to you. TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS If you use . . . 1. Subject to NSPS for PM in 40 CFR 60.102 and not electing § 60.100(e). tkelley on DSK3SPTVN1PROD with RULES2 For each new or existing catalytic cracking unit . . . Continuous system. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 For this operating limit . . . opacity PO 00000 monitoring Frm 00117 Fmt 4701 You shall demonstrate continuous compliance by . . . The 3-hour average opacity of emissions from your catalyst regenerator vent must not exceed 20 percent. Collecting the continuous opacity monitoring data for each regenerator vent according to § 63.1572 and maintain each 3hour rolling average opacity of emissions no higher than 20 percent. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75294 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1); or 40 CFR 60.102 and elect § 60.100(e), electing to meet the PM per coke burn-off limit. a. Continuous opacity monitoring system, used for site-specific opacity limit—Cyclone or electrostatic precipitator. The average opacity must not exceed the opacity established during the performance test. b. Continuous parametric monitoring systems—electrostatic precipitator. i. The average gas flow rate entering or exiting the control device must not exceed the operating limit established during the performance test. Collecting the hourly and 3-hr rolling average opacity monitoring data according to § 63.1572; maintaining the 3-hr rolling average opacity at or above the site-specific limit established during the performance test. Collecting the hourly and daily average coke burn-off rate or average gas flow rate monitoring data according to § 63.1572; and maintaining the daily average coke burn-off rate or average gas flow rate at or below the limit established during the performance test. Collecting the hourly and 3-hr rolling average total power and secondary current monitoring data according to § 63.1572; and maintaining the 3-hr rolling average total power and secondary current at or above the limit established during the performance test. Collecting the hourly and 3-hr rolling average gas flow rate and scrubber liquid flow rate monitoring data according to § 63.1572; determining and recording the 3-hr liquid-to-gas ratio; and maintaining the 3-hr rolling average liquid-to-gas ratio at or above the limit established during the performance test. ii. The average total power and secondary current to the control device must not fall below the operating limit established during the performance test. c. Continuous parametric monitoring systems—wet scrubber. i. The average liquid-to-gas ratio must not fall below the operating limit established during the performance test. ii. Except for periods of startup, shutdown and hot standby, the average pressure drop across the scrubber must not fall below the operating limit established during the performance test. Increases in relative particulate .... 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1), electing to meet the PM concentration limit. 4. Option 1a: Elect NSPS subpart J requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). tkelley on DSK3SPTVN1PROD with RULES2 d. BLD—fabric filter ...................... PM CEMS ..................................... Not applicable ............................... Continuous system. monitoring The 3-hour average opacity of emissions from your catalyst regenerator vent must not exceed 20 percent. 5. Option 1b: Elect NSPS subpart Ja requirements for PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). a. Continuous opacity monitoring system. The opacity of emissions from your catalyst regenerator vent must not exceed the site-specific opacity operating limit established during the performance test. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 opacity PO 00000 Frm 00118 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM Collecting the hourly and 3-hr rolling average pressure drop monitoring data according to § 63.1572; and except for periods of startup, shutdown and hot standby, maintaining the 3hr rolling average pressure drop at or above the limit established during the performance test. Collecting and maintaining records of BLD system output; determining the cause of the alarm within 1 hour of the alarm; and alleviating the cause of the alarm within 3 hours by corrective action. Complying with Table 6 of this subpart, item 4 or 5. Collecting the 3-hr rolling average continuous opacity monitoring system data according to § 63.1572; and maintaining the 3-hr rolling average opacity no higher than 20 percent. Collecting the 3-hr rolling average continuous opacity monitoring system data according to § 63.1572; maintaining the 3-hr rolling average opacity at or below the site-specific limit. 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75295 TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . b. Continuous parametric monitoring systems—electrostatic precipitator. c. Continuous parametric monitoring systems—wet scrubber. d. BLD—fabric filter ...................... PM CEMS ..................................... See item 2.b of this table ............. See item 2.b of this table. See item 2.c of this table ............. See item 2.c of this table. See item 2.d of this table ............. Not applicable ............................... See item 2.d of this table. Complying with Table 6 of this subpart, item 4. a. Continuous opacity monitoring system. The opacity of emissions from your catalyst regenerator vent must not exceed the site-specific opacity operating limit established during the performance test. b. Continuous parameter monitoring systems—electrostatic precipitator. 6. Option 1c: Elect NSPS subpart Ja requirements for PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). 7. Option 2: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or 60.102a(b)(1). If you use . . . i. The average coke burn-off rate or average gas flow rate entering or exiting the control device must not exceed the operating limit established during the performance test. Collecting the hourly and 3-hr rolling average continuous opacity monitoring system data according to § 63.1572; and maintaining the 3-hr rolling average opacity at or below the site-specific limit established during the performance test. Alternatively, before August 1, 2017, collecting the hourly average continuous opacity monitoring system data according to § 63.1572; and maintaining the hourly average opacity at or below the site-specific limit. Collecting the hourly and daily average coke burn-off rate or gas flow rate monitoring data according to § 63.1572; and maintaining the daily coke burn-off rate or average gas flow rate at or below the limit established during the performance test. Collecting the hourly and 3-hr rolling average total power and secondary current monitoring data according to § 63.1572; and maintaining the 3-hr rolling average total power and secondary current at or above the limit established during the performance test. Alternatively, before August 1, 2017, collecting the hourly and daily average voltage and secondary current (or total power input) monitoring data according to § 63.1572; and maintaining the daily average voltage and secondary current (or total power input) at or above the limit established during the performance test. tkelley on DSK3SPTVN1PROD with RULES2 ii. The average total power (voltage and current) and secondary current to the control device must not fall below the operating limit established during the performance test. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00119 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75296 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . c. Continuous parameter monitoring systems—wet scrubber. i. The average liquid-to-gas ratio must not fall below the operating limit established during the performance test. Collecting the hourly and 3-hr rolling average gas flow rate and scrubber liquid flow rate monitoring data according to § 63.1572; determining and recording the 3-hr liquid-to-gas ratio; and maintaining the 3-hr rolling average liquid-to-gas ratio at or above the limit established during the performance test. Alternatively, before August 1, 2017, collecting the hourly average gas flow rate and water (or scrubbing liquid) flow rate monitoring data according to § 63.1572 1; determining and recording the hourly average liquid-to-gas ratio; determining and recording the daily average liquid-to-gas ratio; and maintaining the daily average liquid-to-gas ratio above the limit established during the performance test. Collecting the hourly and 3-hr rolling average pressure drop monitoring data according to § 63.1572; and except for periods of startup, shutdown and hot standby, maintaining the 3hr rolling average pressure drop at or above the limit established during the performance test. Alternatively, before August 1, 2017, collecting the hourly and daily average pressure drop monitoring data according to § 63.1572; and maintaining the daily average pressure drop above the limit established during the performance test. See item 2.d of this table. (1) Collecting the hourly average continuous opacity monitoring system data according to § 63.1572; determining and recording equilibrium catalyst Ni concentration at least once a week 2; collecting the hourly average gas flow rate monitoring data according to § 63.1572 1; and determining and recording the hourly average Ni operating value using Equation 11 of § 63.1564. ii. Except for periods of startup, shutdown and hot standby, the average pressure drop across the scrubber must not fall below the operating limit established during the performance test. tkelley on DSK3SPTVN1PROD with RULES2 8. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 CFR 60.102. VerDate Sep<11>2014 23:11 Nov 30, 2015 d. BLD—fabric filter ...................... a. Continuous opacity monitoring system. Jkt 238001 PO 00000 Frm 00120 Fmt 4701 See item 2.d of this table ............. i. The daily average Ni operating value must not exceed the sitespecific Ni operating limit established during the performance test. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75297 TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . If you use . . . b. Continuous parameter monitoring systems—electrostatic precipitator. c. Continuous parameter monitoring systems—wet scrubber. tkelley on DSK3SPTVN1PROD with RULES2 d. BLD—fabric filter ...................... VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 You shall demonstrate continuous compliance by . . . For this operating limit . . . Frm 00121 Fmt 4701 i. The average gas flow rate entering or exiting the control device must not exceed the operating limit established during the performance test. ii. The average total power (voltage and current) and secondary current must not fall below the level established in the performance test. iii. The monthly rolling average of the equilibrium catalyst Ni concentration must not exceed the level established during the performance test. i. The average liquid-to-gas ratio must not fall below the operating limit established during the performance test.. ii. Except for periods of startup, shutdown and hot standby, the average pressure drop must not fall below the operating limit established in the performance test. iii. The monthly rolling average equilibrium catalyst Ni concentration must not exceed the level established during the performance test. i. Increases in relative particulate Sfmt 4700 E:\FR\FM\01DER2.SGM (2) Determining and recording the 3-hour rolling average Ni operating value and maintaining the 3-hour rolling average Ni operating value below the site-specific Ni operating limit established during the performance test. Alternatively, before August 1, 2017, determining and recording the daily average Ni operating value and maintaining the daily average Ni operating value below the site-specific Ni operating limit established during the performance test. See item 7.b.i of this table. See item 7.b.ii of this table. Determining and recording the equilibrium catalyst Ni concentration at least once a week 2; determining and recording the monthly rolling average of the equilibrium catalyst Ni concentration once each week using the weekly or most recent value; and maintaining the monthly rolling average below the limit established in the performance test. See item 7.c.i of this table. See item 7.c.ii of this table. Determining and recording the equilibrium catalyst Ni concentration at least once a week 2; determining and recording the monthly rolling average of equilibrium catalyst Ni concentration once each week using the weekly or most recent value; and maintaining the monthly rolling average below the limit established in the performance test. See item 7.d of this table. 01DER2 75298 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . You shall demonstrate continuous compliance by . . . ii. The monthly rolling average of the equilibrium catalyst Ni concentration must not exceed the level established during the performance test. 9. Option 4: Ni per coke burn-off limit not subject to the NSPS for PM in 40 CFR 60.102. For this operating limit . . . If you use . . . Determining and recording the equilibrium catalyst Ni concentration at least once a week 2; determining and recording the monthly rolling average of the equilibrium catalyst Ni concentration once each week using the weekly or most recent value; and maintaining the monthly rolling average below the limit established in the performance test. (1) Collecting the hourly average continuous opacity monitoring system data according to § 63.1572; collecting the hourly average coke burn rate and hourly average gas flow rate monitoring data according to § 63.15721; determining and recording equilibrium catalyst Ni concentration at least once a week 2; and determining and recording the hourly average Ni operating value using Equation 12 of § 63.1564. (2) Determining and recording the 3-hour rolling average Ni operating value and maintaining the 3-hour rolling average Ni operating value below the site-specific Ni operating limit established during the performance test Alternatively, before August 1, 2017, determining and recording the daily average Ni operating value and maintaining the daily average Ni operating value below the site-specific Ni operating limit established during the performance test. See item 7.b.i of this table. a. Continuous opacity monitoring system. i. The daily average Ni operating value must not exceed the sitespecific Ni operating limit established during the performance test. b. Continuous parameter monitoring systems—electrostatic precipitator. i. The average gas flow rate to the control device must not exceed the level established in the performance test. ii. The average voltage and secondary current (or total power input) must not fall below the level established in the performance test. iii. The monthly rolling average equilibrium catalyst Ni concentration must not exceed the level established during the performance test. i. The average liquid-to-gas ratio must not fall below the operating limit established during the performance test. ii. Except for periods of startup, shutdown and hot standby, the daily average pressure drop must not fall below the operating limit established in the performance test. tkelley on DSK3SPTVN1PROD with RULES2 c. Continuous parameter monitoring systems—wet scrubber. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00122 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM See item 7.b.ii of this table. See item 8.b.iii of this table. See item 7.c.i of this table. See item 7.c.ii of this table. 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75299 TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . iii. The monthly rolling average equilibrium catalyst Ni concentration must not exceed the level established during the performance test. i. See item 2.d of this table .......... ii. The monthly rolling average of the equilibrium catalyst Ni concentration must not exceed the level established during the performance test. See item 8.c.iii of this table. d. BLD—fabric filter ...................... 10. During periods of startup, shutdown, or hot standby. If you use . . . Any control device, if elected ....... The inlet velocity limit to the primary internal cyclones of the catalytic cracking unit catalyst regenerator in § 63.1564(a)(5)(ii). See item 2.d of this table. Determining and recording the equilibrium catalyst Ni concentration at least once a week 2; determining and recording the monthly rolling average of the equilibrium catalyst Ni concentration once each week using the weekly or most recent value; and maintaining the monthly rolling average below the limit established in the performance test. Meeting the requirements in § 63.1564(c)(5). 1 If applicable, you can use the alternative in § 63.1573(a)(1) for gas flow rate instead of a continuous parameter monitoring system if you used the alternative method in the initial performance test. 2 The equilibrium catalyst Ni concentration must be measured by the procedure, Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure) in appendix A to this subpart; or by EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, or EPA Method 7521, Nickel Atomic Absorption, Direct Aspiration; or by an alternative to EPA Method 6010B, 6020, 7520, or 7521 satisfactory to the Administrator. The EPA Methods 6010B, 6020, 7520, and 7521 are included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW–846 and Updates (document number 955–001–00000–1) are available for purchase from the Superintendent of Documents, U.S. Government Publishing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington, DC. These methods are also available at https://www. epa.gov/epaoswer/hazwaste/test/main.htm. 59. Table 8 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1565(a)(1), you shall meet each emission limitation in the following table that applies to you. TABLE 8 TO SUBPART UUU OF PART 63—ORGANIC HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS For each new and existing catalytic cracking unit . . . You shall meet the following emission limit for each catalyst regenerator vent . . . 1. Subject to the NSPS for carbon monoxide (CO) in 40 CFR 60.103 or 60.102a(b)(4). CO emissions from the catalyst regenerator vent or CO boiler serving the catalytic cracking unit must not exceed 500 parts per million volume (ppmv) (dry basis). a. CO emissions from the catalyst regenerator vent or CO boiler serving the catalytic cracking unit must not exceed 500 ppmv (dry basis). b. If you use a flare to meet the CO limit, then on and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must meet the requirements for control devices in § 63.11(b) and visible emissions must not exceed a total of 5 minutes during any 2 consecutive hours, or the flare must meet the requirements of § 63.670. 2. Not subject to the NSPS for CO in 40 CFR 60.103 or 60.102a(b)(4) 60. Table 9 to subpart UUU of part 63 is revised to read as follows: tkelley on DSK3SPTVN1PROD with RULES2 ■ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 As stated in § 63.1565(a)(2), you shall meet each operating limit in the following table that applies to you. PO 00000 Frm 00123 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75300 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 9 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING UNITS For each new or existing catalytic cracking unit . . . For this type of continuous monitoring system . . . For this type of control device . . . You shall meet this operating limit . . . 1. Subject to the NSPS for carbon monoxide (CO) in 40 CFR 60.103 or 60.102a(b)(4). 2. Not subject to the NSPS for CO in 40 CFR 60.103 or 60.102a(b)(4). Continuous emission monitoring system. Not applicable ............................... Not applicable. a. moni- Not applicable ............................... Not applicable. b. Continuous parameter monitoring systems. i. Thermal incinerator .................... Maintain the daily average combustion zone temperature above the limit established during the performance test; and maintain the daily average oxygen concentration in the vent stream (percent, dry basis) above the limit established during the performance test. Maintain the daily average combustion zone temperature above the limit established in the performance test. Continuous emission toring system. ii. Boiler or process heater with a design heat input capacity under 44 MW or a boiler or process heater in which all vent streams are not introduced into the flame zone. iii. Flare ......................................... 3. During periods of startup, shutdown or hot standby. Any ................................................ 61. Table 10 to subpart UUU of part 63 is revised to read as follows: Any ................................................ On and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare pilot light must be present at all times and the flare must be operating at all times that emissions may be vented to it, or the flare must meet the requirements of § 63.670. Meet the requirements in § 63.1565(a)(5). As stated in § 63.1565(b)(1), you shall meet each requirement in the following table that applies to you. ■ TABLE 10 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING UNITS And you use this type of control device for your vent . . . You shall install, operate, and maintain this type of continuous monitoring system . . . 1. Subject to the NSPS for carbon monoxide (CO) in 40 CFR 60.103 or 60.102a(b)(4). Not applicable ................................................... 2. Not subject to the NSPS for CO in 40 CFR 60.103 or 60.102a(b)(4). tkelley on DSK3SPTVN1PROD with RULES2 For each new or existing catalytic cracking unit . . . a. Thermal incinerator ...................................... Continuous emission monitoring system to measure and record the concentration by volume (dry basis) of CO emissions from each catalyst regenerator vent. Continuous emission monitoring system to measure and record the concentration by volume (dry basis) of CO emissions from each catalyst regenerator vent; or continuous parameter monitoring systems to measure and record the combustion zone temperature and oxygen content (percent, dry basis) in the incinerator vent stream. Continuous emission monitoring system to measure and record the concentration by volume (dry basis) of CO emissions from each catalyst regenerator vent; or continuous parameter monitoring systems to measure and record the combustion zone temperature. b. Process heater or boiler with a design heat input capacity under 44 MW or process heater or boiler in which all vent streams are not introduced into the flame zone. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00124 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75301 TABLE 10 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new or existing catalytic cracking unit . . . And you use this type of control device for your vent . . . You shall install, operate, and maintain this type of continuous monitoring system . . . c. Flare ............................................................. On and after January 30, 2019, the monitoring systems required in §§ 63.670 and 63.671. Prior to January 30, 2019, monitoring device such as a thermocouple, an ultraviolet beam sensor, or infrared sensor to continuously detect the presence of a pilot flame, or the monitoring systems required in §§ 63.670 and 63.671. Continuous emission monitoring system to measure and record the concentration by volume (dry basis) of CO emissions from each catalyst regenerator vent. Continuous parameter monitoring system to measure and record the concentration by volume (dry basis) of oxygen from each catalyst regenerator vent. d. No control device ......................................... 3. During periods of startup, shutdown or hot standby electing to comply with the operating limit in § 63.1565(a)(5)(ii). Any ................................................................... 62. Table 11 to subpart UUU of part 63 is amended by revising the entry for item 3 to read as follows: * * * * * ■ TABLE 11 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR CARBON MONOXIDE (CO) According to these requirements . . . You must . . . Using . . . * 3. Each catalytic cracking unit catalyst regenerator vent if you use continuous parameter monitoring systems. * * a. Measure the CO concentration (dry basis) of emissions exiting the control device. * * Method 10, 10A, or 10B in appendix A–4 to part 60 of this chapter, as applicable. b. Establish each operating limit in Table 9 of this subpart that applies to you. c. Thermal incinerator combustion zone temperature. Data from the continuous parameter monitoring systems. d. Thermal incinerator: oxygen, content (percent, dry basis) in the incinerator vent stream. tkelley on DSK3SPTVN1PROD with RULES2 For . . . Data from the continuous parameter monitoring systems. e. If you use a process heater or boiler with a design heat input capacity under 44 MW or process heater or boiler in which all vent streams are not introduced into the flame zone, establish operating limit for combustion zone temperature. Data from the continuous parameter monitoring systems. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00125 Fmt 4701 Data from the continuous parameter monitoring systems. Sfmt 4700 E:\FR\FM\01DER2.SGM * Collect temperature monitoring data every 15 minutes during the entire period of the CO initial performance test; and determine and record the minimum hourly average combustion zone temperature from all the readings. Collect oxygen concentration (percent, dry basis) monitoring data every 15 minutes during the entire period of the CO initial performance test; and determine and record the minimum hourly average percent excess oxygen concentration from all the readings. Collect the temperature monitoring data every 15 minutes during the entire period of the CO initial performance test; and determine and record the minimum hourly average combustion zone temperature from all the readings. 01DER2 75302 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 11 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR CARBON MONOXIDE (CO)—Continued You must . . . Using . . . According to these requirements . . . f. If you use a flare, conduct visible emission observations. Method 22 (40 CFR part 60, appendix A–7). g. If you use a flare, determine that the flare meets the requirements for net heating value of the gas being combusted and exit velocity. For . . . 40 CFR 63.11(b)(6) through (8) .... On and after January 30, 2019, meet the requirements of § 63.670. Prior to January 30, 2019, maintain a 2-hour observation period; and record the presence of a flame at the pilot light over the full period of the test or meet the requirements of § 63.670. On and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must meet the control device requirements in § 63.11(b) or the requirements of § 63.670. 63. Table 12 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1565(b)(4), you shall meet each requirement in the following table that applies to you. TABLE 12 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS For each new and existing catalytic cracking unit . . . For the following emission limit . . . You have demonstrated initial compliance if . . . 1. Subject to the NSPS for carbon monoxide (CO) in 40 CFR 60.103, 60.100(e), or 60.102a(b)(4). CO emissions from your catalyst regenerator vent or CO boiler serving the catalytic cracking unit must not exceed 500 ppmv (dry basis). 2. Not subject to the NSPS for CO in 40 CFR 60.103 60.102a(b)(4). a. CO emissions from your catalyst regenerator vent or CO boiler serving the catalytic cracking unit must not exceed 500 ppmv (dry basis). You have already conducted a performance test to demonstrate initial compliance with the NSPS and the measured CO emissions are less than or equal to 500 ppm (dry basis). As part of the Notification of Compliance Status, you must certify that your vent meets the CO limit. You are not required to conduct another performance test to demonstrate initial compliance. You have already conducted a performance evaluation to demonstrate initial compliance with the applicable performance specification. As part of your Notification of Compliance Status, you must certify that your continuous emission monitoring system meets the applicable requirements in § 63.1572. You are not required to conduct another performance evaluation to demonstrate initial compliance. i. If you use a continuous parameter monitoring system, the average CO emissions measured by Method 10 over the period of the initial performance test are less than or equal to 500 ppmv (dry basis). b. If you use a flare, visible emissions must not exceed a total of 5 minutes during any 2 operating hours. 64. Table 13 to subpart UUU of part 63 is revised to read as follows: tkelley on DSK3SPTVN1PROD with RULES2 ■ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 ii. If you use a continuous emission monitoring system, the hourly average CO emissions over the 24-hour period for the initial performance test are not more than 500 ppmv (dry basis); and your performance evaluation shows your continuous emission monitoring system meets the applicable requirements in § 63.1572. On and after January 30, 2019, the flare meets the requirements of § 63.670. Prior to January 30, 2019, visible emissions, measured by Method 22 during the 2-hour observation period during the initial performance test, are no higher than 5 minutes, or the flare meets the requirements of § 63.670. As stated in § 63.1565(c)(1), you shall meet each requirement in the following table that applies to you. PO 00000 Frm 00126 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75303 TABLE 13 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS For each new and existing catalytic cracking unit . . . Subject to this emission limit for your catalyst regenerator vent . . . 1. Subject to the NSPS for carbon monoxide (CO) in 40 CFR 60.103, 60.100(e), or 60.102a(b)(4). 2. Not subject to the NSPS for CO in 40 CFR 60.103 or 60.102a(b)(4). If you must . . . You shall demonstrate continuous compliance by . . . CO emissions from your catalyst regenerator vent or CO boiler serving the catalytic cracking unit must not exceed 500 ppmv (dry basis). Continuous emission monitoring system. a. CO emissions from your catalyst regenerator vent or CO boiler serving the catalytic cracking unit must not exceed 500 ppmv (dry basis). b. CO emissions from your catalyst regenerator vent or CO boiler serving the catalytic cracking unit must not exceed 500 ppmv (dry basis). c. Visible emissions from a flare must not exceed a total of 5 minutes during any 2-hour period. Continuous emission monitoring system. Collecting the hourly average CO monitoring data according to § 63.1572; and maintaining the hourly average CO concentration at or below 500 ppmv (dry basis). Same as item 1. 65. Table 14 to subpart UUU of part 63 is revised to read as follows: ■ Continuous parameter monitoring system. Maintaining the hourly average CO concentration below 500 ppmv (dry basis). Control device-flare ...................... On and after January 30, 2019, meeting the requirements of § 63.670. Prior to January 30, 2019, maintaining visible emissions below a total of 5 minutes during any 2-hour operating period, or meeting the requirements of § 63.670. As stated in § 63.1565(c)(1), you shall meet each requirement in the following table that applies to you. TABLE 14 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING UNITS For each new existing catalytic cracking unit . . . For this operating limit . . . If you use . . . 1. Subject to NSPS for carbon Continuous emission monitoring monoxide (CO) in 40 CFR system. 60.103, 60.100(e), 60.102a(b)(4). 2. Not subject to the NSPS for CO a. Continuous emission moniin 40 CFR 60.103 or toring system. 60.102a(b)(4). b. Continuous parameter monitoring systems—thermal incinerator. You shall demonstrate continuous compliance by . . . Not applicable ............................... Complying with Table 13 of this subpart, item 1. Not applicable ............................... Complying with Table 13 of this subpart, item 2.a. i. The daily average combustion zone temperature must not fall below the level established during the performance test. Collecting the hourly and daily average temperature monitoring data according to § 63.1572; and maintaining the daily average combustion zone temperature above the limit established during the performance test. Collecting the hourly and daily average oxygen concentration monitoring data according to § 63.1572; and maintaining the daily average oxygen concentration above the limit established during the performance test. Collecting the average hourly and daily temperature monitoring data according to § 63.1572; and maintaining the daily average combustion zone temperature above the limit established during the performance test. tkelley on DSK3SPTVN1PROD with RULES2 ii. The daily average oxygen concentration in the vent stream (percent, dry basis) must not fall below the level established during the performance test. c. Continuous parameter monitoring systems—boiler or process heater with a design heat input capacity under 44 MW or boiler or process heater in which all vent streams are not introduced into the flame zone. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00127 Fmt 4701 The daily combustion zone temperature must not fall below the level established in the performance test. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75304 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 14 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued For each new existing catalytic cracking unit . . . If you use . . . You shall demonstrate continuous compliance by . . . d. Continuous parameter monitoring system—flare. 3. During periods of startup, shutdown or hot standby electing to comply with the operating limit in § 63.1565(a)(5)(ii). For this operating limit . . . The flare pilot light must be present at all times and the flare must be operating at all times that emissions may be vented to it. Any control device ........................ The oxygen concentration limit in § 63.1565(a)(5)(ii). On and after January 30, 2019, meeting the requirements of § 63.670. Prior to January 30, 2019, collecting the flare monitoring data according to § 63.1572 and recording for each 1-hour period whether the monitor was continuously operating and the pilot light was continuously present during each 1-hour period, or meeting the requirements of § 63.670. Collecting the hourly average oxygen concentration monitoring data according to § 63.1572 and maintaining the hourly average oxygen concentration at or above 1 volume percent (dry basis). 66. Table 15 to subpart UUU of part 63 is amended by revising the entry for item 1 to read as follows: * * * * * ■ TABLE 15 TO SUBPART UUU OF PART 63—ORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS For each applicable process vent for a new or existing catalytic reforming unit . . . You shall meet this emission limit during initial catalyst depressuring and catalyst purging operations . . . 1. Option 1 ................................................ On and after January 30, 2019, vent emissions to a flare that meets the requirements of § 63.670. Prior to January 30, 2019, vent emissions to a flare that meets the requirements for control devices in § 63.11(b) and visible emissions from a flare must not exceed a total of 5 minutes during any 2-hour operating period, or vent emissions to a flare that meets the requirements of § 63.670. * * * * * * * 67. Table 16 to subpart UUU of part 63 is amended by revising the entry for item 1 to read as follows: * * * * * ■ TABLE 16 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS For each new or existing catalytic reforming unit . . . For this type of control device . . . You shall meet this operating limit during initial catalyst depressuring and purging operations. . . 1. Option 1: Vent to flare ............... Flare ............................................... On and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare pilot light must be present at all times and the flare must be operating at all times that emissions may be vented to it, or the flare must meet the requirements of § 63.670. tkelley on DSK3SPTVN1PROD with RULES2 * * * * * * 68. Table 17 to subpart UUU of part 63 is amended by revising the entry for item 1 to read as follows: * * * * * ■ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00128 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 * 75305 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 17 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS For each applicable process vent for a new or existing catalytic reforming unit . . . If you use this type of control device . . . You shall install and operate this type of continuous monitoring system . . . 1. Option 1: Vent to a flare ............ Flare ............................................... On and after January 30, 2019, the monitoring systems required in §§ 63.670 and 63.671. Prior to January 30, 2019, monitoring device such as a thermocouple, an ultraviolet beam sensor, or infrared sensor to continuously detect the presence of a pilot flame, or the monitoring systems required in §§ 63.670 and 63.671. * * * 69. Table 18 to subpart UUU of part 63 is amended by revising the column * * * * headings and the entry for item 1 to read as follows: * * * * * ■ TABLE 18 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS For each new or existing catalytic reforming unit . . . You must . . . Using . . . According to these requirements . . . 1. Option 1: Vent to a flare ........... a. Conduct visible emission observations. Method 22 (40 CFR part 60, appendix A–7). b. Determine that the flare meets the requirements for net heating value of the gas being combusted and exit velocity. 40 CFR 63.11(b)(6) through (8) .... On and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, 2-hour observation period. Record the presence of a flame at the pilot light over the full period of the test, or the requirements of § 63.670. On and after January 30, 2019, the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must meet the control device requirements in § 63.11(b) or the requirements of § 63.670. * * * * * * * 70. Table 19 to subpart UUU of part 63 is amended by revising the entry for item 1 to read as follows: * * * * * ■ TABLE 19 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS For each applicable process vent for a new or existing catalytic reforming unit . . . For the following emission limit . . . You have demonstrated initial compliance if . . . Option 1 ............................................................ Visible emissions from a flare must not exceed a total of 5 minutes during any 2 consecutive hours. On and after January 30, 2019, the flare meets the requirements of § 63.670. Prior to January 30, 2019, visible emissions, measured using Method 22 over the 2-hour observation period of the performance test, do not exceed a total of 5 minutes, or the flare meets the requirements of § 63.670. tkelley on DSK3SPTVN1PROD with RULES2 * * * * * * 71. Table 20 to subpart UUU of part 63 is amended by revising the entry for item 1 to read as follows: * * * * * ■ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00129 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 * 75306 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 20 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS You shall demonstrate continuous compliance during initial catalyst depressuring and catalyst purging operations by . . . For each applicable process vent for a new or existing catalytic reforming unit . . . For this emission limit . . . 1. Option 1 ........................................................ Vent emissions from your process vent to a flare. * * * * On and after January 30, 2019, meeting the requirements of § 63.670. Prior to January 30, 2019, maintaining visible emissions from a flare below a total of 5 minutes during any 2 consecutive hours, or meeting the requirements of § 63.670. * * * 72. Table 21 to subpart UUU of part 63 is amended by revising the entry for item 1 to read as follows: * * * * * ■ TABLE 21 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS You shall demonstrate continuous compliance during initial catalyst depressuring and purging operations by . . . For each applicable process vent for a new or existing catalytic reforming unit . . . If you use . . . For this operating limit . . . 1. Option 1 .................................... Flare .............................................. The flare pilot light must be present at all times and the flare must be operating at all times that emissions may be vented to it. * * * * On and after January 30, 2019, meeting the requirements of § 63.670. Prior to January 30, 2019, collecting flare monitoring data according to § 63.1572 and recording for each 1-hour period whether the monitor was continuously operating and the pilot light was continuously present during each 1-hour period, or meeting the requirements of § 63.670. * * * 73. Table 22 to subpart UUU of part 63 is amended by revising the entries for items 2 and 3 to read as follows: * * * * * ■ TABLE 22 TO SUBPART UUU OF PART 63—INORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS You shall meet this emission limit for each applicable catalytic reforming unit process vent during coke burn-off and catalyst rejuvenation . . . For . . . tkelley on DSK3SPTVN1PROD with RULES2 * * * * * * * 2. Each existing cyclic or continuous catalytic reforming unit .................. Reduce uncontrolled emissions of HCl by 97 percent by weight or to a concentration of 10 ppmv (dry basis), corrected to 3 percent oxygen. 3. Each new semi-regenerative, cyclic, or continuous catalytic reform- Reduce uncontrolled emissions of HCl by 97 percent by weight or to a ing unit. concentration of 10 ppmv (dry basis), corrected to 3 percent oxygen. 74. Table 24 to subpart UUU of part 63 is amended by revising the entries for ■ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 items 2 through 4 and footnote 2 to read as follows: * * * * * PO 00000 Frm 00130 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75307 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 24 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR INORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS You shall install and operate this type of continuous monitoring system . . . If you use this type of control device for your vent . . . * * * * * * * 2. Internal scrubbing system or no control device (e.g., hot regen sys- Colormetric tube sampling system to measure the HCl concentration in tem) to meet HCl outlet concentration limit. the catalyst regenerator exhaust gas during coke burn-off and catalyst rejuvenation. The colormetric tube sampling system must meet the requirements in Table 41 of this subpart. 3. Internal scrubbing system to meet HCl percent reduction standard ... Continuous parameter monitoring system to measure and record the gas flow rate entering or exiting the internal scrubbing system during coke burn-off and catalyst rejuvenation; and continuous parameter monitoring system to measure and record the total water (or scrubbing liquid) flow rate entering the internal scrubbing system during coke burn-off and catalyst rejuvenation; and continuous parameter monitoring system to measure and record the pH or alkalinity of the water (or scrubbing liquid) exiting the internal scrubbing system during coke burn-off and catalyst rejuvenation.2 4. Fixed-bed gas-solid adsorption system ................................................ Continuous parameter monitoring system to measure and record the temperature of the gas entering or exiting the adsorption system during coke burn-off and catalyst rejuvenation; and colormetric tube sampling system to measure the gaseous HCl concentration in the adsorption system exhaust and at a point within the absorbent bed not to exceed 90 percent of the total length of the absorbent bed during coke burn-off and catalyst rejuvenation. The colormetric tube sampling system must meet the requirements in Table 41 of this subpart. * * * * * * * * * * * * * * 2 If applicable, you can use the alternative in § 63.1573(c)(1) instead of a continuous parameter monitoring system for pH of the water (or scrubbing liquid) or the alternative in § 63.1573(c)(2) instead of a continuous parameter monitoring system for alkalinity of the water (or scrubbing liquid). * * * * * 75. Table 25 to subpart UUU of part 63 is amended by revising the entries for ■ items 2.a and 4.a and footnote 1 to read as follows: * * * * * TABLE 25 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR INORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS For each new and existing catalytic reforming unit using . . . You shall . . . * * 2. Wet scrubber ............................ * * * a. Establish operating limit for pH i. Data from continuous parameter level or alkalinity. monitoring systems. According to these requirements . . . Using . . . tkelley on DSK3SPTVN1PROD with RULES2 ii. Alternative pH procedure in § 63.1573(b)(1). VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00131 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM * * Measure and record the pH or alkalinity of the water (or scrubbing liquid) exiting scrubber every 15 minutes during the entire period of the performance test. Determine and record the minimum hourly average pH or alkalinity level from the recorded values. Measure and record the pH of the water (or scrubbing liquid) exiting the scrubber during coke burn-off and catalyst rejuvenation using pH strips at least three times during each test run. Determine and record the average pH level for each test run. Determine and record the minimum test run average pH level. 01DER2 75308 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 25 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR INORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS—Continued For each new and existing catalytic reforming unit using . . . According to these requirements . . . iii. Alternative alkalinity method in § 63.1573(c)(2). 4. Using . . . Measure and record the alkalinity of the water (or scrubbing liquid) exiting the scrubber during coke burn-off and catalyst rejuvenation using discrete titration at least three times during each test run. Determine and record the average alkalinity level for each test run. Determine and record the minimum test run average alkalinity level. * * * a. Establish operating limit for pH i. Data from continuous parameter level or alkalinity. monitoring system. * * Measure and record the pH alkalinity of the water (or scrubbing liquid) exiting the internal scrubbing system every 15 minutes during the entire period of the performance test. Determine and record the minimum hourly average pH or alkalinity level from the recorded values. Measure and in record pH of the water (or scrubbing liquid) exiting the internal scrubbing system during coke burn-off and catalyst rejuvenation using pH strips at least three times during each test run. Determine and record the average pH level for each test run. Determine and record the minimum test run average pH level. Measure and record the alkalinity water (or scrubbing liquid) exiting the internal scrubbing system during coke burn-off and catalyst rejuvenation using discrete titration at least three times during each test run. Determine and record the average alkalinity level for each test run. Determine and record the minimum test run average alkalinity level. You shall . . . * * Internal scrubbing system meeting HCl percent reduction standard. ii. Alternative pH § 63.1573(c)(1). method in iii. Alternative alkalinity method in § 63.1573(c)(2). * * * * * * * 1 The EPA Methods 5050, 9056, 9212 and 9253 are included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW–846 and Updates (document number 955–001–00000–1) are available for purchase from the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington, DC. These methods are also available at https://www.epa.gov/epaoswer/ hazwaste/test/main.htm. 76. Table 28 to subpart UUU of part 63 is amended by revising the entry for tkelley on DSK3SPTVN1PROD with RULES2 ■ item 5 and footnotes 1 and 3 to read as follows: * * * * * TABLE 28 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR INORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS For each new and existing catalytic reforming unit using this type of control device or system . . . VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 For this operating limit . . . PO 00000 Frm 00132 Fmt 4701 Sfmt 4700 You shall demonstrate continuous compliance during coke burn-off and catalyst rejuvenation by . . . E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75309 TABLE 28 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR INORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS—Continued For each new and existing catalytic reforming unit using this type of control device or system . . . * * 5. Moving-bed gas-solid adsorption system (e.g., ChlorsorbTM System). You shall demonstrate continuous compliance during coke burn-off and catalyst rejuvenation by . . . For this operating limit . . . * * * a. The daily average temperature of the gas entering or exiting the adsorption system must not exceed the limit established during the performance test. b. The weekly average chloride level on the sorbent entering the adsorption system must not exceed the design or manufacturer’s recommended limit (1.35 weight percent for the ChlorsorbTM System). c. The weekly average chloride level on the sorbent exiting the adsorption system must not exceed the design or manufacturer’s recommended limit (1.8 weight percent for the ChlorsorbTM System). * * Collecting the hourly and daily average temperature monitoring data according to § 63.1572; and maintaining the daily average temperature below the operating limit established during the performance test. Collecting samples of the sorbent exiting the adsorption system three times per week (on non-consecutive days); and analyzing the samples for total chloride3; and determining and recording the weekly average chloride concentration; and maintaining the chloride concentration below the design or manufacturer’s recommended limit (1.35 weight percent for the ChlorsorbTM System). Collecting samples of the sorbent exiting the adsorption system three times per week (on non-consecutive days); and analyzing the samples for total chloride concentration; and determining and recording the weekly average chloride concentration; and maintaining the chloride concentration below the design or manufacturer’s recommended limit (1.8 weight percent ChlorsorbTM System). 1 If applicable, you can use either alternative in § 63.1573(c) instead of a continuous parameter monitoring system for pH or alkalinity if you used the alternative method in the initial performance test. * * * * * * * 3 The total chloride concentration of the sorbent material must be measured by the procedure, ‘‘Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure)’’ in appendix A to this subpart; or by using EPA Method 5050, Bomb Preparation Method for Solid Waste, combined either with EPA Method 9056, Determination of Inorganic Anions by Ion Chromatography, or with EPA Method 9253, Chloride (Titrimetric, Silver Nitrate); or by using EPA Method 9212, Potentiometric Determination of Chloride in Aqueous Samples with Ion-Selective Electrode, and using the soil extraction procedures listed within the method. The EPA Methods 5050, 9056, 9212 and 9253 are included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW–846 and Updates (document number 955–001–00000–1) are available for purchase from the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building, (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington, DC. These methods are also available at https://www.epa.gov/epaoswer/hazwaste/test/main.htm. 77. Table 29 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1568(a)(1), you shall meet each emission limitation in the following table that applies to you. TABLE 29 TO SUBPART UUU OF PART 63—HAP EMISSION LIMITS FOR SULFUR RECOVERY UNITS For . . . You shall meet this emission limit for each process vent . . . 1. Subject to NSPS. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 long tons per day (LTD) and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). a. 250 ppmv (dry basis) of sulfur dioxide (SO2) at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use an oxidation control system or if you use a reduction control system followed by incineration. b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction control system without incineration. a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use an oxidation control system or if you use a reduction control system followed by incineration. b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction control system without incineration. 300 ppmv of total reduced sulfur (TRS) compounds, expressed as an equivalent SO2 concentration (dry basis) at zero percent oxygen. tkelley on DSK3SPTVN1PROD with RULES2 2. Option 1: Elect NSPS. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). 3. Option 2: TRS limit. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00133 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75310 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 78. Table 30 to subpart UUU of part 63 is revised to read as follows: As stated in § 63.1568(a)(2), you shall meet each operating limit in the following table that applies to you. ■ TABLE 30 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS For . . . If use this type of control device . . . You shall meet this operating limit . . . 1. Subject to NSPS. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). 2. Option 1: Elect NSPS. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). 3. Option 2: TRS limit, if using continuous emissions monitoring systems. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). 4. Option 2: TRS limit, if using continuous parameter monitoring systems. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). Not applicable .................................................. Not applicable. Not applicable .................................................. Not applicable. Not applicable .................................................. Not applicable. Thermal incinerator .......................................... 5. Startup or shutdown option 1: Electing to comply with § 63.1568(a)(4)(ii). Each new or existing sulfur recovery unit (Claus or other type, regardless of size) during periods of startup or shutdown. 6. Startup or shutdown option 2: Electing to comply with § 63.1568(a)(4)(iii). Each new or existing sulfur recovery unit (Claus or other type, regardless of size) during startup or shutdown events. Flare ................................................................. Maintain the daily average combustion zone temperature above the limit established during the performance test; and maintain the daily average oxygen concentration in the vent stream (percent, dry basis) above the limit established during the performance test. On and after January 30, 2019, meet the applicable requirements of § 63.670. Prior to January 30, 2019, meet the applicable requirements of either § 63.11(b) or § 63.670. 79. Table 31 to subpart UUU is revised to read as follows: ■ Thermal incinerator or thermal oxidizer ........... Maintain the hourly average combustion zone temperature at or above 1,200 degrees Fahrenheit and maintain the hourly average oxygen concentration in the exhaust gas stream at or above 2 volume percent (dry basis). As stated in § 63.1568(b)(1), you shall meet each requirement in the following table that applies to you. TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS For this limit . . . You shall install and operate this continuous monitoring system . . . 1. Subject to NSPS. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). tkelley on DSK3SPTVN1PROD with RULES2 For . . . a. 250 ppmv (dry basis) of SO2 at zero percent excess air if you use an oxidation or reduction control system followed by incineration. Continuous emission monitoring system to measure and record the hourly average concentration of SO2 (dry basis) at zero percent excess air for each exhaust stack. This system must include an oxygen monitor for correcting the data for excess air. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00134 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75311 TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS—Continued For this limit . . . You shall install and operate this continuous monitoring system . . . b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero percent excess air if you use a reduction control system without incineration. For . . . Continuous emission monitoring system to measure and record the hourly average concentration of reduced sulfur and oxygen (O2) emissions. Calculate the reduced sulfur emissions as SO2 (dry basis) at zero percent excess air. Exception: You can use an instrument having an air or SO2 dilution and oxidation system to convert the reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry basis) at zero percent excess air of the resultant SO2 instead of the reduced sulfur monitor. The monitor must include an oxygen monitor for correcting the data for excess oxygen. i. Complete either item 1.a or item 1.b; and ii. Either a continuous emission monitoring system to measure and record the O2 concentration for the inlet air/oxygen supplied to the system or a continuous parameter monitoring system to measure and record the volumetric gas flow rate of ambient air and purchased oxygen-enriched gas. Continuous emission monitoring system to measure and record the hourly average concentration of SO2 (dry basis), at zero percent excess air for each exhaust stack. This system must include an oxygen monitor for correcting the data for excess air. Continuous emission monitoring system to measure and record the hourly average concentration of reduced sulfur and O2 emissions for each exhaust stack. Calculate the reduced sulfur emissions as SO2 (dry basis), at zero percent excess air. Exception: You can use an instrument having an air or O2 dilution and oxidation system to convert the reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry basis) at zero percent excess air of the resultant SO2 instead of the reduced sulfur monitor. The monitor must include an oxygen monitor for correcting the data for excess oxygen. i. Complete either item 2.a or item 2.b; and ii. Either a continuous emission monitoring system to measure and record the O2 concentration for the inlet air/oxygen supplied to the system, or a continuous parameter monitoring system to measure and record the volumetric gas flow rate of ambient air and purchased oxygen-enriched gas. i. Continuous emission monitoring system to measure and record the hourly average concentration of TRS for each exhaust stack; this monitor must include an oxygen monitor for correcting the data for excess oxygen; or ii. Continuous parameter monitoring systems to measure and record the combustion zone temperature of each thermal incinerator and the oxygen content (percent, dry basis) in the vent stream of the incinerator. c. If you use Equation 1 of 40 CFR 60.102a(f)(1)(i) to set your emission limit. 2. Option 1: Elect NSPS. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). a. 250 ppmv (dry basis) of SO2 at zero percent excess air if you use an oxidation or reduction control system followed by incineration. b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero percent excess air if you use a reduction control system without incineration. c. If you use Equation 1 of 40 CFR 60.102a(f)(1)(i) to set your emission limit. tkelley on DSK3SPTVN1PROD with RULES2 3. Option 2: TRS limit. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 a. 300 ppmv of total reduced sulfur (TRS) compounds, expressed as an equivalent SO2 concentration (dry basis) at zero percent oxygen. PO 00000 Frm 00135 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75312 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS—Continued For . . . For this limit . . . You shall install and operate this continuous monitoring system . . . 4. Startup or shutdown option 1: electing to comply with § 63.1568(a)(4)(ii). Each new or existing sulfur recovery unit (Claus or other type, regardless of size) during periods of startup or shutdown. Any ................................................................... 5. Startup or shutdown option 2: electing to comply with § 63.1568(a)(4)(iii). Each new or existing sulfur recovery unit (Claus or other type, regardless of size) during periods of startup or shutdown. Any ................................................................... On and after January 30, 2019, monitoring systems as specified in §§ 63.670 and 63.671. Prior to January 30, 2019, either continuous parameter monitoring systems following the requirements in § 63.11 (to detect the presence of a flame; to measure and record the net heating value of the gas being combusted; and to measure and record the volumetric flow of the gas being combusted) or monitoring systems as specified in §§ 63.670 and 63.671. Continuous parameter monitoring systems to measure and record the firebox temperature of each thermal incinerator or oxidizer and the oxygen content (percent, dry basis) in the exhaust vent from the incinerator or oxidizer. 80. Table 32 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1568(b)(2) and (3), you shall meet each requirement in the following table that applies to you. TABLE 32 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARDS FOR SULFUR OXIDES For . . . You must . . . Using . . . According to these requirements . . . 1. Option 1: Elect NSPS. Each new and existing sulfur recovery unit. a. Measure SO2 concentration (for an oxidation or reduction system followed by incineration) or measure the concentration of reduced sulfur (or SO2 if you use an instrument to convert the reduced sulfur to SO2) for a reduction control system without incineration. b. Measure O2 concentration for the inlet air/oxygen supplied to the system, if using Equation 1 of 40 CFR 60.102a(f)1)(i) to set your emission limit. You may use either an O2 CEMS method in item 1.b.i of this table or the flow monitor in item 1.b.ii of this table. Data from continuous emission monitoring system. Collect SO2 monitoring data every 15 minutes for 24 consecutive operating hours. Reduce the data to 1-hour averages computed from four or more data points equally spaced over each 1-hour period. i. Data from continuous emission monitoring system; or Collect O2 monitoring data every 15 minutes for 24 consecutive operating hours. Reduce the data to 1-hour averages computed from four or more data points equally spaced over each 1-hour period; and average over the 24-hour period for input to Equation 1 of 40 CFR 60.102a(f)(1)(i). Collect gas flow rate monitoring data every 15 minutes for 24 consecutive operating hours. Reduce the data to 1-hour averages computed from 4 or more data points equally spaced over each 1-hour period; calculate the hourly O2 percent using Equation 10 of 40 CFR 60.106a(a)(6)(iv); and average over the 24-hour period for input to Equation 1 of 40 CFR 60.102a(f)(1)(i). Collect TRS data every 15 minutes for 24 consecutive operating hours. Reduce the data to 1-hour averages computed from four or more data points equally spaced over each 1-hour period. tkelley on DSK3SPTVN1PROD with RULES2 ii. Data from flow monitor for ambient air and purchased oxygen-enriched gas. 2. Option 2: TRS limit, using CEMS. Each new and existing sulfur recovery unit. VerDate Sep<11>2014 23:11 Nov 30, 2015 Measure the concentration of reduced sulfur (or SO2 if you use an instrument to convert the reduced sulfur to SO2). Jkt 238001 PO 00000 Frm 00136 Fmt 4701 Data from continuous emission monitoring system. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75313 TABLE 32 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARDS FOR SULFUR OXIDES—Continued For . . . You must . . . Using . . . According to these requirements . . . 3. Option 2: TRS limit, if using continuous parameter monitoring systems. Each new and existing sulfur recovery unit. a. Select sampling port’s location and the number of traverse ports. Method 1 or 1A in Appendix A–1 to part 60 of this chapter. Sampling sites must be located at the outlet of the control device and prior to any releases to the atmosphere. b. Determine velocity and volumetric flow rate. Method 2, 2A, 2C, 2D, or 2F in appendix A–1 to part 60 of this chapter, or Method 2G in appendix A–2 to part 60 of this chapter, as applicable. Method 3, 3A, or 3B in appendix A–2 to part 60 of this chapter, as applicable. c. Conduct gas molecular weight analysis; obtain the oxygen concentration needed to correct the emission rate for excess air. d. Measure moisture content of the stack gas. Method 4 in appendix A–3 to part 60 of this chapter. e. Measure the concentration of TRS. Method 15 or 15A in appendix A– 5 to part 60 of this chapter, as applicable. f. Calculate the SO2 equivalent for each run after correcting for moisture and oxygen. g. Correct the reduced sulfur samples to zero percent excess air. h. Establish each operating limit in Table 30 of this subpart that applies to you. i. Measure thermal incinerator: combustion zone temperature. Data from the continuous parameter monitoring system. 81. Table 33 to subpart UUU of part 63 is revised to read as follows: tkelley on DSK3SPTVN1PROD with RULES2 ■ VerDate Sep<11>2014 23:11 Nov 30, 2015 Make your sampling time for each Method 4 sample equal to that for 4 Method 15 samples. If the cross-sectional area of the duct is less than 5 square meters (m2) or 54 square feet, you must use the centroid of the cross section as the sampling point. If the cross-sectional area is 5 m2 or more and the centroid is more than 1 meter (m) from the wall, your sampling point may be at a point no closer to the walls than 1 m or 39 inches. Your sampling rate must be at least 3 liters per minute or 0.10 cubic feet per minute to ensure minimum residence time for the sample inside the sample lines. The arithmetic average of the SO2 equivalent for each sample during the run. Equation 1 of § 63.1568 ............... j. Measure thermal incinerator: oxygen concentration (percent, dry basis) in the vent stream. Take the samples simultaneously with reduced sulfur or moisture samples. Jkt 238001 Data from the continuous parameter monitoring system. Data from the continuous parameter monitoring system. Collect temperature monitoring data every 15 minutes during the entire period of the performance test; and determine and record the minimum hourly average temperature from all the readings. Collect oxygen concentration (percent, dry basis) data every 15 minutes during the entire period of the performance test; and determine and record the minimum hourly average percent excess oxygen concentration. As stated in § 63.1568(b)(5), you shall meet each requirement in the following table that applies to you. PO 00000 Frm 00137 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75314 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 33 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY UNITS For . . . For the following emission limit . . . You have demonstrated initial compliance if . . . 1. Subject to NSPS: Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). a. 250 ppmv (dry basis) SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use an oxidation or reduction control system followed by incineration. You have already conducted a performance test to demonstrate initial compliance with the NSPS and each 12-hour rolling average concentration of SO2 emissions measured by the continuous emission monitoring system is less than or equal to 250 ppmv (dry basis) at zero percent excess air, or the concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i). As part of the Notification of Compliance Status, you must certify that your vent meets the SO2 limit. You are not required to do another performance test to demonstrate initial compliance. You have already conducted a performance evaluation to demonstrate initial compliance with the applicable performance specification. As part of your Notification of Compliance Status, you must certify that your continuous emission monitoring system meets the applicable requirements in § 63.1572. You are not required to do another performance evaluation to demonstrate initial compliance. You have already conducted a performance test to demonstrate initial compliance with the NSPS and each 12-hour rolling average concentration of reduced sulfur compounds measured by your continuous emission monitoring system is less than or equal to 300 ppmv, calculated as ppmv SO2 (dry basis) at zero percent excess air, or the concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i). As part of the Notification of Compliance Status, you must certify that your vent meets the SO2 limit. You are not required to do another performance test to demonstrate initial compliance. You have already conducted a performance evaluation to demonstrate initial compliance with the applicable performance specification. As part of your Notification of Compliance Status, you must certify that your continuous emission monitoring system meets the applicable requirements in § 63.1572. You are not required to do another performance evaluation to demonstrate initial compliance. Each 12-hour rolling average concentration of SO2 emissions measured by the continuous emission monitoring system during the initial performance test is less than or equal to 250 ppmv (dry basis) at zero percent excess air, or the concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i); and your performance evaluation shows the monitoring system meets the applicable requirements in § 63.1572. Each 12-hour rolling average concentration of reduced sulfur compounds measured by the continuous emission monitoring system during the initial performance test is less than or equal to 300 ppmv, calculated as ppmv SO2 (dry basis) at zero percent excess air, or the concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i); and your performance evaluation shows the continuous emission monitoring system meets the applicable requirements in § 63.1572. b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction control system without incineration. tkelley on DSK3SPTVN1PROD with RULES2 2. Option 1: Elect NSPS. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use an oxidation or reduction control system followed by incineration. b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction control system without incineration. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00138 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75315 TABLE 33 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY UNITS—Continued For . . . For the following emission limit . . . You have demonstrated initial compliance if . . . 3. Option 2: TRS limit. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). 300 ppmv of TRS compounds expressed as an equivalent SO2 concentration (dry basis) at zero percent oxygen. If you use continuous parameter monitoring systems, the average concentration of TRS emissions measured using Method 15 during the initial performance test is less than or equal to 300 ppmv expressed as equivalent SO2 concentration (dry basis) at zero percent oxygen. If you use a continuous emission monitoring system, each 12-hour rolling average concentration of TRS emissions measured by the continuous emission monitoring system during the initial performance test is less than or equal to 300 ppmv expressed as an equivalent SO2 (dry basis) at zero percent oxygen; and your performance evaluation shows the continuous emission monitoring system meets the applicable requirements in § 63.1572. 82. Table 34 to subpart UUU of part 63 is revised to read as follows: As stated in § 63.1568(c)(1), you shall meet each requirement in the following table that applies to you. ■ TABLE 34 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY UNITS For . . . For this emission limit . . . You shall demonstrate continuous compliance by . . . 1. Subject to NSPS. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use an oxidation or reduction control system followed by incineration. Collecting the hourly average SO2 monitoring data (dry basis, percent excess air) and, if using Equation 1 of 40 CFR 60.102a(f)(1)(i), collecting the hourly O2 concentration or flow monitoring data according to § 63.1572; determining and recording each 12-hour rolling average concentration of SO2; maintaining each 12-hour rolling average concentration of SO2 at or below the applicable emission limitation; and reporting any 12-hour rolling average concentration of SO2 greater than the applicable emission limitation in the semiannual compliance report required by § 63.1575. Collecting the hourly average reduced sulfur (and air or O2 dilution and oxidation) monitoring data and, if using Equation 1 of 40 CFR 60.102a(f)(1)(i), collecting the hourly O2 concentration or flow monitoring data according to § 63.1572; determining and recording each 12-hour rolling average concentration of reduced sulfur; maintaining each 12-hour rolling average concentration of reduced sulfur at or below the applicable emission limitation; and reporting any 12hour rolling average concentration of reduced sulfur greater than the applicable emission limitation in the semiannual compliance report required by § 63.1575. tkelley on DSK3SPTVN1PROD with RULES2 b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction control system without incineration. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00139 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75316 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 34 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY UNITS—Continued For . . . For this emission limit . . . You shall demonstrate continuous compliance by . . . 2. Option 1: Elect NSPS. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use an oxidation or reduction control system followed by incineration. Collecting the hourly average SO2 data (dry basis, percent excess air) and, if using Equation 1 of 40 CFR 60.102a(f)(1)(i), collecting the hourly O2 concentration or flow monitoring data according to § 63.1572; determining and recording each 12-hour rolling average concentration of SO2; maintaining each 12-hour rolling average concentration of SO2 at or below the applicable emission limitation; and reporting any 12-hour rolling average concentration of SO2 greater than the applicable emission limitation in the semiannual compliance report required by § 63.1575. Collecting the hourly average reduced sulfur (and air or O2 dilution and oxidation) monitoring data and, if using Equation 1 of 40 CFR 60.102a(f)(1)(i), collecting the hourly O2 concentration or flow monitoring data according to § 63.1572; determining and recording each 12-hour rolling average concentration of reduced sulfur; maintaining each 12-hour rolling average concentration of reduced sulfur at or below the applicable emission limitation; and reporting any 12hour rolling average concentration of reduced sulfur greater than the applicable emission limitation in the semiannual compliance report required by § 63.1575. i. If you use continuous parameter monitoring systems, collecting the hourly average TRS monitoring data according to § 63.1572 and maintaining each 12-hour average concentration of TRS at or below the applicable emission limitation; or ii. If you use a continuous emission monitoring system, collecting the hourly average TRS monitoring data according to § 63.1572, determining and recording each 12-hour rolling average concentration of TRS; maintaining each 12-hour rolling average concentration of TRS at or below the applicable emission limitation; and reporting any 12-hour rolling average TRS concentration greater than the applicable emission limitation in the semiannual compliance report required by § 63.1575. b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction control system without incineration. 3. Option 2: TRS limit. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). 83. Table 35 to subpart UUU of part 63 is revised to read as follows: 300 ppmv of TRS compounds, expressed as an SO2 concentration (dry basis) at zero percent oxygen or reduced sulfur compounds calculated as ppmv SO2 (dry basis) at zero percent excess air. As stated in § 63.1568(c)(1), you shall meet each requirement in the following table that applies to you. ■ TABLE 35 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS tkelley on DSK3SPTVN1PROD with RULES2 For . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 1. Subject to NSPS. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). Not applicable .................................................. Meeting the requirements of Table 34 of this subpart. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00140 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75317 TABLE 35 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS—Continued For . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 2. Option 1: Elect NSPS. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). 3. Option 2: TRS limit. Each new or existing sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1). Not applicable .................................................. Meeting the requirements of Table 34 of this subpart. a. Maintain the daily average combustion zone temperature above the level established during the performance test. Collecting the hourly and daily average temperature monitoring data according to § 63.1572; and maintaining the daily average combustion zone temperature at or above the limit established during the performance test Collecting the hourly and daily average O2 monitoring data according to § 63.1572; and maintaining the average O2 concentration above the level established during the performance test. On and after January 30, 2019, complying with the applicable requirements of § 63.670. Prior to January 30, 2019, complying with the applicable requirements of either § 63.11(b) or § 63.670. Collecting continuous (at least once every 15 minutes) and hourly average temperature monitoring data according to § 63.1572; and maintaining the daily average firebox temperature at or above 1,200 degrees Fahrenheit. Collecting continuous (at least once every 15 minutes) and hourly average O2 monitoring data according to § 63.1572; and maintaining the average O2 concentration at or above 2 volume percent (dry basis). b. The daily average oxygen concentration in the vent stream (percent, dry basis) must not fall below the level established during the performance test.. 4. Startup or shutdown option 1: Electing to comply with § 63.1568(a)(4)(ii). Each new or existing sulfur recovery unit (Claus or other type, regardless of size) during periods of startup or shutdown. 5. Startup or shutdown option 2: Electing to comply with § 63.1568(a)(4)(iii). Each new or existing sulfur recovery unit (Claus or other type, regardless of size) during periods of startup or shutdown. Using a flare meeting the requirements in § 63.11(b) or § 63.670. a. Minimum hourly average temperature of 1,200 degrees Fahrenheit. b. Minimum hourly average outlet oxygen concentration of 2 volume percent (dry basis). 84. Table 40 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1572(a)(1) and (b)(1), you shall meet each requirement in the following table that applies to you. TABLE 40 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF CONTINUOUS OPACITY MONITORING SYSTEMS AND CONTINUOUS EMISSION MONITORING SYSTEMS This type of continuous opacity or emission monitoring system . . . Must meet these requirements . . . 1. Continuous opacity monitoring system ................................................ 2. PM CEMS; this monitor must include an O2 monitor for correcting the data for excess air. 3. CO continuous emission monitoring system ........................................ Performance specification 1 (40 CFR part 60, appendix B). The requirements in 40 CFR 60.105a(d). tkelley on DSK3SPTVN1PROD with RULES2 4. CO continuous emission monitoring system used to demonstrate emissions average under 50 ppm (dry basis). 5. SO2 continuous emission monitoring system for sulfur recovery unit with oxidation control system or reduction control system; this monitor must include an O2 monitor for correcting the data for excess air. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00141 Fmt 4701 Performance specification 4 (40 CFR part 60, appendix B); span value of 1,000 ppm; and procedure 1 (40 CFR part 60, appendix F) except relative accuracy test audits are required annually instead of quarterly. Performance specification 4 (40 CFR part 60, appendix B); and span value of 100 ppm. Performance specification 2 (40 CFR part 60, appendix B); span value of 500 ppm SO2, or if using Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at the highest O2 concentration; use Methods 6 or 6C (40 CFR part 60, appendix A–4) for certifying the SO2 monitor and Methods 3A or 3B (40 CFR part 60, appendix A–2) for certifying the O2 monitor; and procedure 1 (40 CFR part 60, appendix F) except relative accuracy test audits are required annually instead of quarterly. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75318 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 40 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF CONTINUOUS OPACITY MONITORING SYSTEMS AND CONTINUOUS EMISSION MONITORING SYSTEMS—Continued This type of continuous opacity or emission monitoring system . . . Must meet these requirements . . . 6. Reduced sulfur and O2 continuous emission monitoring system for sulfur recovery unit with reduction control system not followed by incineration; this monitor must include an O2 monitor for correcting the data for excess air unless exempted. Performance specification 5 (40 CFR part 60, appendix B), except calibration drift specification is 2.5 percent of the span value instead of 5 percent; span value is 450 ppm reduced sulfur, or if using Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at the highest O2 concentration; use Methods 15 or 15A (40 CFR part 60, appendix A–5) for certifying the reduced sulfur monitor and Methods 3A or 3B (40 CFR part 60, appendix A–2) for certifying the O2 monitor; if Method 3A or 3B yields O2 concentrations below 0.25 percent during the performance evaluation, the O2 concentration can be assumed to be zero and the O2 monitor is not required; and procedure 1 (40 CFR part 60, appendix F), except relative accuracy test audits, are required annually instead of quarterly. Performance specification 5 (40 CFR part 60, appendix B); span value of 375 ppm SO2 or if using Equation 1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at the highest O2 concentration; use Methods 15 or 15A (40 CFR part 60, appendix A–5) for certifying the reduced sulfur monitor and 3A or 3B (40 CFR part 60, appendix A– 2) for certifying the O2 monitor; and procedure 1 (40 CFR part 60, appendix F), except relative accuracy test audits, are required annually instead of quarterly. Performance specification 5 (40 CFR part 60, appendix B). 7. Instrument with an air or O2 dilution and oxidation system to convert reduced sulfur to SO2 for continuously monitoring the concentration of SO2 instead of reduced sulfur monitor and O2 monitor. 8. TRS continuous emission monitoring system for sulfur recovery unit; this monitor must include an O2 monitor for correcting the data for excess air. 9. O2 monitor for oxygen concentration ................................................... 85. Table 41 to subpart UUU of part 63 is revised to read as follows: ■ If necessary due to interferences, locate the oxygen sensor prior to the introduction of any outside gas stream; performance specification 3 (40 CFR part 60, appendix B; and procedure 1 (40 CFR part 60, appendix F), except relative accuracy test audits, are required annually instead of quarterly. As stated in § 63.1572(c)(1), you shall meet each requirement in the following table that applies to you. TABLE 41 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF CONTINUOUS PARAMETER MONITORING SYSTEMS If you use . . . You shall . . . 1. pH strips ............ 2. pH meter ............ Use pH strips with an accuracy of ±10 percent. Locate the pH sensor in a position that provides a representative measurement of pH; ensure the sample is properly mixed and representative of the fluid to be measured. Use a pH sensor with an accuracy of at least ±0.2 pH units. Check the pH meter’s calibration on at least one point at least once daily; check the pH meter’s calibration on at least two points at least once quarterly; at least monthly, inspect all components for integrity and all electrical components for continuity; record the results of each calibration check and inspection. Use a colormetric tube sampling system with a printed numerical scale in ppmv, a standard measurement range of 1 to 10 ppmv (or 1 to 30 ppmv if applicable), and a standard deviation for measured values of no more than ±15 percent. System must include a gas detection pump and hot air probe if needed for the measurement range. a. Locate the concentration sensor so that it provides a representative measurement of the content of the exit gas stream; ensure the sample is properly mixed and representative of the gas to be measured. 3. Colormetric tube sampling system. tkelley on DSK3SPTVN1PROD with RULES2 4. CO2, O2, and CO monitors for coke burn-off rate. 5. BLD .................... 6. Voltage, secondary current, or total power input sensors. VerDate Sep<11>2014 Use a sensor with an accuracy of at least ±1 percent of the range of the sensor or to a nominal gas concentration of ±0.5 percent, whichever is greater. Use a monitor that is able to measure concentration on a dry basis or is able to correct for moisture content and record on a dry basis. Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours throughout which the sensor reading exceeds the manufacturer’s specified maximum operating range or install a new sensor; at least quarterly, inspect all components for integrity and all electrical connections for continuity; record the results of each calibration and inspection. b. As an alternative, the requirements in 40 CFR 60.105a(b)(2) may be used. Follow the requirements in 40 CFR 60.105a(c). Use meters with an accuracy of at least ±5 percent over the operating range. 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00142 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75319 TABLE 41 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF CONTINUOUS PARAMETER MONITORING SYSTEMS—Continued If you use . . . You shall . . . 7. Pressure/Pressure drop1 sensors. 8. Air flow rate, gas flow rate, or total water (or scrubbing liquid) flow rate sensors. 9. Temperature sensors. 10. Oxygen content sensors 2. Each time that the unit is not operating, confirm that the meters read zero. Conduct a calibration check at least annually; conduct calibration checks following any period of more than 24 hours throughout which the meter reading exceeds the manufacturer’s specified maximum operating range; at least monthly, inspect all components of the continuous parameter monitoring system for integrity and all electrical connections for continuity; record the results of each calibration check and inspection. Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure and minimizes or eliminates pulsating pressure, vibration, and internal and external corrosion. Use a gauge with an accuracy of at least ±5 percent over the normal operating range or 0.12 kilopascals (0.5 inches of water column), whichever is greater. Review pressure sensor readings at least once a week for straightline (unchanging) pressure and perform corrective action to ensure proper pressure sensor operation if blockage is indicated; using an instrument recommended by the sensor’s manufacturer, check gauge calibration and transducer calibration annually; conduct calibration checks following any period of more than 24 hours throughout which the pressure exceeded the manufacturer’s specified maximum rated pressure or install a new pressure sensor; at least quarterly, inspect all components for integrity, all electrical connections for continuity, and all mechanical connections for leakage, unless the CPMS has a redundant pressure sensor; record the results of each calibration check and inspection. Locate the flow sensor(s) and other necessary equipment (such as straightening vanes) in a position that provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances. If you elect to comply with Option 3 (Ni lb/hr) or Option 4 (Ni lb/1,000 lb of coke burn-off) for the HAP metal emission limitations in § 63.1564, install the continuous parameter monitoring system for gas flow rate as close as practical to the continuous opacity monitoring system; and if you don’t use a continuous opacity monitoring system, install the continuous parameter monitoring system for gas flow rate as close as practical to the control device. Use a flow rate sensor with an accuracy of at least ±5 percent over the normal range of flow measured, or 1.9 liter per minute (0.5 gallons per minute), whichever is greater, for liquid flow. Use a flow rate sensor with an accuracy of at least ±5 percent over the normal range of flow measured, or 280 liters per minute (10 cubic feet per minute), whichever is greater, for gas flow. Conduct a flow sensor calibration check at least biennially (every two years); conduct a calibration check following any period of more than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow rate or install a new flow sensor; at least quarterly, inspect all components for leakage, unless the CPMS has a redundant flow sensor; record the results of each calibration check and inspection. Locate the temperature sensor in the combustion zone, or in the ductwork immediately downstream of the combustion zone before any substantial heat exchange occurs or in the ductwork immediately downstream of the regenerator; locate the temperature sensor in a position that provides a representative temperature; shield the temperature sensor system from electromagnetic interference and chemical contaminants. Use a temperature sensor with an accuracy of at least ±1 percent over the normal range of temperature measured, expressed in degrees Celsius (C), or 2.8 degrees C, whichever is greater. Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours throughout which the temperature exceeded the manufacturer’s specified maximum rated temperature or install a new temperature sensor; at least quarterly, inspect all components for integrity and all electrical connections for continuity, oxidation, and galvanic corrosion, unless the CPMS has a redundant temperature sensor; record the results of each calibration check and inspection. Locate the oxygen sensor so that it provides a representative measurement of the oxygen content of the exit gas stream; ensure the sample is properly mixed and representative of the gas to be measured. Use an oxygen sensor with an accuracy of at least ±1 percent of the range of the sensor or to a nominal gas concentration of ±0.5 percent, whichever is greater. Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours throughout which the sensor reading exceeds the manufacturer’s specified maximum operating range or install a new oxygen sensor; at least quarterly, inspect all components for integrity and all electrical connections for continuity; record the results of each calibration and inspection. 1 Not applicable to non-venturi wet scrubbers of the jet-ejector design. does not replace the requirements for oxygen monitors that are required to use continuous emissions monitoring systems. The requirements in this table apply to oxygen sensors that are continuous parameter monitors, such as those that monitor combustion zone oxygen concentration and regenerator exit oxygen concentration. 2 This 86. Table 43 to subpart UUU is revised to read as follows: tkelley on DSK3SPTVN1PROD with RULES2 ■ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 As stated in § 63.1575(a), you shall meet each requirement in the following table that applies to you. PO 00000 Frm 00143 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75320 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 43 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR REPORTS You must submit . . . The report must contain . . . You shall submit the report . . . 1. A compliance report .................... If there are no deviations from any emission limitation or work practice standard that applies to you, a statement that there were no deviations from the standards during the reporting period and that no continuous opacity monitoring system or continuous emission monitoring system was inoperative, inactive, out-of-control, repaired, or adjusted; if you have a deviation from any emission limitation or work practice standard during the reporting period, the report must contain the information in § 63.1575(c) through (e). On and after January 30, 2019, the information specified in § 63.1575(k)(1). Semiannually according to the requirements in § 63.1575(b). 2. Performance test and CEMS performance evaluation data. 87. Table 44 to subpart UUU of part 63 is revised to read as follows: ■ Within 60 days after the date of completing each test according to the requirements in § 63.1575(k). As stated in § 63.1577, you shall meet each requirement in the following table that applies to you. TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU Citation Subject Applies to subpart UUU § 63.1(a)(1)–(4) ..................................... § 63.1(a)(5) ............................................ § 63.1(a)(6) ............................................ General Applicability ........................... [Reserved] .......................................... ............................................................. Yes ............................. Not applicable ............ Yes ............................. § 63.1(a)(7)–(9) ..................................... § 63.1(a)(10)–(12) ................................. [Reserved] .......................................... ............................................................. Not applicable ............ Yes ............................. § 63.1(b)(1) ............................................ Yes ............................. § 63.1(c)(2) ............................................ Initial Applicability Determination for this part. [Reserved] .......................................... ............................................................. Applicability of this part after a Relevant Standard has been set under this part. ............................................................. No ............................... § 63.1(c)(3)–(4) ..................................... § 63.1(c)(5) ............................................ § 63.1(d) ................................................ § 63.1(e) ................................................ § 63.2 .................................................... [Reserved] .......................................... ............................................................. [Reserved] .......................................... Applicability of Permit Program .......... Definitions ........................................... Not applicable ............ Yes ............................. Not applicable ............ Yes ............................. Yes ............................. § 63.3 .................................................... § 63.4(a)(1)–(2) ..................................... § 63.4(a)(3)–(5) ..................................... § 63.4(b)–(c) .......................................... § 63.5(a) ................................................ § 63.5(b)(1) ............................................ § 63.5(b)(2) ............................................ § 63.5(b)(3)–(4) ..................................... Units and Abbreviations ..................... Prohibited Activities ............................ [Reserved] .......................................... Circumvention and Fragmentation ..... Construction and Reconstruction ....... ............................................................. [Reserved] .......................................... ............................................................. Yes ............................. Yes ............................. Not applicable ............ Yes ............................. Yes ............................. Yes ............................. Not applicable ............ Yes ............................. § 63.5(b)(5) ............................................ § 63.5(b)(6) ............................................ § 63.5(c) ................................................ § 63.5(d)(1)(i) ........................................ [Reserved] .......................................... ............................................................. [Reserved] .......................................... Application for Approval of Construction or Reconstruction—General Application Requirements. Not applicable ............ Yes ............................. Not applicable ............ Yes ............................. tkelley on DSK3SPTVN1PROD with RULES2 § 63.1(b)(2) ............................................ § 63.1(b)(3) ............................................ § 63.1(c)(1) ............................................ VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00144 Fmt 4701 Explanation Except the correct mail drop (MD) number is C404–04. Except that this subpart specifies calendar or operating day. Not applicable ............ Yes ............................. Yes ............................. Sfmt 4700 E:\FR\FM\01DER2.SGM Area sources are not subject to this subpart. § 63.1579 specifies that if the same term is defined in subparts A and UUU of this part, it shall have the meaning given in this subpart. In § 63.5(b)(4), replace the reference to § 63.9(b) with § 63.9(b)(4) and (5). Except this subpart specifies the application is submitted as soon as practicable before startup but not later than 90 days after the promulgation date if construction or reconstruction had commenced and initial startup had not occurred before promulgation. 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75321 TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— Continued Citation Subject Applies to subpart UUU Explanation § 63.5(d)(1)(ii) ........................................ ............................................................. Yes ............................. § 63.5(d)(1)(iii) ....................................... ............................................................. No ............................... Except that emission estimates specified in § 63.5(d)(1)(ii)(H) are not required, and § 63.5(d)(1)(ii)(G) and (I) are Reserved and do not apply. This subpart specifies submission of notification of compliance status. § 63.5(d)(2) ............................................ § 63.5(d)(3) ............................................ § 63.5(d)(4) ............................................ § 63.5(e) ................................................ ............................................................. ............................................................. ............................................................. Approval of Construction or Reconstruction. Approval of Construction or Reconstruction Based on State Review. ............................................................. Yes Yes Yes Yes Compliance with Standards and Maintenance—Applicability. Compliance Dates for New and Reconstructed Sources. ............................................................. Yes ............................. [Reserved] .......................................... Compliance Dates for New and Reconstructed Area Sources That Become Major. Compliance Dates for Existing Sources. Not applicable ............ Yes ............................. [Reserved] .......................................... Compliance Dates for Existing Area Sources That Become Major. [Reserved] .......................................... General Duty to Minimize Emissions Not applicable ............ Yes ............................. Requirement to Correct Malfunctions as Soon as Possible. Compliance with Standards and Maintenance Requirements. [Reserved] .......................................... Startup, Shutdown, and Malfunction Plan Requirements. [Reserved] .......................................... ............................................................. SSM Exemption .................................. Compliance with Standards and Maintenance Requirements. ............................................................. ............................................................. ............................................................. No ............................... § 63.5(f)(1) ............................................. § 63.5(f)(2) ............................................. § 63.6(a) ................................................ § 63.6(b)(1)–(4) ..................................... § 63.6(b)(5) ............................................ § 63.6(b)(6) ............................................ § 63.6(b)(7) ............................................ § 63.6(c)(1)–(2) ..................................... § 63.6(c)(3)–(4) ..................................... § 63.6(c)(5) ............................................ § 63.6(d) ................................................ § 63.6(e)(1)(i) ........................................ § 63.6(e)(1)(ii) ........................................ § 63.6(e)(1)(iii) ....................................... § 63.6(e)(2) ............................................ § 63.6(e)(3)(i) ........................................ § 63.6(e)(3)(ii) ........................................ § 63.6(e)(3)(iii)–(ix) ................................ § 63.6(f)(1) ............................................. § 63.6(f)(2)(i)–(iii)(C) .............................. § 63.6(f)(2)(iii)(D) ................................... § 63.6(f)(2)(iv)–(v) ................................. § 63.6(f)(3) ............................................. § 63.6(g) ................................................ § 63.6(h)(1) ............................................ tkelley on DSK3SPTVN1PROD with RULES2 § 63.6(h)(2)(i) ........................................ § 63.6(h)(2)(ii) ........................................ § 63.6(h)(2)(iii) ....................................... § 63.6(h)(3) ............................................ § 63.6(h)(4) ............................................ § 63.6(h)(5) ............................................ § 63.6(h)(6) ............................................ § 63.6(h)(7)(i) ........................................ § 63.6(h)(7)(ii) ........................................ VerDate Sep<11>2014 23:11 Nov 30, 2015 Alternative Standard ........................... SSM Exemption for Opacity/VE Standards. Determining Compliance with Opacity/VE Standards. [Reserved] .......................................... ............................................................. [Reserved] .......................................... Notification of Opacity/VE Observation Date. Conducting Opacity/VE Observations Records of Conditions During Opacity/VE Observations. Report COM Monitoring Data from Performance Test. Using COM Instead of Method 9 ....... Jkt 238001 PO 00000 Frm 00145 Fmt 4701 ............................. ............................. ............................. ............................. Yes ............................. Yes ............................. Except that the cross-reference to § 63.9(b)(2) does not apply. Yes ............................. Yes ............................. Yes ............................. Not applicable ............ No ............................... Except that this subpart specifies different compliance dates for sources. Except that this subpart specifies different compliance dates for sources subject to Tier II gasoline sulfur control requirements. See § 63.1570(c) for general duty requirement. Yes ............................. Not Applicable ............ No ............................... Not applicable ............ No ............................... No ............................... Yes ............................. Yes ............................. Yes ............................. Yes ............................. Except the cross-references to § 63.6(f)(1) and (e)(1)(i) are changed to § 63.1570(c). Yes ............................. No ............................... No ............................... Not applicable ............ Yes ............................. Not applicable ............ Yes ............................. No ............................... Yes ............................. This subpart specifies methods. Applies to Method 22 (40 CFR part 60, appendix A–7) tests. Applies to Method 22 (40 CFR part 60, appendix A–7) observations. Yes ............................. No ............................... Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75322 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— Continued Citation Subject Applies to subpart UUU § 63.6(h)(7)(iii) ....................................... Averaging Time for COM during Performance Test. COM Requirements ............................ COMS Results and Visual Observations. Determining Compliance with Opacity/VE Standards. Adjusted Opacity Standard ................ Extension of Compliance ................... Yes ............................. § 63.6(h)(7)(iv) ....................................... § 63.6(h)(7)(v) ....................................... § 63.6(h)(8) ............................................ § 63.6(h)(9) ............................................ § 63.6(i)(1)–(14) .................................... Yes ............................. Yes ............................. Yes ............................. Yes ............................. Yes ............................. § 63.6(i)(15) ........................................... § 63.6(i)(16) ........................................... § 63.6(j) ................................................. § 63.7(a)(1) ............................................ [Reserved] .......................................... ............................................................. Presidential Compliance Exemption .. Performance Test Requirements Applicability. Not applicable ............ Yes ............................. Yes ............................. Yes ............................. § 63.7(a)(2) ............................................ Performance Test Dates .................... Yes ............................. § 63.7(a)(3) ............................................ § 63.7(a)(4) ............................................ § 63.7(b) ................................................ Section 114 Authority ......................... Force Majeure .................................... Notifications ........................................ Yes ............................. Yes ............................. Yes ............................. § 63.7(c) ................................................ Quality Assurance Program/Site-Specific Test Plan. Yes ............................. § 63.7(d) ................................................ § 63.7(e)(1) ............................................ § 63.7(e)(2)–(4) ..................................... § 63.7(f) ................................................. § 63.7(g) ................................................ Performance Test Facilities ................ Performance Testing .......................... Conduct of Tests ................................ Alternative Test Method ..................... Data Analysis, Recordkeeping, Reporting. Yes ............................. No ............................... Yes ............................. Yes ............................. Yes ............................. § 63.7(h) ................................................ § 63.8(a)(1) ............................................ § 63.8(a)(2) ............................................ § 63.8(a)(3) ............................................ § 63.8(a)(4) ............................................ Waiver of Tests .................................. Monitoring Requirements-Applicability Performance Specifications ................ [Reserved] .......................................... Monitoring with Flares ........................ Yes ............................. Yes ............................. Yes ............................. Not applicable ............ Yes ............................. § 63.8(b)(1) ............................................ § 63.8(b)(2)–(3) ..................................... Conduct of Monitoring ........................ Multiple Effluents and Multiple Monitoring Systems. Monitoring System Operation and Maintenance. General Duty to Minimize Emissions and CMS Operation. Keep Necessary Parts for CMS ......... Requirement to Develop SSM Plan for CMS. Yes ............................. Yes ............................. § 63.8(c)(1) ............................................ tkelley on DSK3SPTVN1PROD with RULES2 § 63.8(c)(1)(i) ......................................... § 63.8(c)(1)(ii) ........................................ § 63.8(c)(1)(iii) ....................................... VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00146 Fmt 4701 Explanation Extension of compliance under § 63.6(i)(4) not applicable to a facility that installs catalytic cracking feed hydrotreating and receives an extended compliance date under § 63.1563(c). Except that this subpart specifies the applicable test and demonstration procedures. Except test results must be submitted in the Notification of Compliance Status report due 150 days after the compliance date. Except that this subpart specifies notification at least 30 days prior to the scheduled test date rather than 60 days. Except that when this subpart specifies to use 40 CFR part 60, appendix F, out of control periods are to be defined as specified in part 60, appendix F. See § 63.1571(b)(1). Except performance test reports must be submitted with notification of compliance status due 150 days after the compliance date, and § 63.7(g)(2) is reserved and does not apply. Except that for a flare complying with § 63.670, the cross-reference to § 63.11 in this paragraph does not include § 63.11(b). This subpart specifies the required monitoring locations. Yes ............................. No ............................... See § 63.1570(c). Yes ............................. No ............................... Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75323 TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— Continued Citation Subject Applies to subpart UUU Explanation § 63.8(c)(2)–(3) ..................................... Monitoring System Installation ........... Yes ............................. Except that this subpart specifies that for continuous parameter monitoring systems, operational status verification includes completion of manufacturer written specifications or installation, operation, and calibration of the system or other written procedures that provide adequate assurance that the equipment will monitor accurately. § 63.8(c)(4) ............................................ Yes ............................. § 63.8(c)(5) ............................................ § 63.8(c)(6) ............................................ § 63.8(c)(7)–(8) ..................................... § 63.8(d)(1)–(2) ..................................... § 63.8(d)(3) ............................................ § 63.8(e) ................................................ Continuous Monitoring System Requirements. COMS Minimum Procedures .............. CMS Requirements ............................ CMS Requirements ............................ Quality Control Program for CMS ...... Written Procedures for CMS .............. CMS Performance Evaluation ............ Yes ............................. Yes ............................. Yes ............................. Yes ............................. No ............................... Yes ............................. § 63.8(f)(1)–(5) ...................................... Alternative Monitoring Methods .......... Yes ............................. § 63.8(f)(6) ............................................. Alternative to Relative Accuracy Test Yes ............................. § 63.8(g)(1)–(4) ..................................... Reduction of Monitoring Data ............ Yes ............................. § 63.8(g)(5) ............................................ § 63.9(a) ................................................ Data Reduction ................................... Notification Requirements—Applicability. No ............................... Yes ............................. § 63.9(b)(1)–(2) ..................................... Initial Notifications .............................. Yes ............................. § 63.9(b)(3) ............................................ § 63.9(b)(4)–(5) ..................................... [Reserved] .......................................... Initial Notification Information ............. Not applicable ............ Yes ............................. § 63.9(c) ................................................ § 63.9(d) ................................................ Request for Extension of Compliance New Source Notification for Special Compliance Requirements. Notification of Performance Test ........ Yes ............................. Yes ............................. § 63.9(e) ................................................ § 63.9(f) ................................................. § 63.9(g) ................................................ tkelley on DSK3SPTVN1PROD with RULES2 § 63.9(h) ................................................ § 63.9(i) ................................................. § 63.9(j) ................................................. 63.10(a) ................................................. § 63.10(b)(1) .......................................... VerDate Sep<11>2014 23:11 Nov 30, 2015 Yes ............................. Notification of VE/Opacity Test .......... Additional Notification Requirements for Sources with Continuous Monitoring Systems. Notification of Compliance Status ...... Except § 63.9(b)(4)(ii)–(iv), which are reserved and do not apply. Except that notification is required at least 30 days before test. Yes ............................. Yes ............................. Adjustment of Deadlines .................... Change in Previous Information ......... Recordkeeping and Reporting Applicability. General Recordkeeping Requirements. Except that results are to be submitted as part of the Notification Compliance Status due 150 days after the compliance date. Except that this subpart specifies procedures for requesting alternative monitoring systems and alternative parameters. Applicable to continuous emission monitoring systems if performance specification requires a relative accuracy test audit. Applies to continuous opacity monitoring system or continuous emission monitoring system. This subpart specifies requirements. Duplicate Notification of Compliance Status report to the Regional Administrator may be required. Except that notification of construction or reconstruction is to be submitted as soon as practicable before startup but no later than 30 days after the effective date if construction or reconstruction had commenced but startup had not occurred before the effective date. Yes ............................. Yes ............................. Yes ............................. Jkt 238001 PO 00000 Frm 00147 Fmt 4701 Yes ............................. Except that this subpart specifies the notification is due no later than 150 days after compliance date, and except that the reference to § 63.5(d)(1)(ii)(H) in § 63.9(h)(5) does not apply. Yes ............................. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 75324 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— Continued Citation Subject Applies to subpart UUU § 63.10(b)(2)(i) ...................................... Recordkeeping of Occurrence and Duration of Startups and Shutdowns. Recordkeeping of Malfunctions .......... No ............................... § 63.10(b)(2)(ii) ...................................... § 63.10(b)(2)(iii) ..................................... § 63.10(b)(2)(iv)–(v) .............................. § 63.10(b)(2)(vi) ..................................... § 63.10(b)(2)(vii)–(xiv) ........................... § 63.10(b)(3) .......................................... § 63.10(c)(1)–(6) ................................... § 63.10(c)(7)–(8) ................................... § 63.10(c)(9) .......................................... § 63.10(c)(10) ........................................ § 63.10(c)(11) ........................................ § 63.10(c)(12)–(14) ............................... Maintenance Records ........................ Actions Taken to Minimize Emissions During SSM. Recordkeeping for CMS Malfunctions Other CMS Requirements .................. Recordkeeping for Applicability Determinations.. Additional Records for Continuous Monitoring Systems. Additional Recordkeeping Requirements for CMS—Identifying Exceedances and Excess Emissions. [Reserved] .......................................... Recording Nature and Cause of Malfunctions. Recording Corrective Actions ............. No ............................... Yes ............................. Yes ............................. Yes ............................. Yes ............................. Not applicable ............ No ............................... No ............................... No ............................... Yes ............................. No ............................... § 63.10(d)(3) .......................................... § 63.10(d)(4) .......................................... § 63.10(d)(5) .......................................... Opacity or VE Observations ............... Progress Reports ............................... SSM Reports ...................................... Yes ............................. Yes ............................. No ............................... § 63.10(e)(1)–(2) ................................... Additional CMS Reports ..................... Yes ............................. § 63.10(e)(3) .......................................... Excess Emissions/CMS Performance Reports. COMS Data Reports .......................... Recordkeeping/Reporting Waiver ...... Control Device and Work Practice Requirements Applicability. Flares .................................................. No ............................... tkelley on DSK3SPTVN1PROD with RULES2 § 63.11(c)–(e) ........................................ § 63.12 § 63.13 § 63.14 § 63.15 .................................................. .................................................. .................................................. .................................................. § 63.16 .................................................. VerDate Sep<11>2014 23:11 Nov 30, 2015 Alternative Work Practice for Monitoring Equipment for Leaks. State Authority and Delegations ........ Addresses ........................................... Incorporation by Reference ................ Availability of Information and Confidentiality. Performance Track Provisions ........... Jkt 238001 PO 00000 Frm 00148 Fmt 4701 Except § 63.10(c)(2)–(4), which are Reserved and do not apply. Yes ............................. § 63.10(c)(15) ........................................ § 63.10(d)(1) .......................................... § 63.10(d)(2) .......................................... § 63.11(b) .............................................. See § 63.1576(a)(2) for recordkeeping of (1) date, time and duration; (2) listing of affected source or equipment, and an estimate of the volume of each regulated pollutant emitted over the standard; and (3) actions taken to minimize emissions and correct the failure. Yes ............................. No ............................... Additional CMS Recordkeeping Requirements. Use of SSM Plan ................................ General Reporting Requirements ...... Performance Test Results .................. § 63.10(e)(4) .......................................... § 63.10(f) ............................................... § 63.11(a) .............................................. Explanation See § 63.1576(a)(2) for malfunctions recordkeeping requirements. See § 63.1576(a)(2) for malfunctions recordkeeping requirements. Yes ............................. This subpart requires performance test results to be reported as part of the Notification of Compliance Status due 150 days after the compliance date. See § 63.1575(d) for CPMS malfunction reporting and § 63.1575(e) for COMS and CEMS malfunction reporting. Except that reports of performance evaluations must be submitted in Notification of Compliance Status. This subpart specifies the applicable requirements. Yes ............................. Yes ............................. Yes ............................. Yes ............................. Except that flares complying with § 63.670 are not subject to the requirements of § 63.11(b). Yes ............................. Yes Yes Yes Yes ............................. ............................. ............................. ............................. Yes ............................. Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 88. Appendix A to subpart UUU of part 63 is amended by revising the first sentence of section 2.1 and section 7.1.3 to read as follows: ■ Appendix A to Subpart UUU of Part 63—Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure) * * * * * 2.1 A representative sample of catalyst particles is collected, prepared, and analyzed for analyte concentration using either energy or wavelength dispersive X-ray fluorescent (XRF) spectrometry instrumental analyzers. * * * * * * * * 7.1.3 Low-Range Calibration Standard. Concentration equivalent to 1 to 20 percent of the span. The concentration of the lowrange calibration standard should be selected so that it is less than either one-fourth of the applicable concentration limit or of the lowest concentration anticipated in the catalyst samples. * * * * * 89. Appendix A to part 63 is amended by adding Method 325A and Method 325B in numerical order to read as follows: ■ Appendix A to Part 63—Test Methods Pollutant Measurement Methods From Various Waste Media * * * * * tkelley on DSK3SPTVN1PROD with RULES2 Method 325A—Volatile Organic Compounds from Fugitive and Area Sources: Sampler Deployment and VOC Sample Collection 1.0 Scope and Application 1.1 This method describes collection of volatile organic compounds (VOCs) at or inside a facility property boundary or from fugitive and area emission sources using passive (diffusive) tube samplers (PS). The concentration of airborne VOCs at or near these potential fugitive- or area-emission sources may be determined using this method in combination with Method 325B. Companion Method 325B (Sampler Preparation and Analysis) describes preparation of sampling tubes, shipment and storage of exposed sampling tubes, and analysis of sampling tubes collected using either this passive sampling procedure or alternative active (pumped) sampling methods. 1.2 This method may be used to determine the average concentration of the select VOCs using the corresponding uptake rates listed in Method 325B, Table 12.1. Additional compounds or alternative sorbents must be evaluated as described in Addendum A of Method 325B or by one of the following national/international standard methods: ISO 16017–2:2003(E), ASTM D6196–03 (Reapproved 2009), or BS EN 14662–4:2005 (all incorporated by reference—see § 63.14), or reported in the peer-reviewed open literature. 1.3 Methods 325A and 325B are valid for the measurement of benzene. Supporting VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 literature (References 1–8) indicates that benzene can be measured by flame ionization detection or mass spectrometry over a concentration range of approximately 0.5 micrograms per cubic meter (mg/m3) to at least 500 mg/m3 when industry standard (3.5 inch long × 0.25 inch outside diameter (o.d.) × 5 mm inner diameter (i.d.)) inert-coated stainless steel sorbent tubes packed with CarbographTM 1 TD, CarbopackTM B, or CarbopackTM X or equivalent are used and when samples are accumulated over a period of 14 days. 1.4 This method may be applied to screening average airborne VOC concentrations at facility property boundaries or monitoring perimeters over an extended period of time using multiple sampling periods (e.g., 26 × 14-day sampling periods). The duration of each sampling period is normally 14 days. 1.5 This method requires the collection of local meteorological data (wind speed and direction, temperature, and barometric pressure). Although local meteorology is a component of this method, non-regulatory applications of this method may use regional meteorological data. Such applications risk that the results may not identify the precise source of the emissions. 2.0 Summary of the Method 2.1 Principle of the Method The diffusive passive sampler collects VOC from air for a measured time period at a rate that is proportional to the concentration of vapor in the air at that location. 2.1.1 This method describes the deployment of prepared passive samplers, including determination of the number of passive samplers needed for each survey and placement of samplers along or inside the facility property boundary depending on the size and shape of the site or linear length of the boundary. 2.1.2 The rate of sampling is specific to each compound and depends on the diffusion constants of that VOC and the sampler dimensions/characteristics as determined by prior calibration in a standard atmosphere (Reference 1). 2.1.3 The gaseous VOC target compounds migrate through a constant diffusion barrier (e.g., an air gap of fixed dimensions) at the sampling end of the diffusion sampling tube and adsorb onto the sorbent. 2.1.4 Heat and a flow of inert carrier gas are then used to extract (desorb) the retained VOCs back from the sampling end of the tube and transport/transfer them to a gas chromatograph (GC) equipped with a chromatographic column to separate the VOCs and a detector to determine the quantity of target VOCs. 2.1.5 Gaseous or liquid calibration standards loaded onto the sampling ends of clean sorbent tubes must be used to calibrate the analytical equipment. 2.1.6 This method requires the use of field blanks to ensure sample integrity associated with shipment, collection, and storage of the passive samples. It also requires the use of field duplicates to validate the sampling process. 2.1.7 At the end of each sampling period, the passive samples are collected, sealed, and PO 00000 Frm 00149 Fmt 4701 Sfmt 4700 75325 shipped to a laboratory for analysis of target VOCs by thermal desorption gas chromatography, as described in Method 325B. 2.2 Application of Diffusive Sampling 2.2.1 This method requires deployment of passive sampling tubes on a monitoring perimeter encompassing all known emission sources at a facility and collection of local meteorological data. It may be used to determine average concentration of VOC at a facility’s ‘‘fenceline’’ using time integrated passive sampling (Reference 2). 2.2.2 Collecting samples and meteorological data at progressively higher frequencies may be employed to resolve shorter term concentration fluctuations and wind conditions that could introduce interfering emissions from other sources. 2.2.3 This passive sampling method provides a low cost approach to screening of fugitive or area emissions compared to active sampling methods that are based on pumped sorbent tubes or time weighted average canister sampling. 2.2.3.1 Additional passive sampling tubes may be deployed at different distances from the facility property boundary or from the geometric center of the fugitive emission source. 2.2.3.2 Additional meteorological measurements may also be collected as needed to perform preliminary gradientbased assessment of the extent of the pollution plume at ground level and the effect of ‘‘background’’ sources contributing to airborne VOC concentrations at the location. 2.2.4 Time-resolved concentration measurements coupled with time-resolved meteorological monitoring may be used to generate data needed for source apportionment procedures and mass flux calculations. 3.0 Definitions (See also Section 3.0 of Method 325B.) 3.1 Fenceline means the property boundary of a facility or internal monitoring perimeter established in accordance with the requirements in Section 8.2 of this method. 3.2 Passive sampler (PS) means a specific type of sorbent tube (defined in this method) that has a fixed dimension air (diffusion) gap at the sampling end and is sealed at the other end. 3.3 Passive sampling refers to the activity of quantitatively collecting VOC on sorbent tubes using the process of diffusion. 3.4 PSi is the annual average for all PS concentration results from location i. 3.5 PSi3 is the set of annual average concentration results for PSi and two sorbent tubes nearest to the PS location i. 3.6 PSip is the concentration from the sorbent tube at location i for the test period or episode p. 3.7 Sampling period is the length of time each passive sampler is exposed during field monitoring. The sampling period for this method is 14 days. 3.8 Sorbent tube (Also referred to as tube, PS tube, adsorbent tube, and sampling tube) is an inert coated stainless steel tube. Standard PS tube dimensions for this method E:\FR\FM\01DER2.SGM 01DER2 75326 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations are 3.5-inch (89 mm) long × 0.25-inch (6.4 mm) o.d. with an i.d. of 5 mm, a crosssectional area of 19.6 mm2 and an air gap of 15 mm. The central portion of the tube is packed with solid adsorbent material contained between 2 × 100-mesh stainless steel gauzes and terminated with a diffusion cap at the sampling end of the tube. These axial passive samplers are installed under a protective hood during field deployment. Note: Glass and glass- (or fused silica-) lined stainless steel sorbent tubes (typically 4 mm i.d.) are also available in various lengths to suit different makes of thermal desorption equipment, but these are rarely used for passive sampling because it is more difficult to adequately define the diffusive air gap in glass or glass-line tubing. Such tubes are not recommended for this method. 4.0 Sampling Interferences 4.1 General Interferences Passive tube samplers should be sited at a distance beyond the influence of possible obstructions such as trees, walls, or buildings at the monitoring site. Complex topography and physical site obstructions, such as bodies of water, hills, buildings, and other structures that may prevent access to a planned PS location must be taken into consideration. You must document and report siting interference with the results of this method. 4.2 Background Interference Nearby or upwind sources of target emissions outside the facility being tested can contribute to background concentrations. Moreover, because passive samplers measure continuously, changes in wind direction can cause variation in the level of background concentrations from interfering sources during the monitoring period. This is why local meteorological information, particularly wind direction and speed, is required to be collected throughout the monitoring period. Interfering sources can include neighboring industrial facilities, transportation facilities, fueling operations, combustion sources, short-term transient sources, residential sources, and nearby highways or roads. As PS data are evaluated, the location of potential interferences with respect to PS locations and local wind conditions should be considered, especially when high PS concentration values are observed. tkelley on DSK3SPTVN1PROD with RULES2 4.3 Tube Handling You must protect the PS tubes from gross external contamination during field VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 sampling. Analytical thermal desorption equipment used to analyze PS tubes must desorb organic compounds from the interior of PS tubes and exclude contamination from external sampler surfaces in the analytical/ sample flow path. If the analytical equipment does not comply with this requirement, you must wear clean, white, cotton or powderfree nitrile gloves to handle sampling tubes to prevent contamination of the external sampler surfaces. Sampling tubes must be capped with two-piece, brass, 0.25 inch, long-term storage caps fitted with combined polytetrafluoroethylene ferrules (see Section 6.1 and Method 325B) to prevent ingress of airborne contaminants outside the sampling period. When not being used for field monitoring, the capped tubes must be stored in a clean, air-tight, shipping container to prevent the collection of VOCs (see Section 6.4.2 of Method 325B). 4.4 Local Weather Conditions and Airborne Particulates Although air speeds are a constraint for many forms of passive samplers, axial tube PS devices have such a slow inherent uptake rate that they are largely immune to these effects (References 4,5). Passive samplers must nevertheless be deployed under nonemitting weatherproof hoods to moderate the effect of local weather conditions such as solar heating and rain. The cover must not impede the ingress of ambient air. Sampling tubes should also be orientated vertically and pointing downwards, to minimize accumulation of particulates. 4.5 Temperature The normal working range for field sampling for sorbent packing is 0–40 °C (References 6,7). Note that most published passive uptake rate data for sorbent tubes is quoted at 20 °C. Note also that, as a rough guide, an increase in temperature of 10 °C will reduce the collection capacity for a given analyte on a given sorbent packing by a factor of 2, but the uptake rate will not change significantly (Reference 4). 5.0 Safety This method does not purport to include all safety issues or procedures needed when deploying or collecting passive sampling tubes. Precautions typical of field air sampling projects are required. Tripping, falling, electrical, and weather safety considerations must all be included in plans to deploy and collect passive sampling tubes. PO 00000 Frm 00150 Fmt 4701 Sfmt 4700 6.0 Sampling Equipment and Supplies, and Pre-Deployment Planning This section describes the equipment and supplies needed to deploy passive sampling monitoring equipment at a facility property boundary. Details of the passive sampling tubes themselves and equipment required for subsequent analysis are described in Method 325B. 6.1 Passive Sampling Tubes The industry standard PS tubes used in this method must meet the specific configuration and preparation requirements described in Section 3.0 of this method and Section 6.1 of Method 325B. Note: The use of PS tubes packed with various sorbent materials for monitoring a wide variety of organic compounds in ambient air has been documented in the literature (References 4–10). Other sorbents may be used in standard passive sampling tubes for monitoring additional target compound(s) once their uptake rate and performance has been demonstrated following procedures in Addendum A to Method 325B. Guidance on sorbent selection can also be obtained from relevant national and international standard methods such as ASTM D6196–03 (Reapproved 2009) (Reference 14) and ISO 16017–2:2003(E) (Reference 13) (both incorporated by reference—see § 63.14). 6.2 Passive or Diffusive Sampling Cap One diffusive sampling cap is required per PS tube. The cap fits onto the sampling end of the tube during air monitoring. The other end of the tube remains sealed with the longterm storage cap. Each diffusive sampling cap is fitted with a stainless steel gauze, which defines the outer limit of the diffusion air gap. 6.3 Sorbent Tube Protection Cover A simple weatherproof hood, suitable for protecting passive sampling tubes from the worst of the weather (see Section 4.4) consists of an inverted cone/funnel constructed of an inert, non-outgassing material that fits over the diffusive tube, with the open (sampling) end of the tube projecting just below the cone opening. An example is shown in Figure 6.1 (Adapted from Reference 13). E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Thermal Desorption Apparatus If the analytical thermal desorber that will subsequently be used to analyze the passive sampling tubes does not meet the requirement to exclude outer surface contaminants from the sample flow path (see Section 6.6 of Method 325B), then clean, white, cotton or powder-free nitrile gloves must be used for handling the passive sampling tubes during field deployment. 6.5 Sorbent Selection Sorbent tube configurations, sorbents or other VOC not listed in this method must be evaluated according to Method 325B, Addendum A or ISO 16017–2:2003(E) (Reference 13) (incorporated by reference— see § 63.14). The supporting evaluation and verification data described in Method 325B, Addendum A for configurations or compounds different from the ones described in this method must meet the performance requirements of Method 325A/B and must be submitted with the test plan for your measurement program. 7.0 Reagents and Standards No reagents or standards are needed for the field deployment and collection of passive sampling tubes. Specifications for sorbents, gas and liquid phase standards, preloaded standard tubes, and carrier gases are covered in Section 7 of Method 325B. tkelley on DSK3SPTVN1PROD with RULES2 8.0 Sample Deployment, Recovery, and Storage Pre-deployment and planning steps are required before field deployment of passive sampling tubes. These activities include but are not limited to conducting a site visit, determining suitable and required monitoring locations, and determining the monitoring frequency to be used. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 8.1 Conducting the Site Visit 8.1.1 Determine the size and shape of the facility footprint in order to determine the required number of monitoring locations. 8.1.2 Identify obstacles or obstructions (buildings, roads, fences), hills and other terrain issues (e.g., bodies of water or swamp land) that could interfere with air parcel flow to the sampler or that prevent reasonable access to the location. You may use the general guidance in Section 4.1 of this method during the site visit to identify sampling locations. You must evaluate the placement of each passive sampler to determine if the conditions in this section are met. 8.1.3 Identify to the extent possible and record potential off-site source interferences (e.g., neighboring industrial facilities, transportation facilities, fueling operations, combustion sources, short-term transient sources, residential sources, nearby highways). 8.1.4 Identify the closest available meteorological station. Identify potential locations for one or more on-site or near-site meteorological station(s) following the guidance in EPA–454/B–08–002 (Reference 11) (incorporated by reference—see § 63.14). 8.2 Determining Sampling Locations (References 2, 3) 8.2.1 The number and placement of the passive samplers depends on the size, the shape of the facility footprint or the linear distance around the facility, and the proximity of emission sources near the property boundaries. Aerial photographs or site maps may be used to determine the size (acreage) and shape of the facility or the length of the monitoring perimeter. Place passive samplers on an internal monitoring perimeter on or inside the facility boundary encompassing all emission sources at the facility at different angles circling the PO 00000 Frm 00151 Fmt 4701 Sfmt 4700 geometric center of the facility or at different distances based on the monitoring perimeter length of the facility. Note: In some instances, permanent air monitoring stations may already be located in close proximity to the facility. These stations may be operated and maintained by the site, or local or state regulatory agencies. If access to the station is possible, a PS may be deployed adjacent to other air monitoring instrumentation. A comparison of the pollutant concentrations measured with the PS to concentrations measured by site instrumentation may be used as an optional data quality indicator to assess the accuracy of PS results. 8.2.1.1 The monitoring perimeter may be located between the property boundary and any potential emission source near the property boundary, as long as the distance from the source to the monitoring perimeter is at least 50 meters (162 feet). If a potential emissions source is within 50 meters (162 feet) of the property boundary, the property boundary shall be used as the monitoring perimeter near that source. 8.2.1.2 Samplers need only be placed around the monitoring perimeter and not along internal roads or other right of ways that may bisect the facility. 8.2.1.3 Extra samplers must be placed near known sources of VOCs if the potential emission source is within 50 meters (162 feet) of the boundary and the source location is between two monitors. Measure the distance (x) between the two monitors and place another monitor halfway between (x/2) the two monitors. For example, in Figure 8.1, the facility added three additional monitors (i.e., light shaded sampler locations) and in Figure 8.2, the facility added two additional monitors to provide sufficient coverage of all area sources. BILLING CODE 6560–50–P E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.025</GPH> 6.4 75327 75328 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations ~ 0 :!:: c 0 E ro c 0 :-e "'0 "'0 <( Refinery (20% Angle) Note: Shaded sources are within 50 meters of the property boundary and are located between two monitors. Additional coverage required by this method was accomplished by placing the monitors halfway between two existing monitors. Figure 8.1. Facility with a Regular Shape Between 750 and 1,500 Acres in Area (f) (f) (f) (f) (f) Refinery (24,000 Feet Perimeter) Figure 8.2. Facility with a Boundary Length of 24,000 feet 8.2.2 Option 1 for Determining Sampling Locations. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 8.2.2.1 For facilities with a regular (circular, triangular, rectangular, or square) PO 00000 Frm 00152 Fmt 4701 Sfmt 4700 shape, determine the geographic center of the facility. E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.026</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Note: Shaded sources are within 50 meters of the property boundary and are located between two monitors. Additional coverqe required by this method was accomplished by placing the monitors halfway between two existing monitors. Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75329 determine sampling locations. The subareas must be defined such that a circle can reasonably encompass the subarea. Then determine the geometric center point of each of the subareas. 8.2.2.2.1 If a subarea is less than or equal to 750 acres (e.g., Figure 8.3), measure angles of 30 degrees from the center point for a total of twelve 30 degree measurements (±1 degree). center for a total of twenty-four 15 degree measurements (±1 degree). 8.2.2.2.4 Locate each sampling point where the measured angle intersects the outer monitoring perimeter. Sampling points need not be placed closer than 152 meters (500 feet) apart (or 76 meters (250 feet) if known sources are within 50 meters (162 feet) of the monitoring perimeter), as long as a minimum of 3 monitoring locations are used for each subarea. 8.2.2.2.5 Sampling sites are not needed at the intersection of an inner boundary with an adjacent subarea. The sampling location must be sited where the measured angle intersects the subarea’s outer monitoring perimeter. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00153 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.027</GPH> acres. Monitor placements are represented with black dots along the property boundary. 8.2.2.1.3 For facilities covering an area greater than 1,500 acres, measure angles of 15 degrees from the center point for a total of twenty-four 15 degree measurements evenly spaced (±1 degree). 8.2.2.1.4 Locate each sampling point where the measured angle intersects the outer monitoring perimeter. 8.2.2.2 For irregularly shaped facilities, divide the area into a set of connecting subarea circles, triangles or rectangles to 8.2.2.2.2 If a subarea is greater than 750 acres but less than or equal to 1,500 acres (e.g., Figure 8.4), measure angles of 20 degrees from the center point for a total of eighteen 20 degree measurements (±1 degree). 8.2.2.2.3 If a subarea is greater than 1,500 acres, measure angles of 15 degrees from the tkelley on DSK3SPTVN1PROD with RULES2 8.2.2.1.1 For facilities with an area of less than or equal to 750 acres, measure angles of 30 degrees from the center point for a total of twelve 30 degree measurements evenly spaced (±1 degree). 8.2.2.1.2 For facilities covering an area greater than 750 acres but less than or equal to 1,500 acres, measure angles of 20 degrees from the center point for a total of eighteen 20 degree measurements evenly spaced (±1 degree). Figure 8.1 shows the monitor placement around the property boundary of a facility with an area between 750 and 1,500 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations tkelley on DSK3SPTVN1PROD with RULES2 8.2.3 Option 2 for Determining Sampling Locations. 8.2.3.1 For facilities with a monitoring perimeter length of less than 7,315 meters (24,000 feet), a minimum of twelve sampling locations evenly spaced ±10 percent of the location interval is required. 8.2.3.2 For facilities with a monitoring perimeter length greater than 7,315 meters (24,000 feet), sampling locations are spaced 610 ±76 meters (2,000 ± 250 feet) apart. 8.3 Siting a Meteorological Station A meteorological station is required at or near the facility you are monitoring. A number of commercially available meteorological stations can be used. Information on meteorological instruments can be found in EPA–454/R–99–005 (Reference 11) (incorporated by reference— see § 63.14). Some important considerations for siting of meteorological stations are detailed below. 8.3.1 Place meteorological stations in locations that represent conditions affecting the transport and dispersion of pollutants in the area of interest. Complex terrain may require the use of more than one meteorological station. 8.3.2 Deploy wind instruments over level, open terrain at a height of 10 meters (33 feet). If possible, locate wind instruments at a distance away from nearby structures that is equal to at least 10 times the height of the structure. 8.3.3 Protect meteorological instruments from thermal radiation and adequately ventilate them using aspirated shields. The temperature sensor must be located at a distance away from any nearby structures that is equal to at least four times the height VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 of the structure. Temperature sensors must be located at least 30 meters (98 feet) from large paved areas. 8.3.4 Collect and record meteorological data, including wind speed, wind direction, temperature and barometric pressure on an hourly basis. Calculate average unit vector wind direction, sigma theta, temperature and barometric pressure per sampling period to enable calculation of concentrations at standard conditions. Supply this information to the laboratory. 8.3.5 Identify and record the location of the meteorological station by its GPS coordinate. 8.4 Monitoring Frequency 8.4.1 Sample collection may be performed for periods up to 14 days. 8.4.2 A site screening protocol that meets method requirements may be performed by collecting samples for a year where each PS accumulates VOC for a 14-day sampling period. Study results are accumulated for the sampling periods (typically 26) over the course of one calendar year. To the extent practical, sampling tubes should be changed at approximately the same time of day at each of the monitoring sites. 8.5 Passive Sampler Deployment 8.5.1 Clean (conditioned) sorbent tubes must be prepared and packaged by the laboratory as described in Method 325B and must be deployed for sampling within 30 days of conditioning. 8.5.2 Allow the tubes to equilibrate with ambient temperature (approximately 30 minutes to 1 hour) at the monitoring location before removing them from their storage/ shipping container for sample collection. PO 00000 Frm 00154 Fmt 4701 Sfmt 4700 8.5.3 If there is any risk that the analytical equipment will not meet the requirement to exclude contamination on outer tube surfaces from the sample flow path (see Section 6.6 of Method 325B), sample handlers must wear clean, white, cotton or powder-free nitrile gloves during PS deployment and collection and throughout any other tube handling operations. 8.5.4 Inspect the sampling tubes immediately prior to deployment. Ensure that they are intact, securely capped, and in good condition. Any suspect tubes (e.g., tubes that appear to have leaked sorbent) should be removed from the sampling set. 8.5.5 Secure passive samplers so the bottom of the diffusive sampling cap is 1.5 to 3 meters (4.9 to 9.8 feet) above ground using a pole or other secure structure at each sampling location. Orient the PS vertically and with the sampling end pointing downward to avoid ingress of particulates. Note: Duplicate sampling assemblies must be deployed in at least one monitoring location for every 10 monitoring locations during each field monitoring period. 8.5.6 Protect the PS from rain and excessive wind velocity by placing them under the type of protective hood described in Section 6.1.3 or equivalent. 8.5.7 Remove the storage cap on the sampling end of the tube and replace it with a diffusive sampling cap at the start of the sampling period. Make sure the diffusion cap is properly seated and store the removed storage caps in the empty tube shipping container. 8.5.8 Record the start time and location details for each sampler on the field sample data sheet (see example in Section 17.0.). E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.028</GPH> 75330 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 8.6 Sorbent Tube Recovery and Meteorological Data Collection Recover deployed sampling tubes and field blanks as follows: 8.6.1 After the sampling period is complete, immediately replace the diffusion end cap on each sampled tube with a longterm storage end cap. Tighten the seal securely by hand and then tighten an additional quarter turn with an appropriate tool. Record the stop date and time and any additional relevant information on the sample data sheet. 8.6.2 Place the sampled tubes, together with the field blanks, in the storage/shipping container. Label the storage container, but do not use paints, markers, or adhesive labels to identify the tubes. TD-compatible electronic (radio frequency identification (RFID)) tube labels are available commercially and are compatible with some brands of thermal desorber. If used, these may be programmed with relevant tube and sample information, which can be read and automatically transcribed into the sequence report by the TD system. Note: Sampled tubes must not be placed in the same shipping container as clean conditioned sampling tubes. 8.6.3 Sampled tubes may be shipped at ambient temperature to a laboratory for sample analysis. 8.6.4 Specify whether the tubes are field blanks or were used for sampling and document relevant information for each tube using a Chain of Custody form (see example in Section 17.0) that accompanies the samples from preparation of the tubes through receipt for analysis, including the tkelley on DSK3SPTVN1PROD with RULES2 Where: PSi = Annual average for location i. PSip = Sampling period specific concentration from Method 325B. i = Location of passive sampler (0 to 360°). p = The sampling period. N = The number of sampling periods in the year (e.g., for 14-day sampling periods, from 1 to 26). Note: PSip is a function of sampling location-specific factors such as the contribution from facility sources, unusual localized meteorological conditions, contribution from nearby interfering sources, the background caused by integrated far-field sources and measurement error due to VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 following information: Unique tube identification numbers for each sampled tube; the date, time, and location code for each PS placement; the date, time, and location code for each PS recovery; the GPS reference for each sampling location; the unique identification number of the duplicate sample (if applicable); and problems or anomalies encountered. 8.6.5 If the sorbent tubes are supplied with electronic (e.g., RFID) tags, it is also possible to allocate a sample identifier to each PS tube. In this case, the recommended format for the identification number of each sampled tube is AA–BB–CC–DD–VOC, where: AA = Sequence number of placement on route (01, 02, 03 . . .) BB = Sampling location code (01, 02, 03 . . .) CC = 14-day sample period number (01 to 26) DD = Sample code (SA = sample, DU = duplicate, FB = field blank) VOC = 3-letter code for target compound(s) (e.g., BNZ for benzene or BTX for benzene, toluene, and xylenes) Note: Sampling start and end times/dates can also be logged using RFID tube tags. 9.0 Quality Control 9.1 Most quality control checks are carried out by the laboratory and associated requirements are in Section 9.0 of Method 325B, including requirements for laboratory blanks, field blanks, and duplicate samples. 9.2 Evaluate for potential outliers the laboratory results for neighboring sampling tubes collected over the same time period. A potential outlier is a result for which one or more PS tube does not agree with the trend in results shown by neighboring PS tubes— particularly when data from those locations have been more consistent during previous sampling periods. Accidental contamination by the sample handler must be documented before any result can be eliminated as an outlier. Rare but possible examples of contamination include loose or missing storage caps or contaminated storage/ shipping containers. Review data from the same and neighboring monitoring locations deployment, handling, siting, or analytical errors. 12.2 Identify Sampling Locations of Interest If data from neighboring sampling locations are significantly different, then you may add extra sampling points to isolate background contributions or identify facilityspecific ‘‘hot spots.’’ 12.3 Evaluate Trends You may evaluate trends and patterns in the PS data over multiple sampling periods to determine if elevated concentrations of target compounds are due to operations on PO 00000 Frm 00155 Fmt 4701 Sfmt 4700 for the subsequent sampling periods. If the anomalous result is not repeated for that monitoring location, the episode can be ascribed to transient contamination and the data in question must be flagged for potential elimination from the dataset. 9.3 Duplicates and Field Blanks 9.3.1 Collect at least one co-located/ duplicate sample for every 10 field samples to determine precision of the measurements. 9.3.2 Collect at least two field blanks sorbent samples per sampling period to ensure sample integrity associated with shipment, collection, and storage. You must use the entire sampling apparatus for field blanks including unopened sorbent tubes mounted in protective sampling hoods. The tube closures must not be removed. Field blanks must be placed in two different quadrants (e.g., 90° and 270°) and remain at the sampling location for the sampling period. 10.0 Calibration and Standardization Follow the calibration and standardization procedures for meteorological measurements in EPA–454/B–08–002 March 2008 (Reference 11) (incorporated by reference— see § 63.14). Refer to Method 325B for calibration and standardization procedures for analysis of the passive sampling tubes. 11.0 Analytical Procedures Refer to Method 325B, which provides details for the preparation and analysis of sampled passive monitoring tubes (preparation of sampling tubes, shipment and storage of exposed sampling tubes, and analysis of sampling tubes). 12.0 Data Analysis, Calculations and Documentation 12.1 Calculate Annual Average Fenceline Concentration. After a year’s worth of sampling at the facility fenceline (for example, 26 14-day samples), the average (PSi) may be calculated for any specified period at each PS location using Equation 12.1. the facility or if contributions from background sources are significant. 12.3.1 Obtain meteorological data including wind speed and wind direction or unit vector wind data from the on-site meteorological station. Use this meteorological data to determine the prevailing wind direction and speed during the periods of elevated concentrations. 12.3.2 As an option you may perform preliminary back trajectory calculations (https://ready.arl.noaa.gov/HYSPLIT.php) to aid in identifying the source of the background contribution to elevated target compound concentrations. E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.029</GPH> 8.5.9 Expose the sampling tubes for the required sampling period-normally 14-days. 8.5.10 Field blank tubes (see Section 9.3 of Method 325B) are stored outside the shipping container at representative sampling locations around the site, but with both long-term storage caps kept in place throughout the monitoring exercise. Collect at least two field blanks sorbent samples per sampling period to ensure sample integrity associated with shipment, collection, and storage. 75331 75332 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 12.3.3 Information on published or documented events on- and off-site may also be included in the associated sampling period report to explain elevated concentrations if relevant. For example, you would describe if there was a chemical spill on site, or an accident on an adjacent road. 12.3.4 Additional monitoring for shorter periods (See section 8.4) may be necessary to allow better discrimination/resolution of contributing emission sources if the measured trends and associated meteorology do not provide a clear assessment of facility contribution to the measured fenceline concentration. 12.3.5 Additional records necessary to calculate sampling period average target compound concentration can be found in Section 12.1 of Method 325B. 13.0 Method Performance Method performance requirements are described in Method 325B. 14.0 Pollution Prevention [Reserved] 15.0 Waste Management [Reserved] tkelley on DSK3SPTVN1PROD with RULES2 16.0 References 1. Ambient air quality—Standard method for measurement of benzene concentrations—Part 4: Diffusive sampling followed by thermal desorption and gas chromatography, BS EN 14662– 4:2005. 2. Thoma, E.D., Miller, C.M., Chung, K.C., Parsons, N.L. and Shine, B.C. Facility VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Fence Line Monitoring using Passive Samplers, J. Air & Waste Mange. Assoc. 2011, 61:834–842. 3. Quality Assurance Handbook for Air Pollution C Systems, Volume II: Ambient Air Quality Monitoring Program, EPA– 454/B–13–003, May 2013. Available at https://www.epa.gov/ttnamti1/files/ ambient/pm25/qa/QA-Handbook-VolII.pdf. 4. Brown, R.H., Charlton, J. and Saunders, K.J.: The development of an improved diffusive sampler. Am. Ind. Hyg. Assoc. J. 1981, 42(12): 865–869. 5. Brown, R. H. Environmental use of diffusive samplers: evaluation of reliable diffusive uptake rates for benzene, toluene and xylene. J. Environ. Monit. 1999, 1 (1), 115–116. 6. Ballach, J.; Greuter, B.; Schultz, E.; Jaeschke, W. Variations of uptake rates in benzene diffusive sampling as a function of ambient conditions. Sci. Total Environ. 1999, 244, 203–217. 7. Brown, R. H. Monitoring the ambient environment with diffusive samplers: theory and practical considerations. J Environ. Monit. 2000, 2 (1), 1–9. 8. Buzica, D.; Gerboles, M.; Plaisance, H. The equivalence of diffusive samplers to reference methods for monitoring O3, benzene and NO2 in ambient air. J. Environ. Monit. 2008, 10 (9), 1052–1059. 9. Woolfenden, E. Sorbent-based sampling methods for volatile and semi-volatile organic compounds in air. Part 2. Sorbent selection and other aspects of optimizing air monitoring methods. J. PO 00000 Frm 00156 Fmt 4701 Sfmt 4700 Chromatogr. A 2010, 1217, (16), 2685– 94. 10. Pfeffer, H. U.; Breuer, L. BTX measurements with diffusive samplers in the vicinity of a cokery: Comparison between ORSA-type samplers and pumped sampling. J. Environ. Monit. 2000, 2 (5), 483–486. 11. US EPA. 2000. Meteorological Monitoring Guidance for Regulatory Modeling Applications. EPA–454/R–99–005. Office of Air Quality Planning and Standards, Research Triangle Park, NC. February 2000. Available at https://www.epa.gov/ scram001/guidance/met/mmgrma.pdf. 12. Quality Assurance Handbook for Air Pollution Measurement Systems. Volume IV: Meteorological Measurements Version 2.0 Final, EPA–454/B–08–002 March 2008. Available at https://www. epa.gov/ttnamti1/files/ambient/met/ Volume%20IV_Meteorological_ Measurements.pdf. 13. ISO 16017–2:2003(E), Indoor, ambient and workplace air—Sampling and analysis of volatile organic compounds by sorbent tube/thermal desorption/ capillary gas chromatography. Part 2: Diffusive sampling. 14. ASTM D6196–03 (Reapproved 2009): Standard practice for selection of sorbents, sampling, and thermal desorption analysis procedures for volatile organic compounds in air. 17.0 Tables, Diagrams, Flowcharts and Validation Data E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75333 Method 325 A/B EXAMPLE FIELD TEST DATA SHEET (FTDS) AND CHAIN OF CUSTODY I. GENERAL INFORMATION SITE NAME: SITE LOCATION ADDRESS: CITY: STATE: ZIP: II. SAMPLING DATA Sample ID (Tube) # Sorbent Sample or blank Start Date Start Time Stop Date Stop Time Location (gps) Ambient Temp. (oF) Barometric Pressure (in. Hg) III. CUSTODY INFORMATION COLLECTED BY: Relinquished to Shipper Name: Date: Received by Laboratory Date: Name Sample condition upon receipt: Time Time Analysis Required: Figure 17.1. Example Field Data Form and Chain of Custody VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00157 Fmt 4701 Sfmt 4725 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.030</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Comments: 75334 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Method 325B—Volatile Organic Compounds from Fugitive and Area Sources: tkelley on DSK3SPTVN1PROD with RULES2 Sampler Preparation and Analysis 1.0 Scope and Application 1.1 This method describes thermal desorption/gas chromatography (TD/GC) analysis of volatile organic compounds (VOCs) from fugitive and area emission sources collected onto sorbent tubes using passive sampling. It could also be applied to the TD/GC analysis of VOCs collected using active (pumped) sampling onto sorbent tubes. The concentration of airborne VOCs at or near potential fugitive- or area-emission sources may be determined using this method in combination with Method 325A. Companion Method 325A (Sampler Deployment and VOC Sample Collection) describes procedures for deploying the sorbent tubes and passively collecting VOCs. 1.2 The preferred GC detector for this method is a mass spectrometer (MS), but flame ionization detectors (FID) may also be used. Other conventional GC detectors such as electron capture (ECD), photoionization (PID), or flame photometric (FPD) may also be used if they are selective and sensitive to the target compound(s) and if they meet the method performance criteria provided in this method. 1.3 There are 97 VOCs listed as hazardous air pollutants in Title III of the Clean Air Act Amendments of 1990. Many of these VOC are candidate compounds for this method. Compounds with known uptake rates for CarbographTM 1 TD, CarbopackTM B, or CarbopackTM X are listed in Table 12.1. This method provides performance criteria to demonstrate acceptable performance of the method (or modifications of the method) for monitoring one or more of the compounds listed Table 12.1. If standard passive sampling tubes are packed with other sorbents or used for other analytes than those listed in Table 12.1, then method performance and relevant uptake rates should be verified according to Addendum A to this method or by one of the following national/international standard methods: ISO 16017–2:2003(E), ASTM D6196–03 (Reapproved 2009), or BS EN 14662–4:2005 (all incorporated by reference—see § 63.14), or reported in the peer-reviewed open literature. 1.4 The analytical approach using TD/ GC/MS is based on previously published EPA guidance in Compendium Method TO– 17 (https://www.epa.gov/ttnamti1/airtox. html#compendium) (Reference 1), which describes active (pumped) sampling of VOCs from ambient air onto tubes packed with thermally stable adsorbents. 1.5 Inorganic gases not suitable for analysis by this method include oxides of carbon, nitrogen and sulfur, ozone (O3), and other diatomic permanent gases. Other pollutants not suitable for this analysis method include particulate pollutants, (i.e., fumes, aerosols, and dusts), compounds too labile (reactive) for conventional GC analysis, and VOCs that are more volatile than propane. 2.0 Summary of Method 2.1 This method provides procedures for the preparation, conditioning, blanking, and VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 shipping of sorbent tubes prior to sample collection. 2.2 Laboratory and field personnel must have experience of sampling trace-level VOCs using sorbent tubes (References 2,5) and must have experience operating thermal desorption/GC/multi-detector instrumentation. 2.3 Key steps of this method as implemented for each sample tube include: Stringent leak testing under stop flow, recording ambient temperature conditions, adding internal standards, purging the tube, thermally desorbing the sampling tube, refocusing on a focusing trap, desorbing and transferring/injecting the VOCs from the secondary trap into the capillary GC column for separation and analysis. 2.4 Water management steps incorporated into this method include: (a) Selection of hydrophobic sorbents in the sampling tube; (b) optional dry purging of sample tubes prior to analysis; and (c) additional selective elimination of water during primary (tube) desorption (if required) by selecting trapping sorbents and temperatures such that target compounds are quantitatively retained while water is purged to vent. 3.0 Definitions (See also Section 3.0 of Method 325A). 3.1 Blanking is the desorption and confirmatory analysis of conditioned sorbent tubes before they are sent for field sampling. 3.2 Breakthrough volume and associated relation to passive sampling. Breakthrough volumes, as applied to active sorbent tube sampling, equate to the volume of air containing a constant concentration of analyte that may be passed through a sorbent tube at a given temperature before a detectable level (5 percent) of the input analyte concentration elutes from the tube. Although breakthrough volumes are directly related to active rather than passive sampling, they provide a measure of the strength of the sorbent-sorbate interaction and therefore also relate to the efficiency of the passive sampling process. The best direct measure of passive sampling efficiency is the stability of the uptake rate. Quantitative passive sampling is compromised when the sorbent no longer acts as a perfect sink—i.e., when the concentration of a target analyte immediately above the sorbent sampling surface no longer approximates to zero. This causes a reduction in the uptake rate over time. If the uptake rate for a given analyte on a given sorbent tube remains relatively constant —i.e., if the uptake rate determined for 48 hours is similar to that determined for 7 or 14 days—the user can be confident that passive sampling is occurring at a constant rate. As a general rule of thumb, such ideal passive sampling conditions typically exist for analyte:sorbent combinations where the breakthrough volume exceeds 100 L (Reference 4). 3.3 Continuing calibration verification sample (CCV). Single level calibration samples run periodically to confirm that the analytical system continues to generate sample results within acceptable agreement to the current calibration curve. 3.4 Focusing trap is a cooled, secondary sorbent trap integrated into the analytical PO 00000 Frm 00158 Fmt 4701 Sfmt 4700 thermal desorber. It typically has a smaller i.d. and lower thermal mass than the original sample tube allowing it to effectively refocus desorbed analytes and then heat rapidly to ensure efficient transfer/injection into the capillary GC analytical column. 3.5 High Resolution Capillary Column Chromatography uses fused silica capillary columns with an inner diameter of 320 mm or less and with a stationary phase film thickness of 5 mm or less. 3.6 h is time in hours. 3.7 i.d. is inner diameter. 3.8 min is time in minutes. 3.9 Method Detection Limit is the lowest level of analyte that can be detected in the sample matrix with 99% confidence. 3.10 MS–SCAN is the mode of operation of a GC quadrupole mass spectrometer detector that measures all ions over a given mass range over a given period of time. 3.11 MS–SIM is the mode of operation of a GC quadrupole mass spectrometer detector that measures only a single ion or a selected number of discrete ions for each analyte. 3.12 o.d. is outer diameter. 3.13 ppbv is parts per billion by volume. 3.14 Thermal desorption is the use of heat and a flow of inert (carrier) gas to extract volatiles from a solid matrix. No solvent is required. 3.15 Total ion chromatogram is the chromatogram produced from a mass spectrometer detector collecting full spectral information. 3.16 Two-stage thermal desorption is the process of thermally desorbing analytes from a sorbent tube, reconcentrating them on a focusing trap (see Section 3.4), which is then itself rapidly heated to ‘‘inject’’ the concentrated compounds into the GC analyzer. 3.17 VOC is volatile organic compound. 4.0 Analytical Interferences 4.1 Interference from Sorbent Artifacts. Artifacts may include target analytes as well as other VOC that co-elute chromatographically with the compounds of interest or otherwise interfere with the identification or quantitation of target analytes. 4.1.1 Sorbent decomposition artifacts are VOCs that form when sorbents degenerate, e.g., when exposed to reactive species during sampling. For example, benzaldehyde, phenol, and acetophenone artifacts are reported to be formed via oxidation of the polymeric sorbent Tenax® when sampling high concentration (100–500 ppb) ozone atmospheres (Reference 5). 4.1.2 Preparation and storage artifacts are VOCs that were not completely cleaned from the sorbent tube during conditioning or that are an inherent feature of that sorbent at a given temperature. 4.2 Humidity. Moisture captured during sampling can interfere with VOC analysis. Passive sampling using tubes packed with hydrophobic sorbents, like those described in this method, minimizes water retention. However, if water interference is found to be an issue under extreme conditions, one or more of the water management steps described in Section 2.4 can be applied. 4.3 Contamination from Sample Handling. The type of analytical thermal E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 6.0 Equipment and Supplies 6.1 Tube Dimensions and Materials. The sampling tubes for this method are 3.5-inches (89 mm) long, 1⁄4 inch (6.4 mm) o.d., and 5 6.2 Tube Conditioning Apparatus 6.2.1 Freshly packed or newly purchased tubes must be conditioned as described in Section 9 using an appropriate dedicated tube conditioning unit or the thermal desorber. Note that the analytical TD system should be used for tube conditioning if it supports a dedicated tube conditioning mode in which effluent from contaminated tubes is directed to vent without passing through key parts of the sample flow path such as the focusing trap. 6.2.2 Dedicated tube conditioning units must be leak-tight to prevent air ingress, allow precise and reproducible temperature selection (±5 °C), offer a temperature range at least as great as that of the thermal desorber, and support inert gas flows in the range up to 100 mL/min. Note: For safety and to avoid laboratory contamination, effluent gases from freshly packed or highly contaminated tubes should be passed through a charcoal filter during the conditioning process to prevent desorbed VOCs from polluting the laboratory atmosphere. with relevant tube and sample information, which can be read and automatically transcribed into the sequence report by the TD system (see Section 8.6 of Method 325A). 6.3 Tube Labeling 6.3.1 Label the sample tubes with a unique permanent identification number and an indication of the sampling end of the tube. Labeling options include etching and TDcompatible electronic (radio frequency identification (RFID)) tube labels. 6.3.2 To avoid contamination, do not make ink markings of any kind on clean sorbent tubes or apply adhesive labels. Note: TD-compatible electronic (RFID) tube labels are available commercially and are compatible with some brands of thermal desorber. If used, these may be programmed VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 6.4 Blank and Sampled Tube Storage Apparatus 6.4.1 Long-term storage caps. Seal clean, blank and sampled sorbent tubes using inert, long-term tube storage caps comprising nongreased, 2-piece, 0.25-inch, metal SwageLok®-type screw caps fitted with combined polytetrafluoroethylene ferrules. 6.4.2 Storage and transportation containers. Use clean glass jars, metal cans or rigid, non-emitting polymer boxes. Note: You may add a small packet of new activated charcoal or charcoal/silica gel to the shipping container for storage and transportation of batches of conditioned sorbent tubes prior to use. Coolers without ice packs make suitable shipping boxes for containers of tubes because the coolers help to insulate the samples from extreme temperatures (e.g., if left in a parked vehicle). 6.5 Unheated GC Injection Unit for Loading Standards Onto Blank Tubes A suitable device has a simple push fit or finger-tightening connector for attaching the sampling end of blank sorbent tubes without damaging the tube. It also has a means of controlling carrier gas flow through the injector and attached sorbent tube at 50–100 mL/min and includes a low emission septum cap that allows the introduction of gas or liquid standards via appropriate syringes. Reproducible and quantitative transfer of higher boiling compounds in liquid standards is facilitated if the injection unit PO 00000 Frm 00159 Fmt 4701 Sfmt 4700 mm i.d. passive sampling tubes (see Figure 6.1). The tubes are made of inert-coated stainless steel with the central section (up to 60 mm) packed with sorbent, typically supported between two 100 mesh stainless steel gauze. The tubes have a cross sectional area of 19.6 square mm (5 mm i.d.). When used for passive sampling, these tubes have an internal diffusion (air) gap (DG) of 1.5 cm between the sorbent retaining gauze at the sampling end of the tube, and the gauze in the diffusion cap. allows the tip of the syringe to just touch the sorbent retaining gauze inside the tube. 6.6 Thermal Desorption Apparatus The manual or automated thermal desorption system must heat sorbent tubes while a controlled flow of inert (carrier) gas passes through the tube and out of the sampling end. The apparatus must also incorporate a focusing trap to quantitatively refocus compounds desorbed from the tube. Secondary desorption of the focusing trap should be fast/efficient enough to transfer the compounds into the high resolution capillary GC column without band broadening and without any need for further pre- or oncolumn focusing. Typical TD focusing traps comprise small sorbent traps (Reference 16) that are electrically-cooled using multistage Peltier cells (References 17, 18). The direction of gas flow during trap desorption should be the reverse of that used for focusing to extend the compatible analyte volatility range. Closed cycle coolers offer another cryogen-free trap cooling option. Other TD system requirements and operational stages are described in Section 11 and in Figures 17–2 through 17–4. 6.7 Thermal Desorber—GC Interface 6.7.1 The interface between the thermal desorber and the GC must be heated uniformly and the connection between the transfer line insert and the capillary GC analytical column itself must be leak tight. 6.7.2 A portion of capillary column can alternatively be threaded through the heated transfer line/TD interface and connected directly to the thermal desorber. Note: Use of a metal syringe-type needle or unheated length of fused silica pushed through the septum of a conventional GC E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.031</GPH> standard to establish appropriate field and laboratory safety and health practices prior to use. 5.2 Laboratory analysts must exercise extreme care in working with high-pressure gas cylinders. 5.3 Due to the high temperatures involved, operators must use caution when conditioning and analyzing tubes. 5.0 Safety 5.1 This method does not address all of the safety concerns associated with its use. It is the responsibility of the user of this tkelley on DSK3SPTVN1PROD with RULES2 desorption equipment selected should exclude the possibility of outer tube surface contamination entering the sample flow path (see Section 6.6). If the available system does not meet this requirement, sampling tubes and caps must be handled only while wearing clean, white cotton or powder free nitrile gloves to prevent contamination with body oils, hand lotions, perfumes, etc. 75335 75336 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations injector is not permitted as a means of interfacing the thermal desorber to the chromatograph. Such connections result in cold spots, cause band broadening and are prone to leaks. 6.8 GC/MS Analytical Components 6.8.1 The GC system must be capable of temperature programming and operation of a high resolution capillary column. Depending on the choice of column (e.g., film thickness) and the volatility of the target compounds, it may be necessary to cool the GC oven to subambient temperatures (e.g., ¥50 °C) at the start of the run to allow resolution of very volatile organic compounds. 6.8.2 All carrier gas lines supplying the GC must be constructed from clean stainless steel or copper tubing. Nonpolytetrafluoroethylene thread sealants. Flow controllers, cylinder regulators, or other pneumatic components fitted with rubber components are not suitable. 6.9 Chromatographic Columns High-resolution, fused silica or equivalent capillary columns that provide adequate separation of sample components to permit identification and quantitation of target compounds must be used. Note: 100-percent methyl silicone or 5percent phenyl, 95-percent methyl silicone fused silica capillary columns of 0.25- to 0.32-mm i.d. of varying lengths and with varying thicknesses of stationary phase have been used successfully for non-polar and moderately polar compounds. However, given the diversity of potential target lists, GC column choice is left to the operator, subject to the performance criteria of this method. 6.10 Mass Spectrometer Linear quadrupole, magnetic sector, ion trap or time-of-flight mass spectrometers may be used provided they meet specified performance criteria. The mass detector must be capable of collecting data from 35 to 300 atomic mass units (amu) every 1 second or less, utilizing 70 volts (nominal) electron energy in the electron ionization mode, and producing a mass spectrum that meets all the instrument performance acceptance criteria in Section 9 when 50 hg or less of pbromofluorobenzene is analyzed. tkelley on DSK3SPTVN1PROD with RULES2 7.0 Reagents and Standards 7.1 Sorbent Selection 7.1.1 Use commercially packed tubes meeting the requirements of this method or prepare tubes in the laboratory using sieved sorbents of particle size in the range 20 to 80 mesh that meet the retention and quality control requirements of this method. 7.1.2 This passive air monitoring method can be used without the evaluation specified in Addendum A if the type of tubes described in Section 6.1 are packed with 4– 6 cm (typically 400–650 mg) of the sorbents listed in Table 12.1 and used for the respective target analytes. Note: Although CarbopackTM X is the optimum sorbent choice for passive sampling of 1,3-butadiene, recovery of compounds with vapor pressure lower than benzene may VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 be difficult to achieve without exceeding sorbent maximum temperature limitations (see Table 8.1). See ISO 16017–2:2003(E) or ASTM D6196–03 (Reapproved 2009) (both incorporated by reference—see § 63.14) for more details on sorbent choice for air monitoring using passive sampling tubes. 7.1.3 If standard passive sampling tubes are packed with other sorbents or used for analytes other than those tabulated in Section 12.0, method performance and relevant uptake rates should be verified according to Addendum A to this method or by following the techniques described in one of the following national/international standard methods: ISO 16017–2:2003(E), ASTM D6196–03 (Reapproved 2009), or BS EN 14662–4:2005 (all incorporated by reference—see § 63.14)—or reported in the peer-reviewed open literature. A summary table and the supporting evaluation data demonstrating the selected sorbent meets the requirements in Addendum A to this method must be submitted to the regulatory authority as part of a request to use an alternative sorbent. 7.1.4 Passive (diffusive) sampling and thermal desorption methods that have been evaluated at relatively high atmospheric concentrations (i.e., mid-ppb to ppm) and published for use in workplace air and industrial/mobile source emissions testing (References 9–20) may be applied to this procedure. However, the validity of any shorter term uptake rates must be verified and adjusted if necessary for the longer monitoring periods required by this method by following procedures described in Addendum A to this method or those presented in national/international standard methods: ISO 16017–2:2003(E), ASTM D6196–03 (Reapproved 2009), or BS EN 14662–4:2005 (all incorporated by referencesee § 63.14). 7.1.5 Suitable sorbents for passive sampling must have breakthrough volumes of at least 20 L (preferably >100 L) for the compounds of interest and must quantitatively release the analytes during desorption without exceeding maximum temperatures for the sorbent or instrumentation. 7.1.6 Repack/replace the sorbent tubes or demonstrate tube performance following the requirements in Addendum A to this method at least every 2 years or every 50 uses, whichever occurs first. 7.2 Gas Phase Standards 7.2.1 Static or dynamic standard atmospheres may be used to prepare calibration tubes and/or to validate passive sampling uptake rates and can be generated from pure chemicals or by diluting concentrated gas standards. The standard atmosphere must be stable at ambient pressure and accurate to ±10 percent of the target gas concentration. It must be possible to maintain standard atmosphere concentrations at the same or lower levels than the target compound concentration objectives of the test. Test atmospheres used for validation of uptake rates must also contain at least 35 percent relative humidity. Note: Accurate, low-(ppb-) level gas-phase VOC standards are difficult to generate from PO 00000 Frm 00160 Fmt 4701 Sfmt 4700 pure materials and may be unstable depending on analyte polarity and volatility. Parallel monitoring of vapor concentrations with alternative methods, such as pumped sorbent tubes or sensitive/selective on-line detectors, may be necessary to minimize uncertainty. For these reasons, standard atmospheres are rarely used for routine calibration. 7.2.2 Concentrated, pressurized gas phase standards. Accurate (±5 percent or better), concentrated gas phase standards supplied in pressurized cylinders may also be used for calibration. The concentration of the standard should be such that a 0.5–5.0 mL volume contains approximately the same mass of analytes as will be collected from a typical air sample. 7.2.3 Follow manufacturer’s guidelines concerning storage conditions and recertification of the concentrated gas phase standard. Gas standards must be recertified a minimum of once every 12 months. 7.3 Liquid Standards Target analytes can also be introduced to the sampling end of sorbent tubes in the form of liquid calibration standards. 7.3.1 The concentration of liquid standards must be such that an injection of 0.5–2 ml of the solution introduces the same mass of target analyte that is expected to be collected during the passive air sampling period. 7.3.2 Solvent Selection. The solvent selected for the liquid standard must be pure (contaminants <10 percent of minimum analyte levels) and must not interfere chromatographically with the compounds of interest. 7.3.3 If liquid standards are sourced commercially, follow manufacturer’s guidelines concerning storage conditions and shelf life of unopened and opened liquid stock standards. Note: Commercial VOC standards are typically supplied in volatile or noninterfering solvents such as methanol. 7.3.4 Working standards must be stored at 6 °C or less and used or discarded within two weeks of preparation. 7.4 Gas Phase Internal Standards 7.4.1 Gas-phase deuterated or fluorinated organic compounds may be used as internal standards for MS-based systems. 7.4.2 Typical compounds include deuterated toluene, perfluorobenzene and perfluorotoluene. 7.4.3 Use multiple internal standards to cover the volatility range of the target analytes. 7.4.4 Gas-phase standards must be obtained in pressurized cylinders and containing vendor certified gas concentrations accurate to ±5 percent. The concentration should be such that the mass of internal standard components introduced is similar to those of the target analytes collected during field monitoring. 7.5 Preloaded Standard Tubes Certified, preloaded standard tubes, accurate within ±5 percent for each analyte at the microgram level and ±10 percent at the nanogram level, are available commercially E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations and may be used for auditing and quality control purposes. (See Section 9.5 for audit accuracy evaluation criteria.) Certified preloaded tubes may also be used for routine calibration. Note: Proficiency testing schemes are also available for TD/GC/MS analysis of sorbent tubes preloaded with common analytes such as benzene, toluene, and xylene. filters must be installed in the carrier gas lines supplying the analytical system according to the manufacturer’s instructions. Keep records of filter and oxygen scrubber replacement. 7.6 Carrier Gases Use inert, 99.999-percent or higher purity helium as carrier gas. Oxygen and organic 75337 8.1.2 New tubes should be conditioned for 2 hours to supplement the vendor’s conditioning procedure. Recommended temperatures for tube conditioning are given in Table 8.1. 8.1.3 After conditioning, the blank must be verified on each new sorbent tube and on 10 percent of each batch of reconditioned tubes. See Section 9.0 for acceptance criteria. 8.1.1 Sampling tubes must be conditioned using the apparatus described in Section 6.2. 8.0 Sorbent Tube Handling (Before and After Sampling) 8.1 Sample Tube Conditioning TABLE 8.1—EXAMPLE SORBENT TUBE CONDITIONING PARAMETERS Maximum temperature (°C) Sampling sorbent Carbotrap® C ............................................................................................................................... CarbopackTM C Anasorb® GCB2 CarbographTM 1 TD Carbotrap® CarbopackTM B Anasorb® GCB1 Tenax® TA CarbopackTM X ............................................................................................................................ 8.2 Capping, Storage and Shipment of Conditioned Tubes tkelley on DSK3SPTVN1PROD with RULES2 8.2.1 Conditioned tubes must be sealed using long-term storage caps (see Section 6.4) pushed fully down onto both ends of the PS sorbent tube, tightened by hand and then tighten an additional quarter turn using an appropriate tool. 8.2.2 The capped tubes must be kept in appropriate containers for storage and transportation (see Section 6.4.2). Containers of sorbent tubes may be stored and shipped at ambient temperature and must be kept in a clean environment. 8.2.3 You must keep batches of capped tubes in their shipping boxes or wrap them in uncoated aluminum foil before placing them in their storage container, especially before air freight, because the packaging helps hold caps in position if the tubes get very cold. 8.3 Calculating the Number of Tubes Required for a Monitoring Exercise 8.3.1 Follow guidance given in Method 325A to determine the number of tubes required for site monitoring. 8.3.2 The following additional samples will also be required: Laboratory blanks as specified in Section 9.1.2 (one per analytical sequence minimum), field blanks as specified in Section 9.3.2 (two per sampling period minimum), CCV tubes as specified in Section 10.9.4. (at least one per analysis sequence or every 24 hours), and duplicate samples as specified in Section 9.4 (at least one duplicate sample is required for every 10 sampling locations during each monitoring period). 8.4 Sample Collection 8.4.1 Allow the tubes to equilibrate with ambient temperature (approximately 30 minutes to 1 hour) at the monitoring location VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 before removing them from their storage/ shipping container for sample collection. 8.4.2 Tubes must be used for sampling within 30 days of conditioning (Reference 4). 8.4.3 During field monitoring, the longterm storage cap at the sampling end of the tube is replaced with a diffusion cap and the whole assembly is arranged vertically, with the sampling end pointing downward, under a protective hood or shield—See Section 6.1 of Method 325A for more details. 8.5 Sample Storage 8.5.1 After sampling, tubes must be immediately resealed with long-term storage caps and placed back inside the type of storage container described in Section 6.4.2. 8.5.2 Exposed tubes may not be placed in the same container as clean tubes. They should not be taken back out of the container until ready for analysis and after they have had time to equilibrate with ambient temperature in the laboratory. 8.5.3 Sampled tubes must be inspected before analysis to identify problems such as loose or missing caps, damaged tubes, tubes that appear to be leaking sorbent or container contamination. Any and all such problems must be documented together with the unique identification number of the tube or tubes concerned. Affected tubes must not be analyzed but must be set aside. 8.5.4 Intact tubes must be analyzed within 30 days of the end of sample collection (within one week for limonene, carene, bis-chloromethyl ether, labile sulfur or nitrogen-containing compounds, and other reactive VOCs). Note: Ensure ambient temperatures stay below 23 °C during transportation and storage. Refrigeration is not normally required unless the samples contain reactive compounds or cannot be analyzed within 30 days. If refrigeration is used, the atmosphere PO 00000 Frm 00161 Fmt 4701 Sfmt 4700 Conditioning temperature (°C) Carrier gas flow rate >400 350 100 mL/min 350 330 100 mL/min inside the refrigerator must be clean and free of organic solvents. 9.0 Quality Control 9.1 Laboratory Blank The analytical system must be demonstrated to be contaminant free by performing a blank analysis at the beginning of each analytical sequence to demonstrate that the secondary trap and TD/GC/MS analytical equipment are free of any significant interferents. 9.1.1 Laboratory blank tubes must be prepared from tubes that are identical to those used for field sampling. 9.1.2 Analysis of at least one laboratory blank is required per analytical sequence. The laboratory blank must be stored in the laboratory under clean, controlled ambient temperature conditions. 9.1.3 Laboratory blank/artifact levels must meet the requirements of Section 9.2.2 (see also Table 17.1). If the laboratory blank does not meet requirements, stop and perform corrective actions and then reanalyze laboratory blank to ensure it meets requirements. 9.2 Tube Conditioning 9.2.1 Conditioned tubes must be demonstrated to be free of contaminants and interference by running 10 percent of the blank tubes selected at random from each conditioned batch under standard sample analysis conditions (see Section 8.1). 9.2.2 Confirm that artifacts and background contamination are ≤ 0.2 ppbv or less than three times the detection limit of the procedure or less than 10 percent of the target compound(s) mass that would be collected if airborne concentrations were at the regulated limit value, whichever is larger. Only tubes that meet these criteria can be E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 9.4 Duplicate Samples Duplicate (co-located) samples collected must be analyzed and reported as part of method quality control. They are used to evaluate sampling and analysis precision. Relevant performance criteria are given in Section 9.9. 9.5 Method Performance Criteria Unless otherwise noted, monitoring method performance specifications must be demonstrated for the target compounds using the procedures described in Addendum A to this method and the statistical approach presented in Method 301. 9.6 Method Detection Limit Determine the method detection limit under the analytical conditions selected (see 9.8 Where: A1 = A measurement value taken from one spiked tube. A2 = A measurement value taken from a second spiked tube. A = The average of A1 and A2. tkelley on DSK3SPTVN1PROD with RULES2 Where: Spiked Value = A known mass of VOCs added to the tube. Measured Value = Mass determined from analysis of the tube. 9.9 Where: F1 = A measurement value (mass) taken from one of the two field replicate tubes used in sampling. F2 = A measurement value (mass) taken from the second of two field replicate tubes used in sampling. F = The average of F1 and F2. 9.10.1 Quantitative (>95 percent) compound recovery must be demonstrated by repeat analyses on a same standard tube. 9.10.2 Compound recovery through the TD system can also be demonstrated by comparing the calibration check sample response factor obtained from direct GC injection of liquid standards with that obtained from thermal desorption analysis response factor using the same column under identical conditions. 9.10.3 If the relative response factors obtained for one or more target compounds introduced to the column via thermal VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Field Replicate Precision Use Equation 9.3 to determine and report replicate precision for duplicate field samples (see Section 9.4). The level of agreement between duplicate 9.10 Desorption Efficiency and Compound Recovery The efficiency of the thermal desorption method must be determined. Analytical Precision Demonstrate an analytical precision within ±20 percent using Equation 9.2. Analytical precision must be demonstrated during PO 00000 Frm 00162 Fmt 4701 Sfmt 4700 Section 11.3) using the procedure in Section 15 of Method 301. The method detection limit is defined for each system by making seven replicate measurements of a concentration of the compound of interest within a factor of five of the detection limit. Compute the standard deviation for the seven replicate concentrations, and multiply this value by three. The results should demonstrate that the method is able to detect analytes such as benzene at concentrations as low as 50 ppt or 1/3rd (preferably 1/10th) of the lowest concentration of interest, whichever is larger. Note: Determining the detection limit may be an iterative process as described in 40 CFR part 136, Appendix B. 9.7 Analytical Bias Analytical bias must be demonstrated to be within ±30 percent using Equation 9.1. Analytical bias must be demonstrated during initial setup of this method and as part of the CCV carried out with every sequence of 10 samples or less (see Section 9.14). Calibration standard tubes (see Section 10.0) may be used for this purpose. initial setup of this method and at least once per year. Calibration standard tubes may be used (see Section 10.0) and data from CCV may also be applied for this purpose. field samples is a measure of the precision achievable for the entire sampling and analysis procedure. Flag data sets for which the duplicate samples do not agree within 30 percent. desorption fail to meet the criteria in Section 9.10.1, you must adjust the TD parameters to meet the criteria and repeat the experiment. Once the thermal desorption conditions have been optimized, you must repeat this test each time the analytical system is recalibrated to demonstrate continued method performance. 9.11 Audit Samples Certified reference standard samples must be used to audit this procedure (if available). Accuracy within 30 percent must be E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.034</GPH> 9.3 Field Blanks 9.3.1 Field blank tubes must be prepared from tubes that are identical to those used for field sampling—i.e., they should be from the same batch, have a similar history, and be conditioned at the same time. 9.3.2 Field blanks must be shipped to the monitoring site with the sampling tubes and must be stored at the sampling location throughout the monitoring exercise. The field blanks must be installed under a protective hood/cover at the sampling location, but the long-term storage caps must remain in place throughout the monitoring period (see Method 325A). The field blanks are then shipped back to the laboratory in the same container as the sampled tubes. One field blank tube is required for every 10 sampled tubes on a monitoring exercise and no less than two field blanks should be collected, regardless of the size of the monitoring study. 9.3.3 Field blanks must contain no greater than one-third of the measured target analyte or compliance limit for field samples (see Table 17.1). If either field blank fails, flag all data that do not meet this criterion with a note that the associated results are estimated and likely to be biased high due to field blank background. ER01DE15.033</GPH> used for field monitoring, field or laboratory blanks, or for system calibration. 9.2.3 If unacceptable levels of VOCs are observed in the tube blanks, then the processes of tube conditioning and checking the blanks must be repeated. ER01DE15.032</GPH> 75338 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations demonstrated for relevant ambient air concentrations (0.5 to 25 ppb). Verify the instrument performance by analyzing a 50 hg injection of bromofluorobenzene. Prior to the beginning of each analytical sequence or every 24 hours during continuous GC/MS operation for this 9.12 Mass Spectrometer Tuning Criteria Tune the mass spectrometer (if used) according to manufacturer’s specifications. 75339 method demonstrate that the bromofluorobenzene tuning performance criteria in Table 9.1 have been met. TABLE 9.1—GC/MS TUNING CRITERIA 1 Target mass Rel. to mass 50 ................................................................................................................................................. 75 ................................................................................................................................................. 95 ................................................................................................................................................. 96 ................................................................................................................................................. 173 ............................................................................................................................................... 174 ............................................................................................................................................... 175 ............................................................................................................................................... 176 ............................................................................................................................................... 177 ............................................................................................................................................... 95 95 95 95 174 95 174 174 176 Lower limit % Upper limit % 8 30 100 5 0 50 4 93 5 40 66 100 9 2 120 9 101 9 1 All ion abundances must be normalized to m/z 95, the nominal base peak, even though the ion abundance of m/z 174 may be up to 120 percent that of m/z 95. 9.13 Routine CCV at the Start of a Sequence Run CCV before each sequence of analyses and after every tenth sample to ensure that the previous multi-level calibration (see Section 10.6.3) is still valid. 9.13.1 The sample concentration used for the CCV should be near the mid-point of the multi-level calibration range. 9.13.2 Quantitation software must be updated with response factors determined from the CCV standard. The percent deviation between the initial calibration and the CCV for all compounds must be within 30 percent. 9.14 CCV at the End of a Sequence Run another CCV after running each sequence of samples. The initial CCV for a subsequent set of samples may be used as the final CCV for a previous analytical sequence, provided the same analytical method is used and the subsequent set of samples is analyzed immediately (within 4 hours) after the last CCV. 9.15 Additional Verification Use a calibration check standard from a second, separate source to verify the original calibration at least once every three months. 9.16 Integration Method Document the procedure used for integration of analytical data including field samples, calibration standards and blanks. tkelley on DSK3SPTVN1PROD with RULES2 9.17 QC Records Maintain all QC reports/records for each TD/GC/MS analytical system used for application of this method. Routine quality control requirements for this method are listed below and summarized in Table 17.1. 10.0 Calibration and Standardization 10.1 Calibrate the analytical system using standards covering the range of analyte masses expected from field samples. 10.2 Analytical results for field samples must fall within the calibrated range of the analytical system to be valid. 10.3 Calibration standard preparation must be fully traceable to primary standards VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 of mass and/or volume, and/or be confirmed using an independent certified reference method. 10.3.1 Preparation of calibration standard tubes from standard atmospheres. 10.3.1.1 Subject to the requirements in Section 7.2.1, low-level standard atmospheres may be introduced to clean, conditioned sorbent tubes in order to produce calibration standards. 10.3.1.2 The standard atmosphere generator or system must be capable of producing sufficient flow at a constant rate to allow the required analyte mass to be introduced within a reasonable time frame and without affecting the concentration of the standard atmosphere itself. 10.3.1.3 The sampling manifold may be heated to minimize risk of condensation but the temperature of the gas delivered to the sorbent tubes may not exceed 100 °F. 10.3.1.4 The flow rates passed through the tube should be in the order of 50–100 mL/min and the volume of standard atmosphere sampled from the manifold or chamber must not exceed the breakthrough volume of the sorbent at the given temperature. 10.4 Preparation of calibration standard tubes from concentrated gas standards. 10.4.1 If a suitable concentrated gas standard (see Section 7.2.2) can be obtained, follow the manufacturer’s recommendations relating to suitable storage conditions and product lifetime. 10.4.2 Introduce precise 0.5 to 500.0 mL aliquots of the standard to the sampling end of conditioned sorbent tubes in a 50–100 mL/ min flow of pure carrier gas. Note: This can be achieved by connecting the sampling end of the tube to an unheated GC injector (see Section 6.6) and introducing the aliquot of gas using a suitable gas syringe. Gas sample valves could alternatively be used to meter the standard gas volume. 10.4.3 Each sorbent tube should be left connected to the flow of gas for 2 minutes after standard introduction. As soon as each spiked tube is removed from the injection unit, seal it with long-term storage caps and place it in an appropriate tube storage/ PO 00000 Frm 00163 Fmt 4701 Sfmt 4700 transportation container if it is not to be analyzed within 24 hours. 10.5 Preparation of calibration standard tubes from liquid standards. 10.5.1 Suitable standards are described in Section 7.3. 10.5.2 Introduce precise 0.5 to 2 ml aliquots of liquid standards to the sampling end of sorbent tubes in a flow (50–100 mL/ min) of carrier gas using a precision syringe and an unheated injector (Section 6.5). The flow of gas should be sufficient to completely vaporize the liquid standard. Note: If the analytes of interest are higher boiling than n-decane, reproducible analyte transfer to the sorbent bed is optimized by allowing the tip of the syringe to gently touch the sorbent retaining gauze at the sampling end of the tube. 10.5.3 Each sorbent tube is left connected to the flow of gas for 5 minutes after liquid standard introduction. 10.5.3.1 As soon as each spiked tube is removed from the injection unit, seal it with long-term storage caps and place it in an appropriate tube storage container if it is not to be analyzed within 24 hours. Note: In cases where it is possible to selectively purge the solvent from the tube while all target analytes are quantitatively retained, a larger 2 mL injection may be made for optimum accuracy. However, if the solvent cannot be selectively purged and will be present during analysis, the injection volume should be as small as possible (e.g., 0.5 mL) to minimize solvent interference. Note: This standard preparation technique requires the entire liquid plug including the tip volume be brought into the syringe barrel. The volume in the barrel is recorded, the syringe is inserted into the septum of the spiking apparatus. The liquid is then quickly injected. Any remaining liquid in the syringe tip is brought back into the syringe barrel. The volume in the barrel is recorded and the amount spiked onto the tube is the difference between the before spiking volume and the after spiking volume. A bias occurs with this method when sample is drawn continuously up into the syringe to the specified volume E:\FR\FM\01DER2.SGM 01DER2 75340 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations and the calibration solution in the syringe tip is ignored. 10.6 Preparation of calibration standard tubes from multiple standards. 10.6.1 If it is not possible to prepare one standard containing all the compounds of interest (e.g., because of chemical reactivity or the breadth of the volatility range), standard tubes can be prepared from multiple gas or liquid standards. 10.6.2 Follow the procedures described in Sections 10.4 and 10.5, respectively, for introducing each gas and/or liquid standard to the tube and load those containing the highest boiling compounds of interest first and the lightest species last. 10.7 Additional requirements for preparation of calibration tubes. 10.7.1 Storage of Calibration Standard Tubes 10.7.1.1 Seal tubes with long-term storage caps immediately after they have been disconnected from the standard loading manifold or injection apparatus. 10.7.1.2 Calibration standard tubes may be stored for no longer than 30 days and should be refrigerated if there is any risk of chemical interaction or degradation. Audit standards (see section 9.11) are exempt from this criteria and may be stored for the shelflife specified on their certificates. 10.8 Keep records for calibration standard tubes to include the following: 10.8.1 The stock number of any commercial liquid or gas standards used. 10.8.2 A chromatogram of the most recent blank for each tube used as a calibration standard together with the associated analytical conditions and date of cleaning. 10.8.3 Date of standard loading. 10.8.4 List of standard components, approximate masses and associated confidence levels. 10.8.5 Example analysis of an identical standard with associated analytical conditions. 10.8.6 A brief description of the method used for standard preparation. 10.8.7 The standard’s expiration date. 10.9 TD/GC/MS using standard tubes to calibrate system response. 10.9.1 Verify that the TD/GC/MS analytical system meets the instrument performance criteria given in Section 9.1. 10.9.2 The prepared calibration standard tubes must be analyzed using the analytical conditions applied to field samples (see Section 11.0) and must be selected to ensure quantitative transfer and adequate chromatographic resolution of target compounds, surrogates, and internal standards in order to enable reliable identification and quantitation of compounds of interest. The analytical conditions should also be sufficiently stringent to prevent buildup of higher boiling, non-target contaminants that may be collected on the tubes during field monitoring. 10.9.3 Calibration range. Each TD/GC/MS system must be calibrated at five concentrations that span the monitoring range of interest before being used for sample analysis. This initial multi-level calibration determines instrument sensitivity under the analytical conditions selected and the linearity of GC/MS response for the target compounds. One of the calibration points must be within a factor of five of the detection limit for the compounds of interest. 10.9.4 One of the calibration points from the initial calibration curve must be at the same concentration as the daily CCV standard (e.g., the mass collected when sampling air at typical concentrations). 10.9.5 Calibration frequency. Each GC/ MS system must be recalibrated with a full 5-point calibration curve following corrective action (e.g., ion source cleaning or repair, column replacement) or if the instrument fails the daily calibration acceptance criteria. 10.9.5.1 CCV checks must be carried out on a regular routine basis as described in Section 9.14. 10.9.5.2 Quantitation ions for the target compounds are shown in Table 10.1. Use the primary ion unless interferences are present, in which case you should use a secondary ion. TABLE 10.1—CLEAN AIR ACT VOLATILE ORGANIC COMPOUNDS FOR PASSIVE SORBENT SAMPLING Compound Vapor pressure (mmHg) a BP (°C) CAS No. Characteristic ion(s) MW b Primary Secondary 1,1-Dichloroethene ............................. 3-Chloropropene ................................ 1,1,2-Trichloro-1,2,2-trifluoroethane1,1-Dichloroethane ......................... 75–35–4 107–05–1 32 44.5 500 340 96.9 76.5 61 76 96 41, 39, 78 75–34–3 57.0 230 99 63 1,2-Dichloroethane ............................. 1,1,1-Trichloroethane ......................... Benzene ............................................. Carbon tetrachloride .......................... 1,2-Dichloropropane ........................... Trichloroethene .................................. 1,1,2-Trichloroethane ......................... Toluene .............................................. Tetrachloroethene .............................. Chlorobenzene ................................... Ethylbenzene ..................................... m,p-Xylene ......................................... 107–06–2 71–55–6 71–43–2 56–23–5 78–87–5 79–01–6 79–00–5 108–88–3 127–18–4 108–90–7 100–41–4 108–38–3, 106–42–3 100–42–5 95–47–6 106–46–7 83.5 74.1 80.1 76.7 97.0 87.0 114 111 121 132 136 138 61.5 100 76.0 90.0 42.0 20.0 19.0 22.0 14.0 8.8 7.0 6.5 99 133.4 78 153.8 113 131.4 133.4 92 165.8 112.6 106 106.2 62 97 78 117 63 95 83 92 164 112 91 106 65, 83, 85, 98, 100 98 99, 61 .............................. 119 112 97, 130, 132 97, 85 91 129, 131, 166 77, 114 106 91 145 144 173 6.6 5.0 0.60 104 106.2 147 104 106 146 78 91 111, 148 Styrene ............................................... o-Xylene ............................................. p-Dichlorobenzene ............................. a Pressure b Molecular tkelley on DSK3SPTVN1PROD with RULES2 11.0 in millimeters of mercury. weight. Analytical Procedure 11.1 Preparation for Sample Analysis 11.1.1 Each sequence of analyses must be ordered as follows: 11.1.1.1 CCV. 11.1.1.2 A laboratory blank. 11.1.1.3 Field blank. 11.1.1.4 Sample(s). 11.1.1.5 Field blank. 11.1.1.6 CCV after 10 field samples. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 11.1.1.7 batch. CCV at the end of the sample 11.2 Pre-desorption System Checks and Procedures 11.2.1 Ensure all sample tubes and field blanks are at ambient temperature before removing them from the storage container. 11.2.2 If using an automated TD/GC/MS analyzer, remove the long-term storage caps from the tubes, replace them with PO 00000 Frm 00164 Fmt 4701 Sfmt 4700 appropriate analytical caps, and load them into the system in the sequence described in Section 11.1. Alternatively, if using a manual system, uncap and analyze each tube, one at a time, in the sequence described in Section 11.1. 11.2.3 The following thermal desorption system integrity checks and procedures are required before each tube is analyzed. E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Note: Commercial thermal desorbers should implement these steps automatically. 11.2.3.1 Tube leak test: Each tube must be leak tested as soon as it is loaded into the carrier gas flow path before analysis to ensure data integrity. 11.2.3.2 Conduct the leak test at the GC carrier gas pressure, without heat or gas flow applied. Tubes that fail the leak test should not be analyzed, but should be resealed and stored intact. On automated systems, the instrument should continue to leak test and analyze subsequent tubes after a given tube has failed. Automated systems must also store and record which tubes in a sequence have failed the leak test. Information on failed tubes should be downloaded with the batch of sequence information from the analytical system. 11.2.3.3 Leak test the sample flow path. Leak check the sample flow path of the thermal desorber before each analysis without heat or gas flow applied to the sample tube. Stop the automatic sequence of tube desorption and GC analysis if any leak is detected in the main sample flow path. This process may be carried out as a separate step or as part of Section 11.2.3.2. 11.2.4 Optional Dry Purge 11.2.4.1 Tubes may be dry purged with a flow of pure dry gas passing into the tube from the sampling end, to remove water vapor and other very volatile interferents if required. 11.2.5 Internal Standard (IS) Addition 11.2.5.1 Use the internal standard addition function of the automated thermal desorber (if available) to introduce a precise aliquot of the internal standard to the sampling end of each tube after the leak test and shortly before primary (tube) desorption). Note: This step can be combined with dry purging the tube (Section 11.2.4) if required. 11.2.5.2 If the analyzer does not have a facility for automatic IS addition, gas or liquid internal standard can be manually introduced to the sampling end of tubes in a flow of carrier gas using the types of procedure described in Sections 10.3 and 10.4, respectively. 11.2.6 Pre-purge. Each tube should be purged to vent with carrier gas flowing in the desorption direction (i.e., flowing into the tube from the non-sampling end) to remove oxygen before heat is applied. This is to prevent analyte and sorbent oxidation and to prevent deterioration of key analyzer components such as the GC column and mass spectrometer (if applicable). A series of schematics illustrating these steps is presented in Figures 17.2 and 17.3. tkelley on DSK3SPTVN1PROD with RULES2 11.3 Analytical Procedure 11.3.1 Steps Required for Thermal Desorption 11.3.1.1 Ensure that the pressure and purity of purge and carrier gases supplying the TD/GC/MS system, meet manufacturer specifications and the requirements of this method. 11.3.1.2 Ensure also that the analytical method selected meets the QC requirements VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 of this method (Section 9) and that all the analytical parameters are at set point. 11.3.1.3 Conduct predesorption system checks (see Section 11.2). 11.3.1.4 Desorb the sorbent tube under conditions demonstrated to achieve >95 percent recovery of target compounds (see Section 9.5.2). Note: Typical tube desorption conditions range from 280–350 °C for 5–15 minutes with a carrier gas flow of 30–100 mL/min passing through the tube from the non-sampling end such that analytes are flushed out of the tube from the sampling end. Desorbed VOCs are concentrated (refocused) on a secondary, cooled sorbent trap integrated into the analytical equipment (see Figure 17.4). The focusing trap is typically maintained at a temperature between ¥30 and +30 °C during focusing. Selection of hydrophobic sorbents for focusing and setting a trapping temperature of +25 to 27 °C aid analysis of humid samples because these settings allow selective elimination of any residual water from the system, prior to GC/MS analysis. Note: The transfer of analytes from the tube to the focusing trap during primary (tube) desorption can be carried out splitless or under controlled split conditions (see Figure 17.4) depending on the masses of target compounds sampled and the requirements of the system—sensitivity, required calibration range, column overload limitations, etc. Instrument controlled sample splits must be demonstrated by showing the reproducibility using calibration standards. Field and laboratory blank samples must be analyzed at the same split as the lowest calibration standard. During secondary (trap) desorption the focusing trap is heated rapidly (typically at rates >40 °C/s) with inert (carrier) gas flowing through the trap (3–100 mL/min) in the reverse direction to that used during focusing. 11.3.1.5 The split conditions selected for optimum field sample analysis must also be demonstrated on representative standards. Note: Typical trap desorption temperatures are in the range 250–360 °C, with a ‘‘hold’’ time of 1–3 minutes at the highest temperature. Trap desorption automatically triggers the start of GC analysis. The trap desorption can also be carried out under splitless conditions (i.e., with everything desorbed from the trap being transferred to the analytical column and GC detector) or, more commonly, under controlled split conditions (see Figure 17.4). The selected split ratio depends on the masses of target compounds sampled and the requirements of the system—sensitivity, required calibration range, column overload limitations, etc. If a split is selected during both primary (trap) desorption and secondary (trap) desorption, the overall split ratio is the product of the two. Such ‘double’ split capability gives optimum flexibility for accommodating concentrated samples as well as trace-level samples on the TD/GC/MS analytical system. High resolution capillary columns and most GC/MS detectors tend to work best with approximately 20–200 ng per compound per tube to avoid saturation. The overall split ratio must be adjusted such that, when it is applied to the sample mass that is expected PO 00000 Frm 00165 Fmt 4701 Sfmt 4700 75341 to be collected during field monitoring, the amount reaching the column will be attenuated to fall within this range. As a rule of thumb this means that ∼20 ng samples will require splitless or very low split analysis, ∼2 mg samples will require a split ratio in the order of ∼50:1 and 200 mg samples will require a double split method with an overall split ratio in the order of 2,000:1. 11.3.1.6 Analyzed tubes must be resealed with long-term storage caps immediately after analysis (manual systems) or after completion of a sequence (automated systems). This prevents contamination, minimizing the extent of tube reconditioning required before subsequent reuse. 11.3.2 GC/MS Analytical Procedure 11.3.2.1 Heat/cool the GC oven to its starting set point. 11.3.2.2 If using a GC/MS system, it can be operated in either MS-Scan or MS–SIM mode (depending on required sensitivity levels and the type of mass spectrometer selected). As soon as trap desorption and transfer of analytes into the GC column triggers the start of the GC/MS analysis, collect mass spectral data over a range of masses from 35 to 300 amu. Collect at least 10 data points per eluting chromatographic peak in order to adequately integrate and quantify target compounds. 11.3.2.3 Use secondary ion quantitation only when there are sample matrix interferences with the primary ion. If secondary ion quantitation is performed, flag the data and document the reasons for the alternative quantitation procedure. 11.3.2.4 Data reduction is performed by the instruments post processing program that is automatically accessed after data acquisition is completed at the end of the GC run. The concentration of each target compound is calculated using the previously established response factors for the CCV analyzed in Section 11.1.1.6. 11.3.2.5 Whenever the thermal desorption—GC/MS analytical method is changed or major equipment maintenance is performed, you must conduct a new fivelevel calibration (see Section 10.6.3). System calibration remains valid as long as results from subsequent CCV are within 30 percent of the most recent 5-point calibration (see Section 10.9.5). Include relevant CCV data in the supporting information in the data report for each set of samples. 11.3.2.6 Document, flag and explain all sample results that exceed the calibration range. Report flags and provide documentation in the analytical results for the affected sample(s). 12.0 Data Analysis, Calculations, and Reporting 12.1 Recordkeeping Procedures for Sorbent Tubes 12.1.1 Label sample tubes with a unique identification number as described in Section 6.3. 12.1.2 Keep records of the tube numbers and sorbent lots used for each sampling period. 12.1.3 Keep records of sorbent tube packing if tubes are manually prepared in the E:\FR\FM\01DER2.SGM 01DER2 75342 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations laboratory and not supplied commercially. These records must include the masses and/ or bed lengths of sorbent(s) contained in each tube, the maximum allowable temperature for that tube and the date each tube was packed. If a tube is repacked at any stage, record the date of tube repacking and any other relevant information required in Section 12.1. 12.1.4 Keep records of the conditioning and blanking of tubes. These records must include, but are not limited to, the unique identification number and measured background resulting from the tube conditioning. 12.1.5 Record the location, dates, tube identification and times associated with each sample collection. Record this information on a Chain of Custody form that is sent to the analytical laboratory. 12.1.6 Field sampling personnel must complete and send a Chain of Custody to the analysis laboratory (see Section 8.6.4 of Method 325A for what information to include and Section 17.0 of this method for an example form). Duplicate copies of the Chain of Custody must be included with the sample report and stored with the field test data archive. 12.1.7 Field sampling personnel must also keep records of the unit vector wind direction, sigma theta, temperature and barometric pressure averages for the sampling period. See Section 8.3.4 of Method 325A. 12.1.8 Laboratory personnel must record the sample receipt date, and analysis date. 12.1.9 Laboratory personnel must maintain records of the analytical method and sample results in electronic or hardcopy in sufficient detail to reconstruct the calibration, sample, and quality control results from each sampling period. Where: As = Peak area for the characteristic ion of the analyte. Ais = Peak area for the characteristic ion of the internal standard. Ms = Mass of the analyte. Mis = Mass of the internal standard. 12.2.1.2 Standard deviation of the response factors (SDRF). Calculate the SDRF using Equation 12.2: Where: RFi = RF for each of the calibration compounds. RF = Mean RF for each compound from the initial calibration. n = Number of calibration standards. 12.2.1.3 Percent deviation (%DEV). Calculate the %DEV using Equation 12.3: Where: SDRF = Standard deviation. RF = Mean RF for each compound from the initial calibration. 12.2.1.4 Relative percent difference (RPD). Calculate the RPD using Equation 12.4: Where: R1, R2 = Values that are being compared (i.e., response factors in CCV). 12.2.2 Determine the equivalent concentration of compounds in atmospheres as follows. 12.2.3 Correct target concentrations determined at the sampling site temperature and atmospheric pressure to standard conditions (25 °C and 760 mm mercury) using Equation 12.5 (Reference 21). Where: tss = The average temperature during the collection period at the sampling site (K). Pss = The average pressure at the sampling site during the collection period (mm Hg). U = The diffusive uptake rate (sampling rate) (mL/min). 12.2 Calculations 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00166 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.038</GPH> ER01DE15.036</GPH> ER01DE15.037</GPH> VerDate Sep<11>2014 ER01DE15.035</GPH> tkelley on DSK3SPTVN1PROD with RULES2 ER01DE15.039</GPH> 12.2.1 Complete the calculations in this section to determine compliance with calibration quality control criteria (see also Table 17.1). 12.2.1.1 Response factor (RF). Calculate the RF using Equation 12.1: Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 12.2.4 For passive sorbent tube samples, calculate the concentration of the target compound(s) in the sampled air, in mg/m3 by using Equation 12.6 (Reference 22). Where: Cm = The concentration of target compound in the air sampled (mg/m3). mmeas = The mass of the compound as measured in the sorbent tube (mg). UNTP = The diffusive uptake rate corrected for local conditions (sampling rate) (mL/ min). t = The exposure time (minutes). Note: Diffusive uptake rates for common VOCs, using carbon sorbents packed into sorbent tubes of the dimensions specified in Section 6.1, are listed in Table 12.1. Adjust analytical conditions to keep expected sampled masses within range (see Sections 11.3.1.3 to 11.3.1.5). Best possible method 75343 detection limits are typically in the order of 0.1 ppb for 1,3-butadiene and 0.05 ppb for volatile aromatics such as benzene for 14-day monitoring. However, actual detection limits will depend upon the analytical conditions selected. TABLE 12.1—VALIDATED SORBENTS AND UPTAKE RATES (ML/MIN) FOR SELECTED CLEAN AIR ACT COMPOUNDS 1,1-Dichloroethene .............................................................................................. 3-Chloropropene ................................................................................................. 1,1-Dichloroethane .............................................................................................. 1,2-Dichloroethane .............................................................................................. 1,1,1-Trichloroethane .......................................................................................... Benzene .............................................................................................................. Carbon tetrachloride ........................................................................................... 1,2-Dichloropropane ........................................................................................... Trichloroethene ................................................................................................... 1,1,2-Trichloroethane .......................................................................................... Toluene ............................................................................................................... Tetrachloroethene ............................................................................................... Chlorobenzene .................................................................................................... Ethylbenzene ...................................................................................................... m,p-Xylene .......................................................................................................... Styrene ................................................................................................................ o-Xylene .............................................................................................................. p-Dichlorobenzene .............................................................................................. b Reference c Reference tkelley on DSK3SPTVN1PROD with RULES2 13.0 not available not available not available not available not available 0.63 ± 0.07b not available not available not available not available 0.56 ± 0.06c not available not available not available 0.47 ± 0.04c not available 0.47 ± 0.04c not available .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... .......... not available. not available. not available. not available. not available. 0.63 ± 0.07b. not available. not available. not available. not available. 0.56 ± 0.06c. not available. not available. 0.50c. 0.47 ± 0.04c. not available. 0.47 ± 0.04c. not available. 3, McClenny, J. Environ. Monit. 7:248–256. Based on 24-hour duration. 24, BS EN 14662–4:2005 (incorporated by reference—see § 63.14). Based on 14-day duration. 25, ISO 16017–2:2003(E) (incorporated by reference—see § 63.14). Based on 14-day duration. Method Performance The performance of this procedure for VOC not listed in Table 12.1 is determined using the procedure in Addendum A of this Method or by one of the following national/ international standard methods: ISO 16017– 2:2003(E), ASTM D6196–03 (Reapproved 2009), or BS EN 14662–4:2005 (all incorporated by reference—see § 63.14). 13.1 The valid range for measurement of VOC is approximately 0.5 mg/m3 to 5 mg/m3 in air, collected over a 14-day sampling period. The upper limit of the useful range depends on the split ratio selected (Section 11.3.1) and the dynamic range of the analytical system. The lower limit of the useful range depends on the noise from the analytical instrument detector and on the blank level of target compounds or interfering compounds on the sorbent tube (see Section 13.3). 13.2 Diffusive sorbent tubes compatible with passive sampling and thermal desorption methods have been evaluated at relatively high atmospheric concentrations (i.e., mid-ppb to ppm) and published for use in workplace air and industrial/mobile source emissions (References 15–16, 21–22). VerDate Sep<11>2014 0.57 ± 0.14 0.51 ± 0.3 0.57 ± 0.1 0.57 ± 0.08 0.51 ± 0.1 0.67 ± 0.06 0.51 ± 0.06 0.52 ± 0.1 0.5 ± 0.05 0.49 ± 0.13 0.52 ± 0.14 0.48 ± 0.05 0.51 ± 0.06 0.46 ± 0.07 0.46 ± 0.09 0.5 ± 0.14 0.46 ± 0.12 0.45 ± 0.05 CarbopackTM B 23:11 Nov 30, 2015 Jkt 238001 13.3 Best possible detection limits and maximum quantifiable concentrations of air pollutants range from sub-part-per-trillion (sub-ppt) for halogenated species such as CCl4 and the freons using an electron capture detector (ECD), SIM Mode GC/MS, triple quad MS or GC/TOF MS to sub-ppb for volatile hydrocarbons collected over 72 hours followed by analysis using GC with quadrupole MS operated in the full SCAN mode. 13.3.1 Actual detection limits for atmospheric monitoring vary depending on several key factors. These factors are: • Minimum artifact levels. • GC detector selection. • Time of exposure for passive sorbent tubes. • Selected analytical conditions, particularly column resolution and split ratio. 14.0 Pollution Prevention This method involves the use of ambient concentrations of gaseous compounds that post little or no danger of pollution to the environment. PO 00000 Frm 00167 Fmt 4701 Sfmt 4700 15.0 Waste Management Dispose of expired calibration solutions as hazardous materials. Exercise standard laboratory environmental practices to minimize the use and disposal of laboratory solvents. 16.0 References 1. Winberry, W. T. Jr., et al., Determination of Volatile Organic Compounds in Ambient Air Using Active Sampling onto Sorbent Tubes: Method TO–17r, Second Edition, U.S. Environmental Protection Agency, Research Triangle Park, NC 27711, January 1999. https://www.epa. gov/ttnamti1/airtox.html#compendium 2. Ciccioli, P., Brancaleoni, E., Cecinato, A., Sparapini, R., and Frattoni, M., ‘‘Identification and Determination of Biogenic and Anthropogenic VOCs in Forest Areas of Northern and Southern Europe and a Remote Site of the Himalaya Region by High-resolution GC– MS,’’ J. of Chrom., 643, pp 55–69, 1993. 3. McClenny, W.A., K.D. Oliver, H.H. Jacumin, Jr., E.H. Daughtrey, Jr., D.A. Whitaker. 2005. 24 h diffusive sampling of toxic VOCs in air onto CarbopackTM X solid adsorbent followed by thermal E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.040</GPH> a Reference CarbographTM1 TD CarbopackTM Xa Compound 75344 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations desorption/GC/MS analysis—laboratory studies. J. Environ. Monit. 7:248–256. 4. Markes International (www.markes.com/ publications): Thermal desorption Technical Support Note 2: Prediction of uptake rates for diffusive tubes. 5. Ciccioli, P., Brancaleoni, E., Cecinato, A., DiPalo, C., Brachetti, A., and Liberti, A., ‘‘GC Evaluation of the Organic Components Present in the Atmosphere at Trace Levels with the Aid of CarbopackTM B for Preconcentration of the Sample,’’ J. of Chrom., 351, pp 433– 449, 1986. 6. Broadway, G. M., and Trewern, T., ‘‘Design Considerations for the Optimization of a Packed Thermal Desorption Cold Trap for Capillary Gas Chromatography,’’ Proc. 13th Int’l Symposium on Capil. Chrom., Baltimore, MD, pp 310–320, 1991. 7. Broadway, G. M., ‘‘An Automated System for use Without Liquid Cryogen for the Determination of VOC’s in Ambient Air,’’ Proc. 14th Int’l. Symposium on Capil. Chrom., Baltimore, MD, 1992. 8. Gibitch, J., Ogle, L., and Radenheimer, P., ‘‘Analysis of Ozone Precursor Compounds in Houston, Texas Using Automated Continuous GCs,’’ in Proceedings of the Air and Waste Management Association Conference: Measurement of Toxic and Related Air Pollutants, Air and Waste Management Association, Pittsburgh, PA, May 1995. 9. Vandendriessche, S., and Griepink, B., ‘‘The Certification of Benzene, Toluene and m-Xylene Sorbed on Tenax® TA in Tubes,’’ CRM–112 CEC, BCR, EUR12308 EN, 1989. 10. MDHS 2 (Acrylonitrile in Air), ‘‘Laboratory Method Using Porous Polymer Adsorption Tubes, and Thermal Desorption with Gas Chromatographic Analysis,’’ Methods for the Determination of Hazardous Substances (MDHS), UK Health and Safety Executive, Sheffield, UK. 11. MDHS 22 (Benzene in Air), ‘‘Laboratory Method Using Porous Polymer Adsorbent Tubes, Thermal Desorption and Gas Chromatography,’’ Method for the Determination of Hazardous Substances (MDHS), UK Health and Safety Executive, Sheffield, UK. 12. MDHS 23 (Glycol Ether and Glycol Acetate Vapors in Air), ‘‘Laboratory Method Using Tenax® Sorbent Tubes, Thermal Desorption and Gas Chromatography,’’ Method for the Determination of Hazardous Substances (MDHS), UK Health and Safety Executive, Sheffield, UK. 13. MDHS 40 (Toluene in air), ‘‘Laboratory Method Using Pumped Porous Polymer Adsorbent Tubes, Thermal Desorption and Gas Chromatography,’’ Method for the Determination of Hazardous Substances (MDHS), UK Health and Safety Executive, Sheffield, UK. 14. MDHS 60 (Mixed Hydrocarbons (C to C) in Air), ‘‘Laboratory Method Using Pumped Porous Polymer 3 10 and Carbon Sorbent Tubes, Thermal Desorption and Gas Chromatography,’’ Method for the Determination of Hazardous Substances (MDHS), UK Health and Safety Executive, Sheffield, UK. 15. Price, J. A., and Saunders, K. J., ‘‘Determination of Airborne Methyl tertButyl Ether in Gasoline Atmospheres,’’ Analyst, Vol. 109, pp. 829–834, July 1984. 16. Coker, D. T., van den Hoed, N., Saunders, K. J., and Tindle, P. E., ‘‘A Monitoring Method for Gasoline Vapour Giving Detailed Composition,’’ Ann. Occup, Hyg., Vol 33, No. 11, pp 15–26, 1989. 17. DFG, ‘‘Analytische Methoden zur prufing gesundheitsschadlicher Arbeistsstoffe,’’ Deutsche Forschungsgemeinschaft, Verlag Chemie, Weinheim FRG, 1985. 18. NNI, ‘‘Methods in NVN Series (Luchtkwaliteit; Werkplekatmasfeer),’’ Nederlands Normailsatie—Institut, Delft, The Netherlands, 1986–88. 19. ‘‘Sampling by Solid Adsorption Techniques,’’ Standards Association of Australia Organic Vapours, Australian Standard 2976, 1987. 20. Woolfenden, E. A., ‘‘Monitoring VOCs in Air Using Pumped Sampling onto Sorbent Tubes Followed by Thermal Desorption-capillary GC Analysis: Summary of Reported Data and Practical Guidelines for Successful Application,’’ J. Air & Waste Manage. Assoc., Vol. 47, 1997, pp. 20–36. 21. Validation Guidelines for Air Sampling Methods Utilizing Chromatographic Analysis, OSHA T–005, Version 3.0, May 2010, https://www.osha.gov/dts/sltc/ methods/chromguide/chromguide.pdf. 22. ASTM D4597–10, Standard Practice for Sampling Workplace Atmospheres to collect Gases or Vapors with Solid Sorbent Diffusive Samplers. 23. Martin, https://www.hsl.gov.uk/media/ 1619/issue14.pdf. 24. BS EN 14662–4:2005, Ambient air quality—Standard method for the measurement of benzene concentrations—Part 4: Diffusive sampling followed by thermal desorption and gas chromatography. 25. ISO 16017–2:2003(E): Indoor, ambient and workplace air—Sampling and analysis of volatile organic compounds by sorbent tube/thermal desorption/ capillary gas chromatography—Part 2: Diffusive sampling. 17.0 Tables, Diagrams, Flowcharts and Validation Data TABLE 17.1—SUMMARY OF GC/MS ANALYSIS QUALITY CONTROL PROCEDURES Frequency Acceptance criteria Corrective action Bromofluorobenzene Instrument Tune Performance Check. Five point calibration bracketing the expected sample concentration. Dailya prior to sample analysis ..... Evaluation criteria presented in Section 9.5 and Table 9.2. (1) Percent Deviation (%DEV) of response factors ±30%. (2) Relative Retention Times (RRTs) for target peaks ±0.06 units from mean RRT. Calibration Verification (CCV Second source calibration verification check). Laboratory Blank Analysis ............. tkelley on DSK3SPTVN1PROD with RULES2 Parameter Following the calibration curve ..... (1) Retune and or (2) Perform Maintenance. (1) Repeat calibration sample analysis. (2) Repeat linearity check. (3) Prepare new calibration standards as necessary and repeat analysis. (1) Repeat calibration check. (2) Repeat calibration curve. Blank Sorbent Tube Certification ... Samples—Internal Standards ........ a Every Following any major change, repair or maintenance or if daily CCV does not meet method requirements. Recalibration not to exceed three months. Daily a following bromofluoro- benzene and calibration check; prior to sample analysis. One tube analyzed for each batch of tubes cleaned or 10 percent of tubes whichever is greater. All samples ................................... The response factor ±30% DEV from calibration curve average response factor. (1) ≤0.2 ppbv per analyte or ≤3 times the LOD, whichever is greater. (2) Internal Standard (IS) area response ±40% and IS Retention Time (RT) ±0.33 min. of most recent calibration check. <0.2 ppbv per VOC targeted compound or 3 times the LOD, whichever is greater. IS area response ±40% and IS RT ±0.33 min. of most recent calibration validation. (1) Repeat analysis with new blank tube. (2) Check system for leaks, contamination. 3) Analyze additional blank. Reclean all tubes in batch and reanalyze. Flag Data for possible invalidation. 24 hours. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00168 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75345 BILLING CODE 6560–50–P Method 325 A/B EXAMPLE FIELD TEST DATA SHEET (FTDS) AND CHAIN OF CUSTODY I. GENERAL INFORMATION SITE NAME: SITE LOCATION ADDRESS: CITY: STATE: ZIP: II. SAMPLING DATA Sample ID (Tube) # Sorbent Sample or blank Start Date Start Time Stop Date Stop Time Location (gps) Ambient Temp. (oF) Barometric Pressure (in. Hg) III. CUSTODY INFORMATION COLLECTED BY: Relinquished to Shipper Date: Name: Received by Laboratory Name Date: Sample condition upon receipt: Time Time Analysis Required: Figure 17.1. Example Field Data From and Chain of Custody VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00169 Fmt 4701 Sfmt 4725 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.041</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Comments: 75346 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations GCAoalytical Column To Detector T •••\ l···························r·················~······ . I ' : l : : : : : M 1M JiiC * •• •• •* • •• SOrbentTube at Ambient Temperature Cold Sorbeot Focusing Trap I I·····® I Pressure Transducer Split Flow Vent Closed •* --Flow •··••··· Pressure, No Flow Desorb Flow Vent Closed CarrierGas - - - . . . - Supplyln VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00170 Fmt 4701 Sfmt 4725 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.042</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Figure 17.2. Schematic of Ther.mal Desorption Flow Path During Leak Testing Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations 75347 GC Analytical Column lQOetectcir Cold Sorbent Focusing Pressure ·····® Transducer Trap SorbentTube at Ambient Temperature Split Flow Vent Open (optional) liiE liiE •• --Flow •••••••• Pressure, No Flow Desorb Flow Vent Closed (optional) Carrier Gas Supply In CarrierGas;.__ _ _, Supply In Pressurised Internal Standard (IS) Gas In GCAnalvtlcal Column To Detector Cold Sorbent * Focu~il'lll ·····@ Ill( Pressure Tran•duCIIr *Trap SorbentTube at Ambient Ill Temperature • Split Flow Vent • • • --Flow •••••••• Pressure, No Flow Vent Desorb flow Vent Closlild Clrriet Gas Sopplyln - - - - ' VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00171 Fmt 4701 Sfmt 4725 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.043</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Figure 17.3. Schematic of Thermal Desorption Flow During Purge of Air (Top) and Addition of IS Gas to the Sorbent Tube (Bottom) 75348 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations &Analytical Column To l:letector I j I'::\ r···\!:!1 Pressure Transducer ! 1 Sorbent TUbe at Elevated Temperature Split Row Vent (Optional for Inlet Split) -Flow •••···•· Pressure, No Flow Carrier Gas Desorb Aow Vent Open Supply in Carder Gas._ _ __. Supply In GCAnalytlcal Column To l:letector ( ......................... i I'::\ Pressure SQrbent FocuslngTrap at Elevated Temperature SorbentTube ••••v:.:.~ Transducer Coolin& Split Aow Vent (Optional for Outlet Split) --Flow J Carrier Gas •·•···•· Pressure, No Flow !--··" Supply in BILLING CODE 6560–50–C A.1 ADDENDUM A to Method 325B—Method 325 Performance Evaluation VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 Scope and Application A.1.1 To be measured by Methods 325A and 325B, each new target volatile organic compound (VOC) or sorbent that is not listed in Table 12.1 must be evaluated by exposing PO 00000 Frm 00172 Fmt 4701 Sfmt 4700 the selected sorbent tube to a known concentration of the target compound(s) in an exposure chamber following the procedure in this Addendum or by following the procedures in the national/international standard methods: ISO 16017–2:2003(E), E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.044</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Figure 17.4. Schematic of Ther.mal Desorption Flow Path During Primary (Tube) Desorption (Top) and Secondary (Trap) Desorption and Transfer to the GC (Bottom) Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations ASTM D6196–03 (Reapproved 2009), or BS EN 14662–4:2005 (all incorporated by reference—see § 63.14), or reported in peerreviewed open literature. A.1.2 You must determine the uptake rate and the relative standard deviation compared to the theoretical concentration of volatile material in the exposure chamber for each of the tests required in this method. If data that meet the requirement of this Addendum are available in the peer reviewed open literature for VOCs of interest collected on your passive sorbent tube configuration, then such data may be submitted in lieu of the testing required in this Addendum. A.1.3 You must expose sorbent tubes in a test chamber to parts per trillion by volume (pptv) and low parts per billion by volume (ppbv) concentrations of VOCs in humid atmospheres to determine the sorbent tube uptake rate and to confirm compound capture and recovery. A.2 Summary of Method tkelley on DSK3SPTVN1PROD with RULES2 Note: The technique described here is one approach for determining uptake rates for new sorbent/sorbate pairs. It is equally valid to follow the techniques described in any one of the following national/international standards methods: ISO 16017–2:2003(E), ASTM D6196–03 (Reapproved 2009), or BS EN 14662–4:2005 (all incorporated by reference—see § 63.14). A.2.1 Known concentrations of VOC are metered into an exposure chamber containing sorbent tubes filled with media selected to capture the volatile organic compounds of interest (see Figure A.1 and A.2 for an example of the exposure chamber and sorbent tube retaining rack). VOC are diluted with humid air and the chamber is allowed to equilibrate for 6 hours. Clean passive sampling devices are placed into the chamber and exposed for a measured period of time. The passive uptake rate of the passive sampling devices is determined using the standard and dilution gas flow rates. Chamber concentrations are confirmed with whole gas sample collection and analysis or direct interface volatile organic compound measurement methods. A.2.2 An exposure chamber and known gas concentrations must be used to challenge and evaluate the collection and recovery of target compounds from the sorbent and tube selected to perform passive measurements of VOC in atmospheres. A.3 Definitions A.3.1 cc is cubic centimeter. A.3.2 ECD is electron capture detector. A.3.3 FID is flame ionization detector. A.3.4 LED is light-emitting diode. A.3.5 MFC is mass flow controller. A.3.6 MFM is mass flow meter. A.3.7 min is minute. A.3.8 ppbv is parts per billion by volume. A.3.9 ppmv is parts per million by volume. A.3.10 PSD is passive sampling device. A.3.11 psig is pounds per square inch gauge. A.3.12 RH is relative humidity. A.3.13 VOC is volatile organic compound. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 A.4 Interferences A.4.1 VOC contaminants in water can contribute interference or bias results high. Use only distilled, organic-free water for dilution gas humidification. A.4.2 Solvents and other VOC-containing liquids can contaminate the exposure chamber. Store and use solvents and other VOC-containing liquids in the exhaust hood when exposure experiments are in progress to prevent the possibility of contamination of VOCs into the chamber through the chamber’s exhaust vent. Note: Whenever possible, passive sorbent evaluation should be performed in a VOC free laboratory. A.4.3 PSDs should be handled by personnel wearing only clean, white cotton or powder free nitrile gloves to prevent contamination of the PSDs with oils from the hands. A.4.4 This performance evaluation procedure is applicable to only volatile materials that can be measured accurately with direct interface gas chromatography or whole gas sample collection, concentration and analysis. Alternative methods to confirm the concentration of volatile materials in exposure chambers are subject to Administrator approval. A.5 Safety A.5.1 This procedure does not address all of the safety concerns associated with its use. It is the responsibility of the user of this standard to establish appropriate field and laboratory safety and health practices and determine the applicability of regulatory limitations prior to use. A.5.2 Laboratory analysts must exercise appropriate care in working with highpressure gas cylinders. A.6 Equipment and Supplies A.6.1 You must use an exposure chamber of sufficient size to simultaneously expose a minimum of eight sorbent tubes. A.6.2 Your exposure chamber must not contain VOC that interfere with the compound under evaluation. Chambers made of glass and/or stainless steel have been used successfully for measurement of known concentration of selected VOC compounds. A.6.3 The following equipment and supplies are needed: • Clean, white cotton or nitrile gloves; • Conditioned passive sampling device tubes and diffusion caps; and • NIST traceable high resolution digital gas mass flow meters (MFMs) or flow controllers (MFCs). A.7 Reagents and Standards A.7.1 You must generate an exposure gas that contains between 35 and 75 percent relative humidity and a concentration of target compound(s) within 2 to 5 times the concentration to be measured in the field. A.7.2 Target gas concentrations must be generated with certified gas standards and diluted with humid clean air. Dilution to reach the desired concentration must be done with zero grade air or better. A.7.3 The following reagents and standards are needed: • Distilled water for the humidification; PO 00000 Frm 00173 Fmt 4701 Sfmt 4700 75349 • VOC standards mixtures in high-pressure cylinder certified by the supplier (Note: The accuracy of the certified standards has a direct bearing on the accuracy of the measurement results. Typical vendor accuracy is ±5 percent accuracy but some VOC may only be available at lower accuracy (e.g., acrolein at 10 percent)); and • Purified dilution air containing less than 0.2 ppbv of the target VOC. A.8 Sample Collection, Preservation and Storage A.8.1 You must use certified gas standards diluted with humid air. Generate humidified air by adding distilled organic free water to purified or zero grade air. Humidification may be accomplished by quantitative addition of water to the air dilution gas stream in a heated chamber or by passing purified air through a humidifying bubbler. You must control the relative humidity in the test gas throughout the period of passive sampler exposure. Note: The RH in the exposure chamber is directly proportional to the fraction of the purified air that passes through the water in the bubbler before entering the exposure chamber. Achieving uniform humidification in the proper range is a trial-and-error process with a humidifying bubbler. You may need to heat the bubbler to achieve sufficient humidity. An equilibration period of approximately 15 minutes is required following each adjustment of the air flow through the humidifier. Several adjustments or equilibration cycles may be required to achieve the desired RH level. Note: You will need to determine both the dilution rate and the humidification rate for your design of the exposure chamber by trial and error before performing method evaluation tests. A.8.2 Prepare and condition sorbent tubes following the procedures in Method 325B Section 7.0. A.8.3 You must verify that the exposure chamber does not leak. A.8.4 You must complete two evaluation tests using a minimum of eight passive sampling tubes in each test with less than 5percent depletion of test analyte by the samplers. A.8.4.1 Perform at least one evaluation at two to five times the estimated analytical detection limit or less. A.8.4.2 Perform second evaluation at a concentration equivalent to the middle of the analysis calibration range. A.8.5 You must evaluate the samplers in the test chamber operating between 35 percent and 75 percent RH, and at 25 ± 5 °C. Allow the exposure chamber to equilibrate for 6 hours before starting an evaluation. A.8.6 The flow rate through the chamber must be ≤0.5 meter per second face velocity across the sampler face. A.8.7 Place clean, ready to use sorbent tubes into the exposure chamber for predetermined amounts of time to evaluate collection and recovery from the tubes. The exposure time depends on the concentration of volatile test material in the chamber and the detection limit required for the sorbent tube sampling application. Exposure time E:\FR\FM\01DER2.SGM 01DER2 75350 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations should match sample collection time. The sorbent tube exposure chamber time may not be less than 24 hours and should not be longer than 2 weeks. A.8.7.1 To start the exposure, place the clean PSDs equipped with diffusion caps on the tube inlet into a retaining rack. A.8.7.2 Place the entire retaining rack inside the exposure chamber with the diffusive sampling end of the tubes facing into the chamber flow. Seal the chamber and record the exposure start time, chamber RH, chamber temperature, PSD types and numbers, orientation of PSDs, and volatile material mixture composition (see Figure A.2). A.8.7.3 Diluted, humidified target gas must be continuously fed into the exposure chamber during cartridge exposure. Measure the flow rate of target compound standard gas and dilution air to an accuracy of 5 percent. A.8.7.4 Record the time, temperature, and RH at the beginning, middle, and end of the exposure time. A.8.7.5 At the end of the exposure time, remove the PSDs from the exposure chamber. Record the exposure end time, chamber RH, and temperature. BILLING CODE 6560–50–P VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00174 Fmt 4701 Sfmt 4725 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.045</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Figure A.l. Example Sorbent Tube Exposure Chamber VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00175 Fmt 4701 Sfmt 4725 E:\FR\FM\01DER2.SGM 01DER2 75351 ER01DE15.046</GPH> tkelley on DSK3SPTVN1PROD with RULES2 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations BILLING CODE 6560–50–C tkelley on DSK3SPTVN1PROD with RULES2 A.9 Quality Control A.9.1 Monitor and record the exposure chamber temperature and RH during PSD exposures. A.9.2 Measure the flow rates of standards and purified humified air immediately following PSD exposures. A.10 Calibration and Standardization A.10.1 Follow the procedures described in Method 325B Section 10.0 for calibration. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 A.10.2 Verify chamber concentration by direct injection into a gas chromatograph calibrated for the target compound(s) or by collection of an integrated SUMMA canister followed by analysis using a preconcentration gas chromatographic method such as EPA Compendium Method TO–15, Determination of VOCs in Air Collected in Specially-Prepared Canisters and Analyzed By GC/MS. A.10.2.1 To use direct injection gas chromatography to verify the exposure chamber concentration, follow the procedures in Method 18 of 40 CFR part 60, PO 00000 Frm 00176 Fmt 4701 Sfmt 4700 Appendix A–6. The method ASTM D6420– 99 (Reapproved 2010) (incorporated by reference—see § 63.14) is an acceptable alternative to EPA Method 18 of 40 CFR part 60). Note: Direct injection gas chromatography may not be sufficiently sensitive for all compounds. Therefore, the whole gas preconcentration sample and analysis method may be required to measure at low concentrations. A.10.2.2 To verify exposure chamber concentrations using SUMMA canisters, E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.047</GPH> 75352 75353 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations prepare clean canister(s) and measure the concentration of VOC collected in an integrated SUMMA canister over the period used for the evaluation (minimum 24 hours). Analyze the TO–15 canister sample following EPA Compendium Method TO–15. A.10.2.3 Compare the theoretical concentration of volatile material added to the test chamber to the measured concentration to confirm the chamber operation. Theoretical concentration must agree with the measured concentration within 30 percent. A.11 Analysis Procedure Analyze the sorbent tubes following the procedures described in Section 11.0 of Method 325B. A.12 Recordkeeping Procedures for Sorbent Tube Evaluation Keep records for the sorbent tube evaluation to include at a minimum the following information: A.12.1 Sorbent tube description and specifications. A.12.2 Sorbent material description and specifications. A.12.3 Volatile analytes used in the sampler test. A.12.4 Chamber conditions including flow rate, temperature, and relative humidity. A.12.5 Relative standard deviation of the sampler results at the conditions tested. A.12.6 95 percent confidence limit on the sampler overall accuracy. A.12.7 The relative accuracy of the sorbent tube results compared to the direct chamber measurement by direct gas chromatography or SUMMA canister analysis. A.13 Method Performance A.13.1 Sorbent tube performance is acceptable if the relative accuracy of the passive sorbent sampler agrees with the active measurement method by ±10 percent at the 95 percent confidence limit and the uptake ratio is equal to greater than 0.5 mL/ min (1 ng/ppm-min). Note: For example, there is a maximum deviation comparing Perkin-Elmer passive type sorbent tubes packed with CarbopackTM X of 1.3 to 10 percent compared to active sampling using the following uptake rates. 1,3-butadiene uptake rate mL/min CarbopackTM X (2 week) ......................................................... Estimated detection limit (2 week) Benzene uptake rates mL/min Estimated detection limit (2 week) 0.61 ± 0.11 a 0.1 ppbv 0.67 a 0.05 ppbv a McClenny, CarbopackTM W.A., K.D. Oliver, H.H. Jacumin, Jr., E.H. Daughtrey, Jr., D.A. Whitaker. 2005. 24 h diffusive sampling of toxic VOCs in air onto X solid adsorbent followed by thermal desorption/GC/MS analysis—laboratory studies. J. Environ. Monit. 7:248–256. Cs = The concentration of target compound in the standard cylinder (parts per million by volume). A.13.2.3 Determine the uptake rate of the target gas being evaluated using Equation A.2. Tt = The exposure time (minutes). A.13.2.4 Estimate the variance (relative standard deviation (RSD)) of the intersampler results at each condition tested using Equation A.3. RSD for the sampler is estimated by pooling the variance estimates from each test run. Where: Xi = The measured mass of analyte found on sorbent tube i. Xi = The mean value of all Xi. n = The number of measurements of the analyte. A.13.2.4 Determine the percent relative standard deviation of the inter-sampler results using Equation A.4. VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00177 Fmt 4701 Sfmt 4700 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.049</GPH> Where: Mx = The mass of analyte measured on the sampling tube (hg). Ce = The theoretical exposure chamber concentration (hg/mL). ER01DE15.048</GPH> FRt = The flow rate of all target compounds from separate if multiple cylinders are used (mL/min). FRa = The flow rate of dilution air plus moisture (mL/min). ER01DE15.050</GPH> A.13.2.1 Calculate the theoretical concentration of VOC standards using Equation A.1. Where: Cf = The final concentration of standard in the exposure chamber (ppbv). FRi = The flow rate of the target compound I (mL/min). tkelley on DSK3SPTVN1PROD with RULES2 A13.2 Data Analysis and Calculations for Method Evaluation 75354 Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations is determined based on the number of test runs performed to evaluate the sorbent tube and sorbent combination. For the minimum test requirement of eight samplers tested at two concentrations, the number of tests is 16 and the degrees of freedom are 15. Where: D95% = 95 percent confidence interval. %RSD = percent relative standard deviation. t0.95 = The Students t statistic for f degrees of freedom at 95 percent confidence. f = The number of degrees of freedom. n = Number of samples. A.13.2.6 Determine the relative accuracy of the sorbent tube combination compared to the active sampling results using Equation A.6. Where: RA = Relative accuracy. Xi = The mean value of all Xi. Xi = The average concentration of analyte measured by the active measurement method. D95% = 95 percent confidence interval. A.14 Pollution Prevention This method involves the use of ambient concentrations of gaseous compounds that post little or no pollution to the environment. A.16 A.15 Waste Management Expired calibration solutions should be disposed of as hazardous materials. [FR Doc. 2015–26486 Filed 11–30–15; 8:45 am] References 1. ISO TC 146/SC 02 N 361 Workplace atmospheres—Protocol for evaluating the performance of diffusive samplers. ER01DE15.052</GPH> ER01DE15.053</GPH> BILLING CODE 6560–50–P VerDate Sep<11>2014 23:11 Nov 30, 2015 Jkt 238001 PO 00000 Frm 00178 Fmt 4701 Sfmt 9990 E:\FR\FM\01DER2.SGM 01DER2 ER01DE15.051</GPH> tkelley on DSK3SPTVN1PROD with RULES2 A.13.2.5 Determine the 95 percent confidence interval for the sampler results using Equation A.5. The confidence interval

Agencies

ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 80, Number 230 (Tuesday, December 1, 2015)]
[Rules and Regulations]
[Pages 75177-75354]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-26486]

[[Page 75177]]

Vol. 80

Tuesday,

No. 230

December 1, 2015

Part II

Environmental Protection Agency

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40 CFR Parts 60 and 63

Petroleum Refinery Sector Risk and Technology Review and New Source
Performance Standards; Final Rule

Federal Register / Vol. 80 , No. 230 / Tuesday, December 1, 2015 /
Rules and Regulations

[[Page 75178]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2010-0682; FRL-9935-40-OAR]
RIN 2060-AQ75

Petroleum Refinery Sector Risk and Technology Review and New
Source Performance Standards

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: This action finalizes the residual risk and technology review
conducted for the Petroleum Refinery source categories regulated under
national emission standards for hazardous air pollutants (NESHAP)
Refinery MACT 1 and Refinery MACT 2. It also includes revisions to the
Refinery MACT 1 and MACT 2 rules in accordance with provisions
regarding establishment of MACT standards. This action also finalizes
technical corrections and clarifications for the new source performance
standards (NSPS) for petroleum refineries to improve consistency and
clarity and address issues related to a 2008 industry petition for
reconsideration. Implementation of this final rule will result in
projected reductions of 5,200 tons per year (tpy) of hazardous air
pollutants (HAP) which will reduce cancer risk and chronic health
effects.

DATES: This final action is effective on February 1, 2016. The
incorporation by reference of certain publications for part 63 listed
in the rule is approved by the Director of the Federal Register as of
February 1, 2016. The incorporation by reference of certain
publications for part 60 listed in the rule were approved by the
Director of the Federal Register as of June 24, 2008.

ADDRESSES: The Environmental Protection Agency (EPA) has established a
docket for this action under Docket ID No. EPA-HQ-OAR-2010-0682. All
documents in the docket are listed on the www.regulations.gov Web site.
Although listed in the index, some information is not publicly
available, e.g., confidential business information (CBI) or other
information whose disclosure is restricted by statute. Certain other
material, such as copyrighted material, is not placed on the Internet
and will be publicly available only in hard copy form. Publicly
available docket materials are available either electronically through
https://www.regulations.gov, or in hard copy at the EPA Docket Center,
WJC West Building, Room Number 3334, 1301 Constitution Ave. NW.,
Washington, DC. The Public Reading Room hours of operation are 8:30
a.m. to 4:30 p.m. Eastern Standard Time (EST), Monday through Friday.
The telephone number for the Public Reading Room is (202) 566-1744, and
the telephone number for the Air and Radiation Docket and Information
Center is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For questions about this final action,
contact Ms. Brenda Shine, Sector Policies and Programs Division,
Refining and Chemicals Group (E143-01), Office of Air Quality Planning
and Standards, U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, 27711; telephone number: (919) 541-3608; fax
number: (919) 541-0246; and email address: shine.brenda@epa.gov. For
specific information regarding the risk modeling methodology, contact
Mr. Ted Palma, Health and Environmental Impacts Division (C539-02),
Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711;
telephone number: (919) 541-5470; fax number: (919) 541-0840; and email
address: palma.ted@epa.gov. For information about the applicability of
the NESHAP to a particular entity, contact Ms. Maria Malave, Office of
Enforcement and Compliance Assurance, U.S. Environmental Protection
Agency, William Jefferson Clinton Building, 1200 Pennsylvania Ave. NW.,
Washington, DC 20460; telephone number: (202) 564-7027; fax number:
(202) 564-0050; and email address: malave.maria@epa.gov.

SUPPLEMENTARY INFORMATION:
Preamble Acronyms and Abbreviations. We use multiple acronyms and
terms in this preamble. While this list may not be exhaustive, to ease
the reading of this preamble and for reference purposes, the EPA
defines the following terms and acronyms here:

10/25 tpy emissions equal to or greater than 10 tons per year of a
single pollutant or 25 tons per year of cumulative pollutants
AEGL acute exposure guideline levels
APCD air pollution control devices
API American Petroleum Institute
BAAQMD Bay Area Air Quality Management District
BDT best demonstrated technology
BLD bag leak detectors
BSER best system of emission reductions
Btu/ft² British thermal units per square foot
Btu/scf British thermal units per standard cubic foot
CAA Clean Air Act
CBI confidential business information
CCU catalytic cracking units
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CO carbon monoxide
CO2 carbon dioxide
CO2e carbon dioxide equivalents
COMS continuous opacity monitoring system
COS carbonyl sulfide
CPMS continuous parameter monitoring system
CRA Congressional Review Act
CRU catalytic reforming units
CS2 carbon disulfide
DCU delayed coking units
EPA Environmental Protection Agency
ERPG emergency response and planning guidelines
ERT Electronic Reporting Tool
ESP electrostatic precipitator
FCCU fluid catalytic cracking unit
FGCD fuel gas combustion device
FMP flare management plan
FR Federal Register
FTIR Fourier transform infrared spectroscopy
GC gas chromatograph
GHG greenhouse gases
H2S hydrogen sulfide
HAP hazardous air pollutants
HCl hydrogen chloride
HCN hydrogen cyanide
HF hydrogen fluoride
HFC highest fenceline concentration
HI hazard index
HQ hazard quotient
ICR information collection request
IRIS Integrated Risk Information System
km kilometers
LAER lowest achievable emission rate
lb/day pounds per day
LDAR leak detection and repair
LEL lower explosive limit
LTD long tons per day
MACT maximum achievable control technology
MIR maximum individual risk
mph miles per hour
MPV miscellaneous process vent
NAICS North American Industry Classification System
NESHAP National Emissions Standards for Hazardous Air Pollutants
NFS near-field interfering source
NHVCZ combustion zone net heating value
Ni nickel
NOX nitrogen oxides
NRDC Natural Resources Defense Council
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and standards
OECA Office of Enforcement and Compliance Assurance
OEHHA Office of Environmental Health Hazard Assessment
OEL open-ended line
OMB Office of Management and Budget
PM particulate matter
PM2.5 particulate matter 2.5 micrometers in diameter and
smaller
ppbv parts per billion by volume
ppm parts per million

[[Page 75179]]

ppmv parts per million by volume
PRA Paperwork Reduction Act
PRD pressure relief device \1\
---------------------------------------------------------------------------

\1\ This term is common vernacular to describe the variety of
devices regulated as pressure relief valves subject to the
requirements in 40 CFR part 63 subpart CC.
---------------------------------------------------------------------------

psia pounds per square inch absolute
psig pounds per square inch gauge
REL reference exposure level
REM Model Refinery Emissions Model
RFA Regulatory Flexibility Act
RTC response to comment
RTR Risk and Technology Review
SAB Science Advisory Board
SBA Small Business Administration
SCAQMD South Coast Air Quality Management District
SCR selective catalytic reduction
SISNOSE significant economic impact on a substantial number of small
entities
SO2 sulfur dioxide
SRP sulfur recovery plant
SRU sulfur recovery unit
SSM startup, shutdown and malfunction
TOSHI target organ-specific hazard index
tpy tons per year
UMRA Unfunded Mandates Reform Act
URE unit risk estimate
UV-DOAS ultraviolet differential optical absorption spectroscopy
VCS voluntary consensus standards
VOC volatile organic compounds
[deg]F degrees Fahrenheit
[Delta]C the concentration difference between the highest measured
concentration and the lowest measured concentration
[mu]g/m\3\ micrograms per cubic meter

Background Information. On June 30, 2014, the EPA proposed
revisions to both of the petroleum refinery NESHAP based on our
residual risk and technology review (RTR). In that action, we also
proposed to revise the NESHAP pursuant to CAA section 112(d)(2) and
(3), to revise the SSM provisions in the NESHAP, and to make technical
corrections to the NSPS to address issues related to reconsideration of
the final NSPS subpart Ja rule in 2008. In this action, we are
finalizing decisions and revisions for these rules. We summarize some
of the more significant comments received regarding the proposed rule
and provide our responses in this preamble. A summary of all other
public comments on the proposal and the EPA's responses to those
comments is provided in the ``Response to Comment'' document, which is
available in Docket ID No. EPA-HQ-OAR-2010-0682. The ``track changes''
version of the regulatory language that incorporates the changes in
this final action is also available in the docket for this rulemaking.
Organization of this Document. This preamble is organized as
follows:

I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other related
information?
C. Judicial Review and Administrative Reconsideration
II. Background
A. What is the statutory authority for this action?
B. How do the NESHAP and NSPS regulate air pollutant emissions
from refineries?
C. What changes did we propose for the Petroleum Refinery NESHAP
and NSPS in our June 30, 2014 RTR proposal?
III. What is included in this final rule?
A. What are the final NESHAP amendments based on the risk review
for the Petroleum Refinery source categories?
B. What are the final NESHAP amendments based on the technology
review for the Petroleum Refinery source categories?
C. What are the final NESHAP amendments pursuant to section
112(d)(2) & (3) for the Petroleum Refinery source categories?
D. What are the final NESHAP amendments addressing emissions
during periods of SSM?
E. What other revisions to the NESHAP and NSPS are being
promulgated?
F. What are the requirements for submission of performance test
data to the EPA?
G. What are the effective and compliance dates of the NESHAP and
NSPS?
H. What materials are being incorporated by reference?
IV. What is the rationale for our final decisions and amendments to
the Petroleum Refinery NESHAP and NSPS?
A. Residual Risk Review for the Petroleum Refinery Source
Categories
B. Technology Review for the Petroleum Refinery Source
Categories
C. Refinery MACT Amendments Pursuant to CAA section 112(d)(2)
and (d)(3)
D. NESHAP Amendments Addressing Emissions During Periods of SSM
E. Technical Amendments to Refinery MACT 1 and 2
F. Technical Amendments to Refinery NSPS Subparts J and Ja
V. Summary of Cost, Environmental, and Economic Impacts and
Additional Analyses Conducted
A. What are the affected facilities, the air quality impacts and
cost impacts?
B. What are the economic impacts?
C. What are the benefits?
D. Impacts of This Rulemaking on Environmental Justice
Populations
E. Impacts of This Rulemaking on Children's Health
VI. Statutory and Executive Order Reviews
A. Executive Orders 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution or Use
I. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR part 51
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act (CRA)

I. General Information

A. Does this action apply to me?

Regulated Entities. Categories and entities potentially regulated
by this action are shown in Table 1 of this preamble.

Table 1--Industrial Source Categories Affected by This Final Action
------------------------------------------------------------------------
NAICS \a\
NESHAP and source category Code
------------------------------------------------------------------------
Petroleum Refining Industry................................. 324110
------------------------------------------------------------------------
\a\ North American Industry Classification System.

Table 1 of this preamble is not intended to be exhaustive, but
rather to provide a guide for readers regarding entities likely to be
affected by the final action for the source categories listed. To
determine whether your facility is affected, you should examine the
applicability criteria in the appropriate NESHAP or NSPS. If you have
any questions regarding the applicability of any aspect of these NESHAP
or NSPS, please contact the appropriate person listed in the preceding
FOR FURTHER INFORMATION CONTACT section of this preamble.

B. Where can I get a copy of this document and other related
information?

In addition to being available in the docket, an electronic copy of
this final action will also be available on the Internet through the
Technology Transfer Network (TTN) Web site, a forum for information and
technology exchange in various areas of air pollution control.
Following signature by the EPA Administrator, the EPA will post a copy
of this final action at: https://www.epa.gov/ttn/atw/petref.html.
Following publication in the Federal Register, the EPA will post the
Federal Register version and key technical documents at this same Web
site.
Additional information is available on the RTR Web site at https://www.epa.gov/ttn/atw/rrisk/rtrpg.html. This information includes an
overview of the RTR program, links to project Web sites

[[Page 75180]]

for the RTR source categories, and detailed emissions and other data we
used as inputs to the risk assessments.

C. Judicial Review and Administrative Reconsideration

Under CAA section 307(b)(1), judicial review of this final action
is available only by filing a petition for review in the United States
Court of Appeals for the District of Columbia Circuit by February 1,
2016. Under CAA section 307(b)(2), the requirements established by this
final rule may not be challenged separately in any civil or criminal
proceedings brought by the EPA to enforce the requirements.
Section 307(d)(7)(B) of the CAA further provides that ``[o]nly an
objection to a rule or procedure which was raised with reasonable
specificity during the period for public comment (including any public
hearing) may be raised during judicial review.'' This section also
provides a mechanism for the EPA to reconsider the rule ``[i]f the
person raising an objection can demonstrate to the Administrator that
it was impracticable to raise such objection within [the period for
public comment] or if the grounds for such objection arose after the
period for public comment (but within the time specified for judicial
review) and if such objection is of central relevance to the outcome of
the rule.'' Any person seeking to make such a demonstration should
submit a Petition for Reconsideration to the Office of the
Administrator, U.S. EPA, Room 3000, WJC Building, 1200 Pennsylvania
Ave. NW., Washington, DC 20460, with a copy to both the person(s)
listed in the preceding FOR FURTHER INFORMATION CONTACT section, and
the Associate General Counsel for the Air and Radiation Law Office,
Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200
Pennsylvania Ave. NW., Washington, DC 20460.

II. Background

A. What is the statutory authority for this action?

1. NESHAP
Section 112 of the CAA establishes a two-stage regulatory process
to address emissions of hazardous air pollutants (HAP) from stationary
sources. In the first stage, we must identify categories of sources
emitting one or more of the HAP listed in CAA section 112(b) and then
promulgate technology-based NESHAP for those sources. ``Major sources''
are those that emit, or have the potential to emit, any single HAP at a
rate of 10 tons per year (tpy) or more, or 25 tpy or more of any
combination of HAP. For major sources, these standards are commonly
referred to as maximum achievable control technology (MACT) standards
and must reflect the maximum degree of emission reductions of HAP
achievable (after considering cost, energy requirements, and non-air
quality health and environmental impacts). In developing MACT
standards, CAA section 112(d)(2) directs the EPA to consider the
application of measures, processes, methods, systems or techniques,
including but not limited to those that reduce the volume of or
eliminate HAP emissions through process changes, substitution of
materials, or other modifications; enclose systems or processes to
eliminate emissions; collect, capture, or treat HAP when released from
a process, stack, storage, or fugitive emissions point; are design,
equipment, work practice, or operational standards; or any combination
of the above.
For these MACT standards, the statute specifies certain minimum
stringency requirements, which are referred to as MACT floor
requirements, and which may not be based on cost considerations. See
CAA section 112(d)(3). For new sources, the MACT floor cannot be less
stringent than the emission control achieved in practice by the best-
controlled similar source. The MACT standards for existing sources can
be less stringent than floors for new sources, but they cannot be less
stringent than the average emission limitation achieved by the best-
performing 12-percent of existing sources in the category or
subcategory (or the best-performing 5 sources for categories or
subcategories with fewer than 30 sources). In developing MACT
standards, we must also consider control options that are more
stringent than the floor, under CAA section 112(d)(2). We may establish
standards more stringent than the floor, based on the consideration of
the cost of achieving the emissions reductions, any non-air quality
health and environmental impacts, and energy requirements.
In the second stage of the regulatory process, the CAA requires the
EPA to undertake 2 different analyses, which we refer to as the
technology review and the residual risk review. Under the technology
review, we must review the technology-based standards and revise them
``as necessary (taking into account developments in practices,
processes, and control technologies)'' no less frequently than every
eight years, pursuant to CAA section 112(d)(6). Under the residual risk
review, we must evaluate the risk to public health remaining after
application of the technology-based standards and revise the standards,
if necessary, to provide an ample margin of safety to protect public
health or to prevent, taking into consideration costs, energy, safety
and other relevant factors, an adverse environmental effect. The
residual risk review is required within eight years after promulgation
of the technology-based standards, pursuant to CAA section 112(f). In
conducting the residual risk review, if the EPA determines that the
current standards provide an ample margin of safety to protect public
health, it is not necessary to revise the MACT standards pursuant to
CAA section 112(f).\2\ For more information on the statutory authority
for this rule, see 79 FR 36879.
---------------------------------------------------------------------------

\2\ The U.S. Court of Appeals has affirmed this approach of
implementing CAA section 112(f)(2)(A): NRDC v. EPA, 529 F.3d 1077,
1083 (D.C. Cir. 2008) (``If EPA determines that the existing
technology-based standards provide an `ample margin of safety,' then
the Agency is free to readopt those standards during the residual
risk rulemaking.'').
---------------------------------------------------------------------------

2. NSPS
Section 111 of the CAA establishes mechanisms for controlling
emissions of air pollutants from stationary sources. Section 111(b) of
the CAA provides authority for the EPA to promulgate NSPS that apply
only to newly constructed, reconstructed and modified sources. Once the
EPA has elected to set NSPS for new and modified sources in a given
source category, CAA section 111(d) calls for regulation of existing
sources, with certain exceptions explained below.
Specifically, section 111(b) of the CAA requires the EPA to
establish emission standards for any category of new and modified
stationary sources that the Administrator, in his or her judgment,
finds ``causes, or contributes significantly to, air pollution which
may reasonably be anticipated to endanger public health or welfare.''
The EPA has previously made endangerment findings under this section of
the CAA for more than 60 stationary source categories and subcategories
that are now subject to NSPS.
Section 111 of the CAA gives the EPA significant discretion to
identify the affected facilities within a source category that should
be regulated. To define the affected facilities, the EPA can use size
thresholds for regulation and create subcategories based on source
type, class or size. Emission limits also may be established either for
equipment within a facility or for an entire facility. For listed
source categories, the EPA must establish ``standards of performance''
that apply

[[Page 75181]]

to sources that are constructed, modified or reconstructed after the
EPA proposes the NSPS for the relevant source category.\3\
---------------------------------------------------------------------------

\3\ Specific statutory and regulatory provisions define what
constitutes a modification or reconstruction of a facility. 40 CFR
60.14 provides that an existing facility is modified and, therefore,
subject to an NSPS, if it undergoes any physical change in the
method of operation which increases the amount of any air pollutant
emitted by such source or which results in the emission of any air
pollutant not previously emitted. 40 CFR 60.15, in turn, provides
that a facility is reconstructed if components are replaced at an
existing facility to such an extent that the capital cost of the new
equipment/components exceed 50-percent of what is believed to be the
cost of a completely new facility.
---------------------------------------------------------------------------

The EPA also has significant discretion to determine the
appropriate level for the standards. Section 111(a)(1) of the CAA
provides that NSPS are to reflect the degree of emission limitation
achievable through the application of the best system of emission
reduction which (taking into account the cost of achieving such
reduction and any non-air quality health and environmental impact and
energy requirements) the Administrator determines has been adequately
demonstrated. This level of control is commonly referred to as best
demonstrated technology (BDT) or the best system of emission reduction
(BSER). The standard that the EPA develops, based on the BSER
achievable at that source, is commonly a numerical emission limit,
expressed as a performance level (i.e., a rate-based standard).
Generally, the EPA does not prescribe a particular technological system
that must be used to comply with a NSPS. Rather, sources remain free to
elect whatever combination of measures will achieve equivalent or
greater control of emissions.
Costs are also considered in evaluating the appropriate standard of
performance for each category or subcategory. The EPA generally
compares control options and estimated costs and emission impacts of
multiple, specific emission standard options under consideration. As
part of this analysis, the EPA considers numerous factors relating to
the potential cost of the regulation, including industry organization
and market structure, control options available to reduce emissions of
the regulated pollutant(s) and costs of these controls.

B. How do the NESHAP and NSPS regulate air pollutant emissions from
refineries?

The EPA promulgated the petroleum refinery NESHAP pursuant to CAA
section 112(d)(2) and (3) for refineries located at major sources in
two separate rules. On August 18, 1995, the first petroleum refinery
MACT standard was promulgated in 40 CFR part 63, subpart CC (60 FR
43620). This rule is known as ``Refinery MACT 1'' and covers the
``Sources Not Distinctly Listed,'' meaning it includes all emissions
sources from petroleum refinery process units, except those listed
separately under the section 112(c) source category list and expected
to be regulated by other MACT standards (for example, boilers and
process heaters). Some of the emission sources regulated in Refinery
MACT 1 include miscellaneous process vents (MPV), storage vessels,
wastewater, equipment leaks, gasoline loading racks, marine tank vessel
loading and heat exchange systems.
On April 11, 2002 (67 FR 17762), EPA promulgated a second MACT
standard regulating certain process vents that were listed as a
separate source category under CAA section 112(c) and that were not
addressed as part of the Refinery MACT 1. This standard, which is
referred to as ``Refinery MACT 2'', covers process vents on catalytic
cracking units (CCU) (including FCCU), CRU and SRU and is codified as
40 CFR part 63, subpart UUU.
Finally, on October 28, 2009, we revised Refinery MACT 1 by adding
MACT standards for heat exchange systems, which the EPA had not
addressed in the original 1995 Refinery MACT 1 rule (74 FR 55686). In
this same 2009 action, we updated the cross-references to the General
Provisions in 40 CFR part 63. On June 20, 2013 (78 FR 37133), we
promulgated minor revisions to the heat exchange provisions of Refinery
MACT 1.
On September 27, 2012, Air Alliance Houston, California Communities
Against Toxics and other environmental and public health groups filed a
lawsuit alleging that the EPA missed statutory deadlines to review and
revise Refinery MACT 1 and 2. The EPA reached an agreement to settle
that litigation and entered into a Consent Decree. The Consent Decree
provides for the Administrator to sign a final action no later than
September 30, 2015.
Refinery NSPS subparts J and Ja regulated criteria pollutant
emissions, including particulate matter (PM), sulfur dioxide
(SO2), nitrogen oxides (NOX) and carbon monoxide
(CO) from FCCU catalyst regenerators, fuel gas combustion devices
(FGCD) and sulfur recovery plants. Refinery NSPS subpart Ja also
regulates criteria pollutant emissions from fluid coking units and DCU.
The NSPS for petroleum refineries (40 CFR part 60, subpart J) were
promulgated in 1974, amended in 1976 and amended again in 2008,
following a review of the standards. As part of the review that led to
the 2008 amendments to the Refinery NSPS subpart J, the EPA developed
separate standards of performance for new process units (40 CFR part
60, subpart Ja). However, the EPA received multiple petitions for
reconsideration on issues related to those standards. The Administrator
granted the petitions for reconsideration. The EPA addressed petition
issues related to process heaters and flares by promulgating amendments
to the Refinery NSPS subparts J and Ja on September 12, 2012 (77 FR
56422). In this action, we are finalizing technical corrections and
clarifications to NSPS subparts J and Ja raised by American Petroleum
Institute (API) in their 2008 petition for reconsideration that were
not addressed by the final NSPS amendments of 2012.
The petroleum refining industry consists of facilities that engage
in converting crude oil into refined products, including liquefied
petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel
oils, lubricating oils and feedstocks for the petrochemical industry.
Currently, 142 facilities have emission sources regulated by either or
both Refinery MACT 1 and 2.
Petroleum refinery activities start with the receipt of crude oil
for storage at the refinery, include all the petroleum handling and
refining operations, and terminate with loading of refined products
into pipelines, tank or rail cars, tank trucks, or ships or barges that
take products from the refinery to distribution centers. Petroleum-
specific process units include FCCU and CRU. Other units and processes
found at petroleum refineries (as well as at many other types of
manufacturing facilities) include storage vessels and wastewater
treatment plants. HAP emitted by this industry include organics (e.g.,
acetaldehyde, benzene, formaldehyde, hexane, phenol, naphthalene, 2-
methylnaphthalene, dioxins, furans, ethyl benzene, toluene and xylene);
reduced sulfur compounds (i.e., carbonyl sulfide (COS), carbon
disulfide (CS2))); inorganics (e.g., hydrogen chloride (HCl), hydrogen
cyanide (HCN), chlorine, hydrogen fluoride (HF)); and metals (e.g.,
antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, mercury,
manganese and nickel (Ni)). This industry also emits criteria
pollutants and other non-HAP, including NOX, PM,
SO2, volatile organic compounds (VOC), CO, greenhouse gases
(GHG) and total reduced sulfur.

[[Page 75182]]

C. What changes did we propose for the Petroleum Refinery NESHAP and
NSPS in our June 30, 2014, RTR proposal?

On June 30, 2014, the EPA published a proposed rule in the Federal
Register addressing the RTR for the Petroleum Refinery NESHAP, 40 CFR
part 63, subparts CC and UUU. The proposal also included changes
pursuant to section 112(d)(2) and (3) and technical revisions to the
NSPS. Specifically, we proposed:
(1) Pursuant to CAA sections 112(d)(2) and (3):
a. Refinery MACT 1:
Adding MACT Standards for DCU decoking operations.
Adding operational requirements for flares used as APCD in
Refinery MACT 1 and 2.
Adding requirements and clarifications for vent control
bypasses in Refinery MACT 1.
b. Refinery MACT 2:
Revising the CRU purge vent exemption.
(2) Pursuant to CAA sections 112(d)(6) and 112(f)(2):
Revising Refinery MACT 1 to cross-reference the
corresponding storage vessel requirements in the Generic MACT (40 CFR
part 63, subpart WW, as applicable), and revising the definition of
Group 1 storage vessels to include smaller capacity storage vessels and
to include storage vessels storing materials with lower vapor
pressures.
(3) Pursuant to CAA section 112(d)(6):
a. Refinery MACT 1:
Allowing refineries to meet the leak detection and repair
(LDAR) requirements in Refinery MACT 1 by monitoring for leaks using
optical gas imaging in place of EPA Method 21, once the monitoring
protocol set forth in Appendix K is promulgated.
Amending the Marine Tank Vessel Loading Operations NESHAP,
40 CFR part 63, subpart Y, to delete the exclusion for marine vessel
loading operations at petroleum refineries.
Establishing a fenceline monitoring work practice standard
to improve the management of fugitive emissions.
b. Refinery MACT 2:
Incorporating requirements consistent with those in
Refinery NSPS subpart Ja for FCCU including:
Requiring the use of 3-hour averages rather than daily
averages for parameter operating limits (e.g., depending on the type of
control device: Opacity, total power, secondary current, pressure drop,
and/or liquid-to-gas ratio).
Removing the Refinery NSPS subpart J incremental PM
emissions allowance for post combustion devices when burning liquid or
solid fuels, and removing the 30 percent opacity limit for units
complying with NSPS subpart J.
Adding requirements for FCCU controls to include bag leak
detectors (BLD) as an option to continuous opacity monitoring system
(COMS).
Incorporating total power and the secondary current
operating limits for electrostatic precipitators (ESP).
Requiring daily checks of the air or water pressure to the
spray nozzles on jet ejector-type wet scrubber or other type of wet
scrubber equipped with atomizing spray nozzles.
Requiring FCCU periodic performance testing on a frequency
of once every 5 years, as opposed to the current rule, which only
requires an initial performance test.
Including a correlation equation for the use of oxygen-
enriched air for SRU.
Allowing SRU subject to Refinery NSPS subpart Ja with a
capacity greater than 20 long tons per day (LTD) to comply with
Refinery NSPS subpart Ja as a means of complying with Refinery MACT 2.
(4) Other proposed changes include:
Removing exemptions from the rule requirements for periods
of SSM in order to ensure that the NESHAP are consistent with the court
decision in Sierra Club v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008).
Clarifying requirements related to open-ended valves or
lines.
Adding electronic reporting requirements.
Updating the General Provisions cross-reference tables.
Making technical corrections and clarifications to NSPS
subparts J and Ja.

III. What is included in this final rule?

This action finalizes the EPA's determinations pursuant to the RTR
provisions of CAA section 112 for the Petroleum Refinery source
categories and amends the Petroleum Refinery NESHAP based on those
determinations. This action also finalizes other changes to the NESHAP
including revising Refinery MACT 1 and 2 pursuant to CAA section 112
(d)(2) and (3), including revising requirements for flares and pressure
relief devices (PRD). This action finalizes changes to the SSM
provisions to ensure that the subparts are consistent with the court
decision in Sierra Club v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), adds
electronic reporting requirements in Refinery MACT 1 and 2; and updates
the General Provisions cross-reference tables. Finally, this action
finalizes technical corrections and clarifications to Refinery NSPS
subparts J and Ja to address issues raised in the reconsideration of
these rules.

A. What are the final NESHAP amendments based on the risk review for
the Petroleum Refinery source categories?

The EPA is promulgating final amendments to the Petroleum Refinery
NESHAP pursuant to CAA section 112(f) that expand the existing Refinery
MACT 1 control requirements and extend these requirements to smaller
tanks and tanks with lower vapor pressures. Specifically, consistent
with the proposal, the EPA is amending Refinery MACT 1 by revising the
definition of Group 1 storage vessels to include storage vessels with
capacities greater than or equal to 20,000 gallons but less than 40,000
gallons if the maximum true vapor pressure is 1.0 psia or greater and
to include storage tanks greater than 40,000 gallons if the maximum
true vapor pressure is 0.75 psia or greater. The EPA is also adding a
cross-reference to the storage vessel requirements in the Generic MACT
(40 CFR part 63, subpart WW and subpart CC), which include requirements
for guide pole controls and other fittings as well as inspection
requirements. After considering the public comments, the final
amendments include minor changes from our proposed requirements to
clarify language and correct typographical and referencing errors.

B. What are the final NESHAP amendments based on the technology review
for the Petroleum Refinery source categories?

1. Refinery MACT 1
We determined that there are developments in practices, processes
and control technologies that warrant revisions to the MACT standards
for this source category. Therefore, to satisfy the requirements of CAA
section 112(d)(6), we are revising the MACT standards to amend 40 CFR
part 63, subpart Y to delete the exclusion for marine vessel loading
operations at petroleum refineries. Removing this exclusion will
require small marine vessel loading operations (i.e., operations with
HAP emissions less than 10/25 tpy) and offshore marine vessel loading
operations to use submerged filling based on the cargo filling line
requirements in 46 CFR 153.282, as proposed.
We are also finalizing a fenceline monitoring work practice
standard to improve the management of fugitive emissions and finalizing
EPA Methods 325A and 325B to support the work

[[Page 75183]]

practice, with some changes from proposal to address issues raised by
commenters. Key revisions include: New provisions for reduced
monitoring for facilities with consistently low fenceline
concentrations; requirements for alternatives to passive monitoring;
revised placement guidance to allow perimeter monitoring within a
facility's property boundary provided all sources are encompassed
within the monitoring perimeter; reductions in the number of monitors
required for subareas and segregated areas; clarifications on monitor
placement for internal roadways or other right-of-ways and marine
docks; and revised timelines for submitting periodic reports (quarterly
rather than semiannually) and implementing the work practice standard
(2 years after promulgation rather than 3 years as proposed). We are
also revising Refinery MACT 1 storage vessel requirements as described
above under the risk review, as proposed.
2. Refinery MACT 2
We determined that there are developments in practices, processes
and control technologies that warrant revisions to the MACT standards
for this source category. Therefore, to satisfy the requirements of CAA
section 112(d)(6), we are revising the Refinery MACT 2 standard for
FCCU subject to Refinery NSPS subpart J or those electing to comply
with the Refinery NSPS subpart J requirements. As proposed, we are
removing the incremental PM limit when burning liquid or solid fuels.
We are finalizing a 20-percent opacity operating limit evaluated on a
3-hour average, which differs from the proposal to eliminate the 30-
percent opacity limit and instead allow only for a site-specific
opacity operating limit or control device parameter monitoring. As
proposed, we are finalizing requirements to make Refinery MACT 2
consistent with Refinery NSPS subpart Ja for FCCU by including 3-hour
averages rather than daily averages for parameter operating limits, and
by including 3-hour averages rather than daily averages for the site-
specific opacity operating limit. We are also finalizing requirements,
as proposed, for FCCU controls to include adding BLD as an option to
COMS, incorporating total power and the secondary current operating
limits for ESP and requiring daily checks of the air or water pressure
to the spray nozzles on jet ejector-type wet scrubbers or other types
of wet scrubbers equipped with atomizing spray nozzles.
Finally, we are finalizing, as proposed, requirements for FCCU
periodic performance testing at a frequency of once every 5 years
rather than the current requirements for a one-time initial performance
test. However, for owners or operators complying with the Refinery NSPS
subpart J option (with the 20-percent opacity operating limit discussed
above), if the PM emissions are within 80-percent of the PM limit
during any periodic performance test (i.e., emissions exceed 0.8 lb PM/
1,000 lbs of coke burn-off), the refinery owner or operator must
conduct subsequent performance tests on an annual basis. Based on
comments received, we are also adding requirements in the final rule
for owners or operators of FCCU to conduct a one-time test for HCN
emissions from the FCCU concurrent with their first periodic
performance test, which must be conducted on or before August 1, 2017
for all FCCU subject to Refinery MACT 2.
For SRU, as proposed, we are finalizing a correlation equation for
the use of oxygen-enriched air. Additionally, as proposed, we are
finalizing requirements to allow sulfur recovery plants subject to
Refinery NSPS subpart Ja with a capacity greater than 20 LTD to comply
with Refinery NSPS subpart Ja as a means of complying with Refinery
MACT 2.

C. What are the final NESHAP amendments pursuant to section 112(d)(2) &
(3) for the Petroleum Refinery source categories?

1. Refinery MACT 1
We are finalizing MACT standards for DCU decoking operations that
require that each coke drum be depressured to a closed blowdown system
until the coke drum pressure is 2 psig with minor revisions from
proposal. Specifically, we are finalizing provisions for existing DCU
affected sources to average over a 60-cycle (i.e., 60 batch) basis to
comply with the 2 psig limit, rather than the proposed requirement to
meet the 2 psig limit on a per venting event basis. In addition, we are
finalizing requirements for new DCU affected sources to depressure to
2.0 psig on a per-event, not-to-exceed basis, adding one significant
digit to the limit for new DCU affected sources. For both new and
existing DCU affected sources, we are finalizing specific provisions
for DCU with water overflow design and for double quenching.
We are finalizing operational requirements and the associated
monitoring, recordkeeping and reporting requirements for flares used as
APCD in Refinery MACT 1 and 2 with revisions to the requirements
proposed. Prior to these amendments, Refinery MACT 1 and 2 cross-
referenced the General Provisions requirements at 40 CFR 63.11(b). As
proposed, this final action replaces the cross reference to the General
Provisions and incorporates enhanced flare operational requirements
directly into the Refinery MACT regulations. As proposed, the final
rule amendments require that refinery flares operate with continuously
lit pilot flames at all times. Consistent with our proposal, we are
finalizing requirements for flares to operate with no visible emissions
and comply with consolidated requirements related to flare tip
velocity, but in the final rule these direct emissions limits apply
when flare vent gas flow is below the smokeless capacity of the flare
rather than at all times. Above the smokeless capacity of the flare, we
are establishing a work practice standard related to the visible
emissions and velocity limits; these work practice standards are
described in more detail in section III.D.1 of this preamble.
We are finalizing new operational requirements related to
combustion zone gas properties with revisions from proposal. In
response to comments on the proposal, we are finalizing requirements
that flares meet a minimum operating limit of 270 BTU/scf NHVcz on a
15-minute average, and are allowing refinery owners or operators to use
a corrected heat content of 1,212 BTU/scf for hydrogen to demonstrate
compliance with this operating limit. We had proposed two separate sets
of limits, one being more stringent if an olefins/hydrogen mixture was
present in the waste gas. For each set of limits, we proposed three
different alternative combustion zone operating limits: One based on
the combustion zone net heat content with no correction for the heat
content of hydrogen, one based on the lower flammability limit and one
based on the combustibles concentration. We proposed that these limits
be determined on a 15-minute ``feed-forward'' block average approach
(i.e., compositional data are collected every 15 minutes, after which
adjustments are made). We have included an additional option for
refiners to comply where more frequent data are collected (using direct
net heating value monitoring) to calculate the combustion limit using
net heating value data from the same 15-minute block period. We are
simplifying the compliance approach to a single operating limit based
only on the combustion zone net heating value (with a hydrogen
correction). As proposed, we are requiring refinery owners or operators
to characterize the composition of waste gas, assist gas and

[[Page 75184]]

fuel to demonstrate compliance with the operational requirements.
As proposed, we are also finalizing in this rule a burden reduction
option to use grab sampling every 8 hours rather than continuous vent
gas composition or heat content monitors. We are also including, based
on public comment, provisions to conduct limited initial sampling and
process knowledge to characterize flare gas composition for flares in
``dedicated'' service as an alternative to collecting grab samples
during each specific event. We are finalizing a requirement for daily
visible emissions observations as proposed, but, based on public
comment, we are allowing owners or operators to use video surveillance
cameras to demonstrate compliance with the visible emissions limit as
an alternative to the daily visible emissions observations.
For PRD, we are finalizing requirements for monitoring systems that
are capable of identifying and recording the time and duration of each
pressure release to the atmosphere, as proposed. Certain PRD with low
set pressures or low emission potential or in liquid service would not
be subject to these monitoring requirements. We are finalizing
requirements to minimize or prevent atmospheric releases of HAP through
PRD. Instead of the proposed prohibition on such releases, we are
finalizing work practice requirements that require both preventive
measures as well as root cause analysis and corrective action that will
incentivize refinery owners or operators to eliminate the causes of the
releases.
We are finalizing requirements for bypass lines with minor
revisions from those proposed. Specifically, we are not adopting the
proposed requirement to install quantitative flow monitors and thus are
leaving in place the requirement to use flow indicators on bypass
lines. In addition, we are maintaining the requirements to estimate and
report the quantity of organic HAP released. In response to public
comment, we are also clarifying changes to remove the proposed
reference to air intrusion and specifying that reporting of bypasses is
only required when ``regulated material'' is discharged to the
atmosphere as a result of a bypass of a control device.
We are also finalizing revisions to the definition of miscellaneous
process vent, as proposed. These revisions include deletion of
exclusions associated with episodic releases and vents from in situ
sampling systems. As proposed, the final amendments require that these
vents must meet the standards applicable to MPV.
2. Refinery MACT 2
For CRU vents, we are finalizing the vessel pressure limit
exclusion of 5 psig to apply only to passive depressurization, as
proposed.

D. What are the final NESHAP amendments addressing emissions during
periods of SSM?

We are finalizing, as proposed, changes to Refinery MACT 1 and 2 to
eliminate the SSM exemption. Consistent with Sierra Club v. EPA, 551 F.
3d 1019 (D.C. Cir. 2008), the EPA has established standards in this
rule that apply at all times. EPA is revising Table 6 of subpart CC of
40 CFR part 63 and Table 44 to subpart UUU of 40 CFR part 63 (the
General Provisions Applicability Tables) to change several references
related to requirements that apply during periods of SSM. We also are
eliminating or revising certain recordkeeping and reporting
requirements related to the eliminated SSM exemptions. We also are
removing or modifying inappropriate, unnecessary or redundant language
in the absence of the SSM exemption. Further, for certain emission
sources in both MACT 1 and 2, we are establishing standards to address
emissions during these periods. These are described below.
1. Refinery MACT 1
We are finalizing a work practice standard for PRD that requires
refinery owners or operators to establish prevention measures for each
PRD in organic HAP service. Under the work practice standard, where a
direct release occurs, the refinery is required to perform root cause
analysis and implement corrective action. The work practice standard
also limits the number of events that a PRD may release to the
atmosphere during a 3-year period, as explained further in the section
IV.D. of this preamble.
We are also finalizing a work practice standard for emergency
flaring events that requires refinery owners or operators to establish
prevention measures, including the development of a flare management
plan (FMP), and perform root cause analysis and implement corrective
action following flaring events during which the velocity of waste gas
going to the flare or visible emissions limits (i.e., opacity) at the
flare tip are exceeded, and to limit the number of these events allowed
in a 3-year period, as explained further in section IV.D. of this
preamble. Both of these work practice standards are consistent with the
EPA's goal to improve the effectiveness of the rules. These
requirements will provide a strong incentive for facilities, over time,
to better operate their processes to prevent PRD and flare releases.
We are also finalizing requirements for opening process equipment
to the atmosphere during maintenance events after draining and purging
to a closed system, provided the hydrocarbon content is less than or
equal to 10-percent of the lower explosive limit (LEL). For those
situations where 10-percent LEL cannot be demonstrated, the equipment
may be opened and vented to the atmosphere if the pressure is less than
or equal to 5 psig, provided there is no active purging of the
equipment to the atmosphere until the LEL criterion is met. This 5 psig
allowance is only available during shutdown. We are also providing
additional allowances for situations where it is not technically
feasible to depressurize a control system where there is no more than
72 lbs VOC per day vented to the atmosphere, consistent with our Group
1 applicability cutoff for control of process vents, or for catalyst
changeout activities where hydrotreater pyrophoric catalyst must be
purged. Provisions to demonstrate that process equipment is opened only
after the LEL, pressure or mass in the vessel requirement is met
includes documenting the procedures for equipment openings and
procedures for verifying that the openings meet the specific, above-
discussed requirements using site-specific procedures used to de-
inventory equipment for safety purposes (i.e., hot work or vessel entry
procedures).
2. Refinery MACT 2
The Refinery MACT 2 standards regulate all HAP emissions from the
three refinery process vents subject to Refinery MACT 2. For FCCU, the
standard specifies a CO limit as a surrogate for organic HAP and
specifies a PM limit (or Ni limit) as a surrogate for metal HAP.
Compliance with the organic HAP emissions limit is demonstrated using a
continuous CO monitor; compliance with the metal HAP emissions limit is
demonstrated using either COMS or control device parameter monitoring
systems (CPMS). At proposal, with the removal of the exemptions in the
Refinery MACT 2 rule for periods of startup and shutdown, we recognized
the need for alternative standards during some startup and shutdown
situations, and we proposed alternative requirements.
For this final rule, we are including a 1-percent minimum oxygen
limit as an alternative to the 500 ppmv hourly CO limit during FCCU
startup for partial

[[Page 75185]]

burn FCCU with CO boilers, as proposed. We are extending that
alternative limit to all FCCU and extending it to apply during
shutdown.
We are not finalizing the proposed alternative opacity limit for
FCCU during startup. Instead, based on public comments received, we are
finalizing an alternative minimum cyclone face velocity limit as a
means to demonstrate compliance with the PM limit during both startup
and shutdown, regardless of the type of FCCU and its control device. We
are finalizing alternative standards for sulfur recovery plant (SRP)
incinerator temperature and excess oxygen limits during SRP shutdown,
as proposed, and we are extending the proposed alternative standards to
startup as well.

E. What other revisions to the NESHAP and NSPS are being promulgated?

We are finalizing technical amendments to NSPS subparts J and Ja
with limited changes from what we proposed. First, in response to
comments, we are revising the NSPS requirements that a flow sensor have
a ``measurement sensitivity'' of no more than 5-percent of the flow
rate to an ``accuracy'' requirement that the flow sensor have an
accuracy of 5-percent of the flow rate. This change will make the
requirements more clear and consistent between the flow meter
requirements in the NSPS and the MACT standards since it is the same
flow meter subject to these requirements. We are also revising flare
flow rate accuracy requirements in Refinery NSPS subpart Ja to make
them consistent with those we are finalizing in Refinery MACT 1.
Finally, we are revising 40 CFR 60.101a(b) to begin as ``Except for
flares and delayed coking units . . .'' to correct an inadvertent
error. We proposed revisions to this sentence solely to allow sources
subject to Refinery NSPS subpart J to comply with the provisions in
Refinery NSPS subpart Ja instead. However, the words ``and delayed
coking units'' were inadvertently omitted from the initial part of the
sentence. Thus, as intended, we are finalizing revisions to this
sentence to allow sources subject to Refinery NSPS subpart J to comply
with the provisions in Refinery NSPS subpart Ja.

F. What are the requirements for submission of performance test data to
the EPA?

As proposed, the EPA is taking a step to increase the ease and
efficiency of data submittal and data accessibility. Specifically, the
EPA is finalizing the requirement for owners or operators of Petroleum
Refinery facilities to submit electronic copies of certain required
performance test reports through the EPA's Central Data Exchange (CDX)
using the Compliance and Emissions Data Reporting Interface (CEDRI).
The EPA believes that the electronic submittal of the reports addressed
in this rulemaking will increase the usefulness of the data contained
in those reports, is in keeping with current trends in data
availability, will further assist in the protection of public health
and the environment and will ultimately result in less burden on the
regulated community. Electronic reporting can also eliminate paper-
based, manual processes, thereby saving time and resources, simplifying
data entry, eliminating redundancies, minimizing data reporting errors
and providing data quickly and accurately to the affected facilities,
air agencies, the EPA and the public.
As mentioned in the preamble of the proposal, the EPA Web site that
stores the submitted electronic data, WebFIRE, will be easily
accessible to everyone and will provide a user-friendly interface that
any stakeholder could access. By making the records, data and reports
addressed in this rulemaking readily available, the EPA, the regulated
community and the public will benefit when the EPA conducts its CAA-
required technology and risk-based reviews. As a result of having
reports readily accessible, our ability to carry out comprehensive
reviews will be increased and achieved within a shorter period of time.
We anticipate fewer or less substantial information collection
requests (ICRs) in conjunction with prospective CAA-required technology
and risk-based reviews may be needed. We expect this to result in a
decrease in time spent by industry to respond to data collection
requests. We also expect the ICRs to contain less extensive stack
testing provisions, as we will already have stack test data
electronically. Reduced testing requirements would be a cost savings to
industry. The EPA should also be able to conduct these required reviews
more quickly. While the regulated community may benefit from a reduced
burden of ICRs, the general public benefits from the agency's ability
to provide these required reviews more quickly, resulting in increased
public health and environmental protection.
Air agencies could benefit from more streamlined and automated
review of the electronically submitted data. Having reports and
associated data in electronic format will facilitate review through the
use of software ``search'' options, as well as the downloading and
analyzing of data in spreadsheet format. The ability to access and
review air emission report information electronically will assist air
agencies to more quickly and accurately determine compliance with the
applicable regulations, potentially allowing a faster response to
violations which could minimize harmful air emissions. This benefits
both air agencies and the general public.
For a more thorough discussion of electronic reporting required by
this rule, see the discussion in the preamble of the proposal. In
summary, in addition to supporting regulation development, control
strategy development, and other air pollution control activities,
having an electronic database populated with performance test data will
save industry, air agencies, and the EPA significant time, money, and
effort while improving the quality of emission inventories, air quality
regulations, and enhancing the public's access to this important
information.

G. What are the effective and compliance dates of the NESHAP and NSPS?

The final amendments to the NESHAP and NSPS in this action are
effective on February 1, 2016. As proposed, new sources must comply
with these requirements by the effective date of the final rule or upon
startup, whichever is later.
As proposed, existing sources are required to comply with the final
DCU and CRU requirements no later than 3 years after the effective date
of the final rule. Similarly, as proposed, owners or operators are
required to comply with the new operating and monitoring requirements
for existing flares no later than 3 years after the effective date of
the final rule.
We proposed to provide 3 years from the effective date of the final
rule for refinery owners or operators to install and begin monitoring
(collecting samples) around the fenceline of their existing facility.
If refinery owners and operators determined that a site-specific
monitoring plan was needed, they would also need to submit and receive
approval for such a plan during the 3-year compliance period. Based on
information submitted during the comment period, we are finalizing
requirements that refinery owners or operators begin collecting samples
around the fenceline within 2 years of the effective date of the final
rule. Based on information submitted during the comment period, 1 year
is sufficient time to identify proper monitoring locations and to
install the required monitoring stations around the facility

[[Page 75186]]

fenceline. However, owners or operators may need additional monitoring
systems to account for near-field interfering sources (NFS), for which
the development and approval of a site-specific fenceline monitoring
plan is required. We expect that the site-specific fenceline monitoring
plans can take an additional year to develop, submit and obtain
approval. Consequently, we are providing 2 years from the effective
date of the final rule for refinery owners or operators to install and
begin collecting samples around the fenceline of their facility.
As proposed, we are requiring that existing sources comply with the
submerged filling requirement for marine vessel loading on the
effective date of the final rule.
As proposed, we are providing 18 months after the effective date of
the final rule to conduct required performance tests and comply with
any revised operating limits for FCCU.
We proposed to require refinery owners or operators to comply with
the revisions to the SSM provisions of Refinery MACT 1 and 2 on the
effective date of the final rule. As proposed, this final rule requires
refinery owners or operators to comply with the limits in Refinery MACT
2 or the alternative limits in this final rule during startup and
shutdown for FCCU and SRU on the effective date of the final rule.
The flare work practice standards for high-load flaring events
(events exceeding the smokeless capacity of the flare) require
development of FMP (or revision of an existing plan) to specifically
consider emergency shutdown and other high load events. In this FMP,
refinery owners or operators must consider measures that can be
implemented to reduce the frequency and magnitude of these high-load
flaring events. This may include installation of a flare gas recovery
system. Additionally, the work practice standards will require refinery
owners or operators to identify and implement measures that may involve
process changes. Therefore, we are establishing a compliance date of 3
years from the effective date of the final rule for refinery owners or
operators to comply with the work practice standards for high load
flaring events. We also note that this compliance period is consistent
with the compliance time provided for the flare operating limits.
For atmospheric PRD in HAP service we are establishing a work
practice standard that requires a process hazard analysis and
implementation of a minimum of three redundant measures to prevent
atmospheric releases. Alternately, refinery owners or operators may
elect to install closed vent systems to route these PRD to a flare,
drain (for liquid thermal relief valves) or other control system. We
anticipate that sources will need to identify the most appropriate
preventive measures or control approach; design, install and test the
system; install necessary process instrumentation and safety systems;
and may need to time installations with equipment shutdown or
maintenance outages. Therefore, we have established a compliance date
of 3 years from the effective date of the final rule for refinery
owners or operators to comply with the work practice standards for
atmospheric PRD.
As proposed, we are requiring compliance with the electronic
reporting provisions for performance tests conducted for Refinery MACT
1 and 2 on the effective date of the final rule.
Finally, we are finalizing additional requirements for storage
vessels under CAA sections 112(d)(6) and (f)(2) with a compliance date
90 days after the effective date of the final rule, as proposed.

H. What materials are being incorporated by reference?

In this final rule, the EPA is including regulatory text that
includes incorporation by reference. In accordance with requirements of
1 CFR 51.5, the EPA is incorporating by reference the following
documents described in the amendments to 40 CFR 63.14:
ASTM D1945-03 (Reapproved 2010), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography, (Approved January 1,
2010).
ASTM D1945-14, Standard Test Method for Analysis of
Natural Gas by Gas Chromatography.
ASTM D6196-03 (Reapproved 2009), Standard Practice for
Selection of Sorbents, Sampling, and Thermal Desorption Analysis
Procedures for Volatile Organic Compounds in Air, (Approved March 1,
2009).
ASTM D6348-03 (Reapproved 2010), Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1
through A8, (Approved October 1, 2010).
ASTM D6348-12e1, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy.
ASTM D6420-99 (Reapproved 2010), Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry.
ASTM UOP539-12, Refinery Gas Analysis by GC.
BS EN 14662-4:2005, Ambient air quality--Standard method
for the measurement of benzene concentrations--Part 4: Diffusive
sampling followed by thermal desorption and gas chromatography, June
27, 2005.
EPA-454/B-08-002, Quality Assurance Handbook for Air
Pollution Measurement Systems, Volume IV: Meteorological Measurements,
Version 2.0 (Final), March 2008.
EPA-454/R-99-005, Meteorological Monitoring Guidance for
Regulatory Modeling Applications, February 2000.
ISO 16017-2:2003(E): Indoor, ambient and workplace air--
Sampling and analysis of volatile organic compounds by sorbent tube/
thermal desorption/capillary gas chromatography--Part 2: Diffusive
sampling, May 15, 2003.
Air Stripping Method (Modified El Paso Method) for
Determination of Volatile Organic Compound Emissions from Water
Sources'' Revision Number One, dated January 2003, Sampling Procedures
Manual, Appendix P: Cooling Tower Monitoring, prepared by Texas
Commission on Environmental Quality, January 31, 2003.\4\
---------------------------------------------------------------------------

\4\ The requirements in Sec. 63.655(i)(5)(iii)(G) associated
with this incorporation by reference have not changed, but are being
modified to properly be incorporated into Sec. 63.14(s).
---------------------------------------------------------------------------

The EPA has made, and will continue to make, these documents
available electronically through www.regulations.gov and/or in hard
copy at the appropriate EPA office (see the ADDRESSES section of this
preamble for more information).

IV. What is the rationale for our final decisions and amendments to the
Petroleum Refinery NESHAP and NSPS?

A. Residual Risk Review for the Petroleum Refinery Source Categories

1. What did we propose pursuant to CAA section 112(f) for the Petroleum
Refinery source categories?
The results of our residual risk review for the Petroleum Refinery
source categories were published in the June 30, 2014 proposal at (79
FR 36934 through 36942), and included assessment of chronic and acute
inhalation risk, as well as multipathway and environmental risk, to
inform our decisions regarding acceptability and ample margin of
safety. The results indicated that both the actual and

[[Page 75187]]

allowable inhalation cancer risks to the individual most exposed are no
greater than approximately 100-in-1 million, which is the presumptive
limit of acceptability. In addition, the maximum chronic non-cancer
target organ-specific hazard index (TOSHI) due to inhalation exposures
was less than 1. The evaluation of acute non-cancer risks, which was
conservative, showed acute risks below a level of concern. Based on the
results of the refined site-specific multipathway analysis, we also
concluded that the ingestion cancer risk to the individual most exposed
through ingestion is considerably less than 100-in-1 million. In
determining risk acceptability, we also evaluated population impacts
because of the large number of people living near facilities in the
source category. We estimated that 5-million people are exposed to
increased cancer risks of greater than 1-in-1 million and 100,000
people are exposed to increased cancer risks of greater than 10-in-1
million, but, as noted previously, no individual is exposed to
increased cancer risks of greater than 100-in-1 million. Considering
the above information, we proposed that the risks remaining after
implementation of the existing NESHAP for the Refinery MACT 1 and 2
source categories is acceptable. However, we noted that the risks based
on allowable emissions are at the presumptive limit of acceptable risk,
and that a large number of people are exposed to risks of greater than
1-in-1 million, and we solicited comment on whether EPA should conclude
that the risk was unacceptable based on the health information before
the Agency. We also proposed that the original Refinery MACT 1 and 2
MACT standards, along with the proposed requirements for storage
vessels, provide an ample margin of safety to protect public health.
Finally, we proposed that it is not necessary to set a more stringent
standard to prevent, taking into consideration costs, energy, safety,
and other relevant factors, an adverse environmental effect.
2. How did the risk review change for the Petroleum Refinery source
categories?
As part of the final risk assessment, we conducted a screening
level analysis of how the information we received during the public
comment period, along with the changes we are making to the proposed
rule, would change our proposed risk estimates (More details can be
found in the ``Final Residual Risk Assessment for the Petroleum
Refining Source Sector'', Docket ID No. EPA-HQ-OAR-2010-0682).
First, we received approximately 20 emissions inventory updates for
specific facilities. These updates included revised emission estimates,
revised release latitude/longitude locations and other release
characteristic revisions. The updates provided evidence that the
quantity of HAP emitted at these specific facilities is lower than
considered in the risk modeling for the proposed rule. Our assessment
of the effects of these changes suggests that the cancer maximum
individual risk (MIR) based on actual emissions may be closer to 40-in-
1 million, as opposed to 60-in-1 million, as projected at proposal. We
did not quantify the reductions in chronic or acute non-cancer risks
from these updates. We calculated allowable emissions using the
Refinery Emissions Model (REM), which estimates emissions based on each
refinery's capacities and throughputs [See discussion at 79 FR 36888,
June 30, 2014.] The allowable emission estimates for point and fugitive
sources were not specific to a particular latitude/longitude location
so we assumed them to release from the centroid of the facility.
Therefore, the predicted cancer MIR of approximately 100-in-1 million
based on allowable emissions and reported in the proposal risk
characterization does not change based on the submitted emissions
revisions. We did not quantify changes to other actual risk metrics as
part of the screening level analysis (i.e., incidence, populations in
risk bins, multipathway and ecological analyses), but we would expect
some minor reductions from those presented in the proposed risk
characterization.
Second, we are establishing work practice standards in the final
rule for PRD releases and emergency flaring events, which under the
proposed rule would not have been allowed. Thus, because we did not
consider such non-routine emissions under our risk evaluation for the
proposed rule, we performed a screening assessment of risk associated
with these non-routine events for the final rule. [We provide further
details on the screening approach in ``Final Residual Risk Assessment
for the Petroleum Refining Source Sector'' in Docket ID No. EPA-HQ-OAR-
2010-0682.] We extracted information on these events from the 2011
Petroleum Refinery ICR data that included the process unit
identification, mass of emissions, duration of release, and description
of the incident. We identified the highest HAP mass releases for both
PRDs and flares from these non-routine events. We assumed these HAP
emission releases could occur at any facility in the source category.
Our analysis suggests that these HAP emissions could increase the MIR
based on actual emissions by as much as 2-in-1 million. Because the PRD
and flaring events were the worst case HAP mass emission release events
reported in the 2011 Refinery ICR for the source category, we are
assuming that actual and allowable risks are no different for these
events (i.e., a MIR of 2-in-1 million). A MIR increase of 2-in-1
million attributable to these events, added to our previous estimate
for allowable risk at proposal will not appreciably change our proposed
determination that the MIR based on allowable emissions are
approximately 100-in-1 million. We note that the MIR estimate
attributable to these non-routine PRD and flaring events was estimated
using a conservative, screening-level assessment, while the MIR
estimate at proposal was based on a refined risk assessment. By adding
a screening estimate to a refined risk estimate, we are merely defining
an upper limit that we expect the combined risks from both the routine
and non-routine emissions to be. Similarly, we estimate chronic non-
cancer hazard index (HI) values attributable to the additional
exposures resulting from non-routine flaring and PRD HAP emissions to
be well below 1 (HIimmune-system of 0.007) such that there
is no appreciable change in the maximum chronic non-cancer HI of 0.9
estimated at proposal for routine emissions, which was based on
neurological effects.
The screening analysis projects that the maximum predicted acute
non-cancer risk from non-routine PRD and flare emissions results in a
hazard quotient (HQ) based on a recommended reference exposure level
limit (REL) of up to 14 from benzene emissions. While the analysis
shows that there is a potential for HQs exceeding 1 for benzene,
because of the many uncertainties and conservative nature of this
screening analysis, the likelihood of such exposure and risk are low.
At proposal, we projected a HQ based on the REL for benzene of up to 2
from routine emissions. If we conservatively combine the routine and
non-routine emissions analyses, we would expect the potential for HQs
based on the REL for benzene to have the potential to increase above 2.
However, as projected at proposal, we estimate that the acute HQs
calculated using acute exposure guideline levels (AEGL) and emergency
response and planning guidelines (ERPG) values for all pollutants
including benzene would still be well

[[Page 75188]]

below 1 considering both routine and non-routine emissions.
Considering all of these factors, we do not project risks to be
significantly different from what we proposed. Based on the risk
analysis, as informed by the screening level analysis based on
information obtained during the comment period, we are finalizing our
determination that the risk remaining after promulgation of the NESHAP
is acceptable.
3. What key comments did we receive on the risk review and what are our
responses?
We received numerous comments on the residual risk assessment
analyses and results. We summarize the key comments received below,
along with our responses. A complete summary of all public comments
received and our responses are in the ``Response to Comment'' Document
in the public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
Comment: Several commenters agreed that the EPA has correctly
concluded that the proposed rule requirements protect the public with
an ample margin of safety from refinery emissions. Other commenters
noted that EPA found residual risks remaining after implementation of
the MACT standards to be acceptable, and in light of the acceptability
determination argued that the proposed changes to the rule are not
justified. The commenters noted that the EPA's detailed emissions
inventory assessment and risk modeling results demonstrated that, at
every U.S. refinery, category-specific risks are below the EPA's
presumptive limit of acceptable risk (i.e., cancer risk of less than
100-in-1 million).
Other commenters stated the EPA's risk estimates are understated
and that the EPA should reduce the benchmark of what it considers
acceptable lifetime cancer risk instead of the upper limit of 100-in-1
million. One commenter provided an extensive critique of the cancer,
chronic and acute affects levels used in the risk assessment and
recommended that the EPA use California Office of Environmental Health
Hazard Assessment's (OEHHA) new toxicity values for several chemicals.
The commenter provided some references for the approaches used to
derive the California values. The commenter also asserted that risks
would be unacceptable had these more protective values been used in the
risk assessment. Some commenters stated the risks from petroleum
refinery emissions are underestimated because the EPA did not but
should have included interaction of multiple pollutants, accounted for
exposure to multiple sources, and assessed the cumulative risks from
facility-wide emissions and multiple nearby sources impacting an area.
Response: The approximately 100-in-1 million benchmark was
established in the Benzene NESHAP (54 FR 38044, September 14, 1989),
which Congress specifically referenced in CAA section 112(f)(2)(B).
While this presumptive level provides a benchmark for judging the
acceptability of MIR, it is important to recognize that it does not
constitute a rigid line for making that determination. The EPA
considers the specific uncertainties of the emissions, health effects
and risk information for the source category in question when deciding
whether the risk posed by that source category is acceptable. In
addition, the source category-specific decision of what constitutes an
acceptable level of risk is a holistic one; that is, the EPA considers
all potential health impacts--chronic and acute, cancer and non-cancer,
and multipathway--along with their uncertainties, when determining
whether the source category presents an unacceptable risk.
Regarding the comment that in light of the acceptability
determination the proposed changes to the rule are not justified, we
note that we also are required to ensure that the standards provide an
ample margin of safety to protect public health. That analysis is
separate from the acceptability analysis, and the determination of
acceptability does not automatically lead us to conclude that the
standards provide an ample margin of safety to protect public health.
Regarding the comments that the EPA should use the new California
OEHHA values, we disagree. The EPA's chemical-specific toxicity values
are derived using risk assessment guidelines and approaches that are
well established and vetted through the scientific community, and
follow rigorous peer review processes.\5\ The RTR program gives
preference to the EPA values for use in risk assessments and uses other
values, as appropriate, when those values are derived with methods and
peer review processes consistent with those followed by the EPA. The
approach for selecting appropriate toxicity values for use in the RTR
Program has been endorsed by the Science Advisory Board (SAB).\6\
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\5\ Integrated Risk Information System (IRIS). IRIS Guidance
documents available at https://www.epa.gov/iris/backgrd.html.
\6\ https://yosemite.epa.gov/sab/sabproduct.nsf/0/b031ddf79cffded38525734f00649caf!OpenDocument&TableRow=2.3#2.
---------------------------------------------------------------------------

The EPA scientists reviewed the information provided by the
commenter regarding the California values and concluded that further
information is needed to evaluate the scientific basis and rationale
for the recent changes in California OEHHA risk assessment methods. The
EPA will work on gathering the necessary information to conduct an
evaluation of the scientific merit and the appropriateness of the use
of California OEHHA's new toxicity values in the agency decisions.
Until the EPA has completed its evaluation, it is premature to
determine what role these values might play in the RTR process.
Therefore, the EPA did not use the new California OEHHA toxicity values
as part of this current action. For more detailed responses regarding
appropriate reference values for specific pollutants, see the
``Response to Comment'' document in the public docket (Docket ID No.
EPA-HQ-OAR-2010-0682).
Concerning comments that we should consider aggregate risks from
multiple pollutants and sources, we note that we have done this to the
extent it is appropriate to do so. We modeled whole-facility risks for
both chronic cancer and non-cancer impacts to understand the risk
contribution of the sources within the Petroleum Refinery source
categories. The individual cancer risks for the source categories were
aggregated for all carcinogens. In assessing non-cancer hazard from
chronic exposures to pollutants that have similar modes of action or
(where this information is absent) that affect the same target organ,
we summed the HQs. This process creates, for each target organ, a
TOSHI, defined as the sum of HQs for individual HAP that affect the
same organ or organ system. Whole-facility risks were estimated based
on the 2011 ICR emissions data obtained from facilities, which included
emissions from all sources at the refinery, not just Refinery MACT 1
and 2 emission sources (e.g., emissions were included for combustion
units and units subject to the Hazardous Organic NESHAP, if present at
the refinery). We disagree with the commenter's assertion that
additional quantitative assessment of risks from sources outside the
source category is required under the statute. The statute requires the
EPA to provide the quantitative risk information necessary to inform
RTR regulatory decisions, and to this end, the EPA conducted a
comprehensive assessment of the risks associated with exposure to the
HAP emitted by the source category and supplemented that with
additional

[[Page 75189]]

information available about other possible concurrent and relevant
risks.
Further, the risk assessment modeling accounts for the effects of
multiple facilities that may be in close proximity when estimating
concentration and risk impacts at each block centroid. When evaluating
the risks associated with a particular source category, we combined the
impacts of all facilities within the same source category and assessed
chronic exposure and risk for all census blocks with at least one
resident (i.e., locations where people may reasonably be assumed to
reside). The MIR considers the combined impacts of all sources in the
category that may be in close proximity (i.e., cumulative impact of all
refineries).
Comment: Several commenters stated that the EPA underestimated
exposure because emissions are underreported and underestimated. The
commenters noted that for the risk assessment for the refineries rule,
the EPA evaluated (1) the emissions reported to the agency pursuant to
the 2011 Petroleum Refinery ICR as sources' ``actual'' emissions, and
(2) the emissions the EPA estimates that the existing standards
currently allow sources to emit using the REM, which it describes as
``allowable'' emissions. According to the commenters, both the EPA's
``actual'' and ``allowable'' emissions data sets are incomplete and
undercount emissions, causing the EPA to significantly underestimate
the resulting risk in its risk analysis. For example, the commenters
noted that the EPA assumed the flare destruction efficiency to be 98
percent, while the EPA's own estimates suggest flare efficiency is 93.9
percent. The commenters also noted that the EPA has further understated
risks by ignoring emissions during unplanned SSM events and by ignoring
HAP for which no reference values are established. One commenter cited
the TCEQ Emissions Event Database as evidence that SSM emissions are a
severe public health problem because data show that nearly 1 million
pounds of HAP are reported from Texas refineries between 2009 and 2013.
According to these commenters, the EPA needs to adopt standards that
provide greater protection, including protection from the risks of
accidents.
Response: We used the best and most robust facility-specific HAP
emissions inventory available to us, which was the 2011 ICR, in
performing the analysis for the proposed rule. We conducted a thorough
and exhaustive review of the data submitted through the ICR and we
followed up on source-specific information on a facility-by-facility
basis, as documented in the ``Emissions Data Quality Memorandum and
Development of the Risk Model Input File'' (see Docket ID No. EPA-HQ-
OAR-2010-0682-0076). In addition, we took steps ahead of issuing the
2011 ICR to make sure that facilities could, as accurately as
practicable, estimate their HAP emissions for purposes of responding to
the inventory portion of that ICR. We prepared a Refinery Protocol to
provide guidance to refinery owners or operators to use the best
available, site-specific data when developing their emissions
inventory, to ensure all emission sources are included in the
inventory, and to have a consistent set of emission factors that all
respondents use if no site-specific emissions data were available. If
site-specific emissions data were available, sites were to use these
data preferentially over the default factors. We developed the default
factors provided in the protocol from the best data available at the
time.
The ICR-submitted information for allowable emissions did not
include emission estimates for all HAP and all emission sources.
Consequently, we used the REM to estimate allowable emissions. The REM
relies on model plants that vary based on throughput capacity. Each
model plant contains process-specific default emission factors,
adjusted for compliance with the Refinery MACT 1 and 2 emission
standards.
We agree with the commenters that studies have shown that many
refinery flares are operating less efficiently than 98 percent. Prior
to proposing this rule, we conducted a flare ad hoc peer review to
advise the EPA on factors affecting flare performance (see discussion
in the June 30, 2014, proposal at 79 FR 36905). However, we disagree
with the commenters that the risk analysis should consider this level
of performance since the existing MACT standard does not allow it. For
purposes of the risk analysis, we evaluate whether it is necessary to
tighten the existing MACT standard in order to provide an ample margin
of safety. Thus, in reviewing whether the existing standards provide an
ample margin of safety, we review the level of emissions the MACT
standards allow. In the present case, we considered the level of
performance assumed in establishing the MACT standard for purposes of
determining whether the MACT standard provides an ample margin of
safety. However, we did recognize that facilities were experiencing
performance issues with flares and that many flares were not meeting
the assumed performance level at the time we promulgated the MACT
standard. Thus, we proposed, and are finalizing, revisions to the flare
operating requirements to ensure that the flares meet the required
performance level. These provisions are consistent with the EPA's goals
to improve the effectiveness of our rules.
Similarly, we do not include startup, shutdown (including
maintenance events) and malfunction emissions that are not allowed
under the standard as part of our evaluation of whether the standards
provide an ample margin of safety. Regarding the HAP emissions from SSM
events that the commenter is concerned with, we note that our review of
the TCEQ incident database indicates that many of the large reported
release events were of SO2 emissions and only a few had
significant HAP emissions.
Because in the final rule we are establishing work practice
standards for PRD and emergency flaring events, we performed a
screening-level risk analysis to address changes in facility HAP
emission releases due to these events. Details on this analysis are
presented in the final risk report for the source category (For more
details see Appendix 13 of the ``Final Residual Risk Assessment for the
Petroleum Refining Source Sector,'' Docket ID No. EPA-HQ-OAR-2010-
0682).
As for HAP with no reference value, the SAB addressed this issue in
its May 7, 2010, response to the EPA Administrator. In that response,
the SAB Panel recommended that, for HAP that do not have dose-response
values from the EPA's list, the EPA should consider and use, as
appropriate, additional sources for such values that have undergone
adequate and rigorous scientific peer review. The SAB panel further
recommended that the inclusion of additional sources of dose-response
values into the EPA's list should be adequately documented in a
transparent manner in any residual risk assessment case study. We agree
with this approach and have considered other sources of dose-response
data when conducting our risk determinations under RTR. However, in
some instances no sources of information beyond the EPA's list are
available. Compounds without health benchmarks are typically those
without significant health effects compared to compounds with health
benchmarks, and in such cases we assume these compounds will have a
negligible contribution to the overall health risks from the source
category. A tabular summary of HAPs that have dose response values for
which an exposure assessment was conducted is presented in Table 3.1-1
of the ``Final Residual Risk Assessment for the Petroleum Refining
Source Sector'', Docket ID No. EPA-HQ-OAR-2010-0682.

[[Page 75190]]

Comment: A few commenters asserted that the EPA should decide that
it is unjust and inconsistent with the CAA's health protection purpose
to allow the high health risks caused by refineries to fall
disproportionately on communities of color and lower income communities
who are least equipped to deal with the resulting health effects.
Because of that disparity, the commenter stated that the EPA should
recognize that the risks found are unacceptable and set stronger
national standards for all exposed Americans.
Response: For this rulemaking, the EPA conducted both pre- and
post-control risk-based assessments with analysis of various socio-
economic factors for populations living near petroleum refineries (see
Docket ID Nos. EPA-HQ-OAR-2010-0682-0226 and -0227) and determined that
there are more African-Americans, Other and multiracial groups,
Hispanics, low-income individuals, and individuals with less than a
high school diploma compared to national averages. In determining the
need for tighter residual risk standards, the EPA strives to limit to
no higher than 100-in-1 million the estimated cancer risk for persons
living near a plant if exposed to the maximum pollutant concentration
for 70 years and to protect the greatest number of persons to an
individual lifetime risk of no higher than 1-in-1 million. Although we
consider the risk for all people regardless of racial or socioeconomic
status, communities near petroleum refineries will particularly benefit
from the risk reductions associated with this rule. In particular, as
discussed later, the fenceline monitoring work practice standard will
be a further improvement in the way fugitive emissions are managed and
will provide an extra measure of protection for surrounding
communities.
4. What is the rationale for our final decisions for the risk review?
As described in section IV.A.2 of this preamble, we performed a
screening-level analysis to assess the risks associated with inventory
updates we received for specific facilities and with emissions events
that were previously not included in the risk assessment because the
proposed rule did not allow them. Because we are finalizing work
practice standards to regulate emission events associated with PRD
releases and emergency flaring, we considered the effect these work
practice standards would have on risks. As discussed in section IV.A.2
of this preamble, we project that accounting for these emergency events
in the baseline risks after implementation of the MACT standards does
not appreciably change the risks, and at most, could increase the
proposed rule estimate of MIR by approximately 2-in-1 million.
Therefore, we would project that any controls applied to these
emergency events, including the work practice standards for PRDs and
emergency flaring in this final rule, would not appreciably change the
proposed post-control risks. Although we would anticipate minimal
additional risk reductions, we reviewed more stringent alternatives to
the work practice standards for PRD releases and emergency flaring
events included in this final rule, and we found that the costs of
increasing flare capacity to control all PRD releases and to eliminate
all visible emissions during emergency flaring were too high. We
estimate the capital costs of applying the velocity and visible
emissions limit at all times would be approximately $3 billion, and we
estimate that the costs of controlling all PRD releases with flares
would be approximately $300 million. [See the discussion in the ``Flare
Control Option Impacts for Final Refinery Sector Rule'', Docket ID No.
EPA-HQ-OAR-2010-0682 and the PRD work practice standard discussion in
section IV.C of this preamble.] Further, we did not receive comments on
additional control technologies that we should have considered for
other emission sources (e.g., tanks, DCUs) beyond those considered and
described at proposal. Consequently, as discussed in section IV.A.2, we
conclude that the risks from the Petroleum Refinery source categories
are acceptable and that, with the additional requirements for storage
vessels that we are finalizing, as proposed, the Refinery MACT 1 and 2
rules provide an ample margin of safety to protect public health. We
also maintain, based on the rationale presented in the preamble to the
proposed rule, that the current standards prevent, taking into
consideration costs, energy, safety and other relevant factors, an
adverse environmental effect.

B. Technology Review for the Petroleum Refinery Source Categories

1. What did we propose pursuant to CAA section 112(d)(6) for the
Refinery MACT 1 (40 CFR part 63, subpart CC) source category?
The results of our technology review for the Petroleum Refinery
source categories were published in the June 30, 2014, proposal at (79
FR 36913 through 36928). The technology review was conducted for both
MACT source categories as described below.
a. Refinery MACT 1
Refinery MACT 1 sources include MPV, storage vessels, equipment
leaks, gasoline loading racks, marine vessel loading operations,
cooling towers/heat exchange systems and wastewater. Based on
technology reviews for the sources described above, we proposed that it
was not necessary to revise Refinery MACT 1 requirements for MPV,
gasoline loading racks, cooling towers/heat exchange systems, and
wastewater. For storage vessels, we proposed revisions pursuant to the
technology review. Specifically, we proposed to cross-reference the
storage vessel requirements in the Generic MACT (40 CFR part 63,
subpart WW) to require controls on floating roof fittings (e.g.,
guidepoles, ladder wells and access hatches) and to revise the
definition of Group 1 storage vessels to include smaller tanks with
lower vapor pressures. For equipment leaks, we proposed to allow
refineries to meet LDAR requirements in Refinery MACT 1 by monitoring
for leaks via optical gas imaging in place of the EPA Method 21, using
monitoring requirements to be specified in a not-yet-proposed appendix
K to 40 CFR part 60. For marine vessel loading, we proposed to amend
the Marine Tank Vessel Loading Operations MACT standards (40 CFR part
63, subpart Y) to require small marine vessel loading operations (i.e.,
operations with HAP emissions less than 10/25 tpy) and offshore marine
vessel loading operations at petroleum refineries to use submerged
filling based on the cargo filling line requirements in 46 CFR 153.282.
We also proposed an additional work practice standard under the
technology review to manage fugitive emissions from the entire
petroleum refinery through a fenceline monitoring and corrective action
standard. As part of the work practice standard, we specified the
monitoring technology and approach that must be used, and we developed
a fenceline benzene concentration action level above which refinery
owners or operators would be required to implement corrective action to
reduce their fenceline concentration to below this action level. The
action level we proposed was consistent with the emissions projected
from fugitive sources compliant with the provisions of the refinery
MACT standards as modified by the additional controls proposed for
storage vessels.
b. Refinery MACT 2
The Refinery MACT 2 source category regulates HAP emissions from
FCCU, CRU and SRU process vents. We

[[Page 75191]]

proposed to revise Refinery MACT 2 to incorporate the developments in
monitoring practices and control technologies reflected in Refinery
NSPS subpart Ja (73 FR 35838). This included proposing to incorporate
the Refinery NSPS subpart Ja PM limit for new FCCU sources and to
revise the monitoring provisions in Refinery MACT 2 to require all FCCU
sources to meet operating limits consistent with the requirements in
Refinery NSPS subpart Ja. The existing MACT standard provided that a
refiner could demonstrate compliance with the PM limit in the MACT by
meeting the 30-percent opacity limit requirement of Refinery NSPS
subpart J; we proposed to eliminate that provision and instead
establish control device operating limits or site-specific opacity
limits similar to those required in Refinery NSPS subpart Ja. We also
proposed to incorporate the use of 3-hour averages rather than daily
averages for monitoring data to demonstrate compliance with the FCCU
site-specific opacity and Ni operating limits. We proposed additional
control device-specific monitoring alternatives for various control
devices on FCCU, including BLD monitoring as an option to COMs for
owners or operators of FCCU using fabric filter-type control systems,
and total power and secondary current operating limits for owners or
operators of ESPs. We also proposed to add a requirement to perform
daily checks of the air or water pressure to atomizing spray nozzles
for owners or operators of FCC wet gas scrubbers. Finally, we proposed
to require a performance test once every 5 years for all FCCU in place
of the one-time performance test required by the current Refinery MACT
2.
At proposal, we did not identify any developments in practices,
processes and control technologies for CRU process vents based on our
technology review. For SRU, we proposed to include the Refinery NSPS
subpart Ja allowance for oxygen-enriched air as a development in
practice and to allow SRU to comply with Refinery NSPS subpart Ja as a
means of complying with Refinery MACT 2.
2. How did the technology review change for the Petroleum Refinery
source categories?
a. Refinery MACT 1
We are finalizing most of our technology review decisions for
Refinery MACT 1 emissions sources as proposed; however, as described
briefly below, we are revising certain proposed requirements.
We are not taking final action adopting the use of appendix K to 40
CFR part 60 for optical gas imaging for refinery equipment subject to
the LDAR requirements in Refinery MACT 1 because we have not yet
proposed appendix K.
After considering the public comments, we are finalizing the
proposed fenceline monitoring requirements, with a few revisions.
First, we have made numerous clarifications in this final rule to the
language for the fenceline monitoring siting method and analytical
method (i.e., Methods 325 A and B, respectively). Specific comments on
these methods, along with our responses and explanations of the
revisions to the regulatory text are discussed in the ``Response to
Comment'' document. Second, we are finalizing a revised compliance
schedule for fenceline monitoring, which will require refinery owners
or operators to have the fenceline monitors in place and collecting
benzene concentration data no later than 2 years from the effective
date of the final rule, as opposed to 3 years in the proposed rule.
Third, we have removed the requirement for refinery owners or operators
to obtain the EPA approval for the corrective action plan. Fourth, we
are requiring the submittal of the fenceline monitoring data on a
quarterly basis, as opposed to on a semiannual basis as proposed.
Fifth, we are providing guidelines for operators to use in requesting
use of an alternative fenceline monitoring technology to the passive
sorbent samplers set forth in Method 325B. Finally, to reduce the
burden of monitoring, we are finalizing provisions that would allow
refinery owners or operators to reduce the frequency of fenceline
monitoring for areas that consistently stay well below the fenceline
benzene concentration action level. Specifically, we are allowing
refinery owners or operators to monitor every other two weeks (i.e.,
skip period monitoring) if over a two-year period, each sample
collected at a specific monitoring location is at or below 0.9 [mu]g/
m\3\. If every sample collected from that sampling location during the
subsequent 2-years is at or below 0.9 [mu]g/m\3\, the monitoring
frequency may be reduced from every other two weeks to quarterly. After
an additional two years, the monitoring can be reduced to semiannually
and finally to annually, provided the samples continue to be at or
below 0.9 [mu]g/m\3\ during all sampling events at that location. If at
any time a sample for a monitoring location that is monitored at a
reduced frequency returns a concentration greater than 0.9 [mu]g/m\3\,
the owner or operator must return to the original sampling requirements
for one quarter (monitor every two weeks for the next six monitoring
periods for that location); if every sample collected from this quarter
is at or below 0.9 ug/m\3\, then the sampling frequency reverts back to
the reduced monitoring frequency for that monitoring location; if not
then the sampling frequency reverts back to the original biweekly
monitoring frequency.
b. Refinery MACT 2
We are finalizing, as proposed, our determination that it is not
necessary to revise the requirements for CRU pursuant to the technology
review and we are finalizing our determination that it is necessary to
revise the MACT for SRU and FCCU. For SRU, we are finalizing the
revisions as proposed. For FCCU, we are making modifications to the
proposed requirements in light of public comment.
As discussed previously, we proposed to remove the alternative in
Refinery MACT 2 for owners or operators to demonstrate compliance with
the PM limits on FCCU by meeting a 30-percent opacity standard as
provided in Refinery NSPS subpart J and instead make the FCCU operating
limits in Refinery MACT 2 consistent with Refinery NSPS subpart Ja.
Based on the Refinery NSPS subpart J review in 2008, we determined that
a 30-percent opacity limit does not adequately assure compliance with
the PM emissions limit (see discussion in the proposed rule at 79 FR
36929, June 30, 2014). Thus, we included other monitoring approaches in
Refinery NSPS subpart Ja.
Comments received on this proposal, along with data available to
the Agency, confirmed that the 30-percent opacity standard is not
adequate on its own to demonstrate compliance with the PM (or metal
HAP) emissions limit in Refinery MACT 2. We also received comments that
the site-specific opacity alternative, which is the only compliance
option proposed for FCCU with tertiary cyclones, would essentially
require owners or operators with these FCCU configurations to meet an
opacity limit of 10-percent. According to commenters, opacity increases
with decreasing particle size, so that it is common to exceed 10-
percent opacity during soot blowing or other similar events that
produce very fine particulates even though mass emissions have not
changed appreciably.
Based on the available data, we have determined that a 20-percent
opacity operating limit is well correlated with

[[Page 75192]]

facilities meeting a limit of 1.0 lb PM/1,000 lbs coke burn-off.
Therefore, we are retaining the option in Refinery MACT 2 to comply
with Refinery NSPS subpart J except we are adding a 20-percent opacity
operating limit in Refinery MACT 2, evaluated on a 3-hour basis. To
ensure that FCCU owners or operators complying with the Refinery NSPS
subpart J option can meet the 1.0 lb PM/1,000 lbs emissions limit at
all times, we are finalizing requirements that owners or operators
conduct the performance test during higher PM periods, such as soot
blowing. Where the PM emissions are within 80-percent of the PM limit
during any periodic performance test, we are requiring the refinery
owner or operator to conduct subsequent performance tests on an annual
basis instead of on a 5-year basis.
We are finalizing our proposed requirement that compliance with the
control device operating limits in the other compliance alternatives be
demonstrated on a 3-hour basis, instead of the 24-hour basis currently
allowed in Refinery MACT 2.
3. What key comments did we receive on the technology review, and what
are our responses?
a. Refinery MACT 1
The majority of comments received regarding the proposed amendments
to Refinery MACT 1 pursuant to our technology review dealt with the
proposed fenceline monitoring requirements. The primary comments on the
fenceline monitoring requirements are in this section along with our
responses. Comment summaries and the EPA's responses for additional
issues raised regarding the proposed requirements resulting from our
technology review are in the ``Response to Comment'' document in the
public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
i. Legal Authority and Need for Fenceline Monitoring
Comment: Numerous commenters claimed that the proposed fenceline
monitoring program would unlawfully impose what is effectively an
ambient air quality standard for benzene, which is not authorized by
CAA section 112, which only authorizes the control of emission sources.
The commenters argued it is an ambient standard because sources are
required to meet the benzene level set or ``perform injunctive relief
which may or may not address the source of the benzene.'' The commenter
quoted language from the proposal as support that EPA has described the
benzene level as an ambient standard: ``We are proposing a HAP
concentration to be measured in the ambient air around a refinery, that
if exceeded, would trigger corrective action to minimize fugitive
emissions.'' 79 FR at 36920 (June 30, 2014). The commenter further
noted that this requirement is not just ``monitoring'' because it
establishes a ``not-to-be exceeded'' level. Therefore, the commenters
stated, the EPA should not finalize this portion of the proposal.
Response: We disagree with the comment that the fenceline proposal
is an ambient air standard. First, the owner or operator must place the
monitors on the facility fenceline to measure emissions from the
facility, i.e., on the property of the refiner. While we recognize that
we used the term ``ambient air'' in the preamble to the proposal, we
note that the placement requirements for the monitors make clear that
the monitors are not monitoring ambient air, which EPA has defined at
40 CFR 50.1(e) as ``that portion of the atmosphere, external to
buildings, to which the general public has access.'' Second, the
proposed EPA Method 325A sets out procedures to subtract background
concentrations and contributions to the fenceline benzene
concentrations from non-refinery emission sources, so that the benzene
concentrations measured are attributable to the refinery. In other
words, the fenceline monitoring work practice standard uses a benzene
concentration difference, referred to as the [Delta]C (essentially an
upwind and downwind concentration difference) to isolate the refinery's
emissions contribution.
Furthermore, we disagree that the fact that refiners are required
to perform corrective action if the fenceline benzene concentration
action level is exceeded makes the benzene action level an ambient
standard. As an initial matter sources are not directly responsible for
demonstrating that an area is meeting an ambient standard; rather that
burden falls on states. See e.g., CAA section 110(a)(2). Moreover, the
``corrective action'' is simply that sources must ensure that fugitive
emission sources on the property are not emitting HAP at levels that
will result in exceedances of the fenceline benzene concentration
action level. In other words, the purpose of the fenceline monitoring
work practice is to ensure that sources are limiting HAP emissions at
the fenceline, which are solely attributable to emissions from sources
within the facility. In fact, the fenceline benzene concentration
action level was established using emissions inventories reported by
the facilities, assuming compliance with the MACT standards. Finally,
monitoring is conducted as part of the work practice standard to
identify sources that will require additional controls to reduce their
impact on the fenceline benzene concentration. In that sense, the
fenceline monitoring work practice standard is not different than, for
example, our MACT standard for refinery heat exchangers. If a facility
is exceeding the relevant cooling water pollutant concentration
``level'' when it performs a periodic test, it must undertake
corrective action to bring the concentration down below the action
level.
Comment: Several commenters noted that EPA's authority under
section 112(d) is to set ``emissions standards'' and quoted the CAA
definition of that term: ``A requirement . . . which limits the
quantity, rate, or concentration of emissions of air pollutants on a
continuous basis, including any requirement relating to the operation
or maintenance of a source to assure continuous emission reduction, and
any design, equipment, work practice or operational standard
promulgated under this Act.'' 42 U.S.C. 7602(k). The commenters argued
that the proposed fenceline monitoring standard does not meet this
definition because it would not ``limit the quantity, rate, or
concentration of emissions'' from any given emissions point. Also, the
commenters claimed that the EPA did not designate fenceline monitoring
as a work practice under CAA section 112(h) since the EPA did not even
mention CAA section 112(h), nor did it conduct any analysis to show
that fenceline monitoring meets the CAA section 112(h) factors.
Response: We disagree with the commenters' assertion that the
proposed fenceline monitoring work practice standard is not authorized
under CAA section 112(d)(6). Contrary to the commenter's claims, we
specifically proposed the fenceline monitoring standard under CAA
section 112(d)(6) to be a work practice standard that is applied
broadly to fugitive emissions sources located at petroleum refineries.
As discussed above, the proposed standard does more than impose
monitoring as some commenters suggested; it also will limit emissions
from refineries because it requires the owner or operator to identify
and reduce HAP emissions through a monitoring and repair program, as do
many work practice standards authorized under CAA Section 112(h) and
112(d).
We note that the sources addressed by the fenceline monitoring
standard--refinery fugitive emissions sources such as wastewater
collection and treatment

[[Page 75193]]

operations, equipment leaks, heat exchange systems and storage vessels
in the Refinery MACT 1 rule--are already subject to work practice
standards. Our review of these requirements indicates that this
fenceline monitoring work practice standard would be a further
improvement in the way fugitive emissions are managed and would provide
an extra measure of protection for surrounding communities. The
commenter claims EPA did not analyze how the fenceline monitoring
requirement meets the criteria in section 112(h). However, that is a
misinterpretation of how the criteria apply. The criteria are assessed
with regard to whether it is feasible to ``prescribe or enforce an
emission standard for a source'', and do not apply to the work practice
standard. Consistent with the criteria in section 112(h)(2), we
determined and established that work practice standards are appropriate
for these Refinery MACT fugitive emissions at the time we established
the initial MACT standard. In the proposal, (79 FR at 36919, June 30,
2014), we reaffirmed that it is impracticable to directly measure
fugitive emission sources at refineries but did not consider it
necessary to reiterate these findings as part of this proposal to
revise the existing MACT for these sources under CAA section 112(d)(6).
We note that the commenters do not provide any grounds to support a
reevaluation of whether these fugitive emission sources are
appropriately regulated by a work practice standard.
Comment: Several commenters questioned the EPA's authority under
the CAA to promulgate a rule that amounts to an ongoing information
gathering and reporting obligation. The commenters stated that the EPA
has not demonstrated that the proposed fenceline monitoring program
represents an actual emission reduction technology improvement. A
commenter stated that compliance assurance methods, including
monitoring, for fugitive emissions and other emission standards are
established as part of the emission standard and EPA's authority to
gather information that is not directly required for compliance with a
specific standard but is related to air emissions is found in CAA
section 114. Under CAA section 114, the requirement must be related to
one of the stated purposes and must be reasonable. The commenter did
not believe that the EPA has demonstrated that the costs of fenceline
monitoring are reasonable in light of the information already available
to the EPA and in light of many other means by which the EPA could
obtain such information.
Response: We disagree with the commenters' assertion that the
authority for the fenceline monitoring requirement falls under CAA
section 114 and not CAA section 112(d) because it is an ``ongoing
information gathering and reporting obligation.'' The issue here is not
whether EPA could have required the fenceline monitoring requirement
under CAA section 114, but rather did EPA support that it was a
development in processes practices or controls technology under section
112(d)(6).
As an initial matter, we disagree with the commenters'
characterization of the fenceline monitoring standard as ``an
information gathering and reporting obligation.'' We have repeatedly
stated that we consider the fenceline monitoring requirement to be a
work practice standard that will ensure sources take corrective action
if monitored benzene levels (as a surrogate for HAP emissions from
fugitive emissions sources) exceed the fenceline benzene concentration
action level. The standard requires refinery owners or operators to
monitor the benzene concentration at the refinery perimeter, to
evaluate the refinery's contribution as estimated by taking the
concentration difference between the highest and lowest concentrations
([Delta]C) in each period, and to conduct root cause analysis and take
corrective action to minimize emissions if the concentration difference
is higher (on an annual average) than the benzene concentration action
level. Thus, the fenceline monitoring requirement goes well beyond
``information gathering and reporting.''
In addition, the commenters again read section 112(d)(6) too
narrowly by suggesting that a program considered as a development must
be a ``technology'' improvement. Section 112(d)(6) of the CAA requires
the EPA to review and revise the MACT standards, as necessary, taking
into account developments in ``practices, processes and control
technologies.'' Consistent with our long-standing practice for the
technology review of MACT standards, in section III.C of the proposal
(see 79 FR 36900, June 30, 2014), we list five types of
``developments'' we consider. Fenceline monitoring fits squarely within
two of those five types of developments (emphasis added):
Any add-on control technology or other equipment that was
not identified and considered during development of the original MACT
standards.
Any work practice or operational procedure that was not
identified or considered during development of the original MACT
standards.
As used here, ``other equipment'' is clearly separate from and in
addition to ``add-on control'' technology and is broad enough to
include monitoring equipment. In this case, fenceline monitoring is a
type of equipment that we did not identify and consider during
development of the original MACT standards. Additionally, the fenceline
standard is a work practice standard, involving monitoring, root cause
analysis and corrective action not identified at the time of the
original MACT standards. Therefore, the fenceline requirements are a
development in practices that will improve how facilities manage
fugitive emissions and EPA appropriately relied on section 112(d)(6) in
requiring this standard.
Comment: Some commenters contended that because the fenceline
monitoring standard is in essence an ambient standard, the only
justification that can be used to support it would be under CAA section
112(f)(2). The commenters stated that EPA determined that the MACT
standards pose an acceptable level of risk and protect the public
health with an ample margin of safety and thus, section 112(f) does not
support imposition of the fenceline monitoring requirement. Several
commenters stated that the Agency expressly acknowledges that
imposition of additional emission standards for fugitive emissions from
refinery sources are not warranted under CAA section 112(f). Some
commenters suggested that because the existing MACT standards protect
public health with an ample margin of safety, the fenceline monitoring
requirement imposes an unnecessary burden on industry because it is not
necessary to achieve acceptable risk or provide an ample margin of
safety.
Response: EPA is not relying on section 112(f)(2) as the basis for
the fenceline monitoring requirement. As provided in a previous
response to comment, we disagree with the commenters that the fenceline
monitoring requirement is an ambient standard and therefore, we do not
need to consider what authority would be appropriate for establishing
an ambient standard that would apply to fugitive sources of emissions
at refineries. We also disagree with the commenters who suggest that
EPA may not require fenceline monitoring pursuant to section 112(d)(6)
because EPA has not determined that fenceline monitoring is necessary
to ensure an acceptable level of risk or the provide an ample margin of
safety. Section 112(d)(6) does not

[[Page 75194]]

require EPA to factor in the health considerations provided in section
112(f)(2) when making a determination whether it is ``necessary'' to
revise the MACT.
Comment: Commenters stated that the pilot studies undertaken by the
EPA and pilot studies undertaken by the refining industry (see the API
Fenceline Study in the docket for this rulemaking) demonstrate either
that there is no underestimation of emissions and thus, no need for the
fenceline monitoring work practice standard, or that fenceline benzene
data cannot be used to validate emission estimates. Commenters stated
that none of the refineries in the API study of the proposed refinery
fenceline standard had study-averaged [Delta]C concentrations that
exceeded the proposed action level of 9 [micro]g/m\3\ and thus the
study provides some evidence that U.S. refineries are not
underestimating emissions. Furthermore, the commenter stated that there
is significant ambient air monitoring performed that further supports
low benzene concentrations in the vicinities of refineries and cited
ambient monitoring data collected by the Southeast Texas Regional
Planning Commission Air Quality Group and the Texas Commission on
Environmental Quality (TCEQ).
Response: We disagree that the API fenceline study demonstrates
that there is no underestimation of emissions. The API report referred
to by the commenter actually shows higher [Delta]C concentrations than
what we expected, when we compare the distribution of [Delta]C's
presented in the API fenceline study to the distribution of benzene
concentrations at the 142 refineries we modeled (see memorandum
``Fenceline Ambient Benzene Concentrations Surrounding Petroleum
Refineries'', EPA-HQ-OAR-2010-0682-0208). [Note that API did not
identify the facilities in their study, so we were not able to perform
a one-to-one comparison of the measured [Delta]C concentrations with
the modeled fenceline concentrations.] Furthermore, the API conducted
the study primarily during the fall and winter months (October to
March) when the ambient temperatures are lower than the annual
averages. While this may not impact equipment leak emissions,
temperature can have a significant impact on emissions from storage
vessels and wastewater treatment systems, so it is likely that the
annual average [Delta]C for the facilities tested could be higher than
the ``winter'' averages measured in the API study. Based on our review
of the API study data, we interpret the results to indicate that there
may be higher concentrations of benzene on the fenceline attributable
to fugitive emissions than anticipated at some facilities. These
studies are an indication that the standard we are finalizing will
achieve the goal of ensuring that the owners or operators manage
fugitive emissions within the refinery.
This regulatory approach also fits with the EPA's goals to improve
the effectiveness of rules. Specifically, in this case, we are
improving the effectiveness of the rule in two ways. First, we are
establishing a fenceline benzene trigger to manage overall fugitive HAP
emissions, rather than establishing further requirements on many
individual emission points. Secondly, the rule incentivizes facilities
to reduce fugitive HAP emissions below the fenceline benzene trigger by
providing regulatory options for reduced monitoring.
Regarding ambient monitoring data, we note that existing ambient
monitors are not located at the fenceline; they are located away from
sources, and concentrations typically decrease exponentially with
distance from the emissions source. We are encouraged that data
referenced by the commenter indicate that ambient levels of benzene are
within levels that are protective of human health in communities, but
note that analysis of benzene concentrations in communities does not
necessarily indicate that refineries located near these communities are
adequately managing their fugitive HAP emissions.
Comment: Several commenters reiterated that they do not believe the
proposed fenceline monitoring is a technology development for equipment
leaks, storage vessels or wastewater sources. However, if the EPA
finalizes the fenceline monitoring requirements, the commenters
suggested that there is no longer a need or regulatory basis for
imposing both the fenceline monitoring requirements and the existing
MACT standards for fugitive HAP emission sources. Thus, the EPA should
remove the current MACT requirements for LDAR, storage vessels and
wastewater handling and treatment from Refinery MACT 1 if the EPA
promulgates fenceline monitoring. Addition of fenceline monitoring on
top of the existing MACT requirements, they argue, would violate the
Executive Order 12866 mandate to avoid redundant, costly regulatory
requirements that provide no emission reductions.
Response: We disagree that the fenceline monitoring standards we
are finalizing in this rule are redundant to MACT emissions standards
for fugitive HAP emissions sources. The MACT standards impose
requirements on fugitive HAP emissions sources consistent with the
requirements in CAA section 112(d)(2) & (3), and the fenceline
monitoring requirement is not a replacement for those requirements.
Rather, based on our review of these standards, we concluded that
fenceline monitoring is a development in practices, processes or
control technologies that would improve management of fugitive
emissions in a cost-effective manner. In selecting this development as
an across-the-board means of improving management of fugitive
emissions, we rejected other more costly developments that would have
applied independently to each fugitive emissions source. Requiring
refineries to establish a fenceline monitoring program that identifies
HAP emission sources that cause elevated benzene concentrations at the
fenceline and correcting high emissions through a more focused effort
augments but does not replace the existing requirements. We found that,
through early identification of significant fugitive HAP releases
through fenceline monitoring, compliance with the existing MACT
standards for these emissions sources could be improved and that it was
necessary to revise the existing standards because fenceline monitoring
is a cost-effective development in processes, practices, and control
technologies.
We note that the existing MACT requirements are based on the MACT
floor (the best performers), and as such, provide a significant degree
of emission reductions from the baseline. The action level for the
fenceline work practice standard, by contrast, is not based on the best
performers but rather on the highest value expected on the fenceline
from any refinery, based on the modeling of refinery emission
inventories. As such it is not representative of the best performers
and could not be justified as meeting the requirements of section
112(d)(2)and (3). If we were to remove the existing standards for
fugitive emission sources at the refinery, we would not be able to
justify that sources are meeting the level of control we identified as
the MACT floor when we first promulgated the MACT. Nor could we justify
the fenceline monitoring program we are promulgating as representing
the MACT floor because we considered cost (and not the best performers
as previously noted) in identifying the components of the program.
Although the fenceline monitoring standard on its own cannot be
justified as meeting the MACT floor requirement for each of the
separate

[[Page 75195]]

types of fugitive emission sources, that does not mean that it is not
an effective enhancement of those MACT requirements. To the contrary,
it works in tandem with the existing MACT requirements to provide
improved management of fugitive emissions and, in that sense, it is
precisely the type of program that we believe Congress had in mind when
enacting section 112(d)(6).
ii. Rule Should Require Real-Time Monitoring Technology for Fenceline
Monitoring.
Comment: Numerous commenters stated that the proposed fenceline
standards, which require monitoring using 2-week integrated passive
samplers, are flawed and weak for a number of reasons, including that
the monitoring method does not provide real-time data, does not provide
adequate spatial coverage of the fenceline, and does not provide a
mechanism to identify the specific emission source impacting the
fenceline to manage fugitive emissions. Several commenters suggested
that this monitoring technology is not state of the art. They claimed
that there are superior systems in place at refineries that are
technically and economically feasible, including at Shell Deer Park,
Texas; BP Whiting, Indiana; and Chevron Richmond, California. Further,
they claimed that these systems more effectively achieve the objective
of reducing fugitive emissions. They claimed several systems are
superior to the proposed system, including open-path systems such as
ultraviolet differential optical absorption (UV DOAS) and Fourier
transform infrared spectroscopy (FTIR), as well as point monitors such
as gas chromatographs. A number of commenters suggested that open-path
monitors should be required, stating that this technology is capable of
providing real-time analysis and data on air pollution, is able to
analyze multiple pollutants simultaneously at low, near-ambient
concentrations, and is capable of providing more complete geographic
coverage.
The commenters also stated that the benefits of real-time monitors
are particularly important in communities close to refineries, where
they believe refinery emissions are a major source of toxic pollutants
and short-term upset events that can have significant public health
impacts. In particular, the commenters stated that open-path monitors
promote an individual's right-to-know, in real-time, about harmful
pollution events affecting their communities, and will allow refinery
owners or operators to immediately identify fugitive emissions and
undertake swift corrective action to reduce these emissions. Some
commenters suggested that, if the EPA rejects these open-path real-time
monitors, then at a minimum the EPA should require the use of active
daily monitoring, such as auto-gas chromatograph (GC) systems.
Finally, a number of commenters recommended that the EPA provide
sufficient flexibility in its regulations to allow state and local
jurisdictions to develop, demonstrate, and subsequently require the use
of alternative monitoring programs, provided these monitoring programs
are at least equivalent to those in the final rule.
Response: We understand that many commenters believe real-time
monitoring would not only help refinery owners or operators in
identifying emission sources, but also would warn the community of
releases in real time.
Both open-path systems and active sampling systems (such as auto-
GCs) mentioned by the commenters, are monitoring systems capable of
yielding monitoring data quickly--ranging from a few minutes to about a
day. However, these ``real-time'' systems have not been demonstrated to
be able to achieve all of the goals stated by the commenters--
specifically, able to provide real-time analysis and data on multiple
pollutants simultaneously at low-, near-ambient concentrations, with
more complete geographic (or spatial) coverage of the fenceline.
The real-time open-path systems suggested by the commenters are all
limited in that they are not sensitive enough to detect benzene at the
levels needed to ensure that fenceline monitoring achieves its intended
goal. The fenceline monitoring system needs to be capable of measuring
at sub-ppbv levels--well below the 9 [mu]g/m\3\ fenceline benzene
concentration action level in the final rule, in order to determine the
[Delta]C. In the proposal, we discussed two open-path monitoring
technologies, FTIR and UV-DOAS. For the proposed rule, we analyzed the
feasibility of employing UV-DOAS over FTIR because the UV-DOAS is more
sensitive to detection of benzene than FTIR, as we described in the
proposal. We reviewed performance data on several UV-DOAS systems in
support of the proposed rule, and for this final rule, we considered
information submitted during the comment period. We found that the
lowest detection limit reported for any commercially-available UV-DOAS
system is on the order of 3 ppbv over a 200-meter path length, whereas
the fenceline benzene concentration action level is 2.8 ppbv
(equivalent concentration to 9 [mu]g/m\3\). This system is being
installed at the Shell Deer Park refinery but has not been field
validated yet. Thus, we do not yet know the detection capabilities of
the system, as installed. Based on the lowest reported detection limit,
it cannot achieve the detection levels needed to demonstrate compliance
with the fenceline standard in this final rule. This system also will
only cover approximately 5 percent of the fenceline at Shell Deer Park,
instead of the full fenceline coverage of the passive diffusive tube
monitoring system we proposed. Facilities would have to deploy a
monitoring system consisting of many open-path monitors to achieve the
same spatial coverage as the passive diffusive tube monitoring system.
For the final rule, we also reviewed other UV-DOAS systems in
operation at refineries that commenters identified. However, reported
detection limits for these systems are even higher than for the type of
system being installed at Shell Deer Park. For example, we reviewed the
open-path UV-DOAS system information from BP Whiting and found that
they were able to verify a detection limit of 8 ppbv path average
concentration for benzene over a 1,500-meter optical path. This is well
above the 2.8 ppbv fenceline benzene concentration action level, let
alone the sub-ppbv levels necessary to determine the [Delta]C.
Moreover, this system, though commercially available, was optimized by
developing alternative software to improve the detection limit (see
memorandum ``Meeting Minutes for April 21, 2015, Meeting Between the
U.S. EPA and BP Whiting'' in Docket ID No. EPA-HQ-OAR-2010-0682). Thus,
the system, as installed, would not be readily available to other
refineries. We reviewed data for the UV-DOAS system at the Chevron
Richmond refinery and found that this system, with optical path lengths
ranging from 500 to 1,000 meters, has a reported benzene detection
limit of 5 ppbv averaged over the path length. Again, this is above the
fenceline benzene concentration action level at the fenceline
established in this final rule. In addition, we could not find any
information to support the reported detection limit. We note that the
public Web site operated by the City of Richmond, California indicates
that information provided by the system is informational only, not
quality assured, and not to be used for emergency response or health
purposes.
We also disagree with the commenter's claim that if the EPA does
not finalize requirements for real-time open-path monitors then, at a
minimum, the EPA should require active daily monitoring. There are two
methods of

[[Page 75196]]

active monitoring. One method, which we will refer to as the ``auto-GC
method,'' uses a dedicated gas chromatograph at each monitoring
location and can return ambient air concentration results multiple
times a day or even hourly. The other method, which we refer to as
``method 2,'' uses an active pump to collect gas in a sorbent tube or
in an evacuated canister over a 1-day period, for later analysis at a
central location. While active sampling monitoring networks are capable
of measuring multiple pollutants and would likely be able to detect
benzene at sub-ppbv levels as necessary to demonstrate compliance with
the fenceline requirements in this final rule, they consist of discreet
monitors and would not provide any better spatial coverage of the
refinery fenceline than a passive diffusive tube monitoring network.
Further, as shown in Table 9 of the proposed rule (see 79 FR 36923,
June 30, 2014), like open-path systems, an active sampling monitoring
network would cost many times that of a passive diffusive tube
monitoring network. At proposal, we estimated the costs of active daily
sampling based on ``method 2'' to be approximately 10 times higher than
for the proposed passive monitoring (see memorandum ``Fenceline
Monitoring Technical Support Document'', Docket ID No. EPA-HQ-OAR-2010-
0682-0210). We note that this type of active daily sampling based on
method 2 does not necessarily yield results within 24 hours as the
sample analysis would be conducted separately. We did not specifically
estimate the costs of an auto-GC alternative, but the capital costs
would be at least 20 to 30 times that for the passive diffusive tube
system, would require shelters and power supplies at all monitoring
locations and would have operating costs similar to the ``method 2''
active monitoring option we considered.
To date, there are no commercially-available, real-time open-path
monitors capable of detecting benzene at the sub-ppbv levels necessary
to demonstrate compliance with the fenceline requirements in this final
rule. Only a system that can detect such levels will result in
effective action by facilities to identify and control fugitive
emissions in excess of those contemplated by the MACT standards.
Further, active monitoring systems, while potentially capable of
detecting benzene at sub-ppbv levels, like open-path systems, become
very costly when enough monitors are located around the facility to
approach the spatial coverage of the passive diffusive tubes. However,
we believe that the state of technology is advancing and that the
capabilities of these systems will continue to improve and that the
costs will likely decrease. If a refinery owner or operator can
demonstrate that a particular technology would be able to comply with
the fenceline standards, the owner or operator can request the use of
an alternative test method under the provisions of 40 CFR 63.7(f). A
discussion of the specific requirements for these requests can be found
in the first comment and response summary of Chapter 8.3 of the
``Response to Comment'' document.
Comment: One commenter stated that the required monitoring should
include real-time monitoring of all chemicals released by refineries
that pose risks to human health. The commenter stated that the limited
scope of monitoring required by the proposed rule appears to be guided
by the EPA's judgment that fugitive, or ``unintended'' emissions pose
the greatest threat to public health. On the contrary, communities may
well suffer from the effects of chemicals released into the air under
normal, permitted emissions. A more expansive monitoring strategy would
account for both routine and fugitive emissions.
Several commenters noted that monitoring is limited to benzene as
opposed to multiple HAP. One commenter noted that ill health
experienced by refinery neighbors is due in large part to the
synergistic effects of multiple chemicals. Therefore, the commenter
stated that it is essential that the rule require monitoring of the
full range of chemicals with health implications. Other commenters
recommended that the fenceline monitoring requirement be amended to
include additional contaminants, such as VOC, that may negatively
impact human health and the environment. Conversely, other commenters
stated that the EPA has appropriately selected benzene as a target
analyte and surrogate for HAP emissions from petroleum refineries, as
benzene is a common constituent in refinery feedstocks and numerous
refinery streams, and is present in most HAP-containing streams in a
refinery.
Response: As part of the CAA section 112(d)(6) technology review,
the EPA identified the fenceline monitoring standard as a development
in practices, processes or control technologies that could improve
management of fugitive HAP emissions. Thus, to the extent the commenter
is suggesting that the EPA require the fenceline monitoring system to
monitor for emissions of non-HAP pollutants, such request goes beyond
the scope of our action. Furthermore, to the extent that the commenter
is raising health concerns, although we address residual risk remaining
after implementation of the MACT standards under CAA section 112(f)(2),
we note that the MACT standards themselves, including this requirement,
are aimed at protecting public health, especially in surrounding
communities. As we explained in the proposal, and as we determine for
this final rule, the MACT standards as modified by additional
requirements for storage vessels, provide an ample margin of safety to
protect public health. We did not propose and are not finalizing a
fenceline monitoring requirement as necessary to provide an ample
margin of safety under CAA section 112(f)(2).
Petroleum refining emissions can contain hundreds of different
compounds, including many different HAP, and no single method can
detect every HAP potentially emitted from refineries. While several HAP
are amenable to quantification via passive diffusive tube monitoring
using the same adsorbent tubes used for benzene (e.g., toluene, xylenes
and ethyl benzene, which have uptake rates in Table 12.1 in Method
325B), we selected benzene as a surrogate because it is present in
nearly all refinery fugitive emissions. By selecting a single HAP as a
surrogate for all fugitive HAP, we are able to establish a clear action
level, which simplifies the determination of compliance for refinery
owners or operators and simplifies the ability of regulators and the
public to determine whether sources are complying with the work
practice standard. As described in the proposal preamble, benzene is
ubiquitous at refineries and present in nearly all refinery process
streams, including crude oil, gasoline and wastewater. Additionally,
benzene is primarily emitted from ground level, fugitive sources that
are the focus of the work practice standard. Thus, we conclude that
monitoring of benzene is appropriate and sufficient to identify
emission events for which the monitoring program is targeting.
Consequently, we are not requiring quantification of other pollutants
although refinery owners or operators could choose to analyze the
diffusive tube samples for additional HAP in conducting root cause
analysis and corrective action.
iii. Fenceline Monitoring Action Level
Comment: Several commenters stated that the action level for
fenceline monitoring (i.e., 9 [mu]g/m\3\ or 2.8 ppbv), was set too
high. Some of these commenters noted that the EPA selected 9 [mu]g/m\3\
as the highest modeled benzene

[[Page 75197]]

concentration at any refinery fenceline. One commenter stated that this
was arbitrary and capricious and stated the action threshold level
makes little sense because only 2 of the 142 modeled facilities are
expected to have fenceline concentrations above 4 [mu]g/m\3\. Several
commenters noted that the average modeled benzene concentration is 0.8
[mu]g/m\3\, which is more than an order of magnitude less than the
proposed fenceline benzene concentration action level.
Two commenters argued for a lower action level threshold, citing
the proposed California OEHHA rule, which finalized new and revised
benzene reference exposure levels (REL) that are more stringent than
the ones the EPA used in the residual risk assessment supporting the
proposed rule.
Two commenters stated that while the fenceline benzene
concentration action level of 9 [mu]g/m\3\ is relatively protective
compared to standards adopted by many states, including Louisiana and
Texas, it is still 80-percent higher than the European Union's standard
of 5 [mu]g/m\3\. The commenter urged the agency to consider adopting a
stricter standard comparable to what other industrialized nations use.
Several commenters stated that the EPA's 9 [mu]g/m\3\ action level
is inconsistent with the statutory text and objectives of CAA sections
112(d) and (f), which direct the EPA to focus on the best-performing,
lowest-emitting sources, in order to require the ``maximum achievable''
emission reductions. The commenters stated that the EPA promulgated the
9 [mu]g/m\3\ limit without properly following the statutory
requirements for establishing MACT floor limits, pointing out that the
EPA made no determination of whether or not these general models were
representative of the emissions levels actually achieved by the
submitting refinery, and no connection was drawn between the best
performing sources and the eventual 9 [mu]g/m\3\ limit.
On the other hand, several commenters opposed the 9 [mu]g/m\3\
action level suggesting that it was not achievable and that it is
arbitrary. Some commenters noted that emission/dispersion models are
always very site-specific and do not necessarily yield a result that is
reliable or reproducible. Several commenters stated that additional
studies are necessary to allow the agency to account for these
variables and set a more appropriate concentration corrective action
level. Commenters suggested a 2-year data gathering effort at all
refineries and data evaluation before determining a specific threshold
to use.
Several commenters recommended action levels ranging from 15 [mu]g/
m\3\ to 20 [mu]g/m\3\ of benzene to account for the variability
expected in monitoring data. The commenters stated that modeling biases
have underestimated the necessary action level to achieve the stated
goals of the program.
Response: First, it is important to note that the purpose of the
standard has not changed between proposal and promulgation, namely that
it is a technology-based standard that is an advancement in practices
to manage fugitive emissions. It is not intended to be a separate or
new MACT standard promulgated pursuant to CAA sections 112(d)(2) and
(3) for which a ``floor'' analysis would be required.\7\ Nor is it a
standard that we are promulgating pursuant to CAA section 112(f)(2) as
necessary to provide an ample margin of safety to protect public health
or prevent an adverse environmental effect.\8\ Thus, claims that a
standard should reflect European Union health-based standards or the
California OEHHA rule are misplaced. We also disagree with the
suggestion that the proposed monitoring requirement will allow for
higher emissions. As noted elsewhere, we are retaining all of the
source-specific requirements for fugitive emissions sources that exist
in Refinery MACT 1.
---------------------------------------------------------------------------

\7\ To the extent that the commenters are suggesting that EPA
must re-perform the MACT floor analysis for purposes of setting a
standard pursuant to section 112(d)(6), we note that the D.C.
Circuit has rejected this argument numerous times, most recently in
National Association for Surface Finishing et al. v. EPA No. 12-1459
in the U.S. Court of Appeals for the District of Columbia.
\8\ Although we did not establish this limit to address residual
risk under CAA section 112(f)(2), the limit was derived from the
same inventory used for our risk modelling. Thus, based on our
current reference concentration for benzene, the 9 [mu]g/m\3\ action
level will also ensure that people living near the refinery will not
be exposed to cancer risks exceeding 100-in-1 million.
---------------------------------------------------------------------------

We disagree with the commenters that suggest that the proposed
action level of 9 [mu]g/m\3\ is too low and may not be achievable even
for well-performing facilities. As discussed in the preamble for the
proposed rule, we selected the 9 [mu]g/m\3\ benzene action level
because it is the highest value on the fenceline predicted by the
dispersion modeling and, thus, is a level that we estimate that no
refinery should exceed when in full compliance with the MACT standards,
as amended by this final rule. All of the results of our pilot study,
the API study, and the other ambient monitoring data near refineries
clearly indicate that this level is achievable. Furthermore, we expect
the fenceline concentration difference measured following the
procedures in the final rule to be indicative of refinery source
contributions and we have provided procedures to isolate these
concentrations from outside sources, as well as background.
We expect that the fenceline monitoring standard will result in
improved fugitive HAP emissions management as it will alert the
refinery owners or operators of fugitive sources releasing high levels
of HAPs, such as large leaks, faulty tank seals, etc.
iv. Fenceline Monitoring Root Cause Analysis and Corrective Action
Provisions
Comment: A number of commenters objected to the proposal's ``open-
ended'' provisions allowing the EPA to direct refinery owners or
operators to change their operations in order to achieve the fenceline
limit, with no regulatory limits on costs and without consideration of
the impact to safe operations or operability of the plant. Another
commenter stated that the EPA must properly assess the costs associated
with the root cause analysis/corrective action requirements and should
establish a cost effectiveness threshold for any required root cause
analysis/corrective action to ensure that limited resources are
effectively and efficiently applied for the control of emissions.
One commenter stated the proposed fenceline benzene concentration
action level is effectively an ambient air standard, because corrective
action to achieve that level is required and that if a facility's
initial corrective action is unsuccessful, the rule provides that
further action is required and the EPA must approve that further
corrective action plan. Thus, the commenter argued, the EPA would
essentially be able to dictate corrective actions, with no bounds on
what could be required and no consideration of whether any cost-
effective actions are available to assure the action level is met. The
commenter continued that such a requirement converts a work practice
program to an emission limitation and such ambient air limits are not
authorized by CAA section 112. Several commenters noted that LDAR and
current work practice programs have no similar requirement for the EPA
approval, and the commenters suggested that the requirement for the EPA
approval of any second corrective action should not be included in 40
CFR 63.658(h).
Another commenter recommended that, if after corrective action, a
facility still has an exceedance for the next sampling episode, then
the facility should be required to do more than it

[[Page 75198]]

did after the first root cause analysis, as the prior corrective action
clearly did not correct the problem. The commenter stated that one
corrective action measure the EPA should include in all such instances
is higher-quality monitoring such as UV-DOAS for at least 1 year to
monitor, identify, correct and assure ongoing compliance after the
exceedance problem is fixed.
Response: The ``on-going'' requirement to achieve the fenceline
benzene concentration action level is no different in concept from the
LDAR requirements for equipment or heat exchange systems in the
Refinery MACT 1 rule, which requires the refinery owner or operator to
repair the source of the emissions regardless of what it takes until
compliance with the standard is achieved.
We disagree with the claim that the EPA must assess the costs
associated with the root cause analysis/corrective action requirements
and establish a cost effectiveness threshold for any required root
cause analysis/corrective action to ensure that limited resources are
effectively and efficiently applied for the control of emissions. We
did not attempt to project the costs of the root cause analysis/
corrective action for at least two reasons. First, based on the
dispersion modeling of the benzene emissions reported in response to
the inventory section of the 2011 ICR, we project that no refinery
should exceed that fenceline benzene concentration action level if in
full compliance with the MACT standards, as amended by this action.
Thus, assuming compliance with the MACT standards, we would expect that
there are no costs for root cause analysis/corrective action. To the
extent that there are exceedances of the action level, the premise of
the fenceline monitoring is to provide the refinery owners or operators
with the flexibility to identify the most efficient approaches to
reduce the emissions that are impacting the fenceline level. Since the
choice of control is a very site-specific decision, we would have no
way to know how to estimate the costs. Thus, the source is in the best
position to ensure that resources are effectively and efficiently spent
to address any exceedance.
We intended the proposed requirement for refinery owners or
operators to submit a corrective action plan for the EPA approval to
provide the Administrator with information that they were making a
good-faith effort to reduce emissions below the fenceline benzene
concentration action level, as expeditiously as practicable. However,
we understand the importance for refinery owners or operators to begin
corrective action as soon as possible, without having to wait for the
EPA approval. Therefore, we are finalizing the requirement for refinery
owners or operators to submit such plans but we are not finalizing the
requirement that the EPA must approve the plan prior to the corrective
action being taken.
We previously responded to comments regarding UV-DOAS or other
open-path monitoring systems in this section, explaining that the
current detection limits for these systems exceeds the action level
threshold and, thus, these systems would not provide usable data to
inform corrective action. Thus, we disagree that the EPA should require
these systems for all facilities whose first attempt at corrective
action is ineffective.
v. Fenceline Monitor Siting Requirements
Comment: Numerous commenters provided suggestions on, or requested
clarification of, the monitor siting requirements. Several commenters
stated that proposed Method 325A uses the terms ``fenceline or property
boundary,'' while it should consistently use the term ``property
boundary'' or even ``property line'' as the fenceline location. Several
commenters stated that Sections 8.2.2.1.4 and 8.2.2.3 of Draft Method
325A specify that samplers be placed just beyond the intersection where
the measured angle intersects the property boundary and this could
require placing monitors on other people's property, in a road, in a
water body or in a railroad right-of-way. The commenters suggested that
facilities should be allowed to place monitors at any vector location
that meets other requirements between the property boundary and the
source nearest the property boundary. They stated that facilities need
this clarification to avoid obstructions (e.g., buildings or trees)
that may be at the property line.
Numerous commenters requested that the rule clarify where monitors
need to be placed in special circumstance, such as refineries bisected
by a road, railroad or other public right-of-way or a boundary next to
a navigable waterway. Several commenters stated that refiners should
not need to place monitors on these property boundaries or other
property boundaries where there are no residences within 500 feet of
the property line. Commenters also asked if areas that had non-refinery
operations, but are still inside the property boundary, would be
included for purposes of determining where to site monitors.
A few commenters expressed concern about the approach for
determining the number of required monitors at a site based on the
acreage, noting that it is unfair to small facilities and will leave
gaps in monitoring coverage for very large facilities. Some commenters
recommended amending the proposed rule to require the placement of
fenceline monitors at fixed distances along facilities' perimeters with
no maximum number of monitors. Some commenters stated that the rule
should specify an acceptable range on the 2,000-foot spacing
requirement or the radial placement requirement as it may be necessary
to address accessibility or safety concerns. Several commenters
suggested that a lower minimum number of sampling monitors should be
required for very small refineries or small ``subareas.'' These
commenters noted that refineries often include disconnected parcels
that can be very small (e.g., 10 acres or less). If each disconnected
parcel must be treated as a separate subarea, then both sampler siting
options in Draft Method 325A would result in unnecessarily large
numbers of samplers extremely close together. Some commenters
recommended that Method 325A specify that samplers need not be placed
closer than 500 feet (versus the normal 2,000-foot interval specified
in Option 2) along the fenceline from an adjoining sampler, regardless
of whether the radial or linear approach is used and should waive the
minimum number of samplers specified in Sections 8.2.2.1.1, 8.2.2.2.1,
and 8.2.3.1. Another commenter added that the rule should waive the
requirement for additional samplers in Sections 8.2.2.1.5 and 8.2.3.5
if the 500-foot minimum spacing criterion is compromised.
Response: We agree that the Method 325A should provide clear and
consistent language. We have revised the language to be consistent in
referring to the ``property boundary''. We have also revised the Method
to allow placement of monitors at any radial distance along either a
vector location or linear location (that meets the other placement
requirements) between the property boundary and the source nearest the
property boundary. That is, the monitors do not need to be placed
exactly on the property boundary or outside of the property boundary.
They may be placed within the property closer to the center of the
plant as long as the monitor is still external to all potential
emission sources. We do note that if the monitors are placed farther in
from the property boundary, the owner or operator should take care to
ensure, if possible, that the radial distance from the sources to the
monitors is at least 50

[[Page 75199]]

meters. If the perimeter line of the actual placement of the fenceline
monitors is closer than 50 meters to one or more sources, then the
additional monitor citing requirements will apply. We have revised
subparagraphs of Section 8.2.2 to provide this allowance. This
clarification should address issues related to obstructions such as
tall walls located at the facility boundary.
We intended that the fenceline monitoring would create a monitoring
perimeter capable of detecting emissions from all fugitive emission
sources at the refinery facility. We have long established that a road
or other right of way that bisects a plant site does not make the plant
site two separate facilities, and, thus, would not be considered part
of the property boundary. As we agree that monitors need only be placed
around the property boundary of the facility, it would not be necessary
to place monitors along a road or other right-of-way that bisects a
facility. We have clarified this in the final rule and Method 325A.
If the facility is bounded by a waterway on one or more sides, then
the shoreline is the facility boundary and monitors should be placed
along this boundary. If the waterway bisects the facility, the waterway
would be considered internal to the facility and monitors would only be
needed at the facility perimeter.
Regarding the comment that monitors should not be required where
there is no residence within 500 feet of the property line, we
disagree. We proposed and are finalizing the fenceline monitoring
standards under CAA section 112(d)(6) as a means to improve fugitive
HAP emissions management, regardless of whether there are people living
near a given boundary of the facility.
Regarding the clarification requested about monitor placement
considering non-refinery operations, the property boundary monitors
should be placed outside of all sources at the refinery. This is
because moving the monitoring line inward to exclude the non-refinery
source could lead to an underestimation of the [Delta]C compared to the
monitoring external of the entire site. If the non-refinery source is
suspected of contributing significantly to the maximum concentration
measured at the fenceline, a site-specific monitoring plan and
monitoring location specific near-field interfering source (NFS)
corrections will be needed to address this situation.
Section 8.2.3 of Method 325A includes language to provide some
flexibility when using the linear placement (10% or 250 feet). We consider it reasonable to provide similar placement
allowance criteria for the radial placement option (1
degree). We are not providing requirements that would allow small area
refineries to use fewer than 12 monitoring sites. We do not consider
that any refinery would be so small as to warrant fewer than 12
monitors; however, we did not necessarily consider very small subareas
for irregularly shaped facilities or segregated operations. When
considering these subareas, we agree that fewer than 12 monitoring
sites should be appropriate. Therefore, we have provided that monitors
do not need to be placed closer than 152 meters (500 feet) (or 76
meters (250 feet) if known sources are within 50 meters (162 feet) of
the monitoring perimeter, which is likely for these subareas or
segregated areas) with a stipulation that a minimum of 3 monitoring
locations be used per subarea or segregated area. We note, however,
that this distance provision does not obviate the near source extra
monitoring siting requirements or the requirement to have a minimum of
three monitors per subarea or segregated area.
If facility owners or operators have questions regarding the
required locations of monitors for a specific application, they should
contact the EPA (or designated authority) to resolve questions about
acceptable monitoring placement.
vi. Compliance Time for Fenceline Monitoring Requirements
Comment: Some commenters supported EPA's proposal to provide 3
years to put a fenceline monitoring program in place, but the
commenters believe that timing is unclear in the proposed regulatory
language, which appears in Table 11 to subpart CC, and requested that
the EPA add the initial compliance date to 40 CFR 63.658(a). One
commenter stated that instituting this program for all 142 major source
U.S. refineries would require considerable time. Based on their
experience with their pilot study, one commenter noted that
commercially available weather guards meeting the specifications of
proposed Method 325A are not available and would need to be fabricated.
Additionally, a commenter stated that only a limited number of
laboratories in the U.S. are able to perform the necessary analyses.
According to the commenter, considerable time and effort will be needed
to qualify additional laboratories and to expand the capacity of
existing laboratories to handle the samples from 142 refineries.
Other commenters disagreed with the EPA's proposed compliance time
and suggested that the EPA shorten the timeline for implementation at
refineries so that possible corrective action occurs much sooner than
proposed. The commenters suggested that deployment of passive samplers
can proceed more promptly than proposed, especially since the EPA has
simultaneously proposed specific ``monitor siting and sample collection
requirements as EPA method 325A of 40 CFR part 63, Appendix A, and
specific methods analyzing the sorbent tube samples as EPA Method 325B
of 40 CFR part 63, Appendix A.'' Moreover, the commenter noted, a
principal reason that the EPA selected passive monitors over active
monitors was due to the relative ``ease of deployment.'' The commenter
claimed this ease of deployment rationale is undermined by a 3-year
grace period to deploy passive monitors when the EPA is providing very
specific criteria for their use. The commenter suggested that the EPA
require full compliance with the passive monitoring requirement within
1 year of the effective date of the rule.
Response: While we realize that it will take some time for the
refinery owners or operators to understand the final rule and develop a
compliant monitoring program, we agree that in requiring the passive
sampler monitoring system, we recognized the ease of implementation and
deployment. Although industry commenters identified issues they faced
in the API pilot study while trying to implement the monitoring method,
we note that the 12 facilities that participated in the API pilot study
installed the fenceline monitors and began sampling in late 2013 with
relative ease and within months of obtaining the draft methods. Thus,
we disagree with the suggestion that 3 years is insufficient and agree
with other commenters that 3 years is in fact too long. However, we
also are aware that the API pilot facilities used the direct [Delta]C
approach proposed and did not attempt to develop site-specific
monitoring programs to correct for interfering near-field sources.
Although we expect that facilities could complete direct implementation
of the proposed fenceline monitoring requirement within 1 year after
the effective date of the rule, as suggested by some commenters,
facilities that choose to develop a site-specific monitoring plan would
need a longer period of time. Therefore, we are finalizing requirements
that specify that facilities must begin monitoring for the official

[[Page 75200]]

determination of [Delta]C values no later than 2 years after the
effective date of the rule.
vii. Fenceline Monitoring Recordkeeping and Reporting Requirements
Comment: Some commenters suggested that facilities should be
required to submit the monitoring data via the ERT only if they exceed
the fenceline benzene concentration action level and that all remaining
data should be kept on-site and available for inspection or upon
request of the EPA, citing that this is consistent with EPA's
semiannual NESHAP reporting of only exceptions (i.e., deviations).
Other commenters requested that the EPA only post the rolling annual
average concentration values and not the 2-week monitoring data. These
commenters indicated concern that if errors are present in the raw data
that are submitted semiannually to the EPA, the data, errors and all,
will be released to the public and correcting them will not take place
or will not take place in a timely manner. One commenter added that
there is very little useful information that can be gleaned from the
raw data and posting it simply invites misunderstandings.
Commenters also stated that the EPA should adopt reporting
requirements to ensure that facilities report the monitoring data
appropriately. Specifically, commenters recommended that 40 CFR
63.655(h)(8)(i) should be clarified to only require reporting of valid
data and cautioned that data should be processed to allow accurate
calculations of annual averages to be used for reporting and
evaluation. To accomplish this, commenters recommended that the rule
provide 75 days from the end of a 6-month sampling period to report to
the EPA, rather than the proposed 45-day period, in order to provide
adequate time to obtain quality-assured results for all 2-week sampling
periods.
One commenter applauded the proposal's requirements for electronic
reporting of the fenceline concentration data and making the resulting
information publicly available. However, the commenter recommended that
the EPA consider a more truncated data reporting period that is more
consistent with the associated milestones of collecting a 14-day
sampling episode. As is, the commenter claimed, the proposed rule would
have a lag time of up to 7.5 months between data collection and
posting. The commenter indicated that data reporting on a more frequent
schedule will not only provide transparency, but will provide states
and local agencies with information about air quality at refineries at
a frequency that could allow informed activities to address leaks much
more quickly and protect public health.
Response: We disagree with the commenters who suggest that
facilities only report the rolling annual average or only exceedances
of the fenceline benzene concentration action level because the
commenters believe there is little information to be gleaned from the
raw data. Monitoring data are useful in understanding emissions,
testing programs, and in determining and ensuring compliance. We
generally require reporting of all test data, not just values
calculated from test data and/or where a facility exceeds an emissions
or operating limit. For example, when we conduct risk and technology
reviews for source categories, we are adding requirements for
facilities to submit performance test data into the ERT, not just
performance test data that indicates an exceedance of an applicable
requirement. In the Mercury and Air Toxics Rule, we require facilities
to report direct measurements made with CEMS, such as gas
concentrations, and we require hourly reporting of all measured and
calculated emissions values (see discussion at 77 FR 9374, February 16,
2012). In particular, for the fenceline monitoring requirements in this
final rule, we offer facilities options for delineating background
benzene emissions and benzene emissions not attributable to the
refinery, and we offer options for reduced monitoring, making it even
more necessary that we have all of the data to review to ensure that
testing and analyses are being done correctly and in compliance with
the requirements set out in the regulations, and that root cause
analyses and corrective actions are being performed where necessary.
Therefore, as proposed, we are finalizing the requirements that
facilities report the individual 2-week sampling period results for
each monitor, in addition to the calculated [Delta]C values in their
quarterly reporting.
Regarding commenters' concerns that facilities post accurate data
and have sufficient time to perform quality assurance on the data, in
the final rule, we have established provisions for how sources are to
address outliers and data corrections. Additionally, as proposed, we do
not require an initial report until facilities have collected 1 year of
data so that facilities do not report the data until a rolling annual
average value can be determined. This will allow refinery staff and
analytical laboratories to iron out any issues that might arise as they
implement these methods for the first time. Once this initial data
collection period is complete, we anticipate that data quality issues
should be infrequent. Therefore, we are providing a 45-day period
following each quarterly period before facilities must submit the
monitoring results, which should provide facilities adequate time to
correct any data errors prior to reporting the data.
Regarding comments that suggest reporting each 2-week sample result
soon after its collection, we disagree. This frequency would put undue
burden on the refinery owners or operators in trying to collect, review
and quality assure the data prior to reporting. However, we agree with
commenters that more frequent reporting of the fenceline monitoring
data would be useful. Therefore, we have revised the reporting
frequency for the fenceline monitoring data to be quarterly in the
final rule rather than semiannually as proposed. Additionally, we
understand that there is a lot of interest in how these data will be
presented to the public, and we plan to reach out to all stakeholders
on appropriate approaches for presenting this information in ways that
are helpful and informative.
b. Refinery MACT 2
This section provides comment and responses for the key comments
received regarding the technology review amendments proposed for
Refinery MACT 2. Comment summaries and the EPA's responses for
additional issues raised regarding the proposed requirements resulting
from our technology review are in the ``Response to Comment'' document
in the public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
i. FCCU
We received comments on the consideration of developments in
pollution controls, the averaging time for FCCU PM limits, and the FCCU
opacity limit, as discussed below.
Comment: One commenter stated that the EPA failed to consider
developments in pollution controls for HAP from FCCUs for two reasons.
First, the commenter contended that cost is not a valid consideration
to evaluate if a ``development'' in pollution control is necessary
pursuant to section 7412(d)(2), (3), (6), unless the EPA is setting a
``beyond-the-floor'' requirement.
Second, the commenter claimed that the EPA's review of developments
is nearly 10 years old and misses some important pollution control

[[Page 75201]]

improvements in the industry. For example, the commenter noted that
Valero Benicia installed a combination of controls in 2012 including a
scrubber, SCR and CO Boiler that combine exhaust streams from the FCCU
and coking and reportedly eliminate HAP emissions entirely from these
sources.
The commenter also asserted that EPA consent decrees impose lower
effective limits on PM than the EPA considered under the technology
review. The commenter identified the BP Whiting facility as subject to
0.7 lb PM/1,000 lbs coke burn-off at one FCCU and 0.9 lb PM/1,000 lbs
coke burn-off at another and claimed these limits are lower than the
1.0 lb PM/1,000 lbs coke burn-off limit currently mandated by Refinery
MACT 2.
Response: We disagree that we cannot consider costs when
determining if it is necessary to revise an existing MACT standard
based on developments in practices, processes and control technologies.
The commenter suggests that we cannot consider costs because of the
requirements in CAA section 112(d)(2) and (3) for establishing initial
MACT standards and which do not allow for consideration of costs until
the second, ``beyond the floor'' phase of the analysis. As discussed
previously in this preamble where we respond to comments on the
fenceline monitoring requirements, to the extent that the commenters
are suggesting that EPA must re-perform the MACT floor analysis for
purposes of setting a standard pursuant to section 112(d)(6), we note
that the D.C. Circuit has rejected this argument numerous times, most
recently in National Association for Surface Finishing et al. v. EPA
No. 12-1459 in the U.S. Court of Appeals for the District of Columbia.
Regarding the claim that the EPA did not consider the types of
controls at the Valero and BP facilities, we disagree. The control
measures for both of those facilities are controls that existed at the
time of the development of the MACT standard. Thus, we did not identify
these technologies as developments in control technologies during the
technology review. However, we did identify developments in processes
or practices that reflect better control by the existing technology and
we reviewed modified emission limits that reflect that better level of
control. The commenter suggested that we failed to consider a level of
zero when the Valero facility was able to achieve zero emissions
through a combined SCR, boiler and scrubber. However, the commenter
provided no information to support such a claim and we are skeptical
that such a result could be achieved. We note that the SCR is designed
specifically to reduce NOX emissions, and would not be
capable of reducing significantly, much less eliminating completely,
HAP emissions. Similarly, based on our long-standing understanding of
the processes, neither a boiler nor a scrubber could achieve such a
result. Regarding the level of emissions achieved at the BP Whiting
facility, we note that we evaluated control systems that can meet 0.5
lb PM/1,000 lb coke burn-off, which is a lower limit than that at BP
Whiting. We determined that these were cost-effective to require for
new units that are installing a new control system. However, we
determined that retrofitting controls designed to meet a PM limit of
1.0 lb PM/1,000 lbs coke burn-off to now meet a limit of 0.5 lb PM/
1,000 lbs coke burn-off was not cost-effective when considering PM and
PM2.5 emissions reductions. We projected the cost of the 0.5
lb PM/1,000 lbs coke burn-off limit in retrofit cases to be $23,000 per
ton PM emissions reduced. To meet a limit of 0.7 lb PM/1,000 lbs coke
burn-off or 0.9 lb PM/1,000 lbs coke burn-off, as is the case for BP
Whiting, the retrofit costs would be similar to this 0.5 lb PM/1,000 lb
coke burn-off option, but the reductions would be even less, resulting
in costs over $23,000 per ton. As metal HAP content of FCCU PM is
approximately 0.1 to 0.2-percent of the total PM, the cost of requiring
this lower limit for existing FCCU is over $10 million per ton of metal
HAP reduced. Therefore, we determined that it is not necessary to
revise the PM standard for existing FCCU sources.
Comment: Refinery MACT 2 requires the owner or operator to
demonstrate compliance with the PM FCCU limits by complying with the
operating limits established during the performance test on a daily
(i.e., 24-hour) average basis. Several commenters objected to the EPA's
proposal to revise this requirement to a 3-hour averaging time.
Commenters restated EPA's arguments for 3-hour averaging time as: (1)
Daily average could allow FCCUs to exceed limits for short periods
while still complying with the daily average, (2) consistency with NSPS
subpart Ja and (3) consistency with duration of testing. The commenters
stated that the EPA had not provided any data that show that the daily
average could allow FCCUs to exceed limits for short periods and,
therefore, the EPA is using a hypothetical compliance assurance
argument to change emission limits. The commenters stated that a change
in emission limits is not authorized by CAA section 112 because the
emission limitations in Refinery MACT 2 for FCCUs were established as
daily averages following the floor and ample margin of safety
requirements in section 112(d)(2) of the CAA.
The commenters also state that the EPA's additional arguments for
the change to a 3-hour average are irrelevant and legally deficient.
The commenters stated that the combination of a numerical emission
limit and an averaging period frames the stringency of a limitation and
that a reduction in either of those factors results in a significant
lowering of the operating limit. The commenters conclude that the EPA
has proposed to change the stringency of the requirements without
justification, and the CAA requires that such a change in stringency be
justified pursuant to CAA section 112(d)(6) or (f)(2). The commenters
stated that increasing stringency for consistency with NSPS rules is
not a criterion for a CAA section 112(d)(6) action. Rather that section
requires a change to be due to ``developments.'' The only change in
technology since the 2002 promulgation of Refinery MACT 2 is the
availability of PM continuous emission monitoring system (CEMS), which
is unproven.
One commenter noted that changing the averaging time is a very
significant modification considering that the compliance limits would
apply for periods of SSM. This commenter stated that it is unlikely
that existing operations can consistently be in compliance with a new
3-hour average since the current daily averaging was put in place to
recognize that there will be periods of operating variability that do
not represent the longer term performance of an FCCU. The commenters
recommended that the EPA retain the daily averaging requirement.
Response: We disagree with the commenters' statement that reducing
the averaging time from a 24-hour basis to a 3-hour basis for
demonstrating compliance with the FCCU PM emission limit, using
operating limits established during the performance test, is a change
to the MACT floor. The emission limit of 1.0 lb PM/1,000 lbs coke burn-
off is the MACT floor, and we are not changing the PM emissions limit
(or alternate Ni limits) in Table 1 to subpart UUU (except to remove
the incremental PM limit that did not comport with the MACT floor
emissions limitation).
However, whether or not it is a change from the MACT floor is not
relevant. Pursuant to CAA section 112(d)(6), the EPA must revise MACT
standards ``as necessary'' considering developments in practices,
processes and control technologies. For this

[[Page 75202]]

exercise, we considered any of the following to be a ``development'':
Any add-on control technology or other equipment that was
not identified and considered during development of the original MACT
standards.
Any improvements in add-on control technology or other
equipment (that were identified and considered during development of
the original MACT standards) that could result in additional emissions
reduction.
Any work practice or operational procedure that was not
identified or considered during development of the original MACT
standards.
Any process change or pollution prevention alternative
that could be broadly applied to the industry and that was not
identified or considered during development of the original MACT
standards.
Any significant changes in the cost (including cost
effectiveness) of applying controls (including controls the EPA
considered during the development of the original MACT standards).
In determining whether there are ``developments,'' we review, among
other things, EPA regulations promulgated after adoption of the MACT,
such as the NSPS we identified in this instance. We identified the
enhanced monitoring requirements for these operating limits as a
development in practices that will help ensure FCCU owners or operators
are properly operating control devices and, thus, are meeting the PM
emission limit at all times. We further determined that this enhanced
monitoring was cost effective and proposed that it was necessary to
revise the existing standard pursuant to CAA section 112(d)(6).
While we do not have continuous PM emissions data that show actual
deviations of the PM limit, we do not need such data in order to
conclude that such deviations could occur when daily averages are used.
The Refinery MACT 2 (i.e., subpart UUU) rule requires owners or
operators to establish operating limits based on three 1-hour runs
during the performance test. As a matter of simple mathematics, a
source could demonstrate that it is meeting the operating limit based
on a 24-hour average but could be exceeding the 1.0 lb PM/1,000 lbs
coke burn-off emission limit based on a 24-hour average or for one or
more individual 3-hour periods during that 24-hour average. For
example, an owner or operator could operate with a power input 5-
percent higher than the operating limit for 23 hours, have the ESP off
(zero power) for one hour, and still comply with a 24-hour average
operating limit. However, it would be difficult for this same unit to
meet the 1.0 lb PM/1,000 lbs coke burn-off emissions limit over a 24-
hour period, and it certainly would not meet the limit for every 3-hour
period during that day. As the operating limit can be established to
correspond with 1.0 lb PM/1,000 lbs coke burn-off, the 5-percent higher
power input would likely correspond with a 0.95 lb PM/1,000 lbs coke
burn-off emissions rate (5-percent lower). Uncontrolled emissions are
typically 6 to 8 lbs/1,000 lbs coke burn-off. Thus, this unit would
have emissions averaging approximately 1.2 lbs PM/1,000 lbs coke burn-
off during this 24-hour period [i.e., (0.95*23+7)/24], but would be in
compliance with the 24-hour average operating limit. The unit would
obviously also be out of compliance with the 3-hour average over the
period when the power was turned off. We also have concerns that the
operating limits are not always linear with the emissions, so that the
longer averaging times do not effectively ensure compliance with the PM
emissions limit. Therefore, as proposed, we are finalizing the
requirement for owners or operators to comply with the operating limits
on a 3-hour basis, rather than the 24-hour basis currently in the rule.
Comment: The technology review for FCCUs resulted in the EPA
proposing to remove the 30-percent opacity alternative limit for
demonstrating compliance with the PM emissions limit that is available
for refineries complying with the Refinery NSPS 40 CFR part 63, subpart
J. Two commenters supported the EPA's proposed removal of the 30-
percent opacity limit for FCCUs. Other commenters stated that current
technology is good enough for a 10- or 20-percent opacity limit. On the
other hand, several commenters stated that the proposed removal of the
30-percent opacity limit must meet the criteria specified in CAA
section 112(d)(6) and (f)(2), which requires analysis of the statutory
basis, environmental impacts, costs, operational and compliance
feasibility and impacts, that the EPA has not conducted. The commenters
claimed that had the EPA conducted a proper analysis, the EPA would
have determined that the proposed change to remove the 30-percent
opacity limit is not necessary or supportable. Additionally, these
commenters stated that since the underlying PM emissions limit is
unchanged, there is no emission reduction justification for this
proposed change, and the change would not meet the CAA section
112(d)(6) requirement of being cost effective. The commenters also
noted that processes or practices for existing FCCUs have not changed,
as required for a CAA section 112(d)(6) revision.
Several commenters urged the EPA to maintain the 30-percent opacity
limit for these FCCUs. As a practicable and cost-effective alternative
to address the EPA's concern as to whether compliance with a 30-percent
opacity limit ensures compliance with the PM emissions limit,
commenters suggested annual performance tests to confirm that the FCCU
is meeting the PM emissions limit, rather than performance tests every
5 years, as proposed.
One commenter stated that the EPA never intended for the opacity
limit in Refinery NSPS subpart J to be used to demonstrate compliance
with the PM emissions limit, but instead to assure the PM controls
operate properly. The commenter stated that the EPA's conclusion that
the 30-percent opacity limit may not be sufficiently stringent to
ensure compliance with the underlying PM emissions limit is based on a
false premise as to the purpose of the opacity standard because as the
EPA states, ``Opacity of emissions is indicative of whether control
equipment is properly maintained and operated.''
Several commenters stated that the proposed elimination of the 30-
percent opacity limit currently in Refinery MACT 2 leaves existing
FCCUs that use cyclones with no viable alternative approach to
demonstrate compliance with the PM emissions limit without adding or
replacing controls. They stated the other approaches for demonstrating
compliance with the PM emissions limit in Refinery MACT 2 (such as
development of a site-specific opacity limit) do not work for them. The
commenters stated that although they believe that more frequent
performance tests would show that the FCCUs are in fact meeting the PM
emissions limit, the absence of the 30-percent opacity limit would
force FCCUs using cyclones for PM control to install additional, costly
PM controls (e.g., ESPs or wet gas scrubbers). They projected that
these additional controls would cost tens of millions of dollars per
FCCU and would require at least 3 years of compliance time.
Additionally, one commenter stated that even FCCUs with additional
downstream PM controls would not be able to achieve a site-specific
limit at all times and needed the availability of the alternative 30-
percent opacity limit. One commenter estimated that installing an ESP
to meet the proposed 10-percent opacity limit would cost approximately
$121,000/ton, assuming a 32 tpy PM emission reduction. The commenter
noted that the ESP would also increase GHG emissions and require more
energy

[[Page 75203]]

resources from the facility. The commenter concluded that installing an
ESP is neither cost effective nor appropriate considering non-air
quality environmental and health impacts and energy requirements, and
recommended that the EPA maintain the current NSPS subpart J
alternative limits and add additional alternative limits into Refinery
MACT 2 only as optional limits for demonstrating compliance with the PM
emissions limit.
Response: In promulgating Refinery MACT 2, the EPA identified the
1.0 lb PM/1,000 lbs coke burn-off limit as the MACT floor but allowed a
compliance option for FCCUs subject to Refinery NSPS subpart J to
comply with an opacity limit up to 30 percent with one 6-minute
allowance to exceed the 30-percent opacity in any 1-hour period. As
stated in the proposal, compliance studies have shown that the 30-
percent opacity limit does not correlate well with the 1.0 lb PM/1,000
lbs coke burn-off limit, and that an FCCU can comply with the 30-
percent opacity limit while its emissions exceed the PM emissions
limit.\9\ Regardless of whether the 30-percent opacity limit in
Refinery NSPS subpart J was designed to ``ensure that the control
device was operated properly,'' Refinery MACT 2 allows sources subject
to NSPS subpart J to use the 30-percent opacity limit to demonstrate
continuous compliance with the PM emissions limit. We have determined
that the 30-percent opacity limit is inadequate for the purpose of
demonstrating continuous compliance with the PM emissions limits in
Refinery MACT 2. As such, we proposed to remove this opacity limit and
require the owner or operator to either demonstrate compliance with the
PM emissions limit by continuously monitoring the control device
parameters established during the performance test or establish and
monitor a site-specific opacity limit. For clarity, we note that we
proposed to allow a site-specific opacity limit, not a 10-percent
opacity limit as some commenters suggest. The site-specific opacity
limit can be significantly higher than 10 percent, but it cannot be
lower than 10 percent.
---------------------------------------------------------------------------

\9\ Compliance Investigations and Enforcement of Existing Air
Emission Regulations at Region 5 Petroleum Refineries. U.S.
Environmental Protection Agency, Region 5--Air and Radiation,
Chicago, Illinois. March 9, 1998.
---------------------------------------------------------------------------

While the compliance study indicates that a 30-percent opacity
limit does not correlate well with a 1.0 lb PM/1,000 lbs coke burn-off
emissions limit, further review of this same study indicates that a 20-
percent opacity limit provides a reasonable correlation with units
meeting the 1.0 lb PM/1,000 lbs coke burn-off emissions limit. We also
reviewed the data submitted by the commenters regarding PM emissions
and opacity correlation. While the data suggest that there is
variability and uncertainty in the PM/opacity correlation, the data do
not support that a 30-percent opacity limit would ensure compliance
even when considering the uncertainty associated with the PM/opacity
correlation. Based on the variability of the 3-run average opacity
limits, we determined that, if the 3-hour average opacity exceeded 20-
percent, then it was highly likely (98 to 99-percent confidence) that
the FCCU emissions from the unit tested would exceed the PM emissions
limit.
After considering the public comments, reviewing the data submitted
with those comments, and further review of the compliance study, in
this final rule we are adding a 20-percent opacity limit, evaluated on
a 3-hour average basis for units subject to NSPS subpart J. As we noted
above, a 20-percent opacity limit provides a reasonable correlation
with the PM emissions limit, and an exceedance of this 20-percent
opacity limit will provide evidence that the PM emissions limit is
exceeded. However, it is possible that units could still exceed the PM
emissions limit while complying with the 20-percent opacity limit, if
those units operate close to the 1 lb PM/1,000 lbs coke burn-off
emissions limit. To address this concern, we considered the commenters'
suggestion to require a performance test annually rather than once
every 5 years. Some commenters suggested that this option specifically
apply to FCCUs with cyclones, but this option is applicable to any
control system operating very near the PM emissions limit and using an
opacity limit to demonstrate continuous compliance. We have determined
that the Refinery NSPS subpart J compliance procedures in Refinery MACT
2, in combination with a 20-percent opacity limit demonstrated on a 3-
hour average basis and with annual performance tests when a test
indicates PM emissions are greater than 80-percent of the limit (i.e.,
0.80 lb PM/1,000 lbs coke burn-off), will ensure continuous compliance
with the PM emissions limit. FCCUs with measured PM emissions during
the performance test at or below 0.80 lb PM/1000 lbs of coke burn-off
will remain subject to the requirement to conduct performance tests
once every 5 years, consistent with the requirements we proposed.
We do not agree with commenters that the proposed opacity revision
would add significant cost or compliance burden. The control device-
specific monitoring parameters that were proposed rely on parameters
commonly used to control the operation of the control device, so the
monitoring systems should be already available. Further, since we are
merely changing the opacity limit, we expect these units will already
have opacity monitoring systems needed to demonstrate compliance with
the PM emissions limit and would not incur costs for new equipment.
Comment: Several commenters stated that they agree with the EPA's
determination in the proposal that the current CO limits provide
adequate control of HCN. Two commenters stated that there are limited
HCN emissions data and that more data are needed before the Agency can
appropriately determine whether an HCN standard is necessary and
justified. One commenter noted that the process undertaken by the EPA
to estimate HCN emissions was flawed, and likely overestimates HCN
emissions significantly. Another commenter stated that they performed
HCN stack testing at three refineries and subsequent modeling at two
refineries and concluded that the ambient HCN emissions were well below
the applicable health limits.
In contrast, some commenters expressed concerns about high HCN
levels. One commenter stated that the EPA should consider re-evaluating
the benefit of low NOX emissions from the FCCU, if that is
indeed the cause of higher HCN emissions, because exposing people to
HCN is not acceptable. The commenter also noted that the community now
also has the increased dangers of storing and transporting aqueous
ammonia, which is used in some cases to achieve low NOX
emissions from the FCCU.
One commenter stated that the EPA must set stronger HCN standards
on FCCU emissions because of the high release amounts reported, the
fact that non-cancer risk is driven by emissions of HCN from FCCU, and
the fact that the EPA has never set standards for HCN emissions. The
commenter provided a report that they believe shows that the EPA has
not shown that CO is a reasonable or lawful surrogate to control HCN
and has not shown that the conditions necessary for a surrogate are met
with regard to CO and HCN, which is an inorganic nonmetallic HAP.
Further, the report indicates that SCR is a reasonable and cost
effective method for controlling HCN and that the EPA failed to review
and consider other viable methods to control HCN and must do so to
satisfy its legal obligations in this rulemaking.

[[Page 75204]]

Response: At the time we promulgated the MACT, we determined that
the control strategy used by the best performing facilities to reduce
organic HAP emissions was the use of complete combustion, which occurs
when the CO concentration is reduced to 500 ppmv (see the proposal for
Refinery MACT 2 at 63 FR 48899, September 11, 1998). We rejected
arguments that some facilities operate at CO levels well below 500 ppmv
and, thus, the MACT floor should be set at a lower CO concentration
because once CO concentrations reached 500 ppmv, there was no longer a
correlation between reduced CO concentrations and reduced HAP
concentrations. And, in fact, emissions of certain HAP, such as
formaldehyde, tended to increase as CO concentrations were reduced
below 500 ppmv.\10\
---------------------------------------------------------------------------

\10\ U.S. EPA, 2001. Petroleum Refineries: Catalytic Cracking
Units, Catalytic Reforming Units, and Sulfur Recovery Units--
Background Information for Promulgated Standards and Response to
Comments. Final Report.EPA-453/R-01-011. June. p. 1-19.
---------------------------------------------------------------------------

In the current rulemaking action, we determined at the time of the
proposed rule that this also holds true for HCN emissions. That is,
once CO emissions are reduced to below 500 ppmv (i.e., complete
combustion is achieved), we no longer see a direct correlation between
CO concentrations and HCN emissions.
All of the HCN emissions data we have were reported from units
operating at or below the 500 ppmv CO limit (i.e., in the complete
combustion range), so it is not surprising that there is not a strong
correlation between CO and HCN from the FCCU ICR source test data.
However, catalyst vendor data and combustion kinetic theory support the
fact that, in the partial burn mode (with CO concentrations of 2 to 6-
percent, which is 20,000 to 60,000 ppmv), HCN concentrations exiting
the FCCU regenerator are much greater than for units using complete
combustion FCCU regenerators or the concentration exiting a post-
combustion device used in conjunction with a partial burn FCCU
regenerator. Therefore, we maintain that complete combustion is the
primary control needed to achieve controlled levels of HCN emissions.
We initially thought the higher levels of HCN emissions that were
reported by sources achieving complete combustion might be due to a
switch away from platinum-based combustion promoters to palladium-based
combustion promoters. However, many of the units that were tested and
that had some of the lowest HCN emissions used palladium-based oxygen
promoters. Therefore, it appears unlikely that palladium-based catalyst
promoters are linked to the higher HCN emissions. We also evaluated one
commenter's argument that CO is not a good surrogate for HCN emissions,
but that SCR are a reasonable and cost-effective control strategy. We
are not aware of any data that suggest that an SCR removes HCN and the
commenter did not provide any support for that premise. At proposal, we
evaluated HCN control on units using extra oxygen or converting back to
platinum-based promoters to oxidize any HCN formed. This would cause
more NOX formation, which would then require post-combustion
NOX control, such as an SCR. However, if HCN emissions are
not a function of CO concentration beyond that required to achieve
complete combustion (as noted by the commenter), then more aggressive
combustion conditions and the use of an SCR (to remove the
NOX formed) may not be a viable control strategy. Therefore,
considering all of the data currently available and the comments
received regarding HCN emissions and controls, we maintain that the
only proven control technique is the use of complete combustion as
defined by a CO level of 500 ppmv or less. We are not establishing a
more stringent CO level because, once complete combustion is achieved,
(i.e., CO concentrations drop below 500 ppmv), no further reduction in
HCN emissions are achieved.
For the purposes of Refinery MACT 2, we consider the emission
limits and operating requirements for organic HAP in Tables 8 through
14 to subpart UUU of part 63 adequate to also limit HCN emissions.
Finally, we understand concerns about the reported HCN emissions
being higher than anticipated and the need for more data to better
determine HCN emissions levels. To address these concerns, we are
finalizing a requirement that facility owners or operators conduct a
performance test for HCN from all FCCU at the same time they conduct
the first PM performance test on the FCCU following promulgation of
this rule. Facility owners or operators that conducted a performance
test for HCN from a FCCU in response to the refinery ICR or subsequent
to the 2011 Petroleum Refinery ICR following appropriate methods are
not required to retest that FCCU.
4. What is the rationale for our final approach for the technology
review?
a. Refinery MACT 1
We did not receive substantive comments concerning our proposal
that it was not necessary to revise Refinery MACT 1 requirements for
MPV, gasoline loading racks and cooling towers/heat exchange systems.
Based on the rationale provided in the preamble to the proposed rule,
we are taking final action concluding that it is not necessary pursuant
to CAA section 112(d)(6) to revise the MACT requirements for MPV,
gasoline loading racks and cooling towers/heat exchange systems
emission sources at refineries.
We proposed that the options for additional wastewater controls are
not cost effective and thus it was not necessary to revise the MACT for
these emission sources. We received public comments suggesting that
emissions from wastewater systems are higher than modeled and that we
should develop additional technology standards for wastewater treatment
systems regardless of cost. As we discussed in the proposal, emissions
from wastewater are difficult to measure and emission estimates rely on
process data and empirical correlations, which introduces uncertainty
into the estimates. Although we do not have evidence, based on the
process data we collected, that emissions are higher than modeled at
proposal, we note that the fenceline monitoring program effectively
ensures that wastewater emissions are not significantly greater than
those included in the emissions inventory and modeled in the risk
assessment. Furthermore, we believe that cost is a valid consideration
in determining whether it is necessary within the meaning of section
112(d)(6) to revise requirements and that we are not required to
establish additional controls regardless of cost. Consequently, we
conclude that it is not necessary to revise the Refinery MACT 1
requirements for wastewater systems pursuant to CAA section 112(d)(6).
For storage vessels, we identified a number of options, including
requiring tank fitting controls for external and internal floating roof
tanks, controlling smaller tanks with lower vapor pressures and
requiring additional monitoring to prevent roof landings, liquid level
overfills and to identify leaking vents as developments in practices,
processes and control technology. We proposed to cross-reference the
storage vessel requirements in the Generic MACT (effectively requiring
additional control for tank roof fittings) and to revise the

[[Page 75205]]

definition of Group 1 storage vessels to include smaller tanks with
lower vapor pressures. We received comments that we could have required
additional controls on tanks and monitoring for landings, overfills and
leaking vents described above. We also received comments related to
clarifications of specific rule references and overlap provisions. We
addressed these comments in the ``Response to Comments'' document, and
we maintain that the additional control options described by the
commenters (tank roof landing/degassing requirements or use of geodesic
domes to retrofit external floating roofs) are not cost-effective.
Consequently, based on the rationale provided in the preamble to the
proposed rule and our consideration of public comments, we are
finalizing the requirements as proposed with minor clarifications of
the rule references. However, as with wastewater systems, we note that
the fenceline monitoring program will ensure that the owner or operator
is effectively managing fugitive emissions sources and should detect
landings, overfills, and leaking vents.
For equipment leaks, we identified specific developments in
practices, processes and control technologies that included requiring
repair of leaking components at lower leak definitions, requiring
monitoring of connectors, and allowing the use of the optical imaging
camera as an alternative method of monitoring for leaks. We proposed to
establish an alternative method for refineries to meet LDAR
requirements in Refinery MACT 1. This alternative would allow
refineries to monitor for leaks via optical gas imaging in place of EPA
Method 21, using monitoring requirements to be specified in a not yet
proposed appendix K to 40 CFR part 60. However, the development of
appendix K is taking longer than anticipated. Therefore, we are not
finalizing this alternative monitoring method in Refinery MACT 1.
We received comments suggesting that additional requirements be
imposed to further reduce emissions from leaking equipment components,
such as requiring ``leakless'' equipment, reducing the leak threshold,
and eliminating delay of repair provisions. As provided in the
``Response to Comments'' document, we do not agree that these
additional requirements are cost-effective. Based on the rationale
provided in the preamble to the proposed rule and our consideration of
public comments, we conclude that it is not necessary to revise the
Refinery MACT 1 requirements for equipment leaks. Again, however, the
fenceline monitoring program is intended to ensure that large leaks
from fugitive emissions sources, including equipment leaks, are more
quickly identified and repaired, thereby helping to reduce emissions
from leaking equipment components.
For marine vessel loading, we identified control of marine vessel
loading operations with HAP emissions of less than 10/25 tpy and the
use of lean oil absorption systems as developments that we considered
in the technology review. We proposed to amend 40 CFR part 63, subpart
Y to require small marine vessel loading operations (i.e., operations
with HAP emissions less than 10/25 tpy) and offshore marine vessel
loading operations to use submerged filling based on the cargo filling
line requirements in 46 CFR 153.282. We received comments that other
options considered during the technology review of the standard were
cost-effective for small marine vessel loading operations and should be
required. As provided in the ``Response to Comments,'' we continue to
believe those other controls are not cost-effective because of the high
costs of controls for limited additional organic HAP emission
reduction. Therefore, we are finalizing these amendments as proposed.
Finally, we proposed that it was necessary to revise the MACT to
require fenceline monitoring as a means to manage fugitive emissions
from the entire petroleum refinery, which includes sources such as
wastewater collection and treatment operations, equipment leaks and
storage vessels. We received numerous comments regarding the proposed
requirement to conduct fenceline monitoring, many of which we address
above and the remainder of which we respond to in the ``Response to
Comments'' document. After considering comments, we maintain that the
proposed work practice standard is authorized under section 112 of the
CAA and will improve fugitive management at the refinery. Therefore, we
are finalizing the key components of fenceline monitoring work practice
as proposed. These requirements include the use of passive diffusive
tube samplers (although we are providing a mechanism to request
approval for alternative monitoring systems provided certain criteria
are met), the 9 [mu]g/m³ on a rolling annual average basis
action level, and the need to perform corrective action to comply with
the action level.
Based on public comments received, we are making numerous revisions
to clarify the fenceline monitor siting requirements. This includes
provisions to allow siting of monitors within the property boundary as
long as all emissions sources at the refinery are included within the
monitoring perimeter. We are also clarifying that we do not consider
public roads or public waterways that bisect a refinery to be property
boundaries, and owners or operators do not need to place monitors along
the internal public right-of-ways. We are also providing provisions to
allow fixed placement of monitors at 500 feet intervals (with a minimum
of 3 monitors) for subareas or segregated areas. If an emissions source
is near the monitoring perimeter, an additional monitor siting
requirement would still apply. The 500 feet provision is provided to
reduce burden for facilities with irregular shapes or noncontiguous
property areas that we did not fully consider at proposal.
We also received comments on the compliance time and reporting
requirements associated with the fenceline monitoring provisions. Upon
consideration of public comments, we have revised the compliance period
to 2 years after the effective date of the final rule. Thus, beginning
no later than 2 years after the effective date of the rule, the source
must have a fenceline monitoring system that is collecting samples such
that the first rolling annual average [Delta]C value would be completed
no later than 3 years after the effective date of the final rule.
Facilities will have 45 days after the completion of the first year of
sampling, as proposed, to submit the initial data set. We are reducing
the proposed compliance period from 3 years to 2 years because the
passive diffusive tube monitors are easy to deploy and pilot study
demonstrations indicate that significant time is not needed to deploy
the monitors. However, the reduced compliance period still provides
time to resolve site-specific monitor placement issues and to provide
time to develop and implement a site-specific monitoring plan, if
needed. We are increasing the fenceline monitoring reporting frequency
(after the first year of data collection) from semiannually to
quarterly to provide more timely dissemination of the data collected
via this monitoring program.
b. Refinery MACT 2
We proposed to revise Refinery MACT 2 to incorporate the
developments in monitoring practices and control technologies reflected
in the Refinery NSPS subpart Ja limits and monitoring provisions (73 FR
35838, June 24, 2008). We are finalizing most of these provisions as
proposed. Specifically, we are incorporating the

[[Page 75206]]

Refinery NSPS subpart Ja PM limit for new FCCU sources. We are also
finalizing compliance options for FCCU that are not subject to Refinery
NSPS subpart J or Ja. These options would allow such sources to elect
to comply with the Refinery NSPS subpart Ja monitoring provisions to
demonstrate compliance with the emissions PM limit. We are revising the
averaging period for the control device operating limits or site-
specific opacity limits to be on a 3-hour average basis in order to
more directly link the operating limit to the duration of the
performance test runs, on which they are based, as proposed. We are
incorporating additional control device-specific monitoring
alternatives for various control devices on FCCU, including BLD
monitoring as an option to COMS for owners or operators of FCCU using
fabric filter-type control systems and total power and secondary
current operating limits for owners or operators of ESPs. We are adding
an additional requirement to perform daily checks of the air or water
pressure to atomizing spray nozzles for owners or operators of FCCU wet
gas scrubbers not subject to the pressure drop operating limit, as
proposed. Finally, we finalizing requirements to conduct a performance
test at least once every 5 years for all FCCU, as proposed. These
requirements are being finalized to ensure that control devices are
continuously operated in a manner similar to the operating conditions
of the performance test and to ensure that the emissions limits, which
are assessed based on the results of three 1-hour test runs, are
achieved at all times.
We also proposed to eliminate the Refinery NSPS subpart J
compliance option that allows refineries to meet the 30-percent opacity
emissions limit requirement and revise the MACT to include control
device operating limits or site-specific opacity limits identical to
those required in Refinery NSPS subpart Ja. We received numerous
comments, particularly from owners or operators of FCCU that employ
tertiary cyclones to control FCCU PM emissions. According to the
commenters, opacity is not a direct indicator of PM emissions because
finer particles will increase opacity readings without a corresponding
mass increase in PM emissions. Additionally, the commenters stated that
the site-specific opacity limit generally leads to a site-specific
operating limit of 10-percent opacity, which is too stringent and does
not adequately account for variability between PM emissions and opacity
readings. According to the commenters, FCCU with tertiary cyclones
would need to be retrofitted with expensive and costly controls in
order to meet the 10-percent opacity limit, even though they are
meeting the 1 lb/1000 lbs coke burn PM emissions limit. It was not our
intent to require units to retrofit their controls simply to meet the
site-specific opacity limit. However, the existing 30-percent opacity
limit in the subpart J compliance option is not adequate to ensure
compliance with the PM emissions limit at all times. After reviewing
the public comments and available data, we determined that, rather than
removing the subpart J compliance option altogether, it is sufficient
to add an opacity operating limit of 20-percent opacity determined on a
3-hour average basis to the existing subpart J compliance option and to
require units complying with this operating limit to conduct annual
performance tests (rather than one every 5 years) when the PM emissions
measured during the source test are greater than 0.80 lb PM/1,000 lbs
coke burn-off. These provisions improve assurance that these units are,
in fact, achieving the required PM emissions limitation without
requiring units to retrofit controls due to variability in the
correlation of PM emissions and opacity.
We did not propose to revise the organic HAP emissions limits for
FCCU to further address HCN emissions. We received numerous comments on
this issue. We continue to believe that complete combustion is the
appropriate control needed to control HCN emissions. Consequently, for
the purposes of Refinery MACT 2, we are not changing the MACT standards
to further reduce emissions of HCN. However, we understand that there
are uncertainties and high variability in HCN emissions measured from
FCCU. In order to address the need for more data to better characterize
HCN emissions levels, we are finalizing a requirement for refinery
owners or operators to conduct a performance test for HCN from all FCCU
(except those units that were tested previously using acceptable
methods as outlined in the 2011 Refinery ICR) during the first PM test
required as part of the on-going compliance requirements for FCCU metal
HAP emissions. These data will be useful to the EPA in understanding
HCN emissions from FCU and may help to inform future regulatory reviews
for this source category.
We proposed that there have been no developments in practices,
processes, and control technologies for CRU based on our technology
review and that therefore it is not necessary to revise these
standards. Based on the rationale provided in the preamble to the
proposed rule and our consideration of public comments, we are
finalizing our conclusion.
For SRU, we identified the Refinery NSPS subpart Ja allowance for
oxygen-enriched air as a development in practice and we proposed that
it was necessary to revise the MACT to allow SRU to comply with
Refinery subpart Ja as a means of complying with Refinery MACT 2. The
key issue identified by commenters was that Refinery NSPS subpart Ja
includes a flow monitoring alternative for determining the average
oxygen concentration in the enriched air stream and that this was not
included in the proposed amendments to Refinery MACT 2. This was an
oversight on our part. We are, based on the rationale provided in the
preamble to the proposed rule and our consideration of public comments,
finalizing the SRU revisions as proposed but with inclusion of the flow
monitoring alternative provisions that are in Refinery NSPS subpart Ja
for this source.

C. Refinery MACT Amendments Pursuant to CAA Section 112(d)(2) and
(d)(3)

1. What did we propose pursuant to CAA section 112(d)(2) and (d)(3) for
the Petroleum Refinery source categories?
We proposed the following revisions to the Refinery MACT 1 and 2
standards pursuant to CAA section 112(d)(2) and (3) \11\: (1) Adding
MACT standards for DCU decoking operations; (2) revising the CRU purge
vent pressure exemption; (3) adding operational requirements for flares
used as APCD in Refinery MACT 1 and 2; and (4) adding requirements and
clarifications for vent control bypasses in Refinery MACT 1.
---------------------------------------------------------------------------

\11\ The EPA has authority under CAA section 112(d)(2) and
(d)(3) to set MACT standards for previously unregulated emission
points. EPA also retains the discretion to revise a MACT standard
under the authority of section 112(d)(2) and (3), see Portland
Cement Ass'n v. EPA, 665 F.3d 177, 189 (D.C. Cir. 2011), such as
when it identifies an error in the original standard. See also
Medical Waste Institute v. EPA, 645 F. 3d at 426 (upholding EPA
action establishing MACT floors, based on post-compliance data, when
originally-established floors were improperly established).
---------------------------------------------------------------------------

For DCU, we proposed to require that prior to venting or draining,
each coke drum must be depressured to a closed blowdown system until
the coke drum vessel pressure is 2 psig or less. As proposed, the 2
psig limit would apply to each vessel opening/venting/draining event at
new or existing affected DCU facilities.
For the CRU, we proposed to require that any emissions during the
active

[[Page 75207]]

purging or depressuring of CRU vessels meet the applicable organic HAP
emission limitations in Tables 15 and 16 to subpart UUU regardless of
the vessel pressure.
For flares, we proposed to remove cross references to the General
Provisions requirements for flares used as control devices at 40 CFR
63.11(b) and to incorporate enhanced flare operational requirements
directly into the Refinery MACT rules. The proposed rule amendments
included:
A ban on flaring of halogenated vent streams.
A requirement to operate with continuously lit pilot
flames at all times and to equip the pilot system with an automated
device to relight the pilot if it is extinguished.
A requirement to operate with no visible emissions except
for periods not to exceed a total of 5 minutes during any 2 consecutive
hours and to monitor for visible emissions daily.
A requirement to operate with the flare tip velocity less
than 60-feet-per-second or the velocity limit calculated by an equation
provided in the proposed rule.
A requirement to meet one of three combustion zone gas
properties operating limits based on the net heating value, lower
flammability limit, or combustion concentration. Owners or operators
could elect to comply with any one of the three limits at any time. Two
separate sets of operating limits were proposed: One for gas streams
not meeting all three ``hydrogen-olefin interaction criteria''
specified in the rule and a more stringent set of limits for gas
streams meeting all three hydrogen-olefin interaction criteria. The
combustion zone net heating value considered steam assist rates but not
``perimeter air'' assist rates.
For air-assisted flares, a requirement to meet an
additional ``dilution parameter'' operating limit determined based on
the combustion zone net heating values above, the diameter of the flare
and the perimeter air assist rates.
The proposed amendments for flares also included detailed
monitoring requirements to determine these operating parameters either
through continuous parameter monitoring systems or grab sampling,
detailed calculation instructions for determining these parameters on a
15-minute block average, and detailed recordkeeping and reporting
requirements. We also proposed provisions to allow owners or operators
to request alternative emissions limitations that would apply in place
of the proposed operating limits.
We proposed to revise the definition of MPV to remove the current
exclusion for in situ sampling systems (onstream analyzers). We also
proposed to limit the exclusion for gaseous streams routed to a fuel
gas system to apply only to those systems for which any flares
receiving gas from the fuel gas system are in compliance with the
proposed flare monitoring and operating limits. We note that we also
proposed revisions related to monitoring of bypass lines, but these
revisions were proposed to address concerns related to SSM releases and
are described in further detail in section IV.D. of this preamble.
We proposed that emissions of HAP may not be discharged to the
atmosphere from PRD in organic HAP service to address concerns related
to SSM releases. To ensure compliance with this proposed amendment, we
proposed to require that sources monitor PRD using a system that is
capable of identifying and recording the time and duration of each
pressure release and of notifying operators that a pressure release has
occurred. This proposed requirement was addressed in section IV.A.4. of
the preamble for the proposal.
2. How did the revisions pursuant to CAA section 112(d)(2) and (3)
change since proposal?
We proposed identical standards for existing and new DCU decoking
operations, but we are finalizing standards for new and existing
sources that are not identical. We are finalizing provisions that will
require owners or operators of existing DCU sources to comply with a 2
psig limit averaged over 60 cycles (i.e., 60 venting events), rather
than meet the 2 psig limit on a per venting event basis, as proposed.
We are finalizing provisions that will require owners or operators of
new DCU sources to comply with a 2.0 psig limit on a per event, not-to-
exceed basis. We are adding one significant digit to the limit for new
DCU affected sources because our re-review of permit requirements
conducted in response to comments identified that the best performing
DCU source is required to comply with a 2.0 psig limit on a per event
basis. In response to comments regarding the proposed prohibition on
draining prior to achieving the pressure limit, we are finalizing
specific provisions for DCU with water overflow design and for double
quenching.
For flares, we are not finalizing the ban that we proposed on
halogenated vent streams and we are not finalizing the proposed
requirement to equip the flare pilot system with an automated device to
relight an extinguished pilot.
We are revising the MACT to include the proposed no visible
emissions limit and the flare tip velocity limit as direct emissions
limits only when the flare vent gas flow rate is below the smokeless
capacity of the flare. Under the revised standard, when the flare is
operating above the smokeless capacity, an exceedance of the no visible
emission limit and/or flare tip velocity limit is not a violation of
the standard but instead triggers a work practice standard. Flares
operate above the smokeless capacity only when there is an emergency
release event and thus the work practice standard is intended to
address emissions during such emergency release events. (See section
IV.D. of this preamble for more details regarding this work practice
standard). We are also adding provisions that would allow sources to
use video surveillance of the flare as an alternative to daily Method
22 visible emissions observations.
For flares, we are also simplifying the combustion zone gas
property operating limits by finalizing a requirement only for the net
heating value of the combustion zone gas. We are finalizing
requirements that flares meet a minimum operating limit of 270 BTU/scf
NHVcz on a 15-minute average, as proposed, and we are allowing refinery
owners or operators to use a corrected heat content of 1212 BTU/scf for
hydrogen to demonstrate compliance with this operating limit. We are
not finalizing separate combustion zone operating limits for gases
meeting the hydrogen-olefin interaction criteria that were proposed. We
are also not finalizing the alternative combustion zone operating
limits based on lower flammability limit or combustibles concentration.
We are finalizing ``dilution parameter'' requirements for air-
assisted flares, but we are providing a limit only for the net heating
value dilution parameter. Similar to the requirements we are finalizing
for the combustion zone parameters, we are finalizing requirements that
flares meet a minimum operating limit of 22 BTU/ft²
NHVdil on a 15-minute average, as proposed, and we are
allowing refinery owners or operators to use a corrected heat content
of 1,212 BTU/scf for hydrogen to demonstrate compliance with this
operating limit. We are not finalizing separate dilution parameter
operating limits for gases meeting the hydrogen-olefin interaction
criteria that were proposed. We are also not finalizing the alternative
dilution parameter operating limits based on lower flammability limit
or combustibles concentration.

[[Page 75208]]

We are providing an alternative to use initial sampling period and
process knowledge for flares in dedicated service as an alternative to
continuous or on-going grab sample requirements for determining waste
gas net heat content.
We are finalizing revisions to the definition of MPV, as proposed.
We are establishing work practice standards that apply to PRD
releases in place of the proposed prohibition on PRD releases to the
atmosphere. The work practice standards that we are finalizing for PRD
require refiners to establish proactive, preventative measures for each
PRD to identify and correct direct releases of HAP to the atmosphere as
a result of pressure release events. Over time, these proactive
measures will reduce the occurrence of releases and the magnitude of
releases when they occur, while avoiding the environmental disbenefits
of having additional flare capacity on standby to control these
unpredictable and infrequent events. Refinery owners or operators will
be required to perform a root cause analysis/corrective action
following such pressure release events. In addition, a second release
event in a 3-year period from the same PRD with the same root cause on
the same equipment is a deviation of the work practice standard. A
third release event in a 3-year period from the same PRD is a deviation
of the work practice standard regardless of the root cause. PRD release
events related to force majeure events are not considered in these hard
limits.
3. What key comments did we receive on the proposed revisions pursuant
to CAA section 112(d)(2) and (3) and what are our responses?
i. DCU
Comment: Several commenters argued that the EPA incorrectly set the
MACT floor emission limitation for DCU. Commenters noted that CAA
section 112(d)(3)(A) states that the MACT limit for existing sources
``shall not be less stringent, and may be more stringent than the
average emission limitation achieved by the best performing 12-percent
of the existing sources'' excluding those first achieving that level
within 18 months prior to proposal or 30 months prior to promulgation,
whichever is later. According to the commenters, the EPA failed to
follow this procedure in setting the 2 psig vent limit as a MACT floor
because the EPA incorrectly considered permit limits and other non-
performance based criteria instead of basing the MACT floor on the
actual performance of sources. Commenters stated that the EPA
improperly considered permit limits that should have been excluded from
consideration, as well as considering permit limits for closed
facilities instead of using more accurate data from operating DCUs at
sources that submitted actual emissions data. Specifically, commenters
stated that the DCU at the non-operational plant (Hovensa) should not
be included. One commenter noted that they operate one of the South
Coast DCU listed as subject to a 2 psig limit and asserted that it does
not currently meet that emission limitation. The commenter claimed that
significant capital investment would be required in order for the DCU
to comply with the 2 psig limit. According to one commenter, data for
six of the eight DCU they claim the EPA considered for the MACT floor
should not be counted in determining the limit that represents the
average emission limitation actually achieved 18 months prior to the
proposal.
Response: CAA section 112(d)(3)(A) states that the existing source
standard shall not be less stringent than the average emission
limitation achieved by the best performing 12-percent of the existing
sources (for which the Administrator has emissions information),
excluding those sources that have, within 18 months before the emission
standard is proposed or within 30 months before such standard is
promulgated, whichever is later, first achieved a level of emission
rate or emission reduction which complies, or would comply if the
source is not subject to such standard, with the lowest achievable
emission rate (as defined by section 171) applicable to the source
category and prevailing at the time, in the category or subcategory for
categories and subcategories with 30 or more sources. We consider a 2
psig emissions limitation to be equivalent to the lowest achievable
emission rate (LAER) emission limits. Thus, we agree with the commenter
that sources that first meet the 2 psig limit on or after December 30,
2012, should be excluded from the MACT floor analysis. We also agree
that under CAA section 112(d)(3)(A), the MACT floor analysis focuses on
those sources that are achieving the emission limit (i.e., the emission
limitation ``achieved by . . . ''). The EPA has previously determined
that the 6th-percentile unit is a reasonable estimate of the average
emission limitation achieved by the best performing 12-percent of
sources especially when averaging across units with and without control
requirements. As noted in our DCU MACT floor analysis memorandum
(Docket ID No. EPA-HQ-OAR-2010-0682-0203), the 6th-percentile is
represented by the fifth-best performing DCU. If we exclude the two
South Coast refineries and the two Marathon Garyville DCU because these
sources were not implementing the 2 psig permit limit prior to December
30, 2012, the fifth-best performing DCU would be represented by the Bay
Area refineries (4.6 psig). However, based on the 2011 Petroleum
Refinery ICR responses, 25 out of 75 (33-percent) DCU have a ``typical
coke drum pressure when first vented to the atmosphere'' of 2 psig or
less and 10 out of 75 (13-percent) DCU have a ``typical coke drum
pressure when first vented to the atmosphere'' of 1 psig or less. While
we acknowledge that these data represent ``typical'' operations and not
necessarily a never-to-be-exceeded emissions limitation, we conclude
that this information is sufficient for us to conclude that the average
emission limitation achieved by the best performing 12-percent of
sources is consistent with a 2 psig emissions limitation. This is
because facility owners or operators commonly target to operate at
approximately half the allowable emissions limit to ensure that they
can comply with the emissions limit at all times. Therefore, we
maintain that an average venting pressure of 2 psig is the MACT floor
level for decoking operation at existing sources based on the ICR
responses and considering the average performance expected.
Comment: Four commenters suggested that the 2 psig limit, if
finalized, should be based on a rolling 30-day average per DCU rather
than a never to be exceeded ``instantaneous'' standard. According to
the commenters, an instantaneous standard is unnecessary to address
HAPs with chronic health impacts and adds cost and compliance
challenges. According to the commenters, chronic health impacts are not
materially affected by short-term variability, but instead depend on
the average concentration of exposure over a 70-year lifetime;
therefore, there is no health based or environmental reason for
requiring an instantaneous limit. The commenters noted that there would
be additional capital costs to comply with a 2 psig not-to-be-exceeded
limit compared to a 30-day average 2 psig limit vent pressure. One
commenter specifically requested that the EPA also confirm that a
pressure of 2.4 psig is compliant with the 2 psig limit vent pressure.
Another commenter also requested clarification that the vent pressure
can be rounded to

[[Page 75209]]

one significant figure when determining compliance.
Response: For new sources, the MACT floor emission limit for DCU is
based on the best-performing source. Based on this and other comments
received, we again reviewed existing permit conditions. Based on this
review, we found that one of the permit requirements specified the
pressure limit as 2.0 psig for each coke drum venting event. Therefore,
we are finalizing the new source MACT floor as 2.0 psig on a per coke
drum venting event basis.
As discussed in response to the previous comment, we are basing the
MACT floor for existing source DCU on responses we received from the
2011 Petroleum Refinery ICR. Because the ICR requested the ``typical
coke drum pressure when first vented to the atmosphere,'' we do not
consider the information provided in ICR responses to reflect a
``never-to-be-exceeded'' limit. Therefore, we evaluated whether it is
reasonable to allow averaging, and if so, what averaging period should
be provided.
Health risks are not considered in establishing MACT requirements,
so we do not consider the argument that chronic effects are evaluated
over a 70-year period to be relevant to a determination of the MACT
floor. However, a primary consideration regarding averaging periods is
how the averaging period was considered in setting the floor and
whether the intended reductions will occur under a different averaging
period. According to the heat balance method for estimating DCU
emissions, DCU decoking operations emissions are directly proportional
to the average bed temperature. While the relationship is not exactly
linear, the average bed temperature is expected to be a function of the
venting pressure. Moreover, the shape of the pressure-temperature
correlation curve is such that the emissions at 6 psig are almost
exactly but not quite three times the emissions at 2 psig. Given the
expected linearity of the emissions with venting pressures, we are not
concerned with an occasional venting event above 2 psig because the
average emissions from a facility meeting an average 2 psig pressure
limit would be identical to the emissions achieved by a facility that
vented each time at 2 psig. That is, given the expected linearity in
the projected DCU emissions to the venting pressure, we conclude that
it is reasonable to allow averaging across events and that the precise
averaging period is not a critical concern.
Most industry commenters requested a 30-day average. However,
different facilities have different numbers of DCU, different numbers
of drums per DCU and different cycle times. Consequently, basing the
averaging period across a given time period would result in
significantly different number of venting events included in a 30-day
average for different facilities and generally provide more flexibility
to larger refineries and less flexibility to smaller refineries. Based
on the ICR responses, almost half of all DCU operate with two drums and
about 90-percent of DCU have two to four coke drums; however, a few DCU
have six or even eight drums. Also, based on the ICR responses, the
average complete coke drum cycle time is 32 hours, but can be as short
as 18 hours and as long as 48 hours. Reviewing the ICR responses, we
found that a 30-day average would include 30 events for some facilities
and more than 250 events at other facilities.
Since the existing source MACT standards apply ``in combination''
to ``all releases associated with decoking operations'' at a given
facility, we determined that it was reasonable to consider an averaging
period that applies to the number of venting events from all coke drums
at the facility rather than to all coke drums for a specific DCU for a
specified period of time. This provides a more consistent basis for the
averaging period and allows the same operational flexibility for small
refineries as large refineries. Based on the ICR responses, the median
(typical) DCU has 60 venting events in a 30-day period. Providing an
averaging period of 60 venting events provides a more consistent
averaging basis for all facilities, regardless of the number of DCU at
the facility and the number of drums and cycle times for different DCU.
Additionally, it eliminates issues with respect to how to handle
operating days versus non-operating days, e.g., in the event of a turn-
around resulting in a limited number of venting events in a 30-calendar
day period. Therefore, we are establishing a 2 psig limit based on a
60-event average considering all coke drum venting events at an
existing source and we are finalizing a 2.0 psig limit on a per coke
drum venting event for DCU at new sources.
We have consistently maintained our policy to round to the last
digit provided in the emission limit, a pressure of 2.4 psig would
round to 2 psig and would be compliant with a requirement to depressure
each coke drum to a closed blowdown system until the coke drum vessel
pressure is 2 psig or less, but it would not be compliant with the
revised new source provision to depressure until the coke drum vessel
pressure is 2.0 psig or less. A coke drum pressure of 2.04, however,
would be compliant with the revised new source requirement pressure
limit of 2.0 psig.
ii. Refinery Flares
Comment: Several commenters suggested that the proposed flare
operating limits were too complex. The commenters recommended that the
EPA eliminate the dual flare combustion zone heat content limits
related to the proposed hydrogen-olefin interaction criteria and
instead finalize a single combustion zone net heating value of
approximately 200 BTU/scf, which would minimize the unnecessary burning
of supplemental gas but still ensure good combustion efficiency.
A few commenters suggested that the EPA based the proposed
combustion zone limits on an invalid data analysis, that the 1 minute
PFTIR data should not be used to establish combustion efficiency
correlations, and that the emission limits should be set so as to
provide an equal chance of false positives and negatives. A few
commenters suggested that the EPA should assign hydrogen a heating
value of 1,212 BTU/scf to more accurately reflect its flammability in a
NHV basis and that doing so is consistent with some recent flare
consent decrees and would help reduce natural gas supplementation for
facilities complying only with the NHVcz metric.
Several commenters suggested that neither scientific literature nor
the available flare test data support the EPA's claim of an adverse
hydrogen-olefin interaction on combustion efficiency and that the EPA
should not finalize the more restrictive combustion zone operating
limits for all flare types. These commenters suggested that the EPA did
not provide any evidence the assumed hydrogen-olefin effect actually
exists; that statistical analysis demonstrates the EPA developed their
limit based on random differences in data; that the PFTIR data analysis
method of using the individual minute-by-minute data instead of the
test average data is flawed and leads to invalid conclusions; and that
proper analysis of the data demonstrates the more stringent operating
limits for hydrogen-olefin conditions cannot be supported.
Some commenters suggested that there is evidence to support more
stringent flare combustion zone limits for a narrowly defined high
concentration propylene-only condition as outlined in some of the
recent flare

[[Page 75210]]

consent decrees but that the flare test data do not support more
stringent operating limits for the proposed hydrogen-olefins criteria
by the EPA. Additionally, one commenter suggested that if the EPA
decides to proceed with the more restrictive combustion zone limits for
the hydrogen-olefins interaction cases then the final rule should not
expand beyond an interaction between hydrogen and propylene.
Several commenters suggested that the proposed 15-minute feed
forward averaging time for flares (e.g., combustion zone parameters,
air-assist dilution parameters and associated flow rates) is arbitrary,
unrealistic and unworkable and that the feed forward compliance
determination should not be finalized and, if it is finalized, the
averaging time should be extended to 1-hour, 3-hour, or 24-hour. To
support these suggested averaging periods, commenters claimed that
typical standards for combustion devices are averaged over these
suggested timeframes, noting as an example, recent refinery flare
consent decrees that contain a 3-hour average. The commenters also
asserted that both a GC and calorimeter will be needed to obtain data
rapidly enough to try and maintain a 15-minute average; that the feed
forward approach requires calculation artifices to attempt to correct
for the fact that compliance cannot be determined until the averaging
period is over; and that a longer averaging time is needed for
instrument and control response time.
Response: In addressing these comments, we further analyzed the
flare emissions test data. First, to address concerns that the minute-
by-minute analysis produced flawed results, we re-compiled the data
into approximate ``15-minute averages'' to the extent practical based
on the duration of a given test run (e.g., a 10-minute run was used as
1 run and a 32-minute run was divided into 2 runs of 16 minutes each).
We do not find significant differences in the data or that different
conclusions would be drawn from the data based on this approach as
compared with the minute-by-minute analysis used for the proposed rule.
Next, we evaluated the 15-minute run data using the normal net
heating value for hydrogen of 274 Btu/scf, which is the value we used
in the analysis for the proposed rule and also evaluated the data using
the 1,212 Btu/scf, the value recommended by some commenters. The 1,212
Btu/scf value is based on a comparison between the lower flammability
limit and net heating value of hydrogen compared to light organic
compounds and has been used in several consent decrees to which the EPA
is a party. Based on our analysis, we determined that using a 1,212
Btu/scf value for hydrogen greatly improves the correlation between
combustion efficiency and the combustion zone net heating value over
the entire array of data. Using the net heating value of 1,212 Btu/scf
for hydrogen also greatly reduced the number of ``type 2 failures''
(instances when the combustion efficiency is high, but the gas does not
meet the NHVcz limit). One of the primary motivations for the proposed
approach to provide alternative limits based on lower flammability
limits and combustibles concentrations was to reduce these type 2
failures. Therefore, we proposed all three of these parameters (i.e.,
NHVcz, LFL and total combustibles) and allowed flare owners or
operators to comply with any of the parameter limits at any time. When
using the net heating value of 1,212 Btu/scf for hydrogen, the other
two alternatives no longer provide any improvement in the ability to
predict good flare performance. Consequently, we are simplifying the
operating limits to use only NHVcz.
Next, we re-evaluated whether to finalize the proposed dual
combustion zone operating limits for refinery flares that met certain
hydrogen-olefins interactions or to finalize a single combustion zone
net heating value limit. The newly re-compiled PFTIR run average flare
dataset suggests that higher operating limits may be appropriate for
some olefin-hydrogen mixtures. However, the dataset using 15-minute
test average runs is much smaller than the set using 1-minute runs and
thus creates a greater level of uncertainty. In addition, we cannot
definitively conclude that a dual combustion zone limit for refinery
flares meeting certain hydrogen-olefins interactions is appropriate
given these uncertainties. Thus, in order to minimize these
uncertainties and streamline the compliance requirements, we used all
of the 15-minute test run average data together as a single dataset in
an effort to determine an appropriate, singular combustion zone net
heating value operational limit.
Finally, we conducted a Monte Carlo analysis to help assess the
impacts of extending the averaging time on the test average flare
dataset of 15-minute runs to 1-hour or 3-hour averaging time
alternatives. While we consider it reasonable to provide a longer
averaging time for logistical reasons, the Monte Carlo analysis
demonstrated, consistent with concerns described in our proposal, that
short periods of poor performance can dramatically limit the ability of
a flare to achieve the desired control efficiency. Consequently, we
find it necessary to finalize the proposed 15-minute averaging period
to ensure that the 98-percent control efficiency for flares is achieved
at all times. However, we understand that flare vent gas flow and
composition are variable. While a short averaging time is needed to
ensure adequate control given this variability, we also understand the
complications that this variability places on flare process control in
efforts to meet the NHVcz limit. Therefore, we are clarifying that the
270 Btu/scf NHVcz value is an operational limit that must be calculated
according to the requirements in this rule. We also clarify that
compliance with this operational limit must be evaluated using the
equations and calculation methods provided in the rule. We proposed a
feed forward calculation method to allow refinery owners or operators a
means by which to adjust steam (or air) and, if necessary, supplemental
natural gas flow, in order to meet the limit. In other words, ``feed
forward'' refers to the fact that the rule requires the refinery owners
or operators to use the net heating value of the vent gas (NHVvg) going
into the flare in one 15-minute period to adjust the assist media
(i.e., steam or air) and/or the supplemental gas in the next 15-minute
period, as necessary for the equation in the rule to calculate an NHVcz
limit of 270 BTU/scf or greater. We recognize that when a subsequent
measurement value is determined, the instantaneous NHVcz based on that
compositional analysis and the flow rates that exist at the time may
not be above 270 Btu/scf. We clarify that this is not a deviation of
the operating limit. Rather, the owner or operator is only required to
make operational adjustments based on that information to achieve, at a
minimum, the net heating value limit for the subsequent 15-minute block
average. Failure to make adjustments to assist media or supplemental
natural gas using the equation provided for calculating an NHVcz limit
of 270 BTU/scf, using the NHVvg from the previous period, would be a
deviation of the operating limit.
Alternatively, if the owner or operator is able to directly measure
the NHVvg on a more frequent basis, such as with a calorimeter (and
optional hydrogen analyzer), the process control system is able to
adjust more quickly, and the owner or operator can make adjustments to
assist media or supplemental natural gas more quickly. In this manner,
the owner or operator is not limited by

[[Page 75211]]

relying on NHVvg data that may not represent the current conditions.
Therefore, the owner or operator may opt to use the NHVvg from the same
period to comply with the operating limit.
Based on the results of all of our analyses, the EPA is finalizing
a single minimum NHVcz operating limit for flares subject to the
Petroleum Refinery MACT standards of 270 BTU/scf during any 15-minute
period. The agency believes, given the results from the various data
analyses conducted, that this operating limit is appropriate,
reasonable and will ensure that refinery flares meet 98-percent
destruction efficiency at all times when operated in concert with the
other suite of requirements refinery flares need to achieve (e.g.,
flare tip velocity requirements, visible emissions requirements, and
continuously lit pilot flame requirements). For more detail regarding
our data re-analysis, please see the memorandum titled ``Flare Control
Option Impacts for Final Refinery Sector Rule'' in Docket ID No. EPA-
HQ-OAR-2010-0682.
Comment: Numerous commenters objected to the proposed requirements
to have the velocity and visible emissions limits apply at all times
for flares. Commenters suggested that flares are not designed to meet
the visible emissions and flare tip velocity requirements when being
operated beyond their smokeless capacity and suggested several
alternative approaches: remove the visible emissions and flare tip
velocity requirements from the rule altogether; exempt flares from
these requirements during emergencies; or add a requirement to maintain
a visible flame present at all times or include a work practice
standard in the rule when flares are operated beyond their smokeless
capacity at full hydraulic load. The commenters identified full
hydraulic load as the maximum flow the flare can receive based on the
piping diameter of the flare header and operating pressure of processes
connected to the flare header system. They also specified that full
hydraulic load would only occur if all sources connected to the flare
header vented at the same time, which might result from an emergency
shutdown due to a plant-wide power failure. According to commenters,
flares are typically designed to operate in a smokeless manner at 20 to
30-percent of full hydraulic load. Thus, they claimed, flares have two
different design capacities: A ``smokeless capacity'' to handle normal
operations and typical process variations and a ``hydraulic load
capacity'' to handle very large volumes of gases discharged to the
flare as a result of an emergency shutdown. According to commenters,
this is inherent in all flare designs and it has not previously been an
issue because the flare operating limits did not apply during
malfunction events. However, if flares are required to operate in a
smokeless capacity during emergency releases, the commenters claimed
that refineries would have to quadruple the number of flares at each
refinery to control an event that may occur once every 2 to 5 years.
To support their suggestions, commenters pointed out that flaring
during emergencies is the optimum way of handling very large releases
and that the flare test data clearly demonstrate that visible emissions
and/or high flare tip velocity do not suggest poor destruction
efficiency during such events. The commenters also argued that
operators should not have conflicting safety and environmental
considerations to deal with during these times. The commenters stated
that refiners are still subject to a civil suit even if the EPA uses
its enforcement discretion where such a release would violate the limit
and in order to avoid such liability, many new flares would have to be
built. Commenters estimated that 500 new large flare systems at a
capital cost in excess of $10-20 billion would need to be built because
of the amount of smokeless design capacity that would be needed and
that this significant investment would take the industry at least a
decade to install.
Response: At the time of the proposed rule, we did not have any
information indicating that flares were commonly operated during
emergency releases at exit velocities greater than 400 ft/sec (which is
270 miles per hour (mph)). Similarly, we did not have information to
indicate that flares were commonly designed to have a smokeless
capacity that is only 20 to 30-percent of their ``hydraulic load
capacity.'' While we are uncertain that refineries actually would
install additional flares to the degree the commenters claim, based on
the possibility that there may be an event every 2 to 5 years that
would result in a deviation of the smokeless limit, we also recognize
that it would be environmentally detrimental to operate hundreds of
flares on hot standby in an effort to never have any releases to a
flare that exceed the smokeless capacity of that flare. This is because
operating hundreds of new flares to prevent smoking during these rare
events will generate more ongoing emissions from idling flares than the
no visible emissions limit might prevent during one of these events.
Therefore, we considered alternative operating limits or alternative
standards that could apply during these emergency release events.
As an alternative to the proposed requirement that flares meet the
visible emissions and velocity limits at all times, we considered a
work practice standard for the limited times when the flow to the flare
exceeds the smokeless capacity of the flare. Owners or operators of
flares would establish the smokeless capacity of the flare based on
design specification of the flare. Below this smokeless capacity, the
velocity and visible emissions standards would apply as proposed. Above
the smokeless capacity, flares would be required to perform root cause
analysis and take corrective action to prevent the recurrence of a
similarly caused event. Multiple events from the same flare in a given
time period would be a deviation of the work practice standard. Force
majeure events would not be included in the event count for this
requirement.
Based on industry claims that there is a hydraulic load flaring
event, on average, every 4.4 years, we assumed the best performers
would have no more than one event every 6 years, or a probability of
16.7-percent of having an event in any given year. We found that, over
a long period of time such as 20 years, half of these best performers
would have 2 events in a 3 year period, which would still result in
over half the ``best performing'' flares having a deviation of the work
practice standard if it was limited to 2 events in 3 years. Conversely,
only 6 percent would have 3 events in 3 years over this same time
horizon. Based on this analysis, 3 events in 3 years would appear to be
``achievable'' for the average of the best performing flares.
Pursuant to CAA section 112(d)(2) and (3), we are finalizing a work
practice standard for flares that is based on the best practices of the
industry, and considers the rare hydraulic load events that inevitably
occur at even the best performing facilities.
The best performing facilities have flare management plans that
include measures to minimize flaring during events that may cause a
significant release of material to a flare. Therefore, we are requiring
owners or operators of affected flares to develop a flare management
plan specifically to identify procedures that will be followed to limit
discharges to the flare as a result of process upsets or malfunctions
that cause the flare to exceed its smokeless capacity. We are
specifically requiring refinery owners or operators to implement
appropriate prevention measures applicable to these

[[Page 75212]]

emergency flaring events (similar to the prevention measures we are
requiring in this final rule to minimize the likelihood of a PRD
release). Refiners will be required to develop a flare minimization
plan that describes these proactive measures and reports smokeless
capacity. Refiners will need to conduct a specific root cause analysis
and take corrective action for any flare event above smokeless design
capacity that also exceeds the velocity and/or visible emissions limit.
If the root cause analysis indicates that the exceedance is caused by
operator error or poor maintenance, the exceedance is a deviation from
the work practice standard. A second event within a rolling 3-year
period from the same root cause on the same equipment is a deviation
from the standard. Events caused by force majeure, which is defined in
this subpart, would be excluded from a determination of whether there
has been a second event. Finally, and again excluding force majeure
events, a third opacity or velocity limit exceedance occurring from the
same flare in a rolling 3-year period is a deviation of the work
practice standard, regardless of the cause.
Comment: Several commenters suggested that the EPA should revise
the combustion efficiency requirements to apply only to steam-assisted
flares used as Refinery MACT control devices during periods of time
that the flares are controlling Refinery MACT regulated streams. One
commenter suggested that the EPA misused the TCEQ data in proposing the
NHVcz metric and that the proposed limits are overly
conservative. The commenter requested that the EPA work with
stakeholders to conduct additional testing to determine what, if any,
operating parameters are appropriate and necessary to achieve an
adequate destruction efficiency for non-steam-assisted flares.
Response: We disagree with the commenters that the combustion
efficiency requirements should apply only to steam-assisted flares. The
available data (for runs where steam assist is turned off) as well as
the available combustion theories suggest that the combustion zone net
heating value minimum limit, which is the vent gas net heating value
for unassisted or perimeter air-assisted flares, is necessary to ensure
proper flare performance. While we agree that additional data on air-
assisted flares would allow for a more robust analysis, the data we do
have strongly indicate that air-assisted flares can be over-assisted
and that the combustion efficiency of air-assisted flares that are
over-assisted is below 98-percent control efficiency.
Comment: A few commenters suggested that the proposed flare
regulations should not apply to part 63, subpart R (gasoline loading)
and subpart Y (marine vessel loading) facilities, and to part 61,
subpart FF (benzene waste) facilities. The commenters recommended that
flares associated with gasoline loading, marine vessel loading and
wastewater treatment emissions need to comply only with the General
Provisions for flares. Some of these commenters argued that these
sources are more consistent in flow and composition than other refinery
sources, so the new requirements are not necessary to ensure good
combustion for these ``dedicated'' flares. Some commenters suggested
that operators of flares with consistent flow and composition be
allowed to use process knowledge or engineering judgment rather than be
required to install continuous monitors or be subject to ongoing grab
sampling requirements.
Some commenters noted that the required control efficiency for some
refinery emissions sources subject to subpart CC sources is 95-percent.
One commenter also requested that the EPA provide overlap provisions so
flares used to control sources from different MACT sources would not
have duplicative requirements.
Response: The regulatory revisions that we are finalizing apply to
petroleum refinery sources subject to part 63, subparts CC and UUU.
Gasoline loading, marine vessel loading and wastewater treatment
operations that are part of the refinery affected source as defined at
40 CFR 63.640 are subject to subpart CC. Gasoline loading, marine
vessel loading and wastewater treatment operations located at non-
refinery source categories are not subject to part 63, subpart CC and,
thus, would not be subject to the revisions to subpart CC being
finalized in this action. To the extent that the commenters are
requesting that the EPA establish flare requirements that would apply
to flares that are not part of the refinery affected source, that
request is beyond the scope of this rulemaking, which only addresses
revisions to Refinery MACT 1 and 2. When we issue rules addressing
requirements for other sources with flares, we will consider issues
similar to those we considered in this action and determine at that
time whether revisions to those other flare requirements are necessary.
The commenters note that some subpart CC emissions sources have
only a control efficiency requirement of 95-percent. While this may be
true, where the owner or operator chooses to control these sources
through the use of a flare, operation of that flare was subject to
operational requirements in the General Provisions at 40 CFR 63.11 and
the best performing flares were achieving 98-percent control at the
time the General Provisions were promulgated. At the time the General
Provisions were promulgated, we received no comments that the EPA
should set different operational limits for flares that are controlling
emissions from sources where the standard may vary by level of control
efficiency and we see no basis to do so now. The purpose of the
revisions to the flare operating requirements is to ensure that flares
are operating consistent with the MACT floor requirements for any and
all sources that may use flares as a control device (79 FR 36905, June
30, 2014). As the MACT floor control requirements of certain refinery
sources that allow the use of a flare as a control device is 98-
percent, we established operational limits to ensure flares used as
control devices meet this MACT requirement.
To the extent that the commenters are requesting that the EPA
establish an alternative monitoring approach for flares in dedicated
service that have consistent composition and flow, we agree that these
types of flares, which have limited flare vent gas streams, do not need
to have the same type of on-going monitoring requirements as those with
more variable waste streams. Thus, we are establishing an option that
refinery owners or operators can use to demonstrate compliance with the
operating requirements for flares that are in dedicated service to a
specific emission source, such as a wastewater treatment operation.
Refinery owners or operators will need to submit an application for the
use of this alternative. The application must include a description of
the system, characterization of the vent gases that could be routed to
the flare based on a minimum of 7 grab samples (14 daily grab samples
for continuously operated flares) and specification of the net heating
value that will be used for all flaring events (based on the minimum
net heating value of the grab samples). We are also allowing
engineering estimates to characterize the amount of gas flared and the
amount of assist gas introduced into the system. For example, the use
of fan curves to estimate air assist rates is acceptable. Flare owners
or operators would use the net heating value determined from the
initial sampling phase and measured or estimated flare vent gas and
assist gas

[[Page 75213]]

flow rates, if applicable, to demonstrate compliance with the
standards.
Comment: A few commenters suggested that the EPA's proposed work
practice and monitoring standards for flares are CAA section 112(d)
``developments'' required by law and supported by the evidence, and
reflect best practices at many refineries today. One commenter
suggested that the EPA must allow companies with consent decrees to
meet their consent decree requirements as an alternative compliance
approach and in lieu of the proposed requirements.
Response: We proposed the enhanced monitoring requirements and
operating limits under authority of CAA sections 112(d)(2) and (d)(3)
to ensure that flares used to control regulated Refinery MACT 1 or 2
gas streams are meeting the prescribed control efficiencies established
at the time the MACT standard was promulgated. And, we continue to
believe that these revisions are appropriate under CAA sections
112(d)(2) and (d)(3). The commenter has not suggested, and we do not
believe, that the revisions promulgated would differ in substance if
they were instead promulgated under CAA section 112(d)(6).
In general, we expect that the NHVcz monitoring
requirements that we are finalizing for flares will be consistent with
the requirements in various consent decrees. However, we have not
conducted a rigorous evaluation of equivalency between various
requirements and therefore we are not at this time providing an
allowance for flare owners or operators to comply with the
NHVcz operating limits and any provisions for necessary
monitoring needed in the consent decree in lieu of the NHVcz
limits and monitoring requirements established in this rule. In the
event that an owner or operator wishes to continue complying only with
the requirements of a consent decree, the rule contains provisions by
which owner or operator can seek approval for alternative limits that
are at least equivalent to the performance achieved from complying with
the operating limits included in the final rule.
iii. Pressure Relief Devices
Comment: Several commenters suggested that the EPA develop a work
practice approach for atmospheric PRD rather than a prohibition on
releases. One commenter recommended that the EPA establish a work
practice standard for atmospheric PRDs that requires refiners to
implement a base level of preventative measures including: Basic
process controls, instrumented alarms, documented and verified routine
inspection and maintenance programs, safety-instrumented systems,
disposal systems, provide redundant equipment, increase vessel design
pressure and systems that reduce fire exposure on equipment.
Additionally, the commenter recommended that the EPA require refiners
to perform root cause analysis and implement corrective action in the
event of a release. The commenter stated these requirements would be
similar to the root cause analysis/corrective action requirements
recently promulgated for flares under NSPS subpart Ja and provided
specific regulatory language for a proposed work practice approach.
(See section 2.4.1.8 in Docket item EPA-HQ-OAR-2010-0682-0583.) One
commenter requested that the EPA allow a process for companies to
submit an application for case-by-case limits to be approved by the
agency, either the EPA or a delegated state similar to the alternate
NOX limits for process heaters provided in NSPS subpart Ja.
This commenter recommended that the EPA establish reasonable work
practice standards, specifically suggesting that the EPA develop work
practice standards consistent with API 521. The commenter stated that
the EPA should provide an implementation period for compliance that
goes beyond the timeframe provided under CAA section 112(d). The
commenter added that the EPA should adopt specified changes to the
definition of an atmospheric pressure relief safety valve and provided
suggested regulatory language for a proposed work practice standard for
PRDs in EPA-HQ-OAR-2010-0682-0549.
Another commenter stated that the EPA should require, as the Bay
Area Air Quality Management District (BAAQMD) does, that any refinery
that has a reportable PRD event must take certain steps to prevent such
releases in the future (BAAQMD Rule 8-28-304). In particular, such a
refinery must create a Process Hazard Analysis, meet the Prevention
Measures Procedures specified in section 8-28-405, and conduct a
failure analysis of the incident, to prevent recurrence of similar
incidents (Id. Reg. section 8-28-304.1). If a second release occurs,
then, within one year, the facility must vent its PRDs to a vapor
recovery or disposal system that meets certain requirements (Id. Reg.
section 8-28-304.2). The commenter asserted that the EPA's prohibition
on releases to the atmosphere from PRD will ensure that refineries take
the necessary steps to prevent such releases, or install control
devices so that any releases from PRDs that must occur are vented
through a control device to reduce the amount of toxic air pollution
they emit. At a minimum, the commenter stated, the EPA must prohibit
these uncontrolled emissions and require monitoring and reporting to
assure compliance and ensure that the emission standards apply at all
times, as required by the Act. The commenter argued that the EPA must
also, however, consider requiring the additional developments that have
been put into place in the BAAQMD and also require control devices to
be used for all PRD, as some local air districts require. In addition,
the commenter supported the EPA's monitoring and reporting requirements
for PRD releases and the proposed electronic reporting requirements,
which the EPA recognized are needed to assure compliance and assist
with future rulemakings and as that provision requires, the EPA also
must make all information reported publicly available online promptly
and in an accessible and understandable format.
Response: We agree that, under the proposal, refineries would
consider installing add-on controls to comply with the prohibition on
atmospheric releases from PRDs. In addition, they would consider
venting these control devices to existing control devices, including
flares. However, it may not be feasible to vent some or all of the PRDs
to existing flares if the flares are near their hydraulic load capacity
based on the processes already connected to the flares. Flares have
negative secondary impacts when operated at idle conditions for the
vast majority of time, which could be the case if they were installed
solely to address PRD releases. These secondary impacts result from
GHG, CO and NOX emissions. Some PRDs may vent materials that
are not compatible with flare control and would need to be vented to
other controls.
To estimate the impact of the proposed prohibition on venting PRDs
to the atmosphere, we estimated that at least one new flare per
facility would be required to handle releases from PRDs, based on the
number of atmospheric PRDs reported at refineries; that 60-percent of
the PRDs could be piped to existing controls at minimal costs and the
other 40-percent would have to be piped to new flares; and that, on
average, each new flare would service 40 PRDs. Based on these
assumptions, 151 new flares would be needed or approximately one new
flare per refinery. At a capital cost of $2 million for each new flare,
which would not include long pipe runs, if needed, to PRD that are
dispersed across the plant, we estimate that the capital cost of the

[[Page 75214]]

prohibition on venting to the atmosphere would exceed $300 million.
Considering the fuel needed (approximately 50,000 scf/day per flare)
and a natural gas price of $4.50 per 1,000 scf, we estimate the annual
operating cost for these new flares to be $12 million.
PRDs are unique in that they are designed for the purpose of
releasing or ``popping'' as a safety measure to address pressure build-
up in various systems--pipes, tanks, reactors--at a facility. These
pressure build-ups are typically a sign of a malfunction of the
underlying equipment. While it would be difficult to regulate most
malfunction events because they are unpredictable and can vary widely,
in the case of PRDs, they are equipment installed specifically to
release during malfunctions and as such, we have information on PRDs in
our 2011 Refinery ICR and through the SCAAMD and BAAQ rules to
establish standards for them. After reviewing these comments, we thus
examined whether it would be feasible to regulate these devices under
CAA section 112(d)(2) and (3).
After reviewing the comments, we agree with the commenters who
suggest that the BAAQMD rule, as well as a similar South Coast Air
Quality Management District (SCAQMD) rule that address PRD releases
(SCAQMD Rule 1173), provide work practice standards that reflect the
level of control that applies to the best performers. Consequently, we
developed a work practice standard for PRD based on a detailed MACT
analysis considering the requirements in these rules. Our rationale for
the selected MACT requirements is provided in section IV.C.4 of this
preamble. The work practice standards that we are finalizing for PRDs
require refiners to establish proactive measures for each affected PRD
to prevent direct release of HAP to the atmosphere as a result of
pressure release events. In the event of an atmospheric release, we are
requiring refinery owners or operators to conduct root cause analysis
to determine the cause of a PRD release event. If the root cause was
due to operator error or negligence, then the release would be a
deviation of the standard. For any other release (not including those
caused by force majeure events), the owner or operator would have to
implement corrective action. A second release due to the same root
cause for the same equipment in a 3-year period would be a deviation of
the work practice standard. Finally, a third release in a 3-year period
would be a deviation of the work practice standard, regardless of the
root cause. Force majeure events would not count in determining whether
there has been a second or third event.
With respect to defining ``atmospheric pressure relief safety
valve'' as suggested by the commenter, we note that the June 30, 2014,
proposed amendments in 40 CFR 63.648(j) used the term ``relief valve''
because this was a defined term in Refinery MACT 1. However, the
proposed amendments included clauses such as ``if the relief valve does
not consist of or include a rupture disk.'' Thus, we specifically
intended to apply the pressure relief management requirements broadly
to ``pressure relief devices'' and not just ``valves.'' To clarify
this, we have revised the regulatory language to use the term
``pressure relief device'' rather than ``relief valve'' to clearly
include rupture disks or similar types of equipment that may be used
for pressure relief.
4. What is the rationale for our final approach and final decisions for
the revisions pursuant to CAA section 112(d)(2) and (3)?
We revised the MACT floor determination for DCU sources. CAA
section 112(d)(3)(A) requires the MACT floor for existing sources to
exclude ``. . . those sources that have, within 18 months before the
emission standard is proposed or within 30 months before such standard
is promulgated, whichever is later, first achieved a level of emission
rate or emission reduction which complies, or would comply if the
source is not subject to such standard, with the lowest achievable
emission rate (as defined by section 171) applicable to the source
category and prevailing at the time, in the category or subcategory for
categories and subcategories with 30 or more sources.'' Because we have
determined that a 2 psig emissions limitation is equivalent with a LAER
emission limit for DCU, we revised the MACT floor analysis in order to
exclude sources that first met the 2 psig limit on or after December
30, 2012. For existing sources, based on the revised MACT analysis, we
concluded that the MACT floor is still 2 psig. However, because the
information on which we relied was submitted in response to the 2011
Petroleum Refinery ICR which requested ``typical'' venting pressures
and because providing an allowance to average across venting periods
does not reduce the emissions reductions achieved, we are providing a
60-event averaging period for existing sources in response to public
comments received.
For new DCU sources, our revised analysis identified one DCU
subject to permit emission limitations of 2.0 psig pressure limit prior
to venting on a per event basis. Under CAA section 112(d)(3), the MACT
standard for new sources cannot be less stringent than the emission
control achieved in practice by the best-controlled similar source.
Thus, we are finalizing a limit of 2.0 for new DCU sources. We note
that as 2.0 psig limit is more stringent than a 2 psig limit because of
the rounding convention of rounding to the number of significant digits
for which the standard is expressed. For example, a 2.4 psig venting
pressure is compliant with a 2 psig limit, while it is not compliant
with a 2.0 psig limit.
We evaluated the costs of requiring existing sources to meet a 2.0
psig limit as a beyond-the-MACT-floor option. We determined the
incremental cost of going from a 2 psig limit with an allowance to
average over 60 events to a 2.0 psig limit on a per event basis was
approximately $70,000 per ton of HAP reduced considering VOC credits.
Based on this high incremental cost-effectiveness, we concluded that
the MACT floor requirement for existing DCU sources was MACT. As
discussed in detail in the proposal, we do not consider it technically
feasible to meet a 1 psig pressure limit (effectively a 1.4 psig limit)
on a not-to-be-exceeded basis. Thus, we rejected this beyond the floor
control option for both existing and new DCU sources. See the
memorandum titled ``Reanalysis of MACT for Delayed Coking Unit Decoking
Operations'' in Docket ID No. EPA-HQ-OAR-2010-0682 for additional
details regarding our re-analysis of MACT for DCU decoking operations.
In response to comments received on the prohibition of draining
prior to achieving the proposed pressure limit (see Section 7.2.1 in
the ``National Emission Standards for Hazardous Air Pollutants from
Petroleum Refineries--Background Information for Final Amendments:
Summary of Public Comments and Responses'' in Docket ID No. EPA-HQ-OAR-
2010-0682), we are providing specific provisions to allow for draining
under special conditions. The specific provision and our rationale for
providing them are provided below.
First, we learned that certain DCU are designed to completely fill
the drum with water and allow the water to overflow in the overhead
line and drain to a receiving tank in order to more effectively cool
the coke bed. Owners or operators of this DCU design were concerned
that the water overflow may be considered a drain and also stated that
overhead temperature rather than pressure would be a better indicator
of effective bed cooling. In reviewing this

[[Page 75215]]

type of DCU design, we find that this design has some unique advantages
to traditional DCU to effect better cooling of the coke drum, and
therefore we do not want to preclude its use. Based on saturated steam
properties, we determined that an overhead temperature of 220 [deg]F
would achieve equivalent or greater emissions reductions than a 2 psig
pressure limitation and an overhead temperature of 218 [deg]F would
achieve equivalent or greater emissions reductions than a 2.0 psig
pressure limitation. Therefore, we are including these temperature
limits as alternatives to the 2 or 2.0 psig pressure limitations for
existing and new DCU affected sources, respectively. With respect to
the overflow ``drain,'' we remain concerned with emissions from
draining superheated water. However, if submerged fill is used in the
atmospheric tank receiving the overflow water, the superheated water
will be cooled by the water within the tank and emissions that occur
during the conventional draining of water (from the flashing of
superheated water into steam) can be prevented. Therefore, we are
allowing the use of water overflow provided the overflow ``drain''
water is hard-piped to the receiving tank via a submerged fill pipe
(pipe below the existing liquid level) whenever the overflow water
exceeds 220 [deg]F.
Second, we received comments that, for conventional DCU (those not
designed to allow water overflow), there is a limit to the maximum
water level in the drum, which limits to some extent how much cooling
water can be added to the coke drum. In rare cases, the coke drum does
not cool sufficiently using the typical cooling steps. In this case,
the common industry practice is to partially drain the coke drum and
refill it with additional cooling water. This ``double-quench'' process
is needed for safety reasons to sufficiently cool the coke drum
contents prior to the decoking operations. Therefore, commenters
requested provisions to allow double-quenching of the coke drum. We
recognize the safety issues associated with coke blow-out during coke
cutting if there is a portion of the coke bed that is not sufficiently
cooled and we agree that double-quenching is an effective means to cool
the coke drum in those rare instances that the typical cooling cycle
does not sufficiently cool the coke drum contents, so we considered
granting the commenters' request. As noted previously, the primary
concern with early draining of the coke drum is the emissions that are
expected to occur as a result of draining superheated water. We
recognize, however, that the water temperature near the bottom of the
coke drum is typically much lower than at the top of the coke drum. If
the temperature of the water drained from the bottom of the coke drum
remains below 210 [deg]F, this would minimize steam flashing and
associated HAP emissions since the water drained would not be
superheated. We conclude that the use of double quenching is
appropriate for cases when the coke drum is not sufficiently cooled
using the normal cooling procedures provided the temperature of the
water drained remains below 210 [deg]F, and it is consistent with the
practices of the best performing sources. Consequently, we are
finalizing provisions to allow the use of double-quenching for DCU
provided the temperature of the water drained remains below 210 [deg]F.
For the CRU, we are finalizing the proposed revisions to require
CRU that employ active purging to meet the MACT emissions limitations
in Tables 15 and 16 in subpart UUU at all times regardless of vessel
pressure. We received limited comments regarding our proposal; these
comments generally concerned the costs associated with the proposed
emissions limitations. As discussed in our proposal, and based on data
submitted in response to the ICR, emissions using active purging are
much higher than those not using active purging. In the original rule,
we based the MACT floor on the best performing facilities that used
sequential pressurizations and depressurizations rather than active
purging. Thus, in the proposal, we concluded that allowing owners or
operators to actively purge while at low pressures was inconsistent
with the MACT floor emissions limitations achieved by the best
performing 12-percent of sources when the MACT floor was originally
established. As we are simply requiring these facilities to meet the
same emission levels determined to be MACT, we do not consider costs of
potential additional controls to be a viable rationale to allow these
units to emit several times more HAP than the units upon which the MACT
requirements were based and the emissions levels achieved in practice
by the vast majority of other CRU sources.
For flares, we are finalizing proposed revisions to include
detailed flare monitoring and operating requirements. We are including
the flaring provisions for refineries in the Refinery MACT rules and
removing the cross-references to the flaring requirements in the
General Provisions. The final regulatory requirements differ from the
proposed requirements in several respects. First, we are not finalizing
the ban on halogenated vent streams because we did not include
sufficient justification or include cost estimates for this proposed
provision and we did not include any monitoring requirements to ensure
compliance with this ban on halogenated vent streams.
We are finalizing the proposed no visible emissions limit and the
flare tip velocity limit but they will apply only when the flare vent
gas flow rate is below the smokeless capacity of the flare. We received
a number of comments stating that the no visible emissions limit and
the flare tip velocity limit cannot be met during large malfunctions
and emergency shutdown events. In response to comments, we are
finalizing work practice standards for emergency flaring events using
the proposed no visible emission limit and flare tip velocity limit as
thresholds in the final rule to trigger root cause analysis when the
flare vent gas flow rate is above the smokeless capacity of the flare.
The final work practice standard includes requirements to develop a
flare management plan, to implement prevention measures, and to perform
root cause analysis and implement corrective action following each
flaring event that exceeds the smokeless capacity of the flare. There
is also a limit on the number of these flaring events that a given
flare may have in the 3-year period. We are establishing these
provisions because we now recognize that flares have two different
design capacities: A smokeless design capacity and a hydraulic load
capacity. We determined that the proposed visible emissions limit and
the flare tip velocity limit for very large flow events are not the
MACT floor for such events. The final work practice standards for
flaring events are based on the best performing facilities and will
result in emission reductions in a technically feasible manner without
any negative secondary impacts.
We consider it appropriate to establish a work practice standard
for flares as provided in CAA section 112(h). While it is possible to
monitor gaseous streams going into the flare (as we have required for
the flare operating requirements) it is not possible to design and
construct a conveyance to capture the emissions from a flare. While
knowledge of the composition and flow of gases entering the flare
provides a reasonable basis for establishing operating requirements for
normal operations, we have no data on flare performance under
conditions in the hydraulic load range. While smoke in the flare
exhaust is an indication of incomplete combustion, it is uncertain

[[Page 75216]]

how much deterioration of HAP destruction efficiency occurs during a
smoking event. We also consider that the application of a measurement
methodology for flare exhaust is not practicable due to technological
and economic limitations. Passive FTIR has been used to determine
combustion efficiency in flare exhaust, but these are essentially
manual tests, and the measurement accuracy is dependent on how well the
monitor is aligned with the flare exhaust plume. Changes in wind
direction require manual movement of the monitoring system. It is also
unclear if these systems can accurately measure combustion efficiency
during high smoking events. These systems also require very specialized
expertise, and we consider that it is both technologically and
economically infeasible to measure flare exhaust emissions,
particularly during high load events. Consequently, for emergency flare
releases, we conclude that it is appropriate to establish a work
practice standard as provided in CAA section 112(h).
We also received comments that the daily visible emissions
observations were burdensome and unnecessary and some commenters
suggested that facilities be allowed to use video surveillance cameras.
We concluded that video surveillance cameras would be at least as
effective as the proposed daily 5-minute visible emissions observations
using Method 22. We are finalizing the proposed visible emissions
monitoring requirements Method 22 and the alternative of using video
surveillance cameras.
We are simplifying the combustion zone gas property operating
limits in response to public comments received. Specifically, we are
finalizing requirements that all flares meet a minimum operating limit
of 270 BTU/scf NHVcz on a 15-minute average, and we are
providing that refiners use a corrected heat content of 1,212 BTU/scf
for hydrogen to demonstrate compliance with this operating limit. We
determined that a corrected heat content of 1212 BTU/scf for hydrogen
provided a better indication of flare performance than without the
correction. We also determined that the other combustion zone
parameters, which were primarily proposed to provide suitable methods
for flares that had high hydrogen concentrations, were no longer
necessary when a 1,212 Btu/scf net heating value is used for hydrogen.
Therefore, we are not finalizing the alternative combustion zone
operating limits based on lower flammability limit or combustibles
concentration. We are also not finalizing separate combustion zone
operating limits for gases meeting the proposed hydrogen-olefin
interaction criteria. In our revised analysis of the data, we analyzed
all of the data together and determined the 270 Btu/scf
NHVcz operating limit provided in the final rule would
adequately ensure that flares achieve the desired 98-percent control
efficiency regardless of the composition of gas sent to the flare.
For air-assisted flares, we are finalizing the additional
``dilution parameter'' operating limit only for the net heating value
dilution parameter, NHVdil. Similar to the requirements we
are finalizing for the combustion zone parameters, we are finalizing
requirements that flares meet a minimum operating limit of 22 BTU/
ft² NHVdil on a 15-minute average, and we are
providing that refiners use a corrected heat content of 1,212 BTU/scf
for hydrogen to demonstrate compliance with this operating limit. For
the reasons explained above, we are not finalizing the proposed
alternative dilution parameter operating limits based on lower
flammability limit or combustibles concentration, and we are not
finalizing separate dilution parameter operating limits for gases
meeting the proposed hydrogen-olefin interaction criteria.
For flares in dedicated service, we are establishing an alternative
to continuous or on-going grab sample requirements for determining
waste gas net heating content to reduce the burden of sampling for
flare waste gases that have consistent compositions. Flares in
dedicated service can use initial sampling period and process knowledge
to determine a fixed net heating value of the flare vent gas to be used
in the calculations of NHVcz and, if applicable,
NHVdil.
We are revising the definition of MPV to remove the exemption for
in situ sampling systems for the reasons provided in the proposed rule.
We received comments recommending that a work practice standard be
adopted for PRD rather than the proposed prohibition of atmospheric PRD
releases. Commenters stated that the prohibition was infeasible due to
the proposed immediate timing of the requirement and impractical due to
cost considerations. After reviewing these comments as well as the
BAAQMD rule (Regulation 8, Rule 8-28-304) and the SCAQMD rule (Rule
1173), we have determined that the work practice standards in these
rules reflect the level of control that applies to the best performers.
Therefore, we proceeded to evaluate appropriate MACT requirements based
on the provisions in these rules.
The BAAQMD rule requires sources to implement a minimum of three
prevention measures to limit the possibility of a release. The BAAQMD
uses a ``release event'' threshold of 10 lbs/day of organic or
inorganic pollutants; the SCAQMD rule effectively uses a release event
threshold of 500 lbs VOC/day. When a release event occurs, both rules
require that the refiner perform a root cause analysis and take
corrective action (including additional prevention measures). In
addition, both rules require piping the PRD to a flare if there are
more than two release events (releases above a certain release size
threshold) in a 5-year period. Both rules include a number of
exemptions for certain types of PRD that are not expected to release
significant amounts of pollutants to the air or that are not feasible
to control because of pressure considerations. These include PRD
associated with storage tanks, vacuum systems and equipment in heavy
liquid service as well as liquid thermal relief valves that are vented
to process drains.
There are five refineries subject to the BAAQMD rule and seven
refineries subject to the SCAQMD rule, accounting for 8-percent of
refineries nationwide and representing the industry's best performers.
We consider the BAAQMD rule to be the more stringent of the two because
this rule requires sources to implement a minimum of three prevention
measures to limit the possibility of a release (the SCAQMD rule has no
similar requirement) and uses a lower mass threshold for what is
considered a ``release event'' (10 lbs/day of organic or inorganic
pollutants versus the 500 lbs VOC release threshold in the SCAQMD
rule). Therefore, the BAAQMD rule is considered to be the MACT floor
requirement for PRDs associated with new affected sources and the
SCAQMD rule is considered to be the MACT floor for PRDs associated with
existing affected sources.
In general, an open PRD is essentially the same as a miscellaneous
process vent that is vented directly to the atmosphere. Consistent with
our treatment of miscellaneous process vents and consistent with the
two California rules, we believe that it is appropriate to exclude
certain types of PRD that have very low potential to emit based on
their type of service, size and/or pressure. For example, PRD that have
a potential to emit less than 72 pounds per day of VOC, considering the
size of the valve opening, design release pressure, and equipment
contents, would be considered in a similar manner as Group 2
miscellaneous

[[Page 75217]]

process vents and would not require additional control. The two
California rule requirements do not apply to PRD on storage tanks and
vacuum systems. Most of these PRD have a design release pressure of 2.5
psig and thus have a very limited potential to emit. It is technically
infeasible to pipe these sources to a flare (or other similar control
system) because the back pressure in the flare header system generally
exceeds 2.5 psig. We note that some storage tanks can operate at
elevated pressure (i.e., pressure tanks). Therefore, rather than follow
exactly the requirements in the California rules, we determined it more
practical to exclude PRD with design release pressure of less than 2.5
psig.
Any release from a PRD in heavy liquid service would have a visual
indication of a leak and any repairs to the valve would have to be
further inspected and, if necessary, repaired under the existing
equipment leak provisions. Therefore, consistent with the BAAQMD rule,
we are exempting PRD in heavy liquid service from the work practice
standards we are establishing in this final rule.
Both the BAAQMD and SCAQMD rules exempt thermal expansion valves
that are ``vented to process drains or back to the pipeline.'' We are
unclear what is meant by ``vented to process drains''; however, if a
liquid is released from a PRD via hard-piping to a drain system that
meets the control requirements specified in Refinery MACT 1, we
consider that these PRD are controlled and they would not be subject to
the work practice standard established in this final rule. Similarly,
all PRD in light liquid service that are hard-piped to a controlled
drain system (or back to the process or pipeline) are otherwise subject
to a MACT requirement and would not be subject to the work practice
standard.
In considering thermal relief valves not vented to process drains
or back to the pipeline, we expect that releases from these thermal
relief valves will be small and generally under the release event
thresholds specified in the California rules. Therefore, the work
practice standards do not apply to PRD that are designed solely to
release due to liquid thermal expansion.
The primary goal of the PRD work practice standard is to reduce the
size and frequency of releases. The SCAQMD rule is targeted towards
fairly large releases (compared to the direct PRD releases reported in
response to the Refinery ICR), so it will reduce the frequency of large
releases, but it does little to reduce the frequency of smaller
releases. To more effectively reduce the size and frequency of all
releases, we consider it important to require the implementation of
prevention measures (as required in the BAAQMD rule) and require root
cause analysis and corrective action for PRD releases from all PRD
subject to the work practice standard. While we recognize that if a PRD
opens for a short period of time, the release might be below the
release thresholds in the SCAQMD rules, we believe the release may be
indicative of an important issue or design flaw. Because the potential
for large emissions exist from the PRD subject to the work practice
standard, we think it is reasonable to require a root cause analysis be
conducted and appropriate corrective action implemented to potentially
identify this issue and prevent a second release which, if the issue
remains uncorrected, could be significant.
Requiring that prevention measures be implemented on all PRD
subject to the work practice standard and not establishing a release
threshold for release events is a variation from the SCAQMD rule.
However, we also considered the allowable release frequency. We believe
that our adoption of this approach is balanced by our not adopting the
SCAQMD provisions requiring that PRD be vented to a flare or other
control system or that refiners pay a fee if there are multiple
releases of a certain size within a specified timeframe.\12\ In place
of this system, we are limiting the number of events from each PRD that
can occur in a 3 year time period (2, if root causes are different),
and in place of a fine, or routing to control, stating that the 3rd
release in 3 years for any root cause is a deviation of the standard.
---------------------------------------------------------------------------

\12\ The SCAQMD rule requires PRD to be vented to a flare or
other control device if there is a single release in excess of 2,000
pounds of VOC in a 24-hour period or three releases in excess of 500
pounds of VOC in a 5-year period or, alternatively, pay a $350,000
fee. Thus, the SCAQMD rule would allow, for example, two releases of
over 500 pounds of VOC each within a 5-year period without any
penalty provided a third event did not occur. If a third event did
occur, the refinery owner or operator would then have to vent the
PRD to a flare or other control system or pay a fee ($350,000) for
the third release over 500 pounds of VOC.
---------------------------------------------------------------------------

Because we are not including a size threshold for release events as
in the SCAQMD rule, it is natural to assume release events would occur
more frequently than release events subject to the SCAQMD rules. Also,
based on our Monte Carlo analysis of random rare events, we note that
it is quite likely to have two or three events in a 5-year period when
a long time horizon (e.g., 20 years) is considered. Therefore,
considering our analysis of emergency flaring events and the lack of a
500 lb/day release threshold, we considered it reasonable to use a 3-
year period rather than a 5-year period as the basis of a deviation of
the work practice standard.
The SCAQMD work practice standards do not apply to releases that
are demonstrated to ``result from natural disasters, acts of war or
terrorism, or external power curtailment beyond the refinery's control,
excluding power curtailment due to an interruptible service
agreement.'' These types of events, which we are referring to as
``force majeure'' events, are beyond the control of the refinery owner
or operator. We are providing that these events should not be included
in the event count, but that they would be subject to the root cause
analysis in order to confirm whether the release was caused by a force
majeure event.
Consistent with the requirements in the SCAQMD rule, we are
requiring refinery owners or operators to conduct a root cause analysis
for a PRD release event. If the root cause was due to operator error or
negligence, then the release would be a deviation of the standard. For
any other release (not including those caused by force majeure events),
the owner or operator would have to implement corrective action. We
consider that a second release due to the same root cause for the same
equipment in a 3-year period would be a deviation of the work practice
standard. This provision will help ensure that root cause/corrective
action are conducted effectively. Finally, a third release in a 3-year
period (not including those caused by force majeure events) would be a
deviation of the work practice standard, regardless of the root cause.
While we are using a 3-year interval rather than the 5-year interval
provided in the SCAQMD, we consider that the requirements as included
in this final rule (i.e., the inclusion of prevention measure
requirements and no thresholds for release events) will achieve
equivalent if not greater emissions reductions than the SCAQMD rule. We
also consider that, given the prevention measure requirements and a 3-
year period, there is less likelihood of unusual random events that
happen over a short period of time that may cause refinery owners or
operators to feel compelled to vent the PRD to a flare to eliminate
concerns regarding potential non-compliance. Thus, we project that the
requirements that we have included in the final rule will achieve
emissions reductions commensurate to or exceeding the requirements in
the SCAQMD rule (that serves as the MACT floor for existing sources)
but will achieve those

[[Page 75218]]

reductions in a more cost-effective manner.
We also considered requiring all PRD to be vented through a closed
vent system to a control device as an alternative beyond-the-MACT floor
requirement. While this requirement would provide additional emission
reductions beyond those we are establishing as the MACT floor, these
reduction come at significant costs. Capital costs for requiring
control of all atmospheric PRD is estimated to be approximately $300
million compared to $11 million for the requirements described above.
The total annualized cost for requiring control of all atmospheric PRD
is estimated to be approximately $41 million/year compared to $3.3
million/year for the requirements described above. We estimate that the
incremental cost-effectiveness of requiring control of all atmospheric
PRD compared to the requirements described above exceeds $1 million per
ton of HAP reduced. Consequently, we conclude that this is not a cost-
effective option for existing sources.
The final requirements that we have developed for PRD achieve equal
or greater emission reductions than those achieved by the SCAQMD rule
(MACT floor). To the extent those requirements are more stringent that
the SCAQMD, they are cost-effective. We could not identify an
alternative requirement that provided further emission reductions in a
cost-effective manner. Thus, we conclude that the work practice
standards described above represent MACT for existing sources.
The BAAQMD rule, which represents the requirements applicable to
the best performing sources, is the basis for new source MACT for PRD.
Based on the specific provisions for PRD in the BAAQMD rule, we
conclude that the MACT floor requirement is to have all PRD in HAP
service associated with a new affected source vented through a closed
vent system to a control device. As with existing sources, the PRD WPS
would also contain the same exclusions (e.g., heavy liquid service
PRDs, thermal expansion valves, liquid PRDs that are hard-piped to
controlled drains, PRD with release pressures of less than 2.5 psig,
PRD with emission potential of less than 72 lbs/day, and PRD on mobile
equipment). These provisions are similar to the applicability
provisions of the BAAQMD rule. Thus, we retain the same applicability
of the work practice standard for PRDs on new or existing equipment,
but all affected PRD on a new source would be required to be
controlled. This is essentially equivalent to the proposed requirement
of no atmospheric releases. We could not identify a control option more
stringent than the BAAQMD rule as applied to new sources. Therefore, we
conclude that venting all PRD in HAP service through a closed vent
system to a flare or similar control system is MACT for PRD associated
with new affected sources.
We consider it appropriate to establish a work practice standard
for PRD as provided in CAA section 112(h). While it may be possible to
design and construct a conveyance for PRD releases, we consider that
the application of a measurement methodology for PRDs is not
practicable due to technological and economic limitations. First, it is
not practicable to use a measurement methodology for PRD releases. The
venting time can be very short and may vary widely in composition and
flow rate. The often-short duration of an event makes it infeasible to
collect a grab sample of the gases when a release occurs, and a single
grab sample would not account for potential variation in vent gas
composition. It would be economically prohibitive to construct an
appropriate conveyance and install and operate continuous monitoring
systems for each individual PRD in order to attempt to quantitatively
measure a release event that may occur only a few times in a 3-year
period. Additionally, we have not identified an available, technically
feasible continuous emission monitoring systems that can determine a
mass VOC or HAP release quantity accurately given the flow, composition
and composition variability of potential PRD releases from refineries.
Consequently, we conclude that it is appropriate to establish a work
practice standard for PRD releases as provided in CAA section 112(h).

D. NESHAP Amendments Addressing Emissions During Periods of SSM

1. What amendments did we propose to address emissions during periods
of SSM?
We proposed to eliminate the SSM exemption in 40 CFR part 63,
subparts CC and UUU. Consistent with Sierra Club v. EPA, we proposed
standards in these rules that apply at all times. We also proposed
several revisions to Table 6 of subpart CC of 40 CFR part 63 and to
Table 44 to subpart UUU of 40 CFR part 63 (the General Provisions
Applicability tables for each subpart), including eliminating the
incorporation of the General Provisions' requirement that the source
develop an SSM plan, and eliminating and revising certain recordkeeping
and reporting requirements related to the SSM exemption.
For Refinery MACT 1, we proposed that the use of a bypass at any
time to divert a Group 1 miscellaneous process vent to the atmosphere
is a deviation of the emission standard, and specified that refiners
install, maintain and operate a continuous parameter monitoring system
(CPMS) for flow that is capable of recording the volume of gas that
bypasses the APCD.
We also proposed to revise the definition of MPV to remove the
exclusion for ``Episodic or non-routine releases such as those
associated with startup, shutdown, malfunction, maintenance,
depressuring and catalyst transfer operations.'' We also proposed that
the control requirements for Group 1 MPV apply at all times, including
startup and shutdowns.
For Refinery MACT 2, we proposed alternate standards for three
emission sources for periods of startup or shutdown. We proposed PM
standards for startup of FCCU controlled with an ESP under Refinery
MACT 2 because of safety concerns associated with operating an ESP
during an FCCU startup. For FCCU controlled by an ESP, we proposed a
30-percent opacity limit (on a 6-minute rolling average basis) during
the period that torch oil is used during FCCU startup. For startup of
FCCU without a post-combustion device under Refinery MACT 2, we
proposed a CO standard based on an excess oxygen concentration of 1
volume percent (dry basis) based on a 1-hour average. For periods of
SRU shutdown, we proposed to allow diverting the SRU purge gases to a
flare meeting the design and operating requirements in 40 CFR 63.670
(or, for a limited transitional time period, 40 CFR 63.11) or to a
thermal oxidizer operated at a minimum temperature of
1,200[emsp14][deg]F and a minimum outlet oxygen concentration of 2
volume percent (dry basis). For other emission sources in Refinery MACT
2, we proposed that the requirements that apply during normal
operations should apply during startup and shutdown.
2. How did the SSM provisions change since proposal?
a. Refinery MACT 1
We proposed that when process equipment is opened to the atmosphere
(e.g., for maintenance), the existing MPV emissions limits apply. In
this final rule, we are instead finalizing startup and shutdown
provisions that apply to these venting events. These startup and
shutdown provisions are work practice standards that allow refinery
owners or operators to open process equipment

[[Page 75219]]

during startup and shutdown provided that the equipment is drained and
purged to a closed system until the hydrocarbon content is less than or
equal to 10-percent of the LEL. For those situations where 10-percent
LEL cannot be demonstrated (no direct measurement location), the
equipment may be opened and vented to the atmosphere if the pressure is
less than or equal to 5 psig. Active purging of the equipment is only
allowed after the 10-percent LEL level is achieved, regardless of the
pressure of the equipment/vessel. We are establishing a separate
requirement for very small process equipment, defined as equipment
where it is physically impossible to release more than 72 lbs VOC per
equipment opening based on the size and contents of the equipment. This
definition is consistent with the Group 1 applicability cutoff for
control of miscellaneous process vents. We also developed requirements
specific to catalyst changeout activities where pyrophoric catalyst
(e.g., hydrotreater or hydrocracker catalysts) must be purged using
recovered hydrogen. These provisions include: Documenting the
procedures for equipment openings and procedures for verifying that
events meet the specific conditions above using site procedures used to
de-inventory equipment for safety purposes (i.e., hot work or vessel
entry procedures) and documenting any deviations from the work practice
standard requirements.
b. Refinery MACT 2
We are expanding the proposed 1-percent minimum oxygen operating
limit alternative for organic HAP to apply for all FCCU startup and
shutdown events (rather than only partial burn FCCU with CO boilers
during startup). We are replacing the proposed opacity limit
alternative to the metal HAP standard with a minimum cyclone face
velocity limit and we are extending that alternative limit to all FCCU
(regardless of control device) for both startup and shutdown in this
final rule.
We are extending the proposed alternative for SRU to monitor
incinerator temperature and excess oxygen limits during SRU shutdowns
to also apply during periods of startup.
3. What key comments did we receive on the SSM revisions and what are
our responses?
a. Refinery MACT 1
Comment: Many commenters stated that the proposed extension of the
MPV definition to episodic maintenance startup and shutdown vents and
elimination of the SSM exception for storage tanks would create
hundreds or thousands of new vents per refinery per year and generate
massive on-going burdens. The commenters argued that the EPA has not
included in the record any analysis of the potential environmental
benefits, costs or operational and compliance feasibility and impacts
associated with this requirement and that many of these requirements
will result in delayed and extended equipment and process outages. One
commenter asserted that the EPA has articulated no justification for
applying emission standards to these events, nor any analysis
consistent with CAA section 112 for a determination that MACT standards
are appropriately applied to these emission events under the criteria
in CAA section 112(d).
Many commenters stated that every time a vessel is opened for
inspection or maintenance each vent point will have to be evaluated as
a potential MPV or storage tank vent. If a particular vent point (e.g.,
bleeder) used for maintenance, startup or shutdown handles material
that is initially greater than 20 ppm HAP, then it is a MPV. If there
is a potential to emit greater than or equal 72 lbs/day of VOC, then it
is a Group 1 MPV and must be controlled. If there is a potential of
less than 72 lb/day VOC release, then it is a Group 2 MPV and subject
to recordkeeping requirements. Commenters stated that in a refinery
there would be tens or more such activities per day associated with
normal maintenance and inspection; during turnarounds, there could be
hundreds of such MPVs. Commenters added that these MPVs may then need
to be individually accounted for and permitted creating an unnecessary
permitting and recordkeeping burden for these periodic emissions.
Commenters recommended a general set of work practice requirements
for maintenance, startup and shutdown of vents, based on state
requirements, that do not impose the permitting, notice and evaluation
requirements associated with identifying these vents individually.
Commenters explained that states have dealt with these episodic vents
by establishing them as a special class of process vent with limited
recordkeeping requirements and subject to a work practice standard,
rather than the normal MPV requirements. A key element of these work
practices is clear identification of the criteria for releasing these
vents to the atmosphere and for routing these vents to control after
hydrocarbon is reintroduced, which the commenters asserted the current
rule does not provide. Commenters proposed that a work practice
standard could include removing process liquids to the extent practical
and depressuring smaller volume equipment until a pressure of <5 psig
is achieved and/or purging and depressuring to a control device until
the vent has a hydrocarbon concentration of less than 10-percent of the
LEL. The commenters suggested that these standards should provide clear
easily monitored criteria for when this equipment can be vented to the
atmosphere, and should not impose the permitting, notice and evaluation
requirements associated with identifying these vents as individual
MPVs. One commenter provided draft regulatory language for a work
practice requirement.
Response: We proposed to eliminate the episodic and non-routine
emission exclusion in order to ensure that the MACT includes emission
limits that apply at all times consistent with the holding in Sierra
Club. At the time of the proposal, we expected that essentially all SSM
event emissions would be routed to flares that are subject to the MACT
standards and, thus, would serve to control these emissions. However,
we recognize that maintenance activities that require equipment
openings are a separate class of startup/shutdown emissions because
there must be a point in time when the vessel can be opened and any
emissions vented to the atmosphere. We acknowledge that it would
require a significant effort to identify and characterize each of these
potential release points for permitting purposes.
In considering these comments and whether we should establish a
separate limit that would apply to these equipment openings, we
reviewed state permit requirements and the practices employed by the
best performing sources. We found that some state or local agencies
required depressuring to 5 psig prior to atmospheric releases while
others required the gases to have organic concentrations at or below
10-percent of LEL prior to atmospheric venting. In the final rule, we
are establishing a requirement that prior to opening process equipment
to the atmosphere, the equipment must first be drained and purged to a
closed system so that the hydrocarbon content is less than or equal to
10-percent of the LEL. For those situations where 10-percent LEL cannot
be demonstrated, the equipment may be opened and vented to the
atmosphere if the pressure is less than or equal to 5 psig, provided
there is no active purging of the equipment to the atmosphere until the
LEL criterion is met. For equipment where it is not technically
possible to depressurize to a

[[Page 75220]]

control system, we allow venting to the atmosphere where there is no
more than 72 lbs VOC per day potential, consistent with our Group 1
applicability cutoff for control of process vents. For catalyst
changeout activities where hydrotreater pyrophoric catalyst must be
purged we have provided limited allowances for direct venting.
Provisions to demonstrate compliance with this work practice include
documenting the procedures for equipment openings and procedures for
verifying that events meet the specific conditions above using site
procedures used to de-inventory equipment for safety purposes (i.e.,
hot work or vessel entry procedures).
b. Refinery MACT 2
Comment: Several commenters noted that there was a proposed
specific alternative metal HAP/PM standard for startup of an FCCU
controlled with an ESP, but took issue with the fact that no
alternative PM limits were proposed for startup of FCCU equipped with
other types of PM controls, or for any FCCU during periods of shutdown
or hot standby. Regarding the proposed alternative for startup, which
would provide an alternative in the form of an opacity limit when torch
oil is in use, commenters stated that there are serious process safety
concerns which prevent most FCCU ESPs from being operated when torch
oil is in the regenerator, that is, during periods of startup, shutdown
and hot standby. To avoid the possibility of a fire and explosion, the
commenters claimed ESPs are usually de-energized and bypassed during
these periods and, consequently, these FCCUs are generally unable to
meet the proposed 30-percent opacity limit.
Several commenters stated that the EPA's limits on FCCU opacity
during SSM are unreasonable and ignore the technical requirements for
transitional operations of those units. The commenters indicated that
they have ESPs located downstream of the CO boiler and claimed that for
safety reasons the CO boiler cannot operate during startup, shutdown or
hot standby. Further, a commenter indicated that the ESP cannot operate
if the CO boiler is not operating and thus both the CO boiler and the
ESP must be bypassed during startup, shutdown, and hot standby
operations.
Another commenter stated that the EPA offers no data to support the
achievability of this requirement in practice and discusses information
for 26 startup/shutdown events that found that none complied with a 30-
percent opacity requirement. Several commenters also noted that
experience has shown that the 30-percent opacity limit is unachievable
during these periods for FCCUs controlled with tertiary cyclones, when
regenerator gas flow is below cyclone minimum design flow.
Several commenters suggested that the EPA establish a standard
based on the operation of FCCU catalyst regenerators' internal cyclones
that function to retain the catalyst in the regenerators and thereby
minimize catalyst and metal HAP emissions from the regenerators.
Additional control to meet the Refinery MACT 2 emission limit of not
more than 1.0 lb PM/1,000 lbs coke burn-off is provided by a bag house,
wet gas scrubber (WGS), ESP or tertiary (external) cyclone. The
efficiency of a cyclone is a function of the inlet gas velocity.
Assuring adequate velocity to the internal cyclones ensures that the
catalyst sent to these additional controls is minimized and ensures
that they are operating as effectively as possible. Similarly, even if
the FCCU cannot meet the normal opacity limits during startup, shutdown
or hot standby (e.g. due to the ESP being off-line for safety reasons
or the tertiary cyclones or WGS operating at non-routine conditions),
assuring adequate velocity to the internal regenerator cyclones will
control and minimize particulate emissions. Several commenters stated
support for another commenter's position that all FCCUs should be
allowed the option of complying with a 20 feet/second minimum inlet
velocity to the primary regenerator cyclones during periods of startup
and shutdown, including hot standby, and these commenters provided
additional technical explanations in their comments.
On the other hand, some commenters seemed to support the proposed
opacity limits, but suggested minor revisions. One commenter noted that
the SCAQMD has granted Valero's request for variances from visible
emission standards during startup of the FCCU of up to 65-percent
opacity for up to five minutes, in aggregate, during any 1-hour period,
and 30-percent as an hourly average for the remaining period, during
startup events. The application of this variance reflects the
unavailability and/or ineffectiveness of the ESP during the startup
condition. Another commenter recommended that either the opacity
standard should be raised or the time period for averaging should be
extended so FCCUs can be operated safely during SSM events and still
remain in compliance.
Response: We have reviewed the data submitted by the commenters to
support their assertion that the 30-percent opacity limit (determined
on a 6-minute average basis) is not achievable during startup and
shutdown events. While the data are limited, and it is unclear if the
data provided are indicative of the performance achieved by the best
performing sources, we do not have adequate data to refute the
assertion that the 30-percent opacity limit (determined on a 6-minute
average basis) is not achievable during startup and shutdown events. We
considered the two options suggested by the commenters, the minimum
velocity for the internal FCCU regenerator cyclones and the 30-percent
hourly average opacity limit excluding 5 minutes not exceeding 65-
percent opacity. Again, due to the limited data available during
startup and shutdown events, we are not able to determine which
requirement would provide greater HAP emissions reduction. However, we
note that some facilities may not be required to have an opacity
monitoring system in place and opacity monitoring is not applicable for
FCCU controlled with wet scrubbers. Therefore, we find that the minimum
internal cyclone inlet velocity requirement is more broadly applicable
than the opacity limit. Also, based on the data provided by the
commenters, the minimum internal cyclone inlet velocity requirement
will provide PM (and therefore metal HAP) emissions reductions during
startup and shutdown periods. Therefore, considering the available
data, we conclude that MACT for FCCU startup and shutdown events is
maintaining the minimum internal cyclone inlet velocity of 20 feet/
second.
Comment: Several commenters stated that the EPA should provide
alternate standards for startups of FCCU equipped with CO boilers and
for any FCCU during periods of shutdown and hot standby. The commenters
stated that the EPA incorrectly assumes that refiners are able to
safely and reliably start up their FCCU with flue gas boilers in
service and meet the normal operating limit of 500 ppm CO. They claimed
that most refiners are unable to reliably start up their FCCU with flue
gas boilers in service due to the design of the boiler and the fact
that many boilers are not able to safely and reliably handle the
transient FCCU operations that can occur during startup, shutdown, and
hot standby. One commenter stated that FCCU built with CO boilers
experience issues with flame stability due to fluctuating flue gas
compositions and rates when starting up and shutting down. Accordingly,
the commenter stated, startup and shutdown activities at FCCU using a
boiler as an APCD are not currently meeting the Refinery MACT 2
standard

[[Page 75221]]

of 500 ppm CO on a 1-hour basis, and this level of control does not
qualify as the MACT floor. The commenter gave examples of facilities
where FCCU, including those equipped with post-combustion control
systems, do not consistently demonstrate compliance with a 500 ppm CO
concentration standard during all startup and shutdown events.
Commenters stated that reliable boiler operation is critical to the
overall refinery steam system and refineries must avoid jeopardizing
boiler operation to prevent major upsets of process operations. A major
upset or site-wide shutdown could result in flaring and emissions of
HAP far in excess of that emitted while bypassing the CO boiler.
Commenters stated that combustion of torch oil in the FCCU
regenerator during startup is one of the primary reasons the CO limit
cannot be met during these operations. Torch oil is also used during
shutdown to control the cooling rate (and potential equipment damage)
and during hot standby and, thus, the normal CO standard cannot be met
at these times either. Hot standby is used to hold an FCCU regenerator
at operating temperature for outages where a regenerator shutdown is
not needed and to avoid full FCCU shutdowns. Full cold shutdown also
increases personnel exposures associated with removing catalyst and
securing equipment. Additionally, this can produce additional emissions
over maintaining the unit in hot standby. Commenters claimed that
because of the variability of CO during torch oil operations, it is not
possible for the EPA to establish a CAA section 112(d) standard for
startup and shutdown activities at FCCU because refineries cannot
measure a constant level of emissions reductions.
The commenters recommended expansion of the proposed standard of
greater than 1-percent hourly average excess regenerator oxygen to all
FCCU, including units with fired boilers. These commenters suggested
that maintaining an adequate level of excess oxygen for the combustion
of fuel in the regenerator is the best way to minimize CO and organic
HAP emissions from FCCU during these periods.
Response: After reviewing the comments and discussing CO boiler
operations with facility operators, we agree that the 1-percent minimum
oxygen limit should be more broadly applicable to FCCU startup and
shutdown regardless of the control device configuration and have
revised the final rule accordingly.
Comment: Several commenters stated that the proposed alternative
standards for SRP shutdowns should be extended to startups as well
since the normal SRP emission limitation cannot always be achieved
during SRP startups. Several commenters gave examples of startup
activities where this relief is needed, and noted there may be other
startup activities that also need this relief.
Response: For the control of sulfur HAP, we determined that
incineration effectively controls these HAP. We were not aware that
there would be unusual sulfur loads in the SRU tail gas during startup.
We agree that the alternative standard we proposed for periods of
shutdown is also the MACT floor for periods of startup because
incineration meeting the limits proposed will achieve the MACT control
requirements for sulfur HAP during periods of either startup or
shutdown even though sulfur loadings during these periods may be
elevated. For many SRU configurations, compliance during normal
operations is demonstrated by monitoring SO2 emissions.
However, during startup and shutdown, high sulfur loadings in the SRU
tail gas entering the incinerator will cause high SO2
emissions even though sulfur HAP emissions are well controlled.
Consequently, the proposed incinerator operating limits provide a
better indication of sulfur HAP control during startup and shutdown
than SO2 emissions. Owners or operators that use
incinerators or thermal oxidizers during normal operations may meet the
site-specific temperature and excess oxygen operating limits that were
determined based on their performance test during periods of startup
and shutdown.
4. What is the rationale for our final approach and final decisions to
address emissions during periods of SSM?
a. Refinery MACT 1
We did not receive comments regarding the proposed amendments to
Table 6 of subpart CC of 40 CFR part 63; therefore, for the reasons
provided in the preamble to the proposed rule, we finalizing these
amendments as proposed.
We determined that it was overly burdensome and in most cases
technically infeasible to consider every potential equipment or vessel
opening and classify these ``openings'' (newly classified as MPV in the
proposal) as either Group 1 or Group 2 MPV. We also determined that it
is not always technically feasible, depending on the opening, to
demonstrate compliance with the MPV emissions limitations. After
considering the public comments, we determined it was appropriate to
establish separate startup and shutdown provisions for MPV associated
with process equipment openings. We reviewed state and local
requirements and based the final rule requirements on the emissions
limitations required to be followed by the best performing sources.
Therefore, we are finalizing requirements for refinery owners or
operators to open process equipment during these startup and shutdown
events without directly permitting these ``vents'' as Group 1 or Group
2 MPV provided that the equipment is drained and purged to a closed
system until the hydrocarbon content is less than or equal to 10-
percent of the LEL. As described in further detail previously in this
section, we have provided provisions for special cases where the 10-
percent LEL limit cannot be demonstrated and provisions for less
significant equipment openings, consistent with the practices used by
the best performing facilities.
b. Refinery MACT 2
We did not receive significant comments regarding the proposed
amendments to Table 44 to subpart UUU of 40 CFR part 63; therefore, we
finalizing these amendments as proposed.
In response to comments, we determined that the limited provisions
that were provided for startup only or for shutdown only were too
limited and we have expanded the proposed provisions to both startup
and shutdown regardless of control device used. For the FCCU organic
HAP emissions limit, we are finalizing an alternative limit for periods
of startup of no less than 1-percent oxygen in the exhaust gas as
proposed, but we are extending that alternative limit to shutdown and
to all FCCU in this final rule.
For the FCCU metal HAP emissions limit, we proposed a specific
startup limit for FCCU controlled be an ESP of 30-percent opacity. We
received comments along with limited data suggesting that this limit
was not achievable. Commenters suggested that the best performing units
maintain a minimum face velocity of at least 20 feet/second to minimize
catalyst PM losses during startup and shutdowns. Operators of wet
scrubbers also noted that they cannot maintain pressure drops and that
one cannot meet the PM emissions limit normalized by coke burn-off rate
when the coke burn-off rate approaches zero. Consequently, commenters
stated that the alternative limits should be provided for startup and
shutdown regardless of control device. Upon consideration of the
comments, we determined that it was necessary to revise the proposed

[[Page 75222]]

alternative to be based on minimum inlet face velocity to the FCCU
regenerator internal cyclones and provide the alternative for both
startup and shutdown. We also expanded this limit to all FCCU; however,
we also required FCCU with wet scrubbers to meet only the liquid to gas
ratio operating limit during periods of startup and shutdown to allow
wet scrubbers to use a consistent compliance method at all times.
For SRU, we are finalizing an alternative standard during periods
of startup and shutdown to use a flare that meets the operating limits
included in the final rule or a thermal oxidizer or incinerator
operated at a minimum hourly average temperature of 1,200 [deg]F and a
minimum hourly average outlet oxygen concentration of 2 volume percent
(dry basis). We proposed these alternatives for periods of shutdown
only, but based on comments received regarding startup issues, we
determined that high sulfur loadings can occur during periods of
startup and that the alternative limit proposed was appropriate for
both startup and shutdown.

E. Technical Amendments to Refinery MACT 1 and 2

1. What other amendments did we propose for Refinery MACT 1 and 2?
We proposed a number of amendments to Refinery MACT 1 and 2 to
address technical issues such as rule language clarifications and
reference corrections. First, we proposed to amend Refinery MACT 1 to
clarify what is meant by ``seal'' for open-ended valves and lines that
are ``sealed'' by the cap, blind flange, plug, or second valve by
stating that sealed means when there are no detectable emissions from
the open-ended valve or line at or above an instrument reading of 500
ppm. Second, we also proposed electronic reporting requirements where
owners or operators of petroleum refineries must submit electronic
copies of required performance test and performance evaluation reports
for compliance with Refinery MACT 1 and 2 by direct computer-to-
computer electronic transfer using EPA-provided software. Third, we
proposed to update the General Provisions Tables 6 (for Refinery MACT
1) and 44 (for Refinery MACT 2) to correct cross references and to
incorporate additional sections of the General Provisions that are
necessary to implement these rules.
2. How did the other amendments for Refinery MACT 1 and 2 change since
proposal?
We are not finalizing the definition of ``seal'' for open-ended
lines as proposed. We are finalizing changes to update the General
Provisions cross-reference tables as proposed, with one minor change to
provide an option for the administrator to issue guidance on
performance test reporting timeframes in order to address issues
relating to submittal of data to the ERT.
3. What key comments did we receive on the other amendments for
Refinery MACT 1 and 2 and what are our responses?
Comment: Numerous commenters objected to the proposal to clarify
the meaning of ``seal'' as it relates to open-ended line (OEL)
standards. Commenters contend that there is no basis for the EPA to
assert that the proposed definition merely ``clarifies'' an established
interpretation of the term ``seal'' and stated that the proposed
revision constitutes an illegal change in the requirements for OELs,
and the clarification should not be finalized.
One commenter stated that none of the MACT standards in place
before this proposal have stated or suggested that a ``sealed'' OEL is
one with detectable emissions below 500 ppm. This commenter added this
unique interpretation of the requirement to ``seal'' an OEL with a cap
or plug is incompatible with the historical interpretation of this
requirement by affected facilities and by the EPA, and the EPA has not
issued any sort of definitive guidance or interpretation setting out
this position. The commenter detailed numerous references to
considerations the EPA has made relative to OEL requirements in LDAR
programs. In addition to the examples cited, the commenter noted that
in 2006, the EPA proposed to add a ``no detectible emissions'' limit
and monitoring requirement for OELs to NSPS VV (71 FR 65317, November
7, 2006). Two commenters noted that the proposed monitoring was not
finalized in either NSPS VV or VVa (72 FR 64860, November 16, 2007)
because it was not considered BDT due to the low emission reductions
and the cost effectiveness of the requirement. Another commenter agreed
that there is no explanation provided for why this information could
now support the need for a new OEL seal standard that requires
monitoring to ensure compliance when it was deemed to be unjustified
previously.
In addition, the commenter collected OEL monitoring data and
submitted it to the EPA (see Docket Item No. EPA-HQ-OAR-2010-0869-
0058). Based on these data, the commenter asserted that the existence
of leaks from OELs that are not properly sealed is extremely low.
The commenter noted that the EPA is claiming this change is only a
clarification of current requirements, allowing the EPA to bypass the
need to cite a CAA authorization for this change to the existing CAA
section 112(d)(2) standard or meet the process requirements associated
with such a change, including providing emission reduction, cost and
burden estimates in the record and the associated PRA Information
Collection Request (ICR).
Several commenters claimed that this clarification would result in
retroactive impact and also addressed the implication of the proposed
change on other fugitive emissions standards. One commenter stated that
the EPA cannot retroactively reinterpret the OEL requirements or define
the word ``seal'' and added that the EPA should account for the
thousands of additional monitoring events per year per refinery that
this new requirement would add to LDAR programs and provide proper cost
justification under CAA sections 112(d)(6) or 112(f)(2).
Several commenters also stated that the proposed definition will
effectively change all equipment leak rules in parts 40 CFR parts 60,
61 and 63 and the change should not be finalized. One commenter added
that by claiming this change is only a clarification of current
requirements, the EPA would set a precedent applicable to all OELs in
all industries subject to any similar OEL equipment leak requirement.
Response: We have decided not to finalize the proposed
clarification of the term ``seal'' for OELs at this time. The fenceline
monitoring requirements we are finalizing will detect any significant
leaks from a cap, blind flange, plug or second valve that does not
properly seal an OEL, as well as significant leaks from numerous other
types of fugitive emission sources.
Comment: A few commenters stated that the proposed use of the ERT
is not appropriate because the costs and burdens imposed are additive
to the costs of producing and submitting the written report, and there
is no benefit that justifies the additional cost. One commenter also
stated that the EPA has not developed or articulated a reasonable
approach to using information that would be uploaded to the ERT. The
commenters recommended that the EPA remove this portion of the proposal
until the ERT is demonstrated to handle all the information from
refinery performance

[[Page 75223]]

tests (rather than only portions), thereby eliminating the need for
both written and electronic reporting and until the Agency demonstrates
that it is using the electronic data to develop improved air quality
emission factors.
Other commenters stated that the ERT requirement does not supersede
or replace any state reporting requirements and thus the regulated
industry will be subject to dual reporting requirements. These
commenters disagreed with the preamble claim that eliminating the
recordkeeping requirements for performance test reports is a burden
savings, and stated that it may duplicate burdens already borne by the
regulated community.
The commenters expressed further concern that duplicative reporting
requirements will strain the regulated industry to comply with
deadlines established by rule for report submittals. One commenter
stated that there is no mechanism for obtaining extensions for special
circumstances. Under proposed 40 CFR 63.655(h)(9)(i), all reports are
due in 60 days. The commenter claimed that by not referencing reporting
requirements to the General Provisions in 40 CFR 63.10(d)(2), there is
no allowance for obtaining additional time due to unforeseen
circumstances or due to the difficulties involved with completing
particularly complex reports.
One commenter stated that the primary performance test method
(Method 18) required for determining compliance is not currently
included in the list of methods supported by the ERT. The commenter
stated that the regulated community's experience with Method 18 is that
it is a very broad methodology and can be exceptionally complex to
execute and to report. The commenter stated that the EPA is aware that
Method 18 reporting is complex, that it may be difficult to incorporate
into the ERT, and that no time schedule has been defined for
development or implementation for this method.
The commenter also stated that without formal notice of changes to
the ERT, the regulated community is at risk of non-compliance. The only
way for the regulated community to know that changes have occurred in
the ERT is to monitor the Web site directly because the EPA does not
formally announce changes to the ERT in the Federal Register. As such,
it would be possible for a regulated entity to be unaware of changes
made such as the incorporation of Method 18. The commenter expressed
concern that the proposal language is an open-ended commitment subject
to change without notice. The commenter stated that the EPA should
clearly indicate when facilities would be required to use the ERT when
new test methods are included in the ERT.
Response: We disagree that use of the ERT for completing stack test
reports is an added cost and burden. While the requirement to report
the results of stack tests with the ERT does not supersede state
reporting requirements, we are aware of several states that already
require the use of the ERT, and we are aware of more states that are
considering requiring its use. We note that where states will not
accept an electronic ERT submittal, the ERT provides an option to print
the report, and the printed report can be mailed to the state agency.
We have no reason to believe that the time savings in the ability to
reuse data elements within reports does not, at a minimum, offset the
cost incurred by printing out and mailing a copy of the report and the
commenters have provided no support for their cost claims.
Furthermore, based on the analysis performed for the Electronic
Reporting and Recordkeeping Requirements for the New Source Performance
Standards Rulemaking (ERRRNSPS) (80 FR 15100), electronic reporting
results in an overall cost savings to industry when annualized over a
20-year period. The cost savings is achieved through means such as
standardization of data, embedded quality assurance checks, automatic
calculation routines and reduced data entry through the ability to
reuse data in files instead of starting from scratch with each test. As
outlined in the ERRRNSPS, there are many benefits to electronic
reporting. These benefits span all users of the data--the EPA, state
and local regulators, the regulated entities and the public. We note
that in the preamble to this proposed rule we provided a number of
reasons why the use of the ERT will provide benefit going forward and
that most of the benefits we outlined were longer-term benefits (e.g.,
reducing burden of future information collection requests).
Additionally, we note that in 2011, in response to Executive Order
13563, the EPA developed a plan \13\ to periodically review its
regulations to determine if they should be modified, streamlined,
expanded or repealed in an effort to make regulations more effective
and less burdensome. The plan includes replacing outdated paper
reporting with electronic reporting. In keeping with this plan and the
White House's Digital Government Strategy, \14\ in 2013 the EPA issued
an agency-wide policy specifying that new regulations will require
reports to be electronic to the maximum extent possible. By requiring
electronic submission of stack test reports in this rule, we are taking
steps to implement this policy. We also disagree that we have not
developed or articulated a reasonable approach to using information
that would be uploaded to the ERT. To the contrary, we have discussed
at length our plans for the use of stack test data collected via the
ERT. In 2009, we published an advanced notice of proposed rulemaking
(74 FR 52723) for the Emissions Factors Program Improvements. In that
notice, we first outlined our intended approach for revising our
emissions factors development procedures. This approach included using
stack test data collected with the ERT. We reiterated this position in
our ``Recommended Procedures for the Development of Emissions Factors
and Use of the WebFIRE Database'' (https://www.epa.gov/ttn/chief/efpac/procedures/procedures81213.pdf), which was subject to public notice and
comment before being finalized in 2013. Finally, we discussed uses of
these data in the preamble to the proposed rule and at length in the
preamble to the ERRRNSPS.
---------------------------------------------------------------------------

\13\ EPA's ``Final Plan for Periodic Retrospective Reviews,''
August 2011. Available at: https://www.epa.gov/regdarrt/retrospective/documents/eparetroreviewplan-aug2011.pdf.
\14\ Digital Government: Building a 21st Century Platform to
Better Serve the American People, May 2012. Available at: https://www.whitehouse.gov/sites/default/files/omb/egov/digital-government/digital-government-strategy.pdf.
---------------------------------------------------------------------------

We think that it is a circular argument to say that the agency
should eliminate the use of the ERT until it demonstrates that it is
using the electronic data. It would be impossible for the agency to use
data that it does not have. We can only use electronic data once we
have electronic data. We do note that we are nearing completion of
programming the WebFIRE database with our new emissions factor
development procedures and anticipate running the routines on existing
data sets in the near future.
We continue to improve and upgrade the ERT on an ongoing basis. The
current version of the ERT supports 41 methods, including EPA Methods
1-4, 5, 5B, 5F, 25A 26, and 26A. We note that the ERT does not
currently support EPA Method 18, and for performance tests using Method
18, the source will still have to produce a paper report. However, we
are aware of the need to add Method 18 to the ERT, and we are currently
looking at developing this capability. As noted in the ERRRNSPS, when
new methods are added to the

[[Page 75224]]

ERT, we will not only post them to the Web site; we will also send out
a listserv notice to the Clearinghouse for Inventories and Emissions
Factors (CHIEF) listserv. Information on joining the CHIEF listserv can
be found at https://www.epa.gov/ttn/chief/listserv.html#chief. We are
requiring the use of the ERT if the method is supported by the ERT, as
listed on the ERT Web site (https://www.epa.gov/ttn/chief/ert/ert_info.html) at the time of the test. We do not agree that it is
overly burdensome to check a Web site for updates prior to conducting a
performance test.
We did revise the MACT 1 and 2 tables referencing reporting
requirements to the general provisions (Table 6 for Refinery MACT 1 and
Table 44 for Refinery MACT 2) to provide flexibility in the 60-day
reporting timeline to accommodate unforeseen circumstances or
difficulties involved with completing particularly complex reports.
4. What is the rationale for our final approach and final decisions for
the other amendments for Refinery MACT 1 and 2?
We are not finalizing the definition of seal, as proposed. The
fenceline monitoring work practice standard will detect any significant
leaks from a cap, blind flange, plug or second valve that does not
properly seal an OEL, as well as significant leaks from numerous other
types of fugitive emission sources.
We are finalizing requirements for electronic reporting, as
proposed, with a minor clarification. Specifically, we are revising
Tables 6 in subpart CC and 44 in subpart UUU, which cross-reference the
applicable provisions in the General Provisions to provide flexibility
in the ERT 60-day reporting timeline. Refiners can seek approval from
the EPA or a delegated state additional time for submittal of data due
to unforeseen circumstances or due to the difficulties involved with
completing particularly complex reports.

F. Technical Amendments to Refinery NSPS Subparts J and Ja

1. What amendments did we propose for Refinery NSPS Subparts J and Ja?
We proposed a number of amendments to Refinery NSPS subparts J and
Ja to address reconsideration issues and minor technical
clarifications. First, we proposed revisions to 40 CFR 60.100a(b) to
include a provision that sources subject to Refinery NSPS subpart J
could elect to comply instead with the provisions of Refinery NSPS
subpart Ja.
Second, we proposed a series of amendments to the requirements for
SRP in 40 CFR 60.102a, to clarify the applicable emission limits for
different types of SRP based on whether oxygen enrichment is used. The
amendments proposed also clarified that emissions averaging across a
group of emission points within a given SRP is allowed for each of the
different types of SRP, and that emissions averaging is specific to the
SO2 or reduced sulfur standards (and not to the 10 ppmv
hydrogen sulfide (H2S) limit). We also proposed a series of
corresponding amendments in 40 CFR 60.106a to clarify the monitoring
requirements, particularly when oxygen enrichment or emissions
averaging is used. We also proposed clarifications in 40 CFR 60.106a to
consistently use the term ``reduced sulfur compounds'' when referring
to the emission limits and monitoring devices needed to comply with the
reduced sulfur compound emission limits for sulfur recovery plants with
reduction control systems not followed by incineration.
Third, we proposed amendments to 40 CFR 60.102a(g)(1) to clarify
that CO boilers, while part of the FCCU affected facility, can also be
FGCD.
Fourth, we proposed several revisions to 40 CFR 60.104a to clarify
the performance testing requirements. We proposed revision to 40 CFR
60.104a(a) to clarify that an initial compliance demonstration is
needed for the H2S concentration limit in 40 CFR 60.103a(h).
We proposed revisions to the annual PM testing requirement in 40 CFR
60.104a(b) to clarify that annually means once per calendar year, with
an interval of at least 8 months but no more than 16 months between
annual tests. We also proposed to amend 40 CFR 60.104a(f) to clarify
that the provisions of that paragraph are specific to owners or
operators of an FCCU or FCU that use a cyclone to comply with the PM
emissions limit in 40 CFR 60.102a(b)(1) and not to facilities electing
to comply with the PM emissions limit using a PM CEMS. We also proposed
to amend 40 CFR 60.104a(j) to delete the requirements to measure flow
for the H2S concentration limit for fuel gas.
Fifth, we proposed several amendments to clarify the requirements
for control device operating parameters in 40 CFR 60.105a.
Specifically, we proposed amendments to 40 CFR 60.105a(b)(1)(ii)(A) to
require corrective action be completed to repair faulty (leaking or
plugged) air or water lines within 12 hours of identification of an
abnormal pressure reading during the daily checks. We also proposed
revisions to 40 CFR 60.105a(i) to specify that periods when abnormal
pressure readings for a jet ejector-type wet scrubber (or other type of
wet scrubber equipped with atomizing spray nozzles) are not corrected
within 12 hours of identification and periods when a bag leak detection
system alarm (for a fabric filter) is not alleviated within the time
period specified in the rule are considered to be periods of excess
emissions.
We also proposed amendments to 40 CFR 60.105(b)(1)(iv) and
60.107a(b)(1)(iv) to provide flexibility in span range to accommodate
different manufacturers of the length-of-stain tubes. We also proposed
to delete the last sentence in 40 CFR 60.105(b)(3)(iii).
Finally, we proposed clarification to the performance test
requirements for the H2S concentration limit for affected
flares in 40 CFR 60.107a(e)(1)(ii) and (e)(2)(ii) to remove the
distinction between flares with or without routine flow.
2. How did the amendments to Refinery NSPS Subparts J and Ja change
since proposal?
We are making very few changes to the amendments proposed for
Refinery NSPS subparts J and Ja. In response to comments, we are
revising the NSPS requirements to replace the ``measurement
sensitivity'' requirements with accuracy requirements consistent with
those used in Refinery MACT 1 and 2. Specifically, we are revising 40
CFR 60.106a(a)(6)(i)(B) and (7)(i)(B) to require use of a flow sensor
meeting an accuracy requirement of 5-percent over the
normal range of flow measured or 10-cubic-feet-per-minute, whichever is
greater. We are also revising the flare accuracy requirements in 40 CFR
60.107a(f)(1)(ii) to require use of a flow sensor meeting an accuracy
requirement of 20-percent of the flow rate at velocities
ranging from 0.1 to 1 feet per second and an accuracy of 5-
percent of the flow rate for velocities greater than 1-feet-per-second.
Finally, we are revising 40 CFR 60.101a(b) to correct an
inadvertent error where the phrase ``and delayed coking units'' was not
included in the proposed sentence revision.
3. What key comments did we receive on the amendments to Refinery NSPS
Subparts J and Ja and what are our responses?
Comment: Two commenters noted concern with the term ``measurement
sensitivity'' in proposed 40 CFR 60.106a(a)(6)(i)(B) and (a)(7)(i)(B)
for sulfur recovery unit monitoring alternatives and in existing
regulations 40 CFR 60.107a(f)(1)(ii) for flares because ``sensitivity''
is not a term

[[Page 75225]]

found on typical monitoring system data sheets. Typical flow meter
characteristics include terms such as accuracy and resolution and the
commenters requested that the EPA revise the terminology to match the
wording found in 40 CFR part 63, subpart CC, Table 13 for flow meters
(i.e., accuracy requirements). Additionally, several commenters
suggested that the EPA flow monitor accuracy specifications are
inconsistent with those in the SCAQMD Flare Rule and many refinery
consent decrees. The commenters recommended revising both the flare
flow meter sensitivity specification and accuracy specification in
Refinery MACT 1 Table 13 and in Refinery NSPS subpart Ja to be
consistent with the accuracy specification from the Shell Deer Park
Consent Decree, Appendix 1.10, which specifies the required flare flow
meter accuracy as ``20% of reading over the velocity range
of 0.1-1 feet per second (ft/s) and 5% of reading over the
velocity range of 1-250 ft/s.''
Response: We proposed the term ``measurement sensitivity'' in
proposed 40 CFR 60.106a(a)(6)(i)(B) and (a)(7)(i)(B) to be internally
consistent within Refinery NSPS subpart Ja [i.e., consistent with the
existing language in Sec. 60.107a(f)(1)(ii)]. However, we agree with
the commenters that this term may be unclear. This term is not defined
in Refinery NSPS subpart Ja and it is not commonly used in the flow
monitoring system's technical specification sheets. Therefore, to be
consistent with the terminology used by instrument vendors and used in
Refinery MACT 1 and 2, we are revising these sections to replace the
term ``measurement sensitivity'' with ``accuracy.'' We are also
revising the flow rate accuracy provisions specific for flares to
provide an accuracy requirement of 20-percent over the
velocity range of 0.1-1 ft/s and 5% for velocities
exceeding 1 ft/s in 40 CFR 60.107a(f)(1)(ii) and in Table 13 of subpart
CC. We are providing this provision specifically for flares because
they commonly operate at high turndown ratios. For other flow
measurements, we are retaining the 10-cubic-foot-per-minute accuracy
requirement. We are also clarifying that the 5-percent
accuracy requirement for the SRU alternatives apply to the ``the normal
range of flow measured'' consistent with the requirements in Refinery
MACT 1 and 2.
Comment: One commenter stated that in the proposed revisions to 40
CFR 60.100a, (79 FR 36956), the EPA proposes to remove the phrase ``and
delayed coker units'' from 40 CFR 60.100a(b). However, we state the
compliance date for both flares and delayed coker units separately in
the same paragraph. The commenter believes the EPA should explain the
reason for and implications of the removal of this phrase.
Response: The removal of the phrase ``and delayed coking units''
from the first sentence in 40 CFR 60.100a(b) was an inadvertent error.
The only revision that we intended to make in 40 CFR 60.100a was to
allow owners or operators subject to subpart J to elect to comply with
the requirements in subpart Ja. In the final amendments, we have
included the phrase ``and delayed coking units'' in the first sentence
in 40 CFR 60.100a(b).
4. What is the rationale for our final approach and final decisions for
the amendments to Refinery NSPS Subparts J and Ja?
We are finalizing amendments for Refinery NSPS subparts J and Ja as
proposed with minor revisions. In response to comments, we are revising
the ``measurement sensitivity'' requirements to be an ``accuracy''
requirement. This change will make the requirements more clear and
consistent between the flow meter requirements in the NSPS and the MACT
standards since the same flow meter will be subject to each of these
requirements. We are also providing a dual accuracy requirement for
flare flow meters. This accuracy requirement is necessary because
flares, which can have large diameters to accommodate high flows, are
commonly operated at low flow rates. Together, this makes it
technically infeasible for many flares to meet the lower flow 10 cfm
accuracy requirement. Therefore, we are providing specific accuracy
requirements for flares of 20-percent over the velocity
range of 0.1-1 ft/s and 5-percent for velocities exceeding
1 ft/s, consistent with recent consent decrees and equipment vendor
specifications.
Finally, we are revising the introductory phrase in the first
sentence in 40 CFR 60.101a(b) to read ``Except for flares and delayed
coking units . . .'' to correct an inadvertent error. We intended to
revise this sentence only to include the proposed provision to allow
sources subject to Refinery NSPS subpart J to comply with Refinery NSPS
subpart Ja. The redline text posted on our Web site showed no revisions
to this introductory phrase, but the amendatory text did not include
the words ``and delayed coking units'' in this phrase. This was an
inadvertent error, which we are correcting in the final rule.

V. Summary of Cost, Environmental and Economic Impacts and Additional
Analyses Conducted

A. What are the affected facilities, the air quality impacts and cost
impacts?

The sources affected by significant amendments to the petroleum
refinery standards include flares, storage vessels, pressure relief
devices, fugitive emissions and DCU. The amendments for other sources
subject to one or more of the petroleum refinery standards are expected
to have minimal air quality and cost impacts.
The total capital investment cost of the final amendments and
standards is estimated at $283 million, $112 million from the final
amendments for storage vessels, DCU and fenceline monitoring and $171
million from standards to ensure compliance. We estimate annualized
costs of the final amendments for storage vessels, DCU and fenceline
monitoring to be approximately $13.0 million, which includes an
estimated $11.0 million for recovery of lost product and the annualized
cost of capital. We also estimated annualized costs of the final
standards to ensure compliance to be approximately $50.2 million. The
final amendments for storage vessels, DCU and fenceline monitoring
would achieve a nationwide HAP emission reduction of 1,323 tpy, with a
concurrent reduction in VOC emissions of 16,660 tpy and a reduction in
methane emissions of 8,700 metric tonnes per year. Table 2 of this
preamble summarizes the cost and emission reduction impacts of the
final amendments, and Table 3 of this preamble summarizes the costs of
the final standards to ensure compliance.

[[Page 75226]]

Table 2--Nationwide Impacts of Final Amendments (2010$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total
annualized Product Total Methane
Total cost recovery annualized emission VOC Cost HAP Cost
Affected source capital without credit costs reductions emission effectiveness emission effectiveness
investment credit (million $/ (million $/ (metric reductions ($/ton VOC) reductions ($/ton HAP)
(million $) (million $/ yr) yr) tpy) (tpy) (tpy)
yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Storage Vessels................ 18.5 3.13 (8.16) (5.03) ........... 14,600 (345) 910 (5,530)
Delayed Coking Units........... 81 14.5 (2.80) 11.7 8,700 2,060 5,680 413 28,330
Fugitive Emissions (Fenceline 12.5 6.36 ........... 6.36 ........... ........... ............. ........... .............
Monitoring)...................
------------------------------------------------------------------------------------------------------------------------
Total...................... 112 24.0 (11.0) 13.0 8,700 16,660 780 1,323 9,830
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table 3--Nationwide Costs of Final Amendments To Ensure Compliance (2010$)
----------------------------------------------------------------------------------------------------------------
Total
Total capital annualized Product Total
Affected Source investment cost without recovery annualized
(million $) credit credit costs (million
(million $/yr) (million $/yr) $/yr)
----------------------------------------------------------------------------------------------------------------
Relief Device Monitoring........................ 11.1 3.3 .............. 3.3
Flare Monitoring................................ 160 46.5 .............. 46.5
FCCU Testing.................................... .............. 0.4 .............. 0.4
---------------------------------------------------------------
Total....................................... 171 50.2 .............. 50.2
----------------------------------------------------------------------------------------------------------------

The impacts shown in Table 2 do not include costs, product recovery
credits, or emissions reductions associated with any root cause
analysis or corrective action taken in response to the final amendments
for fenceline monitoring. The impacts shown in Table 3 do not include
(i) the costs or emissions reductions associated with any root cause
analysis and corrective action taken in response to the final source
performance testing at the FCCUs, or (ii) emissions reductions
associated with corrective action taken in response to pressure relief
device or (iii) emissions reductions associated with the flare
operating and monitoring provisions. The operational and monitoring
requirements for flares at refineries have the potential to reduce
excess emissions from flares by up to approximately 3,900 tpy of HAP
and 33,000 tpy of VOC. The operational and monitoring requirements for
flares also have the potential to reduce methane emissions by 25,800
metric tonnes per year while increasing emissions of carbon dioxide
(CO2) and nitrous oxide by 267,000 metric tonnes per year and 2 metric
tonnes per year, respectively, yielding a net reduction in GHG
emissions of 377,000 metric tonnes per year of CO2 equivalents
(CO2e).

B. What are the economic impacts?

We performed a national economic impact analysis for petroleum
product producers. All petroleum product refiners will incur annual
compliance costs of less than 1-percent of their sales. For all firms,
the minimum cost-to-sales ratio is <0.01-percent; the maximum cost-to-
sales ratio is 0.87-percent; and the mean cost-to-sales ratio is 0.03-
percent. Therefore, the overall economic impact of this proposed rule
should be minimal for the refining industry and its consumers.
In addition, the EPA performed a screening analysis for impacts on
small businesses by comparing estimated annualized engineering
compliance costs at the firm-level to firm sales. The screening
analysis found that the ratio of compliance cost to firm revenue falls
below 1-percent for the 28 small companies likely to be affected by the
proposal. For small firms, the minimum cost-to-sales ratio is <0.01-
percent; the maximum cost-to-sales ratio is 0.62-percent; and the mean
cost-to-sales ratio is 0.07-percent.
More information and details of this analysis is provided in the
technical document ``Economic Impact Analysis for Petroleum Refineries
Proposed Amendments to the National Emissions Standards for Hazardous
Air Pollutants'', which is available in the docket for this rule
(Docket ID No. EPA-HQ-OAR-2010-0682).

C. What are the benefits?

The final rule is anticipated to result in a reduction of 1,323 tpy
of HAP (based on allowable emissions under the MACT standards) and
16,660 tpy of VOC, not including potential emission reductions that may
occur as a result of the operating and monitoring requirements for
flares and fugitive emission sources via fenceline monitoring. These
avoided emissions will result in improvements in air quality and
reduced negative health effects associated with exposure to air
pollution of these emissions; however, we have not quantified or
monetized the benefits of reducing these emissions for this rulemaking.

D. Impacts of This Rulemaking on Environmental Justice Populations

To examine the potential impacts on vulnerable populations
(minority, low-income and indigenous communities) that might be
associated with the Petroleum Refinery source categories addressed in
this final rule, we evaluated the percentages of various social,
demographic and economic groups in the at-risk populations living near
the facilities where these sources are located and compared them to
national averages. Our analysis of the demographics of the population
with estimated risks greater than 1-in-1 million indicates potential
disparities in risks between demographic groups including the African
American, Other and Multiracial, Hispanic, Below the Poverty Level, and
Over 25 without a High School Diploma when compared to the nationwide
percentages of those groups. These groups will benefit the most from
the emission reductions achieved by this final rulemaking, which is
projected to result in 1 million fewer people exposed to risks greater
than 1-in-1 million.
Additionally, these communities will benefit from this rulemaking,
as this rulemaking for the first time ever requires fenceline
monitoring, and reporting of fenceline data. The agency during the pre-
proposal period and

[[Page 75227]]

during the comment period received feedback from communities on the
importance of having fenceline monitoring in their communities and the
importance of communities having access to this data. The EPA believes
that vulnerable communities will benefit from this data and the
requirements that EPA has put in place in this rulemaking to manage
fugitive emissions.

E. Impacts of This Rulemaking on Children's Health

Under Executive Order 13045 the EPA must evaluate the effects of
the planned regulation on children's health and safety. This action's
health and risk assessments are contained in section IV.A of this
preamble. We believe we have adequately estimated risk for children,
and we do not believe that the environmental health risks addressed by
this action present a disproportionate risk to children. When the EPA
derives exposure reference concentrations and unit risk estimates (URE)
for HAP, it also considers the most sensitive populations identified
(i.e., children) in the available literature, and importantly, these
are the values used in our risk assessments. With regard to children's
potentially greater susceptibility to non-cancer toxicants, the
assessments rely on the EPA (or comparable) hazard identification and
dose-response values which have been developed to be protective for all
subgroups of the general population, including children. With respect
to cancer, the EPA uses the age-dependent adjustment factor approach,
and applies these factors to carcinogenic pollutants that are known to
act via mutagenic mode of action. Further details are provided in the
``Final Residual Risk Assessment for the Petroleum Refining Source
Sector'', Docket ID No. EPA-HQ-OAR-2010-0682.

VI. Statutory and Executive Order Reviews

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

This action is an economically significant regulatory action that
was submitted to the Office of Management and Budget (OMB) for review.
Any changes made in response to OMB recommendations have been
documented in the docket. The EPA prepared an analysis of the potential
costs and benefits associated with this action. This analysis,
``Economic Impact Analysis: Petroleum Refineries--Final Amendments to
the National Emissions Standards for Hazardous Air Pollutants and New
Source Performance Standards'' is available in Docket ID Number EPA-HQ-
OAR-2010-0682.

B. Paperwork Reduction Act (PRA)

The information collection requirements in this 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 se. The
information collection requirements are not enforceable until OMB
approves them.
Adequate recordkeeping and reporting are necessary to ensure
compliance with these standards as required by the CAA. The ICR
information collected from recordkeeping and reporting requirements is
also used for prioritizing inspections and is of sufficient quality to
be used as evidence in court.
The ICR document prepared by the EPA for the amendments to the
Petroleum Refinery MACT standards for 40 CFR part 63, subpart CC has
been assigned the EPA ICR number 1692.08. Burden changes associated
with these amendments would result from new monitoring, recordkeeping
and reporting requirements. The estimated annual increase in
recordkeeping and reporting burden hours is 99,722 hours; the frequency
of response is quarterly and semiannual for reports for all respondents
that must comply with the rule's reporting requirements; and the
estimated average number of likely respondents per year is 95 (this is
the average in the second year). The cost burden to respondents
resulting from the collection of information includes the total capital
cost annualized over the equipment's expected useful life (about $18
million, which includes monitoring equipment for fenceline monitoring,
pressure relief devices, and flares), a total operation and maintenance
component (about $21 million per year for fenceline and flare
monitoring), and a labor cost component (about $8.3 million per year,
the cost of the additional 99,722 labor hours). Burden is defined at 5
CFR 1320.3(b).
The ICR document prepared by the EPA for the amendments to the
Petroleum Refinery MACT standards for 40 CFR part 63, subpart UUU has
been assigned the EPA ICR number 1844.06. Burden changes associated
with these amendments would result from new testing, recordkeeping and
reporting requirements being finalized with this action. The estimated
average burden per response is 25 hours; the frequency of response
ranges from annually up to every 5 years for respondents that have
FCCU, and the estimated average number of likely respondents per year
is 67. The cost burden to respondents resulting from the collection of
information includes the performance testing costs (approximately
$778,000 per year over the first 3 years for the initial PM and one-
time HCN performance tests and $235,000 per year starting in the fourth
year), and a labor cost component (approximately $410,000 per year for
4,940 additional labor hours). 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 EPA's
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is
approved by OMB, the Agency will publish a technical amendment to 40
CFR part 9 in the Federal Register to display the OMB control number
for the approved information collection requirements contained in this
final rule.

C. Regulatory Flexibility Act (RFA)

I certify that this action will not have a significant economic
impact on a substantial number of small entities (SISNOSE) under the
RFA. The small entities subject to the requirements of this action are
small businesses, small organizations and small governmental
jurisdictions. For purposes of assessing the impacts of this rule on
small entities, a small entity is defined as: (1) A small business in
the petroleum refining industry having 1,500 or fewer employees (Small
Business Administration (SBA), 2011); (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.
Details of this analysis are presented in the economic impact analysis
which can be found in the docket for this rule (Docket ID No. EPA-HQ-
OAR-2010-0682).

D. Unfunded Mandates Reform Act (UMRA)

This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. As discussed
earlier in this preamble, these amendments result in nationwide costs
of $63.2 million per year for the private sector. Additionally, the
rule contains no requirements that apply to small

[[Page 75228]]

governments and does not impose obligations upon them.

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.

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

This action does not have tribal implications, as specified in
Executive Order 13175. The final amendments impose no requirements on
tribal governments. Thus, Executive Order 13175 does not apply to this
action. Consistent with the EPA Policy on Consultation and Coordination
with Indian Tribes, the EPA consulted with tribal officials during the
development of the proposed rule and specifically solicited comment on
the proposed amendments from tribal officials.

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

This action is not subject to Executive Order 13045 because the EPA
does not believe the environmental health or safety risks addressed by
this action present a disproportionate risk to children. This action's
health and risk assessments are contained in section IV.A of this
preamble.

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

This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution or use of energy. The overall economic impact of this
final rule should be minimal for the refining industry and its
consumers.

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51

This rulemaking involves technical standards. Therefore, the EPA
conducted searches for the Petroleum Refinery Sector Risk and
Technology Review and New Source Performance Standards through the
Enhanced National Standards Systems Network (NSSN) Database managed by
the American National Standards Institute (ANSI). We also contacted
voluntary consensus standards (VCS) organizations and accessed and
searched their databases. We conducted searches for EPA Methods 18, 22,
320, 325A, and 325B of 40 CFR parts 60 and 63, appendix A. No
applicable VCS were identified for EPA Method 22.
The following voluntary consensus standards were identified as
acceptable alternatives to the EPA test methods for the purpose of this
rule.
The voluntary consensus standard ISO 16017-2:2003(E) ``Air
quality--Sampling and analysis of volatile organic compounds in ambient
air, indoor air and workplace air by sorbent tube/thermal desorption/
capillary gas chromatography. Part 2: Diffusive sampling'' is an
acceptable alternative to Method 325A, Sections 1.2, 6.1 and 6.5 and
Method 325B Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 12.2.4, 13.0, A.1.1, and
A.2. This voluntary consensus standard gives general guidance for the
sampling and analysis of volatile organic compounds in air. It is
applicable to indoor, ambient and workplace air. This standard is
available at International Organization for Standardization, ISO
Central Secretariat, Chemin de Blandonnet 8, CP 401, 1214 Vernier,
Geneva, Switzerland. See https://www.iso.org.
The voluntary consensus standard BS EN 14662-4:2005 ``Ambient Air
Quality: Standard Method for the Measurement of Benzene
Concentrations--Part 4: Diffusive Sampling Followed By Thermal
Desorption and Gas Chromatography'' is an acceptable alternative to
Method 325A, Section 1.2 and Method 325B, Sections 1.3, 7.1.3, 7.1.4,
12.2.4, 13.0, A.1.1, and A.2. This voluntary consensus standard gives
general guidance for the sampling and analysis of benzene in air by
diffusive sampling, thermal desorption and capillary gas
chromatography. This standard is available the European Committee for
Standardization, Avenue Marnix 17--B-1000 Brussels. See https://www.cen.eu.
The voluntary consensus standard ASTM D6420-99 (2010) ``Test Method
for Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography/Mass Spectrometry'' is an acceptable alternative to EPA
Method 18. This voluntary consensus standard employs a direct interface
gas chromatography/mass spectrometer (GCMS) to identify and quantify a
list of 36 volatile organic compounds (the compounds are listed in the
method).
The voluntary consensus standard ASTM D6196-03 (Reapproved 2009)
``Standard Practice for Selection of Sorbents, Sampling, and Thermal
Desorption Analysis Procedures for Volatile Organic Compounds in Air''
is an acceptable alternative to Method 325A, Sections 1.2 and 6.1, and
Method 325B, Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 13.0, A.1.1, and A.2.
This voluntary consensus standard is intended to assist in the
selection of sorbents and procedures for the sampling and analysis of
ambient, indoor, and workplace atmospheres for a variety of common
volatile organic compounds.
The voluntary consensus standards ASTM D1945-03 and later revision
ASTM D1945-14 ``Standard Test Method for Analysis of Natural Gas by Gas
Chromatography'' are acceptable for natural gas analysis. This
voluntary consensus standard covers the determination of the chemical
composition of natural gases and similar gaseous mixtures. This test
method may be abbreviated for the analysis of lean natural gases
containing negligible amounts of hexanes and higher hydrocarbons, or
for the determination of one or more components, as required.
The voluntary consensus standard ASTM UOP539-12 ``Refinery Gas
Analysis by GC'' is acceptable for refinery gas analysis. This
voluntary consensus standard is for determining the composition of
refinery gas streams or vaporized liquefied petroleum gas using a
preconfigured, commercially available gas chromatograph.
The voluntary consensus standard ASTM D6348-03 (Reapproved 2010)
including Annexes A1 through A8, ``Determination of Gaseous Compounds
by Extractive Direct Interface Fourier Transform (FTIR) Spectroscopy''
is an acceptable alternative to EPA Method 320. This voluntary
consensus standard is a field test method that employs an extractive
sampling system to direct stationary source effluent to an FTIR
spectrometer for the identification and quantification of gaseous
compounds. This field test method provides near real time analysis of
extracted gas samples from stationary sources.
The voluntary consensus standard ASTM D6348-12e1 ``Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
(FTIR) Spectroscopy'' is an acceptable alternative to EPA Method 320
with the following two caveats: (1) The test plan preparation and
implementation in the Annexes to ASTM D 6348-03 (Reapproved 2010),
Sections A1 through A8 are mandatory; and (2) In ASTM D6348-03
(Reapproved 2010) Annex A5 (Analyte Spiking Technique), the percent (%)
R must be determined for each target analyte (Equation A5.5). In order
for the test data to be acceptable for a compound, %R must be 70% >= R
<= 130%. If the %R value does not meet this criterion for a target
compound, the test data is not acceptable for that compound and the
test must be repeated

[[Page 75229]]

for that analyte (i.e., the sampling and/or analytical procedure should
be adjusted before a retest). The %R value for each compound must be
reported in the test report, and all field measurements must be
corrected with the calculated %R value for that compound by using the
following equation:

Reported Result = (Measured Concentration in the Stack x 100)/% R.

This voluntary consensus standard is a field test method that
employs an extractive sampling system to direct stationary source
effluent to an FTIR spectrometer for the identification and
quantification of gaseous compounds. This field test method provides
near real time analysis of extracted gas samples from stationary
sources.
The EPA solicited comments on VCS and invited the public to
identify potentially-applicable VCS; however, we did not receive
comments regarding this aspect of 40 CFR part 60, subparts J and Ja,
and part 63, subparts CC, UUU, and Y. Under 40 CFR 63.7(f) and 63.8(f),
a source may apply to the EPA for permission to use alternative test
methods or alternative monitoring requirements in place of any required
testing methods, performance specifications, or procedures in this
final rule.

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 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 U.S. The EPA defines environmental justice as the
fair treatment and meaningful involvement of all people regardless of
race, color, national origin or income with respect to the development,
implementation and enforcement of environmental laws, regulations and
policies. The EPA has this goal for all communities and persons by
working to ensure that everyone enjoys the same degree of protection
from environmental and health hazards and equal access to the decision-
making process to have a healthy environment in which to live, learn
and work.
The EPA believes the human health or environmental risk addressed
by this action will not have potential disproportionately high and
adverse human health or environmental effects on minority, low-income
or indigenous populations. As discussed in section V.D. of this
preamble, the EPA conducted an analysis of the characteristics of the
population with greater than 1-in-1 million risk living within 50 km of
the 142 refineries affected by this rulemaking and determined that
there are more African-Americans, Other and multiracial groups,
Hispanics, low-income individuals, individuals with less than a high
school diploma compared to national averages. Therefore, these
populations are expected to experience the benefits of the risk
reductions associated with this rule. The results of this evaluation
are contained in two technical reports, ``Risk and Technology Review--
Analysis of Socio-Economic Factors for Populations Living Near
Petroleum Refineries'', available in the docket for this action (See
Docket ID Nos. EPA-HQ-OAR-2010-0682-0226 and -0227). Additionally, a
discussion of the final risk analysis is included in Sections IV.A and
V.D of this preamble.
The EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority, low-income or indigenous populations because it
maintains or increases the level of environmental protection for all
affected populations without having any disproportionately high and
adverse human health or environmental effects on any population,
including any minority, low-income or indigenous populations. Further,
the EPA believes that implementation of this rule will provide an ample
margin of safety to protect public health of all demographic groups.

K. Congressional Review Act (CRA)

This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is a ``major rule'' as defined by 5
U.S.C. 804(2).

List of Subjects

40 CFR Part 60

Environmental protection, Administrative practice and procedures,
Air pollution control, Hazardous substances, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements.

40 CFR Part 63

Dated: September 29, 2015.
Gina McCarthy,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

Authority: 42 U.S.C. 7401 et seq.

Subpart J--Standards of Performance for Petroleum Refineries

0
2. Section 60.105 is amended by revising paragraphs (b)(1)(iv) and
(b)(3)(iii) to read as follows:

Sec. 60.105 Monitoring of emissions and operations.

* * * * *
(b) * * *
(1) * * *
(iv) The supporting test results from sampling the requested fuel
gas stream/system demonstrating that the sulfur content is less than 5
ppmv. Sampling data must include, at minimum, 2 weeks of daily
monitoring (14 grab samples) for frequently operated fuel gas streams/
systems; for infrequently operated fuel gas streams/systems, seven grab
samples must be collected unless other additional information would
support reduced sampling. The owner or operator shall use detector
tubes (``length-of-stain tube'' type measurement) following the ``Gas
Processors Association Standard 2377-86 (incorporated by reference--see
Sec. 60.17), using tubes with a maximum span between 10 and 40 ppmv
inclusive when 1<=N<=10, where N = number of pump strokes, to test the
applicant fuel gas stream for H2S; and
* * * * *
(3) * * *
(iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application and the owner or operator chooses not to submit new
information to support an exemption, the owner or operator must begin
H2S monitoring using daily stain sampling to demonstrate
compliance using length-of

[[Page 75230]]

stain tubes with a maximum span between 200 and 400 ppmv inclusive when
1<=N<=5, where N = number of pump strokes. The owner or operator must
begin monitoring according to the requirements in paragraph (a)(1) or
(2) of this section as soon as practicable but in no case later than
180 days after the operation change. During daily stain tube sampling,
a daily sample exceeding 162 ppmv is an exceedance of the 3-hour
H2S concentration limit.
* * * * *

Subpart Ja--Standards of Performance for Petroleum Refineries for
Which Construction, Reconstruction, or Modification Commenced After
May 14, 2007

0
3. Section 60.100a is amended by revising the first sentence of
paragraph (b) to read as follows:

Sec. 60.100a Applicability, designation of affected facility, and
reconstruction.

* * * * *
(b) Except for flares and delayed coking units, the provisions of
this subpart apply only to affected facilities under paragraph (a) of
this section which either commence construction, modification or
reconstruction after May 14, 2007, or elect to comply with the
provisions of this subpart in lieu of complying with the provisions in
subpart J of this part. * * *
* * * * *

0
4. Section 60.101a is amended by:
0
a. Revising the definition of ``Corrective action''; and
0
b. Adding, in alphabetical order, a definition for ``Sour water''.
The revision and addition read as follows:

Sec. 60.101a Definitions.

* * * * *
Corrective action means the design, operation and maintenance
changes that one takes consistent with good engineering practice to
reduce or eliminate the likelihood of the recurrence of the primary
cause and any other contributing cause(s) of an event identified by a
root cause analysis as having resulted in a discharge of gases from an
affected facility in excess of specified thresholds.
* * * * *
Sour water means water that contains sulfur compounds (usually
H2S) at concentrations of 10 parts per million by weight or
more.
* * * * *

0
5. Section 60.102a is amended by revising paragraphs (b)(1)(i) and
(iii), (f), and (g)(1) introductory text to read as follows:

Sec. 60.102a Emissions limitations.

* * * * *
(b) * * *
(1) * * *
(i) 1.0 gram per kilogram (g/kg) (1 pound (lb) per 1,000 lb) coke
burn-off or, if a PM continuous emission monitoring system (CEMS) is
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0
percent excess air for each modified or reconstructed FCCU.
* * * * *
(iii) 1.0 g/kg (1 lb/1,000 lb) coke burn-off or, if a PM CEMS is
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0
percent excess air for each affected FCU.
* * * * *
(f) Except as provided in paragraph (f)(3) of this section, each
owner or operator of an affected sulfur recovery plant shall comply
with the applicable emission limits in paragraph (f)(1) or (2) of this
section.
(1) For a sulfur recovery plant with a design production capacity
greater than 20 long tons per day (LTD), the owner or operator shall
comply with the applicable emission limit in paragraph (f)(1)(i) or
(ii) of this section. If the sulfur recovery plant consists of multiple
process trains or release points, the owner or operator shall comply
with the applicable emission limit for each process train or release
point individually or comply with the applicable emission limit in
paragraph (f)(1)(i) or (ii) as a flow rate weighted average for a group
of release points from the sulfur recovery plant provided that flow is
monitored as specified in Sec. 60.106a(a)(7); if flow is not monitored
as specified in Sec. 60.106a(a)(7), the owner or operator shall comply
with the applicable emission limit in paragraph (f)(1)(i) or (ii) for
each process train or release point individually. For a sulfur recovery
plant with a design production capacity greater than 20 long LTD and a
reduction control system not followed by incineration, the owner or
operator shall also comply with the H2S emission limit in
paragraph (f)(1)(iii) of this section for each individual release
point.
(i) For a sulfur recovery plant with an oxidation control system or
a reduction control system followed by incineration, the owner or
operator shall not discharge or cause the discharge of any gases into
the atmosphere (SO2) in excess of the emission limit
calculated using Equation 1 of this section. For Claus units that use
only ambient air in the Claus burner or that elect not to monitor
O2 concentration of the air/oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery plants, this SO2
emissions limit is 250 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TR01DE15.000

Where:

ELS = Emission limit for large sulfur recovery plant,
ppmv (as SO2, dry basis at zero percent excess air);
k1 = Constant factor for emission limit conversion:
k1 = 1 for converting to the SO2 limit for a
sulfur recovery plant with an oxidation control system or a
reduction control system followed by incineration and k1
= 1.2 for converting to the reduced sulfur compounds limit for a
sulfur recovery plant with a reduction control system not followed
by incineration; and
%O2 = O2 concentration of the air/oxygen
mixture supplied to the Claus burner, percent by volume (dry basis).
If only ambient air is used for the Claus burner or if the owner or
operator elects not to monitor O2 concentration of the
air/oxygen mixture used in the Claus burner or for non-Claus sulfur
recovery plants, use 20.9% for %O2.

[[Page 75231]]

(2) For a sulfur recovery plant with a design production capacity
of 20 LTD or less, the owner or operator shall comply with the
applicable emission limit in paragraph (f)(2)(i) or (ii) of this
section. If the sulfur recovery plant consists of multiple process
trains or release points, the owner or operator may comply with the
applicable emission limit for each process train or release point
individually or comply with the applicable emission limit in paragraph
(f)(2)(i) or (ii) as a flow rate weighted average for a group of
release points from the sulfur recovery plant provided that flow is
monitored as specified in Sec. 60.106a(a)(7); if flow is not monitored
as specified in Sec. 60.106a(a)(7), the owner or operator shall comply
with the applicable emission limit in paragraph (f)(2)(i) or (ii) for
each process train or release point individually. For a sulfur recovery
plant with a design production capacity of 20 LTD or less and a
reduction control system not followed by incineration, the owner or
operator shall also comply with the H2S emission limit in
paragraph (f)(2)(iii) of this section for each individual release
point.
(i) For a sulfur recovery plant with an oxidation control system or
a reduction control system followed by incineration, the owner or
operator shall not discharge or cause the discharge of any gases into
the atmosphere containing SO2 in excess of the emission
limit calculated using Equation 2 of this section. For Claus units that
use only ambient air in the Claus burner or that elect not to monitor
O2 concentration of the air/oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery plants, this SO2
emission limit is 2,500 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TR01DE15.001

Where:

ESS = Emission limit for small sulfur recovery plant,
ppmv (as SO2, dry basis at zero percent excess air);
k1 = Constant factor for emission limit conversion:
k1 = 1 for converting to the SO2 limit for a
sulfur recovery plant with an oxidation control system or a
reduction control system followed by incineration and k1
= 1.2 for converting to the reduced sulfur compounds limit for a
sulfur recovery plant with a reduction control system not followed
by incineration; and
%O2 = O2 concentration of the air/oxygen
mixture supplied to the Claus burner, percent by volume (dry basis).
If only ambient air is used in the Claus burner or if the owner or
operator elects not to monitor O2 concentration of the
air/oxygen mixture used in the Claus burner or for non-Claus sulfur
recovery plants, use 20.9% for %O2.

(ii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
reduced sulfur compounds in excess of the emission limit calculated
using Equation 2 of this section. For Claus units that use only ambient
air in the Claus burner or for non-Claus sulfur recovery plants, this
reduced sulfur compounds emission limit is 3,000 ppmv calculated as
ppmv SO2 (dry basis) at zero percent excess air.
(iii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
H2S in excess of 100 ppmv calculated as ppmv SO2
(dry basis) at zero percent excess air.
(3) The emission limits in paragraphs (f)(1) and (2) of this
section shall not apply during periods of maintenance of the sulfur
pit, which shall not exceed 240 hours per year. The owner or operator
must document the time periods during which the sulfur pit vents were
not controlled and measures taken to minimize emissions during these
periods. Examples of these measures include not adding fresh sulfur or
shutting off vent fans.
(g) * * *
(1) Except as provided in (g)(1)(iii) of this section, for each
fuel gas combustion device, the owner or operator shall comply with
either the emission limit in paragraph (g)(1)(i) of this section or the
fuel gas concentration limit in paragraph (g)(1)(ii) of this section.
For CO boilers or furnaces that are part of a fluid catalytic cracking
unit or fluid coking unit affected facility, the owner or operator
shall comply with the fuel gas concentration limit in paragraph
(g)(1)(ii) for all fuel gas streams combusted in these units.
* * * * *

0
6. Section 60.104a is amended by:
0
a. Revising the first sentence of paragraph (a) and paragraphs (b), (f)
introductory text, and (h) introductory text;
0
b. Adding paragraph (h)(6); and
0
c. Removing and reserving paragraphs (j)(1) through (3).
The revisions and additions read as follows:

Sec. 60.104a Performance tests.

(a) The owner or operator shall conduct a performance test for each
FCCU, FCU, sulfur recovery plant and fuel gas combustion device to
demonstrate initial compliance with each applicable emissions limit in
Sec. 60.102a and conduct a performance test for each flare to
demonstrate initial compliance with the H2S concentration
requirement in Sec. 60.103a(h) according to the requirements of Sec.
60.8. * * *
(b) The owner or operator of a FCCU or FCU that elects to monitor
control device operating parameters according to the requirements in
Sec. 60.105a(b), to use bag leak detectors according to the
requirements in Sec. 60.105a(c), or to use COMS according to the
requirements in Sec. 60.105a(e) shall conduct a PM performance test at
least annually (i.e., once per calendar year, with an interval of at
least 8 months but no more than 16 months between annual tests) and
furnish the Administrator a written report of the results of each test.
* * * * *
(f) The owner or operator of an FCCU or FCU that uses cyclones to
comply with the PM per coke burn-off emissions limit in Sec.
60.102a(b)(1) shall establish a site-specific opacity operating limit
according to the procedures in paragraphs (f)(1) through (3) of this
section.
* * * * *
(h) The owner or operator shall determine compliance with the
SO2 emissions limits for sulfur recovery plants in Sec.
60.102a(f)(1)(i) and (f)(2)(i) and the reduced sulfur compounds and
H2S emissions limits for sulfur recovery plants in Sec.
60.102a(f)(1)(ii), (f)(1)(iii), (f)(2)(ii), and (f)(2)(iii) using the
following methods and procedures:
* * * * *
(6) If oxygen or oxygen-enriched air is used in the Claus burner
and either Equation 1 or 2 of this subpart is used to determine the
applicable emissions limit, determine the average O2
concentration of the air/oxygen mixture supplied to the Claus burner,
in percent by volume (dry basis), for the performance test using all
hourly average O2 concentrations determined

[[Page 75232]]

during the test runs using the procedures in Sec. 60.106a(a)(5) or
(6).
* * * * *

0
7. Section 60.105a is amended by:
0
a. Revising paragraphs (b)(1)(i), (b)(1)(ii)(A), (b)(2), (h)(1),
(h)(3)(i), and (i)(1);
0
b. Redesignating paragraphs (i)(2) through (6) as (i)(3) through (7);
0
c. Adding paragraph (i)(2); and
0
d. Revising newly redesignated paragraph (i)(7).
The revisions and additions read as follows:

Sec. 60.105a Monitoring of emissions and operations for fluid
catalytic cracking units (FCCU) and fluid coking units (FCU).

* * * * *
(b) * * *
(1) * * *
(i) For units controlled using an electrostatic precipitator, the
owner or operator shall use CPMS to measure and record the hourly
average total power input and secondary current to the entire system.
(ii) * * *
(A) As an alternative to pressure drop, the owner or operator of a
jet ejector type wet scrubber or other type of wet scrubber equipped
with atomizing spray nozzles must conduct a daily check of the air or
water pressure to the spray nozzles and record the results of each
check. Faulty (e.g., leaking or plugged) air or water lines must be
repaired within 12 hours of identification of an abnormal pressure
reading.
* * * * *
(2) For use in determining the coke burn-off rate for an FCCU or
FCU, the owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring the concentrations
of CO2, O2 (dry basis), and if needed, CO in the
exhaust gases prior to any control or energy recovery system that burns
auxiliary fuels. A CO monitor is not required for determining coke
burn-off rate when no auxiliary fuel is burned and a continuous CO
monitor is not required in accordance with paragraph (h)(3) of this
section.
(i) The owner or operator shall install, operate, and maintain each
CO2 and O2 monitor according to Performance
Specification 3 of appendix B to this part.
(ii) The owner or operator shall conduct performance evaluations of
each CO2 and O2 monitor according to the
requirements in Sec. 60.13(c) and Performance Specification 3 of
appendix B to this part. The owner or operator shall use Method 3 of
appendix A-3 to this part for conducting the relative accuracy
evaluations.
(iii) If a CO monitor is required, the owner or operator shall
install, operate, and maintain each CO monitor according to Performance
Specification 4 or 4A of appendix B to this part. If this CO monitor
also serves to demonstrate compliance with the CO emissions limit in
Sec. 60.102a(b)(4), the span value for this instrument is 1,000 ppm;
otherwise, the span value for this instrument should be set at
approximately 2 times the typical CO concentration expected in the FCCU
of FCU flue gas prior to any emission control or energy recovery system
that burns auxiliary fuels.
(iv) If a CO monitor is required, the owner or operator shall
conduct performance evaluations of each CO monitor according to the
requirements in Sec. 60.13(c) and Performance Specification 4 of
appendix B to this part. The owner or operator shall use Method 10,
10A, or 10B of appendix A-3 to this part for conducting the relative
accuracy evaluations.
(v) The owner or operator shall comply with the quality assurance
requirements of procedure 1 of appendix F to this part, including
quarterly accuracy determinations for CO2 and CO monitors,
annual accuracy determinations for O2 monitors, and daily
calibration drift tests.
* * * * *
(h) * * *
(1) The owner or operator shall install, operate, and maintain each
CO monitor according to Performance Specification 4 or 4A of appendix B
to this part. The span value for this instrument is 1,000 ppmv CO.
* * * * *
(3) * * *
(i) The demonstration shall consist of continuously monitoring CO
emissions for 30 days using an instrument that meets the requirements
of Performance Specification 4 or 4A of appendix B to this part. The
span value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative
accuracy limit shall be 10 percent of the average CO emissions or 5
ppmv CO, whichever is greater. For instruments that are identical to
Method 10 of appendix A-4 to this part and employ the sample
conditioning system of Method 10A of appendix A-4 to this part, the
alternative relative accuracy test procedure in section 10.1 of
Performance Specification 2 of appendix B to this part may be used in
place of the relative accuracy test.
* * * * *
(i) * * *
(1) If a CPMS is used according to paragraph (b)(1) of this
section, all 3-hour periods during which the average PM control device
operating characteristics, as measured by the continuous monitoring
systems under paragraph (b)(1), fall below the levels established
during the performance test. If the alternative to pressure drop CPMS
is used for the owner or operator of a jet ejector type wet scrubber or
other type of wet scrubber equipped with atomizing spray nozzles, each
day in which abnormal pressure readings are not corrected within 12
hours of identification.
(2) If a bag leak detection system is used according to paragraph
(c) of this section, each day in which the cause of an alarm is not
alleviated within the time period specified in paragraph (c)(3) of this
section.
* * * * *
(7) All 1-hour periods during which the average CO concentration as
measured by the CO continuous monitoring system under paragraph (h) of
this section exceeds 500 ppmv or, if applicable, all 1-hour periods
during which the average temperature and O2 concentration as
measured by the continuous monitoring systems under paragraph (h)(4) of
this section fall below the operating limits established during the
performance test.

0
8. Section 60.106a is amended by:
0
a. Revising paragraph (a)(1)(i);
0
b. Adding paragraphs (a)(1)(iv) through (vii);
0
c. Revising paragraphs (a)(2) introductory text, (a)(2)(i) and (ii),
and the first sentence of paragraph (a)(2)(iii);
0
d. Removing paragraphs (a)(2)(iv) and (v);
0
e. Redesignating paragraphs (a)(2)(vi) through (ix) as (a)(2)(iv)
through (vii);
0
f. Revising the first sentence of paragraph (a)(3) introductory text
and paragraph (a)(3)(i);
0
g. Adding paragraphs (a)(4) through (7); and
0
h. Revising paragraphs (b)(2) and (3).
The revisions and additions read as follows:

Sec. 60.106a Monitoring of emissions and operations for sulfur
recovery plants.

(a) * * *
(1) * * *
(i) The span value for the SO2 monitor is two times the
applicable SO2 emission limit at the highest O2
concentration in the air/oxygen stream used in the Claus burner, if
applicable.
* * * * *
(iv) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
appendix B to this part.
(v) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.

[[Page 75233]]

(vi) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to this part.
The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
this part for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec. 60.17)
is an acceptable alternative to EPA Method 3B of appendix A-2 to this
part.
(vii) The owner or operator shall comply with the applicable
quality assurance procedures of appendix F to this part for each
monitor, including annual accuracy determinations for each
O2 monitor, and daily calibration drift determinations.
(2) For sulfur recovery plants that are subject to the reduced
sulfur compounds emission limit in Sec. 60.102a(f)(1)(ii) or
(f)(2)(ii), the owner or operator shall install, operate, calibrate,
and maintain an instrument for continuously monitoring and recording
the concentration of reduced sulfur compounds and O2
emissions into the atmosphere. The reduced sulfur compounds emissions
shall be calculated as SO2 (dry basis, zero percent excess
air).
(i) The span value for the reduced sulfur compounds monitor is two
times the applicable reduced sulfur compounds emission limit as
SO2 at the highest O2 concentration in the air/
oxygen stream used in the Claus burner, if applicable.
(ii) The owner or operator shall install, operate, and maintain
each reduced sulfur compounds CEMS according to Performance
Specification 5 of appendix B to this part.
(iii) The owner or operator shall conduct performance evaluations
of each reduced sulfur compounds monitor according to the requirements
in Sec. 60.13(c) and Performance Specification 5 of appendix B to this
part. * * *
* * * * *
(3) In place of the reduced sulfur compounds monitor required in
paragraph (a)(2) of this section, the owner or operator may install,
calibrate, operate, and maintain an instrument using an air or
O2 dilution and oxidation system to convert any reduced
sulfur to SO2 for continuously monitoring and recording the
concentration (dry basis, 0 percent excess air) of the total resultant
SO2. * * *
(i) The span value for this monitor is two times the applicable
reduced sulfur compounds emission limit as SO2 at the
highest O2 concentration in the air/oxygen stream used in
the Claus burner, if applicable.
* * * * *
(4) For sulfur recovery plants that are subject to the
H2S emission limit in Sec. 60.102a(f)(1)(iii) or
(f)(2)(iii), the owner or operator shall install, operate, calibrate,
and maintain an instrument for continuously monitoring and recording
the concentration of H2S, and O2 emissions into
the atmosphere. The H2S emissions shall be calculated as
SO2 (dry basis, zero percent excess air).
(i) The span value for this monitor is two times the applicable
H2S emission limit.
(ii) The owner or operator shall install, operate, and maintain
each H2S CEMS according to Performance Specification 7 of
appendix B to this part.
(iii) The owner or operator shall conduct performance evaluations
for each H2S monitor according to the requirements of Sec.
60.13(c) and Performance Specification 7 of appendix B to this part.
The owner or operator shall use Methods 11 or 15 of appendix A-5 to
this part or Method 16 of appendix A-6 to this part for conducting the
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 15A of appendix A-5 to this part.
(iv) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
appendix B to this part.
(v) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.
(vi) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to this part.
The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
this part for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec. 60.17)
is an acceptable alternative to EPA Method 3B of appendix A-2 to this
part.
(vii) The owner or operator shall comply with the applicable
quality assurance procedures of appendix F to this part for each
monitor, including annual accuracy determinations for each
O2 monitor, and daily calibration drift determinations.
(5) For sulfur recovery plants that use oxygen or oxygen enriched
air in the Claus burner and that elects to monitor O2
concentration of the air/oxygen mixture supplied to the Claus burner,
the owner or operator shall install, operate, calibrate, and maintain
an instrument for continuously monitoring and recording the
O2 concentration of the air/oxygen mixture supplied to the
Claus burner in order to determine the allowable emissions limit.
(i) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to this part.
(ii) The span value for the O2 monitor shall be 100
percent.
(iii) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to this part.
The owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
this part for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec. 60.17)
is an acceptable alternative to EPA Method 3B of appendix A-2 to this
part.
(iv) The owner or operator shall comply with the applicable quality
assurance procedures of appendix F to this part for each monitor,
including annual accuracy determinations for each O2
monitor, and daily calibration drift determinations.
(v) The owner or operator shall use the hourly average
O2 concentration from this monitor for use in Equation 1 or
2 of Sec. 60.102a(f), as applicable, for each hour and determine the
allowable emission limit as the arithmetic average of 12 contiguous 1-
hour averages (i.e., the rolling 12-hour average).
(6) As an alternative to the O2 monitor required in
paragraph (a)(5) of this section, the owner or operator may install,
calibrate, operate, and maintain a CPMS to measure and record the
volumetric gas flow rate of ambient air and oxygen-enriched gas
supplied to the Claus burner and calculate the hourly average
O2 concentration of the air/oxygen mixture used in the Claus
burner as specified in paragraphs (a)(6)(i) through (iv) of this
section in order to determine the allowable emissions limit as
specified in paragraphs (a)(6)(v) of this section.
(i) The owner or operator shall install, calibrate, operate and
maintain each flow monitor according to the manufacturer's procedures
and specifications and the following requirements.
(A) Locate the monitor in a position that provides a representative
measurement of the total gas flow rate.

[[Page 75234]]

(B) Use a flow sensor meeting an accuracy requirement of 5 percent over the normal range of flow measured or 10 cubic feet
per minute, whichever is greater.
(C) Use a flow monitor that is maintainable online, is able to
continuously correct for temperature, pressure and, for ambient air
flow monitor, moisture content, and is able to record dry flow in
standard conditions (as defined in Sec. 60.2) over one-minute
averages.
(D) At least quarterly, perform a visual inspection of all
components of the monitor for physical and operational integrity and
all electrical connections for oxidation and galvanic corrosion if the
flow monitor is not equipped with a redundant flow sensor.
(E) Recalibrate the flow monitor in accordance with the
manufacturer's procedures and specifications biennially (every two
years) or at the frequency specified by the manufacturer.
(ii) The owner or operator shall use 20.9 percent as the oxygen
content of the ambient air.
(iii) The owner or operator shall use product specifications (e.g.,
as reported in material safety data sheets) for percent oxygen for
purchased oxygen. For oxygen produced onsite, the percent oxygen shall
be determined by periodic measurements or process knowledge.
(iv) The owner or operator shall calculate the hourly average
O2 concentration of the air/oxygen mixture used in the Claus
burner using Equation 10 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.002

Where:

%O2 = O2 concentration of the air/oxygen
mixture used in the Claus burner, percent by volume (dry basis);
20.9 = O2 concentration in air, percent dry basis;
Qair = Volumetric flow rate of ambient air used in the
Claus burner, dscfm;
%O2,oxy = O2 concentration in the enriched
oxygen stream, percent dry basis; and
Qoxy = Volumetric flow rate of enriched oxygen stream
used in the Claus burner, dscfm.

(v) The owner or operator shall use the hourly average
O2 concentration determined using Equation 8 of Sec.
60.104a(d)(8) for use in Equation 1 or 2 of Sec. 60.102a(f), as
applicable, for each hour and determine the allowable emission limit as
the arithmetic average of 12 contiguous 1-hour averages (i.e., the
rolling 12-hour average).
(7) Owners or operators of a sulfur recovery plant that elects to
comply with the SO2 emission limit in Sec. 60.102a(f)(1)(i)
or (f)(2)(i) or the reduced sulfur compounds emission limit in Sec.
60.102a(f)(1)(ii) or (f)(2)(ii) as a flow rate weighted average for a
group of release points from the sulfur recovery plant rather than for
each process train or release point individually shall install,
calibrate, operate, and maintain a CPMS to measure and record the
volumetric gas flow rate of each release point within the group of
release points from the sulfur recovery plant as specified in
paragraphs (a)(7)(i) through (iv) of this section.
(i) The owner or operator shall install, calibrate, operate and
maintain each flow monitor according to the manufacturer's procedures
and specifications and the following requirements.
(A) Locate the monitor in a position that provides a representative
measurement of the total gas flow rate.
(B) Use a flow sensor meeting an accuracy requirement of 5 percent over the normal range of flow measured or 10 cubic feet
per minute, whichever is greater.
(C) Use a flow monitor that is maintainable online, is able to
continuously correct for temperature, pressure, and moisture content,
and is able to record dry flow in standard conditions (as defined in
Sec. 60.2) over one-minute averages.
(D) At least quarterly, perform a visual inspection of all
components of the monitor for physical and operational integrity and
all electrical connections for oxidation and galvanic corrosion if the
flow monitor is not equipped with a redundant flow sensor.
(E) Recalibrate the flow monitor in accordance with the
manufacturer's procedures and specifications biennially (every two
years) or at the frequency specified by the manufacturer.
(ii) The owner or operator shall correct the flow to 0 percent
excess air using Equation 11 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.003

Where:

Qadj = Volumetric flow rate adjusted to 0 percent excess
air, dry standard cubic feet per minute (dscfm);
Cmeas = Volumetric flow rate measured by the flow meter
corrected to dry standard conditions, dscfm;
20.9c = 20.9 percent O2-0.0 percent
O2 (defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry
basis, percent.

(iii) The owner or operator shall calculate the flow weighted
average SO2 or reduced sulfur compounds concentration for
each hour using Equation 12 of this section:
[GRAPHIC] [TIFF OMITTED] TR01DE15.004

[[Page 75235]]

Where:

Cave = Flow weighted average concentration of the
pollutant, ppmv (dry basis, zero percent excess air). The pollutant
is either SO2 (if complying with the SO2
emission limit in Sec. 60.102a(f)(1)(i) or (f)(2)(i)) or reduced
sulfur compounds (if complying with the reduced sulfur compounds
emission limit in Sec. 60.102a(f)(1)(ii) or (f)(2)(ii));
N = Number of release points within the group of release points from
the sulfur recovery plant for which emissions averaging is elected;
Cn = Pollutant concentration in the n^th
release point within the group of release points from the sulfur
recovery plant for which emissions averaging is elected, ppmv (dry
basis, zero percent excess air);
Qadj,n = Volumetric flow rate of the n^th
release point within the group of release points from the sulfur
recovery plant for which emissions averaging is elected, dry
standard cubic feet per minute (dscfm, adjusted to 0 percent excess
air).

(iv) For sulfur recovery plants that use oxygen or oxygen enriched
air in the Claus burner, the owner or operator shall use Equation 10 of
this section and the hourly emission limits determined in paragraph
(a)(5)(v) or (a)(6)(v) of this section in-place of the pollutant
concentration to determine the flow weighted average hourly emission
limit for each hour. The allowable emission limit shall be calculated
as the arithmetic average of 12 contiguous 1-hour averages (i.e., the
rolling 12-hour average).
(b) * * *
(2) All 12-hour periods during which the average concentration of
reduced sulfur compounds (as SO2) as measured by the reduced
sulfur compounds continuous monitoring system required under paragraph
(a)(2) or (3) of this section exceeds the applicable emission limit; or
(3) All 12-hour periods during which the average concentration of
H2S as measured by the H2S continuous monitoring
system required under paragraph (a)(4) of this section exceeds the
applicable emission limit (dry basis, 0 percent excess air).

0
9. Section 60.107a is amended by revising paragraphs (a)(1)(i) and
(ii), (b)(1)(iv), the first sentence of paragraph (b)(3)(iii), (d)(3),
(e)(1) introductory text, (e)(1)(ii), (e)(2) introductory text,
(e)(2)(ii), (e)(2)(vi)(C), (e)(3), (f)(1)(ii), and (h)(5) to read as
follows:

Sec. 60.107a Monitoring of emissions and operations for fuel gas
combustion devices and flares.

(a) * * *
(1) * * *
(i) The owner or operator shall install, operate, and maintain each
SO2 monitor according to Performance Specification 2 of
appendix B to this part. The span value for the SO2 monitor
is 50 ppmv SO2.
(ii) The owner or operator shall conduct performance evaluations
for the SO2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 2 of appendix B to this part.
The owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to
this part for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec. 60.17)
is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to
this part. Samples taken by Method 6 of appendix A-4 to this part shall
be taken at a flow rate of approximately 2 liters/min for at least 30
minutes. The relative accuracy limit shall be 20 percent or 4 ppmv,
whichever is greater, and the calibration drift limit shall be 5
percent of the established span value.
* * * * *
(b) * * *
(1) * * *
(iv) The supporting test results from sampling the requested fuel
gas stream/system demonstrating that the sulfur content is less than 5
ppmv H2S. Sampling data must include, at minimum, 2 weeks of
daily monitoring (14 grab samples) for frequently operated fuel gas
streams/systems; for infrequently operated fuel gas streams/systems,
seven grab samples must be collected unless other additional
information would support reduced sampling. The owner or operator shall
use detector tubes (``length-of-stain tube'' type measurement)
following the ``Gas Processors Association Standard 2377-86
(incorporated by reference--see Sec. 60.17), using tubes with a
maximum span between 10 and 40 ppmv inclusive when 1<=N<=10, where N =
number of pump strokes, to test the applicant fuel gas stream for
H2S; and
* * * * *
(3) * * *
(iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application and the owner or operator chooses not to submit new
information to support an exemption, the owner or operator must begin
H2S monitoring using daily stain sampling to demonstrate
compliance using length-of-stain tubes with a maximum span between 200
and 400 ppmv inclusive when 1<=N<=5, where N = number of pump strokes.
* * *
* * * * *
(d) * * *
(3) As an alternative to the requirements in paragraph (d)(2) of
this section, the owner or operator of a gas-fired process heater shall
install, operate and maintain a gas composition analyzer and determine
the average F factor of the fuel gas using the factors in Table 1 of
this subpart and Equation 13 of this section. If a single fuel gas
system provides fuel gas to several process heaters, the F factor may
be determined at a single location in the fuel gas system provided it
is representative of the fuel gas fed to the affected process
heater(s).
[GRAPHIC] [TIFF OMITTED] TR01DE15.005

Where:

Fd = F factor on dry basis at 0% excess air, dscf/MMBtu.
Xi = mole or volume fraction of each component in the
fuel gas.
MEVi = molar exhaust volume, dry standard cubic feet
per mole (dscf/mol).
MHCi = molar heat content, Btu per mole (Btu/mol).
1,000,000 = unit conversion, Btu per MMBtu.
* * * * *
(e) * * *
(1) Total reduced sulfur monitoring requirements. The owner or
operator shall install, operate, calibrate and maintain an instrument
or instruments for continuously monitoring and recording the
concentration of total reduced sulfur in gas discharged to the flare.
* * * * *
(ii) The owner or operator shall conduct performance evaluations of
each total reduced sulfur monitor according to the requirements in
Sec. 60.13(c) and Performance Specification 5 of appendix B to this
part. The owner or operator of each total

[[Page 75236]]

reduced sulfur monitor shall use EPA Method 15A of appendix A-5 to this
part for conducting the relative accuracy evaluations. The method ANSI/
ASME PTC 19.10-1981 (incorporated by reference-see Sec. 60.17) is an
acceptable alternative to EPA Method 15A of appendix A-5 to this part.
The alternative relative accuracy procedures described in section 16.0
of Performance Specification 2 of appendix B to this part (cylinder gas
audits) may be used for conducting the relative accuracy evaluations,
except that it is not necessary to include as much of the sampling
probe or sampling line as practical.
* * * * *
(2) H2S monitoring requirements. The owner or operator shall
install, operate, calibrate, and maintain an instrument or instruments
for continuously monitoring and recording the concentration of
H2S in gas discharged to the flare according to the
requirements in paragraphs (e)(2)(i) through (iii) of this section and
shall collect and analyze samples of the gas and calculate total sulfur
concentrations as specified in paragraphs (e)(2)(iv) through (ix) of
this section.
* * * * *
(ii) The owner or operator shall conduct performance evaluations of
each H2S monitor according to the requirements in Sec.
60.13(c) and Performance Specification 7 of appendix B to this part.
The owner or operator shall use EPA Method 11, 15 or 15A of appendix A-
5 to this part for conducting the relative accuracy evaluations. The
method ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec.
60.17) is an acceptable alternative to EPA Method 15A of appendix A-5
to this part. The alternative relative accuracy procedures described in
section 16.0 of Performance Specification 2 of appendix B to this part
(cylinder gas audits) may be used for conducting the relative accuracy
evaluations, except that it is not necessary to include as much of the
sampling probe or sampling line as practical.
* * * * *
(vi) * * *
(C) Determine the acceptable range for subsequent weekly samples
based on the 95-percent confidence interval for the distribution of
daily ratios based on the 10 individual daily ratios using Equation 14
of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE15.006

Where:

AR = Acceptable range of subsequent ratio determinations,
unitless.
RatioAvg = 10-day average total sulfur-to-
H2S concentration ratio, unitless.
2.262 = t-distribution statistic for 95-percent 2-sided
confidence interval for 10 samples (9 degrees of freedom).
SDev = Standard deviation of the 10 daily average total sulfur-
to-H2S concentration ratios used to develop the 10-day
average total sulfur-to-H2S concentration ratio,
unitless.
* * * * *
(3) SO2 monitoring requirements. The owner or operator shall
install, operate, calibrate, and maintain an instrument for
continuously monitoring and recording the concentration of
SO2 from a process heater or other fuel gas combustion
device that is combusting gas representative of the fuel gas in the
flare gas line according to the requirements in paragraph (a)(1) of
this section, determine the F factor of the fuel gas at least daily
according to the requirements in paragraphs (d)(2) through (4) of this
section, determine the higher heating value of the fuel gas at least
daily according to the requirements in paragraph (d)(7) of this
section, and calculate the total sulfur content (as SO2) in
the fuel gas using Equation 15 of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE15.007

Where:

TSFG = Total sulfur concentration, as SO2,
in the fuel gas, ppmv.
CSO2 = Concentration of SO2 in the exhaust
gas, ppmv (dry basis at 0-percent excess air).
Fd = F factor gas on dry basis at 0-percent excess
air, dscf/MMBtu.
HHVFG = Higher heating value of the fuel gas, MMBtu/
scf.
* * * * *
(f) * * *
(1) * * *
(ii) Use a flow sensor meeting an accuracy requirement of 20 percent of the flow rate at velocities ranging from 0.1 to 1
feet per second and an accuracy of 5 percent of the flow
rate for velocities greater than 1 feet per second.
* * * * *
(h) * * *
(5) Daily O2 limits for fuel gas combustion devices. Each day
during which the concentration of O2 as measured by the
O2 continuous monitoring system required under paragraph
(c)(6) or (d)(8) of this section exceeds the O2 operating
limit or operating curve determined during the most recent biennial
performance test.

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES

0
10. The authority citation for part 63 continues to read as follows:

Authority: 42 U.S.C. 7401 et se.

Subpart A--General Provisions

0
11. Section 63.14 is amended by:
0
a. Revising paragraph (h)(14);
0
b. Redesignating paragraphs (h)(82) through (99) as (h)(86) through
(103), paragraphs (h)(77) through (81) as (h)(80) through (84),
paragraphs (h)(73) through (76) as paragraphs (h)(75) through (78), and
paragraphs (h)(15) through (72) as (16) through (73), respectively;
0
c. Revising newly redesignated paragraph (h)(78);
0
d. Adding paragraphs (h)(15), (74), (79), (85), (104) and (j)(2);
0
e. Redesignating paragraph (m)(3) through (21) as (m)(5) through (23),
respectively, and paragraph (m)(2) as (m)(3).
0
f. Adding paragraphs (m)(2) and (4) and (n)(3); and
0
g. Revising paragraph (s)(1).
The revisions and additions read as follows:

Sec. 63.14 Incorporation by reference.

* * * * *
(h) * * *
(14) ASTM D1945-03 (Reapproved 2010), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography, Approved January 1,
2010, IBR approved for Sec. Sec. 63.670(j), 63.772(h), and 63.1282(g).
(15) ASTM D1945-14, Standard Test Method for Analysis of Natural
Gas by Gas Chromatography, Approved

[[Page 75237]]

November 1, 2014, IBR approved for Sec. 63.670(j).
* * * * *
(74) ASTM D6196-03 (Reapproved 2009), Standard Practice for
Selection of Sorbents, Sampling, and Thermal Desorption Analysis
Procedures for Volatile Organic Compounds in Air, Approved March 1,
2009, IBR approved for appendix A to this part: Method 325A and Method
325B.
* * * * *
(78) ASTM D6348-03 (Reapproved 2010), Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1
through A8, Approved October 1, 2010, IBR approved for Sec.
63.1571(a), tables 4 and 5 to subpart JJJJJ, tables 4 and 6 to subpart
KKKKK, tables 1, 2, and 5 to subpart UUUUU and appendix B to subpart
UUUUU.
* * * * *
(79) ASTM D6348-12e1, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, Approved February 1, 2012, IBR approved
for Sec. 63.1571(a).
* * * * *
(85) ASTM D6420-99 (Reapproved 2010), Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry, Approved October 1, 2010, IBR
approved for Sec. 63.670(j) and appendix A to this part: Method 325B.
* * * * *
(104) ASTM UOP539-12, Refinery Gas Analysis by GC, Copyright 2012
(to UOP), IBR approved for Sec. 63.670(j).
* * * * *
(j) * * *
(2) BS EN 14662-4:2005, Ambient air quality standard method for the
measurement of benzene concentrations--Part 4: Diffusive sampling
followed by thermal desorption and gas chromatography, Published June
27, 2005, IBR approved for appendix A to this part: Method 325A and
Method 325B.
* * * * *
(m) * * *
(2) EPA-454/B-08-002, Office of Air Quality Planning and Standards
(OAQPS), Quality Assurance Handbook for Air Pollution Measurement
Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final),
March 24, 2008, IBR approved for Sec. 63.658(d) and appendix A to this
part: Method 325A.
* * * * *
(4) EPA-454/R-99-005, Office of Air Quality Planning and Standards
(OAQPS), Meteorological Monitoring Guidance for Regulatory Modeling
Applications, February 2000, IBR approved for appendix A to this part:
Method 325A.
* * * * *
(n) * * *
(3) ISO 16017-2:2003(E): Indoor, ambient and workplace air--
sampling and analysis of volatile organic compounds by sorbent tube/
thermal desorption/capillary gas chromatography--Part 2: Diffusive
sampling, May 15, 2003, IBR approved for appendix A to this part:
Method 325A and Method 325B.
* * * * *
(s) * * *
(1) ``Air Stripping Method (Modified El Paso Method) for
Determination of Volatile Organic Compound Emissions from Water
Sources,'' Revision Number One, dated January 2003, Sampling Procedures
Manual, Appendix P: Cooling Tower Monitoring, January 31, 2003, IBR
approved for Sec. Sec. 63.654(c) and (g), 63.655(i), and 63.11920.
* * * * *

Subpart Y--National Emission Standards for Marine Tank Vessel
Loading Operations

0
12. Section 63.560 is amended by revising paragraph (a)(4) to read as
follows:

Sec. 63.560 Applicability and designation of affected source.

(a) * * *
(4) Existing sources with emissions less than 10 and 25 tons must
meet the submerged fill standards of 46 CFR 153.282.
* * * * *

Subpart CC--National Emission Standards for Hazardous Air
Pollutants From Petroleum Refineries

0
13. Section 63.640 is amended by:
0
a. Revising paragraphs (a) introductory text and (c) introductory text;
0
c. Adding paragraph (c)(9);
0
d. Revising paragraphs (d)(5), (h), (k)(1), (l) introductory text,
(l)(2) introductory text, (l)(2)(i), (l)(3) introductory text, (m)
introductory text, (n) introductory text, (n)(1) through (5), (n)(8)
introductory text, and (n)(8)(ii);
0
e. Adding paragraphs (n)(8)(vii) and (viii);
0
f. Revising paragraph (n)(9)(i);
0
g. Adding paragraph (n)(10);
0
h. Revising paragraph (o)(2)(i) introductory text;
0
i. Adding paragraph (o)(2)(i)(D);
0
j. Revising paragraph (o)(2)(ii) introductory text; and
0
k. Adding paragraphs (o)(2)(ii)(C) and (s).
The revisions and additions read as follows:

Sec. 63.640 Applicability and designation of affected source.

(a) This subpart applies to petroleum refining process units and to
related emissions points that are specified in paragraphs (c)(1)
through (9) of this section that are located at a plant site and that
meet the criteria in paragraphs (a)(1) and (2) of this section:
* * * * *
(c) For the purposes of this subpart, the affected source shall
comprise all emissions points, in combination, listed in paragraphs
(c)(1) through (9) of this section that are located at a single
refinery plant site.
* * * * *
(9) All releases associated with the decoking operations of a
delayed coking unit, as defined in this subpart.
(d) * * *
(5) Emission points routed to a fuel gas system, as defined in
Sec. 63.641, provided that on and after January 30, 2019, any flares
receiving gas from that fuel gas system are subject to Sec. 63.670. No
other testing, monitoring, recordkeeping, or reporting is required for
refinery fuel gas systems or emission points routed to refinery fuel
gas systems.
* * * * *
(h) Sources subject to this subpart are required to achieve
compliance on or before the dates specified in table 11 of this
subpart, except as provided in paragraphs (h)(1) through (3) of this
section.
(1) Marine tank vessels at existing sources shall be in compliance
with this subpart, except for Sec. Sec. 63.657 through 63.660, no
later than August 18, 1999, unless the vessels are included in an
emissions average to generate emission credits. Marine tank vessels
used to generate credits in an emissions average shall be in compliance
with this subpart no later than August 18, 1998, unless an extension
has been granted by the Administrator as provided in Sec. 63.6(i).
(2) Existing Group 1 floating roof storage vessels meeting the
applicability criteria in item 1 of the definition of Group 1 storage
vessel shall be in compliance with Sec. 63.646 at the first degassing
and cleaning activity after August 18, 1998, or August 18, 2005,
whichever is first.

[[Page 75238]]

(3) An owner or operator may elect to comply with the provisions of
Sec. 63.648(c) through (i) as an alternative to the provisions of
Sec. 63.648(a) and (b). In such cases, the owner or operator shall
comply no later than the dates specified in paragraphs (h)(3)(i)
through (iii) of this section.
(i) Phase I (see table 2 of this subpart), beginning on August 18,
1998;
(ii) Phase II (see table 2 of this subpart), beginning no later
than August 18, 1999; and
(iii) Phase III (see table 2 of this subpart), beginning no later
than February 18, 2001.
* * * * *
(k) * * *
(1) The reconstructed source, addition, or change shall be in
compliance with the new source requirements in item (1), (2), or (3) of
table 11 of this subpart, as applicable, upon initial startup of the
reconstructed source or by August 18, 1995, whichever is later; and
* * * * *
(l) If an additional petroleum refining process unit is added to a
plant site or if a miscellaneous process vent, storage vessel, gasoline
loading rack, marine tank vessel loading operation, heat exchange
system, or decoking operation that meets the criteria in paragraphs
(c)(1) through (9) of this section is added to an existing petroleum
refinery or if another deliberate operational process change creating
an additional Group 1 emissions point(s) (as defined in Sec. 63.641)
is made to an existing petroleum refining process unit, and if the
addition or process change is not subject to the new source
requirements as determined according to paragraph (i) or (j) of this
section, the requirements in paragraphs (l)(1) through (4) of this
section shall apply. Examples of process changes include, but are not
limited to, changes in production capacity, or feed or raw material
where the change requires construction or physical alteration of the
existing equipment or catalyst type, or whenever there is replacement,
removal, or addition of recovery equipment. For purposes of this
paragraph (l) and paragraph (m) of this section, process changes do not
include: Process upsets, unintentional temporary process changes, and
changes that are within the equipment configuration and operating
conditions documented in the Notification of Compliance Status report
required by Sec. 63.655(f).
* * * * *
(2) The added emission point(s) and any emission point(s) within
the added or changed petroleum refining process unit shall be in
compliance with the applicable requirements in item (4) of table 11 of
this subpart by the dates specified in paragraph (l)(2)(i) or (ii) of
this section.
(i) If a petroleum refining process unit is added to a plant site
or an emission point(s) is added to any existing petroleum refining
process unit, the added emission point(s) shall be in compliance upon
initial startup of any added petroleum refining process unit or
emission point(s) or by the applicable compliance date in item (4) of
table 11 of this subpart, whichever is later.
* * * * *
(3) The owner or operator of a petroleum refining process unit or
of a storage vessel, miscellaneous process vent, wastewater stream,
gasoline loading rack, marine tank vessel loading operation, heat
exchange system, or decoking operation meeting the criteria in
paragraphs (c)(1) through (9) of this section that is added to a plant
site and is subject to the requirements for existing sources shall
comply with the reporting and recordkeeping requirements that are
applicable to existing sources including, but not limited to, the
reports listed in paragraphs (l)(3)(i) through (vii) of this section. A
process change to an existing petroleum refining process unit shall be
subject to the reporting requirements for existing sources including,
but not limited to, the reports listed in paragraphs (l)(3)(i) through
(vii) of this section. The applicable reports include, but are not
limited to:
* * * * *
(m) If a change that does not meet the criteria in paragraph (l) of
this section is made to a petroleum refining process unit subject to
this subpart, and the change causes a Group 2 emission point to become
a Group 1 emission point (as defined in Sec. 63.641), then the owner
or operator shall comply with the applicable requirements of this
subpart for existing sources, as specified in item (4) of table 11 of
this subpart, for the Group 1 emission point as expeditiously as
practicable, but in no event later than 3 years after the emission
point becomes Group 1.
* * * * *
(n) Overlap of this subpart with other regulations for storage
vessels. As applicable, paragraphs (n)(1), (3), (4), (6), and (7) of
this section apply for Group 2 storage vessels and paragraphs (n)(2)
and (5) of this section apply for Group 1 storage vessels.
(1) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is subject to the provisions of
40 CFR part 60, subpart Kb, is required to comply only with the
requirements of 40 CFR part 60, subpart Kb, except as provided in
paragraph (n)(8) of this section. After the compliance dates specified
in paragraph (h) of this section, a Group 2 storage vessel that is
subject to the provisions of 40 CFR part 61, subpart Y, is required to
comply only with the requirements of 40 CFR part 61, subpart Y, except
as provided in paragraph (n)(10) of this section.
(2) After the compliance dates specified in paragraph (h) of this
section, a Group 1 storage vessel that is also subject to 40 CFR part
60, subpart Kb, is required to comply only with either 40 CFR part 60,
subpart Kb, except as provided in paragraph (n)(8) of this section or
this subpart. After the compliance dates specified in paragraph (h) of
this section, a Group 1 storage vessel that is also subject to 40 CFR
part 61, subpart Y, is required to comply only with either 40 CFR part
61, subpart Y, except as provided in paragraph (n)(10) of this section
or this subpart.
(3) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is part of a new source and is
subject to 40 CFR 60.110b, but is not required to apply controls by 40
CFR 60.110b or 60.112b, is required to comply only with this subpart.
(4) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is part of a new source and is
subject to 40 CFR 61.270, but is not required to apply controls by 40
CFR 61.271, is required to comply only with this subpart.
(5) After the compliance dates specified in paragraph (h) of this
section, a Group 1 storage vessel that is also subject to the
provisions of 40 CFR part 60, subpart K or Ka, is required to only
comply with the provisions of this subpart.
* * * * *
(8) Storage vessels described by paragraph (n)(1) of this section
are to comply with 40 CFR part 60, subpart Kb, except as provided in
paragraphs (n)(8)(i) through (vi) of this section. Storage vessels
described by paragraph (n)(2) electing to comply with part 60, subpart
Kb of this chapter shall comply with subpart Kb except as provided in
paragraphs (n)(8)(i) through (viii) of this section.
* * * * *
(ii) If the owner or operator determines that it is unsafe to
perform the seal gap measurements required in Sec. 60.113b(b) of this
chapter or to inspect the vessel to determine compliance with

[[Page 75239]]

Sec. 60.113b(a) of this chapter because the roof appears to be
structurally unsound and poses an imminent danger to inspecting
personnel, the owner or operator shall comply with the requirements in
either Sec. 63.120(b)(7)(i) or (ii) of subpart G (only up to the
compliance date specified in paragraph (h) of this section for
compliance with Sec. 63.660, as applicable) or either Sec.
63.1063(c)(2)(iv)(A) or (B) of subpart WW.
* * * * *
(vii) To be in compliance with Sec. 60.112b(a)(1)(iv) or
(a)(2)(ii) of this chapter, guidepoles in floating roof storage vessels
must be equipped with covers and/or controls (e.g., pole float system,
pole sleeve system, internal sleeve system or flexible enclosure
system) as appropriate to comply with the ``no visible gap''
requirement.
(viii) If a flare is used as a control device for a storage vessel,
on and after January 30, 2019, the owner or operator must meet the
requirements of Sec. 63.670 instead of the requirements referenced
from part 60, subpart Kb of this chapter for that flare.
(9) * * *
(i) If the owner or operator determines that it is unsafe to
perform the seal gap measurements required in Sec. 60.113a(a)(1) of
this chapter because the floating roof appears to be structurally
unsound and poses an imminent danger to inspecting personnel, the owner
or operator shall comply with the requirements in either Sec.
63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date
specified in paragraph (h) of this section for compliance with Sec.
63.660, as applicable) or either Sec. 63.1063(c)(2)(iv)(A) or (B) of
subpart WW.
* * * * *
(10) Storage vessels described by paragraph (n)(1) of this section
are to comply with 40 CFR part 61, subpart Y, except as provided in
paragraphs (n)(10)(i) through (vi) of this section. Storage vessels
described by paragraph (n)(2) electing to comply with 40 CFR part 61,
subpart Y, shall comply with subpart Y except as provided for in
paragraphs (n)(10)(i) through (viii) of this section.
(i) Storage vessels that are to comply with Sec. 61.271(b) of this
chapter are exempt from the secondary seal requirements of Sec.
61.271(b)(2)(ii) of this chapter during the gap measurements for the
primary seal required by Sec. 61.272(b) of this chapter.
(ii) If the owner or operator determines that it is unsafe to
perform the seal gap measurements required in Sec. 61.272(b) of this
chapter or to inspect the vessel to determine compliance with Sec.
61.272(a) of this chapter because the roof appears to be structurally
unsound and poses an imminent danger to inspecting personnel, the owner
or operator shall comply with the requirements in either Sec.
63.120(b)(7)(i) or (ii) of subpart G (only up to the compliance date
specified in paragraph (h) of this section for compliance with Sec.
63.660, as applicable) or either Sec. 63.1063(c)(2)(iv)(A) or (B) of
subpart WW.
(iii) If a failure is detected during the inspections required by
Sec. 61.272(a)(2) of this chapter or during the seal gap measurements
required by Sec. 61.272(b)(1) of this chapter, and the vessel cannot
be repaired within 45 days and the vessel cannot be emptied within 45
days, the owner or operator may utilize up to two extensions of up to
30 additional calendar days each. The owner or operator is not required
to provide a request for the extension to the Administrator.
(iv) If an extension is utilized in accordance with paragraph
(n)(10)(iii) of this section, the owner or operator shall, in the next
periodic report, identify the vessel, provide the information listed in
Sec. 61.272(a)(2) or (b)(4)(iii) of this chapter, and describe the
nature and date of the repair made or provide the date the storage
vessel was emptied.
(v) Owners and operators of storage vessels complying with 40 CFR
part 61, subpart Y, may submit the inspection reports required by Sec.
61.275(a), (b)(1), and (d) of this chapter as part of the periodic
reports required by this subpart, rather than within the 60-day period
specified in Sec. 61.275(a), (b)(1), and (d) of this chapter.
(vi) The reports of rim seal inspections specified in Sec.
61.275(d) of this chapter are not required if none of the measured gaps
or calculated gap areas exceed the limitations specified in Sec.
61.272(b)(4) of this chapter. Documentation of the inspections shall be
recorded as specified in Sec. 61.276(a) of this chapter.
(vii) To be in compliance with Sec. 61.271(a)(6) or (b)(3) of this
chapter, guidepoles in floating roof storage vessels must be equipped
with covers and/or controls (e.g., pole float system, pole sleeve
system, internal sleeve system or flexible enclosure system) as
appropriate to comply with the ``no visible gap'' requirement.
(viii) If a flare is used as a control device for a storage vessel,
on and after January 30, 2019, the owner or operator must meet the
requirements of Sec. 63.670 instead of the requirements referenced
from part 61, subpart Y of this chapter for that flare.
(o) * * *
(2) * * *
(i) Comply with paragraphs (o)(2)(i)(A) through (D) of this
section.
* * * * *
(D) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec. 63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of 40 CFR part 61, subpart FF, and subpart G of this part, or the
requirements of Sec. 63.670.
(ii) Comply with paragraphs (o)(2)(ii)(A) through (C) of this
section.
* * * * *
(C) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec. 63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of 40 CFR part 61, subpart FF, and subpart G of this part, or the
requirements of Sec. 63.670.
* * * * *
(s) Overlap of this subpart with other regulation for flares. On
January 30, 2019, flares that are subject to the provisions of 40 CFR
60.18 or 63.11 and subject to this subpart are required to comply only
with the provisions specified in this subpart. Prior to January 30,
2019, flares that are subject to the provisions of 40 CFR 60.18 or
63.11 and elect to comply with the requirements in Sec. Sec. 63.670
and 63.671 are required to comply only with the provisions specified in
this subpart.
0
14. Section 63.641 is amended by:
0
a. Adding, in alphabetical order, definitions of ``Assist air,''
``Assist steam,'' ``Center steam,'' ``Closed blowdown system,''
``Combustion zone,'' ``Combustion zone gas,'' ``Decoking operations,''
``Delayed coking unit,'' ``Flare,'' ``Flare purge gas,'' ``Flare
supplemental gas,'' ``Flare sweep gas,'' ``Flare vent gas,'' ``Flexible
enclosure device,'' ``Force majeure event,'' ``Lower steam,'' ``Net
heating value,'' ``Perimeter assist air,'' ``Pilot gas,'' ``Premix
assist air,'' ``Regulated material,'' ``Thermal expansion relief
valve,'' ``Total steam,'' and ``Upper steam''; and
0
b. Revising the definitions of ``Delayed coker vent,'' ``Emission
point,'' ``Group 1 storage vessel,'' ``Miscellaneous process vent,''
``Periodically discharged,'' and ``Reference control technology for
storage vessels.''
The revisions and additions read as follows:

Sec. 63.641 Definitions.

* * * * *
Assist air means all air that intentionally is introduced prior to
or at

[[Page 75240]]

a flare tip through nozzles or other hardware conveyance for the
purposes including, but not limited to, protecting the design of the
flare tip, promoting turbulence for mixing or inducing air into the
flame. Assist air includes premix assist air and perimeter assist air.
Assist air does not include the surrounding ambient air.
Assist steam means all steam that intentionally is introduced prior
to or at a flare tip through nozzles or other hardware conveyance for
the purposes including, but not limited to, protecting the design of
the flare tip, promoting turbulence for mixing or inducing air into the
flame. Assist steam includes, but is not necessarily limited to, center
steam, lower steam and upper steam.
* * * * *
Center steam means the portion of assist steam introduced into the
stack of a flare to reduce burnback.
Closed blowdown system means a system used for depressuring process
vessels that is not open to the atmosphere and is configured of piping,
ductwork, connections, accumulators/knockout drums, and, if necessary,
flow inducing devices that transport gas or vapor from process vessel
to a control device or back into the process.
* * * * *
Combustion zone means the area of the flare flame where the
combustion zone gas combines for combustion.
Combustion zone gas means all gases and vapors found just after a
flare tip. This gas includes all flare vent gas, total steam, and
premix air.
* * * * *
Decoking operations means the sequence of steps conducted at the
end of the delayed coking unit's cooling cycle to open the coke drum to
the atmosphere in order to remove coke from the coke drum. Decoking
operations begin at the end of the cooling cycle when steam released
from the coke drum is no longer discharged via the unit's blowdown
system but instead is vented directly to the atmosphere. Decoking
operations include atmospheric depressuring (venting), deheading,
draining, and decoking (coke cutting).
Delayed coker vent means a miscellaneous process vent that contains
uncondensed vapors from the delayed coking unit's blowdown system.
Venting from the delayed coker vent is typically intermittent in
nature, and occurs primarily during the cooling cycle of a delayed
coking unit coke drum when vapor from the coke drums cannot be sent to
the fractionator column for product recovery. The emissions from the
decoking operations, which include direct atmospheric venting,
deheading, draining, or decoking (coke cutting), are not considered to
be delayed coker vents.
Delayed coking unit means a refinery process unit in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced in a series of closed, batch system
reactors. A delayed coking unit includes, but is not limited to, all of
the coke drums associated with a single fractionator; the fractionator,
including the bottoms receiver and the overhead condenser; the coke
drum cutting water and quench system, including the jet pump and coker
quench water tank; and the coke drum blowdown recovery compressor
system.
* * * * *
Emission point means an individual miscellaneous process vent,
storage vessel, wastewater stream, equipment leak, decoking operation
or heat exchange system associated with a petroleum refining process
unit; an individual storage vessel or equipment leak associated with a
bulk gasoline terminal or pipeline breakout station classified under
Standard Industrial Classification code 2911; a gasoline loading rack
classified under Standard Industrial Classification code 2911; or a
marine tank vessel loading operation located at a petroleum refinery.
* * * * *
Flare means a combustion device lacking an enclosed combustion
chamber that uses an uncontrolled volume of ambient air to burn gases.
For the purposes of this rule, the definition of flare includes, but is
not necessarily limited to, air-assisted flares, steam-assisted flares
and non-assisted flares.
Flare purge gas means gas introduced between a flare header's water
seal and the flare tip to prevent oxygen infiltration (backflow) into
the flare tip. For a flare with no water seal, the function of flare
purge gas is performed by flare sweep gas and, therefore, by
definition, such a flare has no flare purge gas.
Flare supplemental gas means all gas introduced to the flare in
order to improve the combustible characteristics of combustion zone
gas.
Flare sweep gas means, for a flare with a flare gas recovery
system, the gas intentionally introduced into the flare header system
to maintain a constant flow of gas through the flare header in order to
prevent oxygen buildup in the flare header; flare sweep gas in these
flares is introduced prior to and recovered by the flare gas recovery
system. For a flare without a flare gas recovery system, flare sweep
gas means the gas intentionally introduced into the flare header system
to maintain a constant flow of gas through the flare header and out the
flare tip in order to prevent oxygen buildup in the flare header and to
prevent oxygen infiltration (backflow) into the flare tip.
Flare vent gas means all gas found just prior to the flare tip.
This gas includes all flare waste gas (i.e., gas from facility
operations that is directed to a flare for the purpose of disposing of
the gas), that portion of flare sweep gas that is not recovered, flare
purge gas and flare supplemental gas, but does not include pilot gas,
total steam or assist air.
Flexible enclosure device means a seal made of an elastomeric
fabric (or other material) which completely encloses a slotted
guidepole or ladder and eliminates the vapor emission pathway from
inside the storage vessel through the guidepole slots or ladder slots
to the outside air.
* * * * *
Force majeure event means a release of HAP, either directly to the
atmosphere from a relief valve or discharged via a flare, that is
demonstrated to the satisfaction of the Administrator to result from an
event beyond the refinery owner or operator's control, such as natural
disasters; acts of war or terrorism; loss of a utility external to the
refinery (e.g., external power curtailment), excluding power
curtailment due to an interruptible service agreement; and fire or
explosion originating at a near or adjoining facility outside of the
refinery owner or operator's control that impacts the refinery's
ability to operate.
* * * * *
Group 1 storage vessel means:
(1) Prior to February 1, 2016:
(i) A storage vessel at an existing source that has a design
capacity greater than or equal to 177 cubic meters and stored-liquid
maximum true vapor pressure greater than or equal to 10.4 kilopascals
and stored-liquid annual average true vapor pressure greater than or
equal to 8.3 kilopascals and annual average HAP liquid concentration
greater than 4 percent by weight total organic HAP;
(ii) A storage vessel at a new source that has a design storage
capacity greater than or equal to 151 cubic meters and stored-liquid
maximum true vapor pressure greater than or equal to 3.4 kilopascals
and annual average HAP liquid concentration greater than 2 percent by
weight total organic HAP; or
(iii) A storage vessel at a new source that has a design storage
capacity greater than or equal to 76 cubic meters and less than 151
cubic meters and stored-

[[Page 75241]]

liquid maximum true vapor pressure greater than or equal to 77
kilopascals and annual average HAP liquid concentration greater than 2
percent by weight total organic HAP.
(2) On and after February 1, 2016:
(i) A storage vessel at an existing source that has a design
capacity greater than or equal to 151 cubic meters (40,000 gallons) and
stored-liquid maximum true vapor pressure greater than or equal to 5.2
kilopascals (0.75 pounds per square inch) and annual average HAP liquid
concentration greater than 4 percent by weight total organic HAP;
(ii) A storage vessel at an existing source that has a design
storage capacity greater than or equal to 76 cubic meters (20,000
gallons) and less than 151 cubic meters (40,000 gallons) and stored-
liquid maximum true vapor pressure greater than or equal to 13.1
kilopascals (1.9 pounds per square inch) and annual average HAP liquid
concentration greater than 4 percent by weight total organic HAP;
(iii) A storage vessel at a new source that has a design storage
capacity greater than or equal to 151 cubic meters (40,000 gallons) and
stored-liquid maximum true vapor pressure greater than or equal to 3.4
kilopascals (0.5 pounds per square inch) and annual average HAP liquid
concentration greater than 2 percent by weight total organic HAP; or
(iv) A storage vessel at a new source that has a design storage
capacity greater than or equal to 76 cubic meters (20,000 gallons) and
less than 151 cubic meters (40,000 gallons) and stored-liquid maximum
true vapor pressure greater than or equal to 13.1 kilopascals (1.9
pounds per square inch) and annual average HAP liquid concentration
greater than 2 percent by weight total organic HAP.
* * * * *
Lower steam means the portion of assist steam piped to an exterior
annular ring near the lower part of a flare tip, which then flows
through tubes to the flare tip, and ultimately exits the tubes at the
flare tip.
* * * * *
Miscellaneous process vent means a gas stream containing greater
than 20 parts per million by volume organic HAP that is continuously or
periodically discharged from a petroleum refining process unit meeting
the criteria specified in Sec. 63.640(a). Miscellaneous process vents
include gas streams that are discharged directly to the atmosphere, gas
streams that are routed to a control device prior to discharge to the
atmosphere, or gas streams that are diverted through a product recovery
device prior to control or discharge to the atmosphere. Miscellaneous
process vents include vent streams from: Caustic wash accumulators,
distillation tower condensers/accumulators, flash/knockout drums,
reactor vessels, scrubber overheads, stripper overheads, vacuum pumps,
steam ejectors, hot wells, high point bleeds, wash tower overheads,
water wash accumulators, blowdown condensers/accumulators, and delayed
coker vents. Miscellaneous process vents do not include:
(1) Gaseous streams routed to a fuel gas system, provided that on
and after January 30, 2019, any flares receiving gas from the fuel gas
system are in compliance with Sec. 63.670;
(2) Pressure relief device discharges;
(3) Leaks from equipment regulated under Sec. 63.648;
(4) [Reserved]
(5) In situ sampling systems (onstream analyzers) until January 30,
2019. After this date, these sampling systems will be included in the
definition of miscellaneous process vents;
(6) Catalytic cracking unit catalyst regeneration vents;
(7) Catalytic reformer regeneration vents;
(8) Sulfur plant vents;
(9) Vents from control devices such as scrubbers, boilers,
incinerators, and electrostatic precipitators applied to catalytic
cracking unit catalyst regeneration vents, catalytic reformer
regeneration vents, and sulfur plant vents;
(10) Vents from any stripping operations applied to comply with the
wastewater provisions of this subpart, subpart G of this part, or 40
CFR part 61, subpart FF;
(11) Emissions associated with delayed coking unit decoking
operations;
(12) Vents from storage vessels;
(13) Emissions from wastewater collection and conveyance systems
including, but not limited to, wastewater drains, sewer vents, and sump
drains; and
(14) Hydrogen production plant vents through which carbon dioxide
is removed from process streams or through which steam condensate
produced or treated within the hydrogen plant is degassed or deaerated.
Net heating value means the energy released as heat when a compound
undergoes complete combustion with oxygen to form gaseous carbon
dioxide and gaseous water (also referred to as lower heating value).
* * * * *
Perimeter assist air means the portion of assist air introduced at
the perimeter of the flare tip or above the flare tip. Perimeter assist
air includes air intentionally entrained in lower and upper steam.
Perimeter assist air includes all assist air except premix assist air.
Periodically discharged means discharges that are intermittent and
associated with routine operations, maintenance activities, startups,
shutdowns, malfunctions, or process upsets.
* * * * *
Pilot gas means gas introduced into a flare tip that provides a
flame to ignite the flare vent gas.
* * * * *
Premix assist air means the portion of assist air that is
introduced to the flare vent gas, whether injected or induced, prior to
the flare tip. Premix assist air also includes any air intentionally
entrained in center steam.
* * * * *
Reference control technology for storage vessels means either:
(1) For Group 1 storage vessels complying with Sec. 63.660:
(i) An internal floating roof, including an external floating roof
converted to an internal floating roof, meeting the specifications of
Sec. 63.1063(a)(1)(i) and (b);
(ii) An external floating roof meeting the specifications of Sec.
63.1063(a)(1)(ii), (a)(2), and (b); or
(iii) [Reserved]
(iv) A closed-vent system to a control device that reduces organic
HAP emissions by 95 percent, or to an outlet concentration of 20 parts
per million by volume (ppmv).
(v) For purposes of emissions averaging, these four technologies
are considered equivalent.
(2) For all other storage vessels:
(i) An internal floating roof meeting the specifications of Sec.
63.119(b) of subpart G except for Sec. 63.119(b)(5) and (6);
(ii) An external floating roof meeting the specifications of Sec.
63.119(c) of subpart G except for Sec. 63.119(c)(2);
(iii) An external floating roof converted to an internal floating
roof meeting the specifications of Sec. 63.119(d) of subpart G except
for Sec. 63.119(d)(2); or
(iv) A closed-vent system to a control device that reduces organic
HAP emissions by 95 percent, or to an outlet concentration of 20 parts
per million by volume.
(v) For purposes of emissions averaging, these four technologies
are considered equivalent.
* * * * *
Regulated material means any stream associated with emission
sources listed

[[Page 75242]]

in Sec. 63.640(c) required to meet control requirements under this
subpart as well as any stream for which this subpart or a cross-
referencing subpart specifies that the requirements for flare control
devices in Sec. 63.670 must be met.
* * * * *
Thermal expansion relief valve means a pressure relief valve
designed to protect equipment from excess pressure due to thermal
expansion of blocked liquid-filled equipment or piping due to ambient
heating or heat from a heat tracing system. Pressure relief valves
designed to protect equipment from excess pressure due to blockage
against a pump or compressor or due to fire contingency are not thermal
expansion relief valves.
* * * * *
Total steam means the total of all steam that is supplied to a
flare and includes, but is not limited to, lower steam, center steam
and upper steam.
Upper steam means the portion of assist steam introduced via
nozzles located on the exterior perimeter of the upper end of the flare
tip.
* * * * *

0
15. Section 63.642 is amended by:
0
a. Adding paragraph (b);
0
b. Revising paragraphs (d)(3), (e), (i), (k) introductory text, (k)(1),
(l) introductory text, and (l)(2); and
0
c. Adding paragraph (n).
The revisions and additions read as follows:

Sec. 63.642 General standards.

* * * * *
(b) The emission standards set forth in this subpart shall apply at
all times.
* * * * *
(d) * * *
(3) Performance tests shall be conducted according to the
provisions of Sec. 63.7(e) except that performance tests shall be
conducted at maximum representative operating capacity for the process.
During the performance test, an owner or operator shall operate the
control device at either maximum or minimum representative operating
conditions for monitored control device parameters, whichever results
in lower emission reduction. An owner or operator shall not conduct a
performance test during startup, shutdown, periods when the control
device is bypassed or periods when the process, monitoring equipment or
control device is not operating properly. The owner/operator may not
conduct performance tests during periods of malfunction. The owner or
operator must record the process information that is necessary to
document operating conditions during the test and include in such
record an explanation to support that the test was conducted at maximum
representative operating capacity. Upon request, the owner or operator
shall make available to the Administrator such records as may be
necessary to determine the conditions of performance tests.
* * * * *
(e) All applicable records shall be maintained as specified in
Sec. 63.655(i).
* * * * *
(i) The owner or operator of an existing source shall demonstrate
compliance with the emission standard in paragraph (g) of this section
by following the procedures specified in paragraph (k) of this section
for all emission points, or by following the emissions averaging
compliance approach specified in paragraph (l) of this section for
specified emission points and the procedures specified in paragraph
(k)(1) of this section.
* * * * *
(k) The owner or operator of an existing source may comply, and the
owner or operator of a new source shall comply, with the applicable
provisions in Sec. Sec. 63.643 through 63.645, 63.646 or 63.660,
63.647, 63.650, and 63.651, as specified in Sec. 63.640(h).
(1) The owner or operator using this compliance approach shall also
comply with the requirements of Sec. Sec. 63.648 and/or 63.649,
63.654, 63.655, 63.657, 63.658, 63.670 and 63.671, as applicable.
* * * * *
(l) The owner or operator of an existing source may elect to
control some of the emission points within the source to different
levels than specified under Sec. Sec. 63.643 through 63.645, 63.646 or
63.660, 63.647, 63.650, and 63.651, as applicable according to Sec.
63.640(h), by using an emissions averaging compliance approach as long
as the overall emissions for the source do not exceed the emission
level specified in paragraph (g) of this section. The owner or operator
using emissions averaging shall meet the requirements in paragraphs
(l)(1) and (2) of this section.
* * * * *
(2) Comply with the requirements of Sec. Sec. 63.648 and/or
63.649, 63.654, 63.652, 63.653, 63.655, 63.657, 63.658, 63.670 and
63.671, as applicable.
* * * * *
(n) At all times, the owner or operator must operate and maintain
any affected source, including associated air pollution control
equipment and monitoring equipment, in a manner consistent with safety
and good air pollution control practices for minimizing emissions. The
general duty to minimize emissions does not require the owner operator
to make any further efforts to reduce emissions if levels required by
the applicable standard have been achieved. Determination of whether a
source is operating in compliance with operation and maintenance
requirements will be based on information available to the
Administrator which may include, but is not limited to, monitoring
results, review of operation and maintenance procedures, review of
operation and maintenance records, and inspection of the source.

0
16. Section 63.643 is amended by revising paragraphs (a) introductory
text and (a)(1) and adding paragraph (c) to read as follows:

Sec. 63.643 Miscellaneous process vent provisions.

(a) The owner or operator of a Group 1 miscellaneous process vent
as defined in Sec. 63.641 shall comply with the requirements of either
paragraph (a)(1) or (2) of this section or, if applicable, paragraph
(c) of this section. The owner or operator of a miscellaneous process
vent that meets the conditions in paragraph (c) of this section is only
required to comply with the requirements of paragraph (c) of this
section and Sec. 63.655(g)(13) and (i)(12) for that vent.
(1) Reduce emissions of organic HAP's using a flare. On and after
January 30, 2019, the flare shall meet the requirements of Sec.
63.670. Prior to January 30, 2019, the flare shall meet the
requirements of Sec. 63.11(b) of subpart A or the requirements of
Sec. 63.670.
* * * * *
(c) An owner or operator may designate a process vent as a
maintenance vent if the vent is only used as a result of startup,
shutdown, maintenance, or inspection of equipment where equipment is
emptied, depressurized, degassed or placed into service. The owner of
operator does not need to designate a maintenance vent as a Group 1 or
Group 2 miscellaneous process vent. The owner or operator must comply
with the applicable requirements in paragraphs (c)(1) through (3) of
this section for each maintenance vent.
(1) Prior to venting to the atmosphere, process liquids are removed
from the equipment as much as practical and the equipment is
depressured to a control device, fuel gas system, or back to the
process until one of the following conditions, as applicable, is met.
(i) The vapor in the equipment served by the maintenance vent has a
lower

[[Page 75243]]

explosive limit (LEL) of less than 10 percent.
(ii) If there is no ability to measure the LEL of the vapor in the
equipment based on the design of the equipment, the pressure in the
equipment served by the maintenance vent is reduced to 5 psig or less.
Upon opening the maintenance vent, active purging of the equipment
cannot be used until the LEL of the vapors in the maintenance vent (or
inside the equipment if the maintenance is a hatch or similar type of
opening) equipment is less than 10 percent.
(iii) The equipment served by the maintenance vent contains less
than 72 pounds of VOC.
(iv) If the maintenance vent is associated with equipment
containing pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers)
at refineries that do not have a pure hydrogen supply, the LEL of the
vapor in the equipment must be less than 20 percent, except for one
event per year not to exceed 35 percent.
(2) Except for maintenance vents complying with the alternative in
paragraph (c)(1)(iii) of this section, the owner or operator must
determine the LEL or, if applicable, equipment pressure using process
instrumentation or portable measurement devices and follow procedures
for calibration and maintenance according to manufacturer's
specifications.
(3) For maintenance vents complying with the alternative in
paragraph (c)(1)(iii) of this section, the owner or operator shall
determine mass of VOC in the equipment served by the maintenance vent
based on the equipment size and contents after considering any contents
drained or purged from the equipment. Equipment size may be determined
from equipment design specifications. Equipment contents may be
determined using process knowledge.

0
17. Section 63.644 is amended by revising paragraphs (a) introductory
text, (a)(2), and (c) to read as follows:

Sec. 63.644 Monitoring provisions for miscellaneous process vents.

(a) Except as provided in paragraph (b) of this section, each owner
or operator of a Group 1 miscellaneous process vent that uses a
combustion device to comply with the requirements in Sec. 63.643(a)
shall install the monitoring equipment specified in paragraph (a)(1),
(2), (3), or (4) of this section, depending on the type of combustion
device used. All monitoring equipment shall be installed, calibrated,
maintained, and operated according to manufacturer's specifications or
other written procedures that provide adequate assurance that the
equipment will monitor accurately and, except for CPMS installed for
pilot flame monitoring, must meet the applicable minimum accuracy,
calibration and quality control requirements specified in table 13 of
this subpart.
* * * * *
(2) Where a flare is used prior to January 30, 2019, a device
(including but not limited to a thermocouple, an ultraviolet beam
sensor, or an infrared sensor) capable of continuously detecting the
presence of a pilot flame is required, or the requirements of Sec.
63.670 shall be met. Where a flare is used on and after January 30,
2019, the requirements of Sec. 63.670 shall be met.
* * * * *
(c) The owner or operator of a Group 1 miscellaneous process vent
using a vent system that contains bypass lines that could divert a vent
stream away from the control device used to comply with paragraph (a)
of this section either directly to the atmosphere or to a control
device that does not comply with the requirements in Sec. 63.643(a)
shall comply with either paragraph (c)(1) or (2) of this section. Use
of the bypass at any time to divert a Group 1 miscellaneous process
vent stream to the atmosphere or to a control device that does not
comply with the requirements in Sec. 63.643(a) is an emissions
standards violation. Equipment such as low leg drains and equipment
subject to Sec. 63.648 are not subject to this paragraph (c).
(1) Install, calibrate and maintain a flow indicator that
determines whether a vent stream flow is present at least once every
hour. A manual block valve equipped with a valve position indicator may
be used in lieu of a flow indicator, as long as the valve position
indicator is monitored continuously. Records shall be generated as
specified in Sec. 63.655(h) and (i). The flow indicator shall be
installed at the entrance to any bypass line that could divert the vent
stream away from the control device to the atmosphere; or
(2) Secure the bypass line valve in the non-diverting position with
a car-seal or a lock-and-key type configuration. A visual inspection of
the seal or closure mechanism shall be performed at least once every
month to ensure that the valve is maintained in the non-diverting
position and that the vent stream is not diverted through the bypass
line.
* * * * *

0
18. Section 63.645 is amended by revising paragraphs (e)(1) and (f)(2)
to read as follows:

Sec. 63.645 Test methods and procedures for miscellaneous process
vents.

* * * * *
(e) * * *
(1) Methods 1 or 1A of 40 CFR part 60, appendix A-1, as
appropriate, shall be used for selection of the sampling site. For
vents smaller than 0.10 meter in diameter, sample at the center of the
vent.
* * * * *
(f) * * *
(2) The gas volumetric flow rate shall be determined using Methods
2, 2A, 2C, 2D, or 2F of 40 CFR part 60, appendix A-1 or Method 2G of 40
CFR part 60, appendix A-2, as appropriate.
* * * * *

0
19. Section 63.646 is amended by adding introductory text and revising
paragraph (b)(2) to read as follows:

Sec. 63.646 Storage vessel provisions.

Upon a demonstration of compliance with the standards in Sec.
63.660 by the compliance dates specified in Sec. 63.640(h), the
standards in this section shall no longer apply.
* * * * *
(b) * * *
(2) When an owner or operator and the Administrator do not agree on
whether the annual average weight percent organic HAP in the stored
liquid is above or below 4 percent for a storage vessel at an existing
source or above or below 2 percent for a storage vessel at a new
source, an appropriate method (based on the type of liquid stored) as
published by EPA or a consensus-based standards organization shall be
used. Consensus-based standards organizations include, but are not
limited to, the following: ASTM International (100 Barr Harbor Drive,
P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-
1373, https://www.astm.org), the American National Standards Institute
(ANSI, 1819 L Street NW., 6th floor, Washington, DC 20036, (202) 293-
8020, https://www.ansi.org), the American Gas Association (AGA, 400
North Capitol Street NW., 4th Floor, Washington, DC 20001, (202) 824-
7000, https://www.aga.org), the American Society of Mechanical Engineers
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763,
https://www.asme.org), the American Petroleum Institute (API, 1220 L
Street NW., Washington, DC 20005-4070, (202) 682-8000, https://www.api.org), and the North American Energy Standards Board (NAESB, 801
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, https://www.naesb.org).
* * * * *

[[Page 75244]]

0
20. Section 63.647 is amended by:
0
a. Revising paragraph (a);
0
b. Redesignating paragraph (c) as paragraph (d); and
0
c. Adding paragraph (c).
The revisions and additions read as follows:

Sec. 63.647 Wastewater provisions.

(a) Except as provided in paragraphs (b) and (c) of this section,
each owner or operator of a Group 1 wastewater stream shall comply with
the requirements of Sec. Sec. 61.340 through 61.355 of this chapter
for each process wastewater stream that meets the definition in Sec.
63.641.
* * * * *
(c) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec. 63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of part 61, subpart FF of this chapter, or the requirements of Sec.
63.670.
* * * * *

0
21. Section 63.648 is amended by:
0
a. Adding paragraph (a)(3);
0
b. Revising paragraph (c) introductory text; and
0
c. Adding paragraphs (c)(11) and (12) and (j).
The revisions and additions read as follows:

Sec. 63.648 Equipment leak standards.

(a) * * *
(3) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec. 63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of part 60, subpart VV of this chapter, or the requirements of Sec.
63.670.
* * * * *
(c) In lieu of complying with the existing source provisions of
paragraph (a) in this section, an owner or operator may elect to comply
with the requirements of Sec. Sec. 63.161 through 63.169, 63.171,
63.172, 63.175, 63.176, 63.177, 63.179, and 63.180 of subpart H except
as provided in paragraphs (c)(1) through (12) and (e) through (i) of
this section.
* * * * *
(11) [Reserved]
(12) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec. 63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of Sec. Sec. 63.172 and 63.180, or the requirements of Sec. 63.670.
* * * * *
(j) Except as specified in paragraph (j)(4) of this section, the
owner or operator must comply with the requirements specified in
paragraphs (j)(1) and (2) of this section for pressure relief devices,
such as relief valves or rupture disks, in organic HAP gas or vapor
service instead of the pressure relief device requirements of Sec.
60.482-4 or Sec. 63.165, as applicable. Except as specified in
paragraphs (j)(4) and (5) of this section, the owner or operator must
also comply with the requirements specified in paragraph (j)(3) of this
section for all pressure relief devices.
(1) Operating requirements. Except during a pressure release,
operate each pressure relief device in organic HAP gas or vapor service
with an instrument reading of less than 500 ppm above background as
detected by Method 21 of 40 CFR part 60, appendix A-7.
(2) Pressure release requirements. For pressure relief devices in
organic HAP gas or vapor service, the owner or operator must comply
with the applicable requirements in paragraphs (j)(2)(i) through (iii)
of this section following a pressure release.
(i) If the pressure relief device does not consist of or include a
rupture disk, conduct instrument monitoring, as specified in Sec.
60.485(b) or Sec. 63.180(c), as applicable, no later than 5 calendar
days after the pressure relief device returns to organic HAP gas or
vapor service following a pressure release to verify that the pressure
relief device is operating with an instrument reading of less than 500
ppm.
(ii) If the pressure relief device includes a rupture disk, either
comply with the requirements in paragraph (j)(2)(i) of this section
(not replacing the rupture disk) or install a replacement disk as soon
as practicable after a pressure release, but no later than 5 calendar
days after the pressure release. The owner or operator must conduct
instrument monitoring, as specified in Sec. 60.485(b) or Sec.
63.180(c), as applicable, no later than 5 calendar days after the
pressure relief device returns to organic HAP gas or vapor service
following a pressure release to verify that the pressure relief device
is operating with an instrument reading of less than 500 ppm.
(iii) If the pressure relief device consists only of a rupture
disk, install a replacement disk as soon as practicable after a
pressure release, but no later than 5 calendar days after the pressure
release. The owner or operator may not initiate startup of the
equipment served by the rupture disk until the rupture disc is
replaced. The owner or operator must conduct instrument monitoring, as
specified in Sec. 60.485(b) or Sec. 63.180(c), as applicable, no
later than 5 calendar days after the pressure relief device returns to
organic HAP gas or vapor service following a pressure release to verify
that the pressure relief device is operating with an instrument reading
of less than 500 ppm.
(3) Pressure release management. Except as specified in paragraphs
(j)(4) and (5) of this section, the owner or operator shall comply with
the requirements specified in paragraphs (j)(3)(i) through (v) of this
section for all pressure relief devices in organic HAP service no later
than January 30, 2019.
(i) The owner or operator must equip each affected pressure relief
device with a device(s) or use a monitoring system that is capable of:
(A) Identifying the pressure release;
(B) Recording the time and duration of each pressure release; and
(C) Notifying operators immediately that a pressure release is
occurring. The device or monitoring system may be either specific to
the pressure relief device itself or may be associated with the process
system or piping, sufficient to indicate a pressure release to the
atmosphere. Examples of these types of devices and systems include, but
are not limited to, a rupture disk indicator, magnetic sensor, motion
detector on the pressure relief valve stem, flow monitor, or pressure
monitor.
(ii) The owner or operator must apply at least three redundant
prevention measures to each affected pressure relief device and
document these measures. Examples of prevention measures include:
(A) Flow, temperature, level and pressure indicators with deadman
switches, monitors, or automatic actuators.
(B) Documented routine inspection and maintenance programs and/or
operator training (maintenance programs and operator training may count
as only one redundant prevention measure).
(C) Inherently safer designs or safety instrumentation systems.
(D) Deluge systems.
(E) Staged relief system where initial pressure relief valve (with
lower set release pressure) discharges to a flare or other closed vent
system and control device.
(iii) If any affected pressure relief device releases to atmosphere
as a result of a pressure release event, the owner or operator must
perform root cause analysis and corrective action analysis according to
the requirement in paragraph (j)(6) of this section and implement
corrective actions according to the requirements in paragraph (j)(7) of
this section. The owner or operator must also calculate the quantity of
organic HAP released during each pressure

[[Page 75245]]

release event and report this quantity as required in Sec.
63.655(g)(10)(iii). Calculations may be based on data from the pressure
relief device monitoring alone or in combination with process parameter
monitoring data and process knowledge.
(iv) The owner or operator shall determine the total number of
release events occurred during the calendar year for each affected
pressure relief device separately. The owner or operator shall also
determine the total number of release events for each pressure relief
device for which the root cause analysis concluded that the root cause
was a force majeureevent, as defined in this subpart.
(v) Except for pressure relief devices described in paragraphs
(j)(4) and (5) of this section, the following release events are a
violation of the pressure release management work practice standards.
(A) Any release event for which the root cause of the event was
determined to be operator error or poor maintenance.
(B) A second release event not including force majeure events from
a single pressure relief device in a 3 calendar year period for the
same root cause for the same equipment.
(C) A third release event not including force majeure events from a
single pressure relief device in a 3 calendar year period for any
reason.
(4) Pressure relief devices routed to a control device. If all
releases and potential leaks from a pressure relief device are routed
through a closed vent system to a control device, back into the process
or to the fuel gas system, the owner or operator is not required to
comply with paragraph (j)(1), (2), or (3) (if applicable) of this
section. Both the closed vent system and control device (if applicable)
must meet the requirements of Sec. 63.644. When complying with this
paragraph (j)(4), all references to ``Group 1 miscellaneous process
vent'' in Sec. 63.644 mean ``pressure relief device.'' If a pressure
relief device complying with this paragraph (j)(4) is routed to the
fuel gas system, then on and after January 30, 2019, any flares
receiving gas from that fuel gas system must be in compliance with
Sec. 63.670.
(5) Pressure relief devices exempted from pressure release
management requirements. The following types of pressure relief devices
are not subject to the pressure release management requirements in
paragraph (j)(3) of this section.
(i) Pressure relief devices in heavy liquid service, as defined in
Sec. 63.641.
(ii) Pressure relief devices that only release material that is
liquid at standard conditions (1 atmosphere and 68 degrees Fahrenheit)
and that are hard-piped to a controlled drain system (i.e., a drain
system meeting the requirements for Group 1 wastewater streams in Sec.
63.647(a)) or piped back to the process or pipeline.
(iii) Thermal expansion relief valves.
(iv) Pressure relief devices designed with a set relief pressure of
less than 2.5 psig.
(v) Pressure relief devices that do not have the potential to emit
72 lbs/day or more of VOC based on the valve diameter, the set release
pressure, and the equipment contents.
(vi) Pressure relief devices on mobile equipment.
(6) Root cause analysis and corrective action analysis. A root
cause analysis and corrective action analysis must be completed as soon
as possible, but no later than 45 days after a release event. Special
circumstances affecting the number of root cause analyses and/or
corrective action analyses are provided in paragraphs (j)(6)(i) through
(iv) of this section.
(i) You may conduct a single root cause analysis and corrective
action analysis for a single emergency event that causes two or more
pressure relief devices installed on the same equipment to release.
(ii) You may conduct a single root cause analysis and corrective
action analysis for a single emergency event that causes two or more
pressure relief devices to release, regardless of the equipment served,
if the root cause is reasonably expected to be a force majeure event,
as defined in this subpart.
(iii) Except as provided in paragraphs (j)(6)(i) and (ii) of this
section, if more than one pressure relief device has a release during
the same time period, an initial root cause analysis shall be conducted
separately for each pressure relief device that had a release. If the
initial root cause analysis indicates that the release events have the
same root cause(s), the initially separate root cause analyses may be
recorded as a single root cause analysis and a single corrective action
analysis may be conducted.
(7) Corrective action implementation. Each owner or operator
required to conduct a root cause analysis and corrective action
analysis as specified in paragraphs (j)(3)(iii) and (j)(6) of this
section shall implement the corrective action(s) identified in the
corrective action analysis in accordance with the applicable
requirements in paragraphs (j)(7)(i) through (iii) of this section.
(i) All corrective action(s) must be implemented within 45 days of
the event for which the root cause and corrective action analyses were
required or as soon thereafter as practicable. If an owner or operator
concludes that no corrective action should be implemented, the owner or
operator shall record and explain the basis for that conclusion no
later than 45 days following the event.
(ii) For corrective actions that cannot be fully implemented within
45 days following the event for which the root cause and corrective
action analyses were required, the owner or operator shall develop an
implementation schedule to complete the corrective action(s) as soon as
practicable.
(iii) No later than 45 days following the event for which a root
cause and corrective action analyses were required, the owner or
operator shall record the corrective action(s) completed to date, and,
for action(s) not already completed, a schedule for implementation,
including proposed commencement and completion dates.

0
22. Section 63.649 is amended by revising definition of Cc
term in the equation in paragraph (c)(6)(i) to read as follows:

Sec. 63.649 Alternative means of emission limitation: Connectors in
gas/vapor service and light liquid service.

* * * * *
(c) * * *
(6) * * *
(i) * * *

Cc = Optional credit for removed connectors = 0.67 x net
number (i.e., the total number of connectors removed minus the total
added) of connectors in organic HAP service removed from the process
unit after the applicability date set forth in Sec.
63.640(h)(3)(iii) for existing process units, and after the date of
start-up for new process units. If credits are not taken, then
Cc = 0.

* * * * *

0
23. Section 63.650 is amended by revising paragraph (a) and adding
paragraph (d) to read as follows:

Sec. 63.650 Gasoline loading rack provisions.

(a) Except as provided in paragraphs (b) through (d) of this
section, each owner or operator of a Group 1 gasoline loading rack
classified under Standard Industrial Classification code 2911 located
within a contiguous area and under common control with a petroleum
refinery shall comply with subpart R of this part, Sec. Sec. 63.421,
63.422(a) through (c) and (e), 63.425(a) through (c) and (e) through
(i), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3),
and (k).
* * * * *

[[Page 75246]]

(d) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec. 63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of subpart R of this part, or the requirements of Sec. 63.670.

0
24. Section 63.651 is amended by revising paragraphs (a) and (d) and
adding paragraph (e) to read as follows:

Sec. 63.651 Marine tank vessel loading operation provisions.

(a) Except as provided in paragraphs (b) through (e) of this
section, each owner or operator of a marine tank vessel loading
operation located at a petroleum refinery shall comply with the
requirements of Sec. Sec. 63.560 through 63.568.
* * * * *
(d) The compliance time of 4 years after promulgation of 40 CFR
part 63, subpart Y, does not apply. The compliance time is specified in
Sec. 63.640(h)(1).
(e) If a flare is used as a control device, on and after January
30, 2019, the flare shall meet the requirements of Sec. 63.670. Prior
to January 30, 2019, the flare shall meet the applicable requirements
of subpart Y of this part, or the requirements of Sec. 63.670.

0
25. Section 63.652 is amended by:
0
a. Revising paragraph (a);
0
b. Removing and reserving paragraph (f)(2); and
0
c. Revising paragraphs (g)(2)(iii)(B)(1), (h)(3), (k) introductory
text, and (k)(3).
The revisions and additions read as follows:

Sec. 63.652 Emissions averaging provisions.

(a) This section applies to owners or operators of existing sources
who seek to comply with the emission standard in Sec. 63.642(g) by
using emissions averaging according to Sec. 63.642(l) rather than
following the provisions of Sec. Sec. 63.643 through 63.645, 63.646 or
63.660, 63.647, 63.650, and 63.651. Existing marine tank vessel loading
operations located at the Valdez Marine Terminal source may not comply
with the standard by using emissions averaging.
* * * * *
(g) * * *
(2) * * *
(iii) * * *
(B) * * *
(1) The percent reduction shall be measured according to the
procedures in Sec. 63.116 of subpart G if a combustion control device
is used. For a flare meeting the criteria in Sec. 63.116(a) of subpart
G or Sec. 63.670, as applicable, or a boiler or process heater meeting
the criteria in Sec. 63.645(d) or Sec. 63.116(b) of subpart G, the
percentage of reduction shall be 98 percent. If a noncombustion control
device is used, percentage of reduction shall be demonstrated by a
performance test at the inlet and outlet of the device, or, if testing
is not feasible, by a control design evaluation and documented
engineering calculations.
* * * * *
(h) * * *
(3) Emissions from storage vessels shall be determined as specified
in Sec. 63.150(h)(3) of subpart G, except as follows:
(i) For storage vessels complying with Sec. 63.646:
(A) All references to Sec. 63.119(b) in Sec. 63.150(h)(3) of
subpart G shall be replaced with: Sec. 63.119(b) or Sec. 63.119(b)
except for Sec. 63.119(b)(5) and (6).
(B) All references to Sec. 63.119(c) in Sec. 63.150(h)(3) of
subpart G shall be replaced with: Sec. 63.119(c) or Sec. 63.119(c)
except for Sec. 63.119(c)(2).
(C) All references to Sec. 63.119(d) in Sec. 63.150(h)(3) of
subpart G shall be replaced with: Sec. 63.119(d) or Sec. 63.119(d)
except for Sec. 63.119(d)(2).
(ii) For storage vessels complying with Sec. 63.660:
(A) Section 63.1063(a)(1)(i), (a)(2), and (b) or Sec.
63.1063(a)(1)(i) and (b) shall apply instead of Sec. 63.119(b) in
Sec. 63.150(h)(3) of subpart G.
(B) Section 63.1063(a)(1)(ii), (a)(2), and (b) shall apply instead
of Sec. 63.119(c) in Sec. 63.150(h)(3) of subpart G.
(C) Section 63.1063(a)(1)(i), (a)(2), and (b) or Sec.
63.1063(a)(1)(i) and (b) shall apply instead of Sec. 63.119(d) in
Sec. 63.150(h)(3) of subpart G.
* * * * *
(k) The owner or operator shall demonstrate that the emissions from
the emission points proposed to be included in the average will not
result in greater hazard or, at the option of the State or local
permitting authority, greater risk to human health or the environment
than if the emission points were controlled according to the provisions
in Sec. Sec. 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650,
and 63.651, as applicable.
* * * * *
(3) An emissions averaging plan that does not demonstrate an
equivalent or lower hazard or risk to the satisfaction of the State or
local permitting authority shall not be approved. The State or local
permitting authority may require such adjustments to the emissions
averaging plan as are necessary in order to ensure that the average
will not result in greater hazard or risk to human health or the
environment than would result if the emission points were controlled
according to Sec. Sec. 63.643 through 63.645, 63.646 or 63.660,
63.647, 63.650, and 63.651, as applicable.
* * * * *

0
26. Section 63.653 is amended by revising paragraphs (a) introductory
text, (a)(3)(i) and (ii), and (a)(7) to read as follows:

Sec. 63.653 Monitoring, recordkeeping, and implementation plan for
emissions averaging.

(a) For each emission point included in an emissions average, the
owner or operator shall perform testing, monitoring, recordkeeping, and
reporting equivalent to that required for Group 1 emission points
complying with Sec. Sec. 63.643 through 63.645, 63.646 or 63.660,
63.647, 63.650, and 63.651, as applicable. The specific requirements
for miscellaneous process vents, storage vessels, wastewater, gasoline
loading racks, and marine tank vessels are identified in paragraphs
(a)(1) through (7) of this section.
* * * * *
(3) * * *
(i) Perform the monitoring or inspection procedures in Sec. 63.646
and either Sec. 63.120 of subpart G or Sec. 63.1063 of subpart WW, as
applicable; and
(ii) For closed vent systems with control devices, conduct an
initial design evaluation as specified in Sec. 63.646 and either Sec.
63.120(d) of subpart G or Sec. 63.985(b) of subpart SS, as applicable.
* * * * *
(7) If an emission point in an emissions average is controlled
using a pollution prevention measure or a device or technique for which
no monitoring parameters or inspection procedures are specified in
Sec. Sec. 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and
63.651, as applicable, the owner or operator shall establish a site-
specific monitoring parameter and shall submit the information
specified in Sec. 63.655(h)(4) in the Implementation Plan.
* * * * *

0
27. Section 63.655 is amended by:
0
a. Revising paragraphs (f) introductory text, (f)(1) introductory text,
(f)(1)(i)(A) introductory text, (f)(1)(i)(A)(2) and (3), (f)(1)(i)(B)
introductory text, (f)(1)(i)(B)(2), (f)(1)(i)(D)(2), (f)(1)(iv)
introductory text, and (f)(1)(iv)(A);
0
b. Adding paragraphs (f)(1)(vii) and (viii);
0
c. Revising paragraphs (f)(2) introductory text, (f)(3) introductory
text, the first sentence of (f)(6), (g) introductory text, (g)(1)
through (5), (g)(6)(i)(D), (g)(6)(iii), and (g)(7)(i);

[[Page 75247]]

0
d. Adding paragraphs (g)(10) through (14);
0
e. Removing and reserving paragraph (h)(1);
0
f. Revising paragraphs (h)(2) introductory text, (h)(2)(i)(B),
(h)(2)(ii), and (h)(5)(iii);
0
g. Adding paragraphs (h)(8) and (9) and (i) introductory text;
0
h. Revising paragraph (i)(1) introductory text and paragraph
(i)(1)(ii);
0
i. Adding paragraphs (i)(1)(v) and (vi);
0
j. Redesignating paragraphs (i)(4) and (5) as paragraphs (i)(5) and
(6), respectively;
0
k. Adding paragraph (i)(4);
0
l. Revising newly redesignated paragraph (i)(5) introductory text; and
0
m. Adding paragraphs (i)(7) through (12).
The revisions and additions read as follows:

Sec. 63.655 Reporting and recordkeeping requirements.

* * * * *
(f) Each owner or operator of a source subject to this subpart
shall submit a Notification of Compliance Status report within 150 days
after the compliance dates specified in Sec. 63.640(h) with the
exception of Notification of Compliance Status reports submitted to
comply with Sec. 63.640(l)(3) and for storage vessels subject to the
compliance schedule specified in Sec. 63.640(h)(2). Notification of
Compliance Status reports required by Sec. 63.640(l)(3) and for
storage vessels subject to the compliance dates specified in Sec.
63.640(h)(2) shall be submitted according to paragraph (f)(6) of this
section. This information may be submitted in an operating permit
application, in an amendment to an operating permit application, in a
separate submittal, or in any combination of the three. If the required
information has been submitted before the date 150 days after the
compliance date specified in Sec. 63.640(h), a separate Notification
of Compliance Status report is not required within 150 days after the
compliance dates specified in Sec. 63.640(h). If an owner or operator
submits the information specified in paragraphs (f)(1) through (5) of
this section at different times, and/or in different submittals, later
submittals may refer to earlier submittals instead of duplicating and
resubmitting the previously submitted information. Each owner or
operator of a gasoline loading rack classified under Standard
Industrial Classification Code 2911 located within a contiguous area
and under common control with a petroleum refinery subject to the
standards of this subpart shall submit the Notification of Compliance
Status report required by subpart R of this part within 150 days after
the compliance dates specified in Sec. 63.640(h).
(1) The Notification of Compliance Status report shall include the
information specified in paragraphs (f)(1)(i) through (viii) of this
section.
(i) * * *
(A) Identification of each storage vessel subject to this subpart,
and for each Group 1 storage vessel subject to this subpart, the
information specified in paragraphs (f)(1)(i)(A)(1) through (3) of this
section. This information is to be revised each time a Notification of
Compliance Status report is submitted for a storage vessel subject to
the compliance schedule specified in Sec. 63.640(h)(2) or to comply
with Sec. 63.640(l)(3).
* * * * *
(2) For storage vessels subject to the compliance schedule
specified in Sec. 63.640(h)(2) that are not complying with Sec.
63.646, the anticipated compliance date.
(3) For storage vessels subject to the compliance schedule
specified in Sec. 63.640(h)(2) that are complying with Sec. 63.646
and the Group 1 storage vessels described in Sec. 63.640(l), the
actual compliance date.
(B) If a closed vent system and a control device other than a flare
is used to comply with Sec. 63.646 or Sec. 63.660, the owner or
operator shall submit:
* * * * *
(2) The design evaluation documentation specified in Sec.
63.120(d)(1)(i) of subpart G or Sec. 63.985(b)(1)(i) of subpart SS (as
applicable), if the owner or operator elects to prepare a design
evaluation; or
* * * * *
(D) * * *
(2) All visible emission readings, heat content determinations,
flow rate measurements, and exit velocity determinations made during
the compliance determination required by Sec. 63.120(e) of subpart G
or Sec. 63.987(b) of subpart SS or Sec. 63.670(h), as applicable; and
* * * * *
(iv) For miscellaneous process vents controlled by flares, initial
compliance test results including the information in paragraphs
(f)(1)(iv)(A) and (B) of this section.
(A) All visible emission readings, heat content determinations,
flow rate measurements, and exit velocity determinations made during
the compliance determination required by Sec. Sec. 63.645 and
63.116(a) of subpart G or Sec. 63.670(h), as applicable; and
* * * * *
(vii) For pressure relief devices in organic HAP service subject to
the requirements in Sec. 63.648(j)(3)(i) and (ii), this report shall
include the information specified in paragraphs (f)(1)(vii)(A) and (B)
of this section.
(A) A description of the monitoring system to be implemented,
including the relief devices and process parameters to be monitored,
and a description of the alarms or other methods by which operators
will be notified of a pressure release.
(B) A description of the prevention measures to be implemented for
each affected pressure relief device.
(viii) For each delayed coking unit, identification of whether the
unit is an existing affected source or a new affected source and
whether monitoring will be conducted as specified in Sec. 63.657(b) or
(c).
(2) If initial performance tests are required by Sec. Sec. 63.643
through 63.653, the Notification of Compliance Status report shall
include one complete test report for each test method used for a
particular source. On and after February 1, 2016, performance tests
shall be submitted according to paragraph (h)(9) of this section.
* * * * *
(3) For each monitored parameter for which a range is required to
be established under Sec. 63.120(d) of subpart G or Sec. 63.985(b) of
subpart SS for storage vessels or Sec. 63.644 for miscellaneous
process vents, the Notification of Compliance Status report shall
include the information in paragraphs (f)(3)(i) through (iii) of this
section.
* * * * *
(6) Notification of Compliance Status reports required by Sec.
63.640(l)(3) and for storage vessels subject to the compliance dates
specified in Sec. 63.640(h)(2) shall be submitted no later than 60
days after the end of the 6-month period during which the change or
addition was made that resulted in the Group 1 emission point or the
existing Group 1 storage vessel was brought into compliance, and may be
combined with the periodic report. * * *
(g) The owner or operator of a source subject to this subpart shall
submit Periodic Reports no later than 60 days after the end of each 6-
month period when any of the information specified in paragraphs (g)(1)
through (7) of this section or paragraphs (g)(9) through (14) of this
section is collected. The first 6-month period shall begin on the date
the Notification of Compliance Status report is required to be
submitted. A Periodic Report is not required if none of the events
identified in paragraphs (g)(1)

[[Page 75248]]

through (7) of this section or paragraphs (g)(9) through (14) of this
section occurred during the 6-month period unless emissions averaging
is utilized. Quarterly reports must be submitted for emission points
included in emission averages, as provided in paragraph (g)(8) of this
section. An owner or operator may submit reports required by other
regulations in place of or as part of the Periodic Report required by
this paragraph (g) if the reports contain the information required by
paragraphs (g)(1) through (14) of this section.
(1) For storage vessels, Periodic Reports shall include the
information specified for Periodic Reports in paragraphs (g)(2) through
(5) of this section. Information related to gaskets, slotted membranes,
and sleeve seals is not required for storage vessels that are part of
an existing source complying with Sec. 63.646.
(2) Internal floating roofs. (i) An owner or operator who elects to
comply with Sec. 63.646 by using a fixed roof and an internal floating
roof or by using an external floating roof converted to an internal
floating roof shall submit the results of each inspection conducted in
accordance with Sec. 63.120(a) of subpart G in which a failure is
detected in the control equipment.
(A) For vessels for which annual inspections are required under
Sec. 63.120(a)(2)(i) or (a)(3)(ii) of subpart G, the specifications
and requirements listed in paragraphs (g)(2)(i)(A)(1) through (3) of
this section apply.
(1) A failure is defined as any time in which the internal floating
roof is not resting on the surface of the liquid inside the storage
vessel and is not resting on the leg supports; or there is liquid on
the floating roof; or the seal is detached from the internal floating
roof; or there are holes, tears, or other openings in the seal or seal
fabric; or there are visible gaps between the seal and the wall of the
storage vessel.
(2) Except as provided in paragraph (g)(2)(i)(A)(3) of this
section, each Periodic Report shall include the date of the inspection,
identification of each storage vessel in which a failure was detected,
and a description of the failure. The Periodic Report shall also
describe the nature of and date the repair was made or the date the
storage vessel was emptied.
(3) If an extension is utilized in accordance with Sec.
63.120(a)(4) of subpart G, the owner or operator shall, in the next
Periodic Report, identify the vessel; include the documentation
specified in Sec. 63.120(a)(4) of subpart G; and describe the date the
storage vessel was emptied and the nature of and date the repair was
made.
(B) For vessels for which inspections are required under Sec.
63.120(a)(2)(ii), (a)(3)(i), or (a)(3)(iii) of subpart G (i.e.,
internal inspections), the specifications and requirements listed in
paragraphs (g)(2)(i)(B)(1) and (2) of this section apply.
(1) A failure is defined as any time in which the internal floating
roof has defects; or the primary seal has holes, tears, or other
openings in the seal or the seal fabric; or the secondary seal (if one
has been installed) has holes, tears, or other openings in the seal or
the seal fabric; or, for a storage vessel that is part of a new source,
the gaskets no longer close off the liquid surface from the atmosphere;
or, for a storage vessel that is part of a new source, the slotted
membrane has more than a 10 percent open.
(2) Each Periodic Report shall include the date of the inspection,
identification of each storage vessel in which a failure was detected,
and a description of the failure. The Periodic Report shall also
describe the nature of and date the repair was made.
(ii) An owner or operator who elects to comply with Sec. 63.660 by
using a fixed roof and an internal floating roof shall submit the
results of each inspection conducted in accordance with Sec.
63.1063(c)(1), (d)(1), and (d)(2) of subpart WW in which a failure is
detected in the control equipment. For vessels for which inspections
are required under Sec. 63.1063(c) and (d), the specifications and
requirements listed in paragraphs (g)(2)(ii)(A) through (C) of this
section apply.
(A) A failure is defined in Sec. 63.1063(d)(1) of subpart WW.
(B) Each Periodic Report shall include a copy of the inspection
record required by Sec. 63.1065(b) of subpart WW when a failure
occurs.
(C) An owner or operator who elects to use an extension in
accordance with Sec. 63.1063(e)(2) of subpart WW shall, in the next
Periodic Report, submit the documentation required by Sec.
63.1063(e)(2).
(3) External floating roofs. (i) An owner or operator who elects to
comply with Sec. 63.646 by using an external floating roof shall meet
the periodic reporting requirements specified in paragraphs
(g)(3)(i)(A) through (C) of this section.
(A) The owner or operator shall submit, as part of the Periodic
Report, documentation of the results of each seal gap measurement made
in accordance with Sec. 63.120(b) of subpart G in which the seal and
seal gap requirements of Sec. 63.120(b)(3), (4), (5), or (6) of
subpart G are not met. This documentation shall include the information
specified in paragraphs (g)(3)(i)(A)(1) through (4) of this section.
(1) The date of the seal gap measurement.
(2) The raw data obtained in the seal gap measurement and the
calculations described in Sec. 63.120(b)(3) and (4) of subpart G.
(3) A description of any seal condition specified in Sec.
63.120(b)(5) or (6) of subpart G that is not met.
(4) A description of the nature of and date the repair was made, or
the date the storage vessel was emptied.
(B) If an extension is utilized in accordance with Sec.
63.120(b)(7)(ii) or (b)(8) of subpart G, the owner or operator shall,
in the next Periodic Report, identify the vessel; include the
documentation specified in Sec. 63.120(b)(7)(ii) or (b)(8) of subpart
G, as applicable; and describe the date the vessel was emptied and the
nature of and date the repair was made.
(C) The owner or operator shall submit, as part of the Periodic
Report, documentation of any failures that are identified during visual
inspections required by Sec. 63.120(b)(10) of subpart G. This
documentation shall meet the specifications and requirements in
paragraphs (g)(3)(i)(C)(1) and (2) of this section.
(1) A failure is defined as any time in which the external floating
roof has defects; or the primary seal has holes or other openings in
the seal or the seal fabric; or the secondary seal has holes, tears, or
other openings in the seal or the seal fabric; or, for a storage vessel
that is part of a new source, the gaskets no longer close off the
liquid surface from the atmosphere; or, for a storage vessel that is
part of a new source, the slotted membrane has more than 10 percent
open area.
(2) Each Periodic Report shall include the date of the inspection,
identification of each storage vessel in which a failure was detected,
and a description of the failure. The Periodic Report shall also
describe the nature of and date the repair was made.
(ii) An owner or operator who elects to comply with Sec. 63.660 by
using an external floating roof shall meet the periodic reporting
requirements specified in paragraphs (g)(3)(ii)(A) and (B) of this
section.
(A) For vessels for which inspections are required under Sec.
63.1063(c)(2), (d)(1), and (d)(3) of subpart WW, the owner or operator
shall submit, as part of the Periodic Report, a copy of the inspection
record required by Sec. 63.1065(b) of subpart WW when a failure
occurs. A failure is defined in Sec. 63.1063(d)(1).

[[Page 75249]]

(B) An owner or operator who elects to use an extension in
accordance with Sec. 63.1063(e)(2) or (c)(2)(iv)(B) of subpart WW
shall, in the next Periodic Report, submit the documentation required
by those paragraphs.
(4) [Reserved]
(5) An owner or operator who elects to comply with Sec. 63.646 or
Sec. 63.660 by installing a closed vent system and control device
shall submit, as part of the next Periodic Report, the information
specified in paragraphs (g)(5)(i) through (v) of this section, as
applicable.
(i) The Periodic Report shall include the information specified in
paragraphs (g)(5)(i)(A) and (B) of this section for those planned
routine maintenance operations that would require the control device
not to meet the requirements of either Sec. 63.119(e)(1) or (2) of
subpart G, Sec. 63.985(a) and (b) of subpart SS, or Sec. 63.670, as
applicable.
(A) A description of the planned routine maintenance that is
anticipated to be performed for the control device during the next 6
months. This description shall include the type of maintenance
necessary, planned frequency of maintenance, and lengths of maintenance
periods.
(B) A description of the planned routine maintenance that was
performed for the control device during the previous 6 months. This
description shall include the type of maintenance performed and the
total number of hours during those 6 months that the control device did
not meet the requirements of either Sec. 63.119(e)(1) or (2) of
subpart G, Sec. 63.985(a) and (b) of subpart SS, or Sec. 63.670, as
applicable, due to planned routine maintenance.
(ii) If a control device other than a flare is used, the Periodic
Report shall describe each occurrence when the monitored parameters
were outside of the parameter ranges documented in the Notification of
Compliance Status report. The description shall include: Identification
of the control device for which the measured parameters were outside of
the established ranges, and causes for the measured parameters to be
outside of the established ranges.
(iii) If a flare is used prior to January 30, 2019 and prior to
electing to comply with the requirements in Sec. 63.670, the Periodic
Report shall describe each occurrence when the flare does not meet the
general control device requirements specified in Sec. 63.11(b) of
subpart A and shall include: Identification of the flare that does not
meet the general requirements specified in Sec. 63.11(b) of subpart A,
and reasons the flare did not meet the general requirements specified
in Sec. 63.11(b) of subpart A.
(iv) If a flare is used on or after the date for which compliance
with the requirements in Sec. 63.670 is elected, which can be no later
than January 30, 2019, the Periodic Report shall include the items
specified in paragraph (g)(11) of this section.
(v) An owner or operator who elects to comply with Sec. 63.660 by
installing an alternate control device as described in Sec. 63.1064 of
subpart WW shall submit, as part of the next Periodic Report, a written
application as described in Sec. 63.1066(b)(3) of subpart WW.
(6) * * *
(i) * * *
(D) For data compression systems under paragraph (h)(5)(iii) of
this section, an operating day when the monitor operated for less than
75 percent of the operating hours or a day when less than 18 monitoring
values were recorded.
* * * * *
(iii) For periods in closed vent systems when a Group 1
miscellaneous process vent stream was detected in the bypass line or
diverted from the control device and either directly to the atmosphere
or to a control device that does not comply with the requirements in
Sec. 63.643(a), report the date, time, duration, estimate of the
volume of gas, the concentration of organic HAP in the gas and the
resulting mass emissions of organic HAP that bypassed the control
device. For periods when the flow indicator is not operating, report
the date, time, and duration.
(7) * * *
(i) Results of the performance test shall include the
identification of the source tested, the date of the test, the
percentage of emissions reduction or outlet pollutant concentration
reduction (whichever is needed to determine compliance) for each run
and for the average of all runs, and the values of the monitored
operating parameters.
* * * * *
(10) For pressure relief devices subject to the requirements Sec.
63.648(j), Periodic Reports must include the information specified in
paragraphs (g)(10)(i) through (iii) of this section.
(i) For pressure relief devices in organic HAP gas or vapor
service, pursuant to Sec. 63.648(j)(1), report any instrument reading
of 500 ppm or greater.
(ii) For pressure relief devices in organic HAP gas or vapor
service subject to Sec. 63.648(j)(2), report confirmation that any
monitoring required to be done during the reporting period to show
compliance was conducted.
(iii) For pressure relief devices in organic HAP service subject to
Sec. 63.648(j)(3), report each pressure release to the atmosphere,
including duration of the pressure release and estimate of the mass
quantity of each organic HAP released, and the results of any root
cause analysis and corrective action analysis completed during the
reporting period, including the corrective actions implemented during
the reporting period and, if applicable, the implementation schedule
for planned corrective actions to be implemented subsequent to the
reporting period.
(11) For flares subject to Sec. 63.670, Periodic Reports must
include the information specified in paragraphs (g)(11)(i) through (iv)
of this section.
(i) Records as specified in paragraph (i)(9)(i) of this section for
each 15-minute block during which there was at least one minute when
regulated material is routed to a flare and no pilot flame is present.
(ii) Visible emission records as specified in paragraph
(i)(9)(ii)(C) of this section for each period of 2 consecutive hours
during which visible emissions exceeded a total of 5 minutes.
(iii) The 15-minute block periods for which the applicable
operating limits specified in Sec. 63.670(d) through (f) are not met.
Indicate the date and time for the period, the net heating value
operating parameter(s) determined following the methods in Sec.
63.670(k) through (n) as applicable.
(iv) For flaring events meeting the criteria in Sec. 63.670(o)(3):
(A) The start and stop time and date of the flaring event.
(B) The length of time for which emissions were visible from the
flare during the event.
(C) The periods of time that the flare tip velocity exceeds the
maximum flare tip velocity determined using the methods in Sec.
63.670(d)(2) and the maximum 15-minute block average flare tip velocity
recorded during the event.
(D) Results of the root cause and corrective actions analysis
completed during the reporting period, including the corrective actions
implemented during the reporting period and, if applicable, the
implementation schedule for planned corrective actions to be
implemented subsequent to the reporting period.
(12) For delayed coking units, the Periodic Report must include the
information specified in paragraphs (g)(12)(i) through (iv) of this
section.
(i) For existing source delayed coking units, any 60-cycle average
exceeding the applicable limit in Sec. 63.657(a)(1).
(ii) For new source delayed coking units, any direct venting event

[[Page 75250]]

exceeding the applicable limit in Sec. 63.657(a)(2).
(iii) The total number of double quenching events performed during
the reporting period.
(iv) For each double quenching draining event when the drain water
temperature exceeded 210 [deg]F, report the drum, date, time, the coke
drum vessel pressure or temperature, as applicable, when pre-vent
draining was initiated, and the maximum drain water temperature during
the pre-vent draining period.
(13) For maintenance vents subject to the requirements in Sec.
63.643(c), Periodic Reports must include the information specified in
paragraphs (g)(13)(i) through (iv) of this section for any release
exceeding the applicable limits in Sec. 63.643(c)(1). For the purposes
of this reporting requirement, owners or operators complying with Sec.
63.643(c)(1)(iv) must report each venting event for which the lower
explosive limit is 20 percent or greater.
(i) Identification of the maintenance vent and the equipment served
by the maintenance vent.
(ii) The date and time the maintenance vent was opened to the
atmosphere.
(iii) The lower explosive limit, vessel pressure, or mass of VOC in
the equipment, as applicable, at the start of atmospheric venting. If
the 5 psig vessel pressure option in Sec. 63.643(c)(1)(ii) was used
and active purging was initiated while the lower explosive limit was 10
percent or greater, also include the lower explosive limit of the
vapors at the time active purging was initiated.
(iv) An estimate of the mass of organic HAP released during the
entire atmospheric venting event.
(14) Any changes in the information provided in a previous
Notification of Compliance Status report.
(h) * * *
(2) For storage vessels, notifications of inspections as specified
in paragraphs (h)(2)(i) and (ii) of this section.
(i) * * *
(B) Except as provided in paragraph (h)(2)(i)(C) of this section,
if the internal inspection required by Sec. 63.120(a)(2), (a)(3), or
(b)(10) of subpart G or Sec. 63.1063(d)(1) of subpart WW is not
planned and the owner or operator could not have known about the
inspection 30 calendar days in advance of refilling the vessel with
organic HAP, the owner or operator shall notify the Administrator at
least 7 calendar days prior to refilling of the storage vessel.
Notification may be made by telephone and immediately followed by
written documentation demonstrating why the inspection was unplanned.
This notification, including the written documentation, may also be
made in writing and sent so that it is received by the Administrator at
least 7 calendar days prior to the refilling.
* * * * *
(ii) In order to afford the Administrator the opportunity to have
an observer present, the owner or operator of a storage vessel equipped
with an external floating roof shall notify the Administrator of any
seal gap measurements. The notification shall be made in writing at
least 30 calendar days in advance of any gap measurements required by
Sec. 63.120(b)(1) or (2) of subpart G or Sec. 63.1062(d)(3) of
subpart WW. The State or local permitting authority can waive this
notification requirement for all or some storage vessels subject to the
rule or can allow less than 30 calendar days' notice.
* * * * *
(5) * * *
(iii) An owner or operator may use an automated data compression
recording system that does not record monitored operating parameter
values at a set frequency (for example, once every hour) but records
all values that meet set criteria for variation from previously
recorded values.
(A) The system shall be designed to:
(1) Measure the operating parameter value at least once every hour.
(2) Record at least 24 values each day during periods of operation.
(3) Record the date and time when monitors are turned off or on.
(4) Recognize unchanging data that may indicate the monitor is not
functioning properly, alert the operator, and record the incident.
(5) Compute daily average values of the monitored operating
parameter based on recorded data.
(B) You must maintain a record of the description of the monitoring
system and data compression recording system including the criteria
used to determine which monitored values are recorded and retained, the
method for calculating daily averages, and a demonstrations that they
system meets all criteria of paragraph (h)(5)(iii)(A) of this section.
* * * * *
(8) For fenceline monitoring systems subject to Sec. 63.658,
within 45 calendar days after the end of each quarterly reporting
period covered by the periodic report, each owner or operator shall
submit the following information to the EPA's Compliance and Emissions
Data Reporting Interface (CEDRI). (CEDRI can be accessed through the
EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). The owner or
operator need not transmit this data prior to obtaining 12 months of
data.
(i) Individual sample results for each monitor for each sampling
period during the quarterly reporting period. For the first reporting
period and for any period in which a passive monitor is added or moved,
the owner or operator shall report the coordinates of all of the
passive monitor locations. The owner or operator shall determine the
coordinates using an instrument with an accuracy of at least 3 meters.
Coordinates shall be in decimal degrees with at least five decimal
places.
(ii) The biweekly annual average concentration difference
([Delta]c) values for benzene for the quarterly reporting period.
(iii) Notation for each biweekly value that indicates whether
background correction was used, all measurements in the sampling period
were below detection, or whether an outlier was removed from the
sampling period data set.
(9) On and after February 1, 2016, if required to submit the
results of a performance test or CEMS performance evaluation, the owner
or operator shall submit the results according to the procedures in
paragraphs (h)(9)(i) and (ii) of this section.
(i) Within 60 days after the date of completing each performance
test as required by this subpart, the owner or operator shall submit
the results of the performance tests following the procedure specified
in either paragraph (h)(9)(i)(A) or (B) of this section.
(A) For data collected using test methods supported by the EPA's
Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site
(https://www.epa.gov/ttn/chief/ert/) at the time of the test,
the owner or operator must submit the results of the performance test
to the EPA via the CEDRI. (CEDRI can be accessed through the EPA's
CDX.) Performance test data must be submitted in a file format
generated through the use of the EPA's ERT or an alternate electronic
file format consistent with the extensible markup language (XML) schema
listed on the EPA's ERT Web site. If an owner or operator claims that
some of the performance test information being submitted is
confidential business information (CBI), the owner or operator must
submit a complete file generated through the use of the EPA's ERT or an
alternate electronic file consistent with the XML schema listed on the
EPA's ERT Web site, including information claimed to be CBI, on a
compact disc, flash drive or other commonly used electronic storage
media to the EPA. The electronic storage media must be clearly marked
as CBI and mailed to U.S. EPA/OAQPS/

[[Page 75251]]

CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD
C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate
file with the CBI omitted must be submitted to the EPA via the EPA's
CDX as described earlier in this paragraph (h)(9)(i)(A).
(B) For data collected using test methods that are not supported by
the EPA's ERT as listed on the EPA's ERT Web site at the time of the
test, the owner or operator must submit the results of the performance
test to the Administrator at the appropriate address listed in Sec.
63.13.
(ii) Within 60 days after the date of completing each CEMS
performance evaluation as required by this subpart, the owner or
operator must submit the results of the performance evaluation
following the procedure specified in either paragraph (h)(9)(ii)(A) or
(B) of this section.
(A) For performance evaluations of continuous monitoring systems
measuring relative accuracy test audit (RATA) pollutants that are
supported by the EPA's ERT as listed on the EPA's ERT Web site at the
time of the evaluation, the owner or operator must submit the results
of the performance evaluation to the EPA via the CEDRI. (CEDRI can be
accessed through the EPA's CDX.) Performance evaluation data must be
submitted in a file format generated through the use of the EPA's ERT
or an alternate file format consistent with the XML schema listed on
the EPA's ERT Web site. If an owner or operator claims that some of the
performance evaluation information being submitted is CBI, the owner or
operator must submit a complete file generated through the use of the
EPA's ERT or an alternate electronic file consistent with the XML
schema listed on the EPA's ERT Web site, including information claimed
to be CBI, on a compact disc, flash drive or other commonly used
electronic storage media to the EPA. The electronic storage media must
be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office,
Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old
Page Rd., Durham, NC 27703. The same ERT or alternate file with the CBI
omitted must be submitted to the EPA via the EPA's CDX as described
earlier in this paragraph (h)(9)(ii)(A).
(B) For any performance evaluations of continuous monitoring
systems measuring RATA pollutants that are not supported by the EPA's
ERT as listed on the EPA's ERT Web site at the time of the evaluation,
the owner or operator must submit the results of the performance
evaluation to the Administrator at the appropriate address listed in
Sec. 63.13.
(i) Recordkeeping. Each owner or operator of a source subject to
this subpart shall keep copies of all applicable reports and records
required by this subpart for at least 5 years except as otherwise
specified in paragraphs (i)(1) through (12) of this section. All
applicable records shall be maintained in such a manner that they can
be readily accessed within 24 hours. Records may be maintained in hard
copy or computer-readable form including, but not limited to, on paper,
microfilm, computer, flash drive, floppy disk, magnetic tape, or
microfiche.
(1) Each owner or operator subject to the storage vessel provisions
in Sec. 63.646 shall keep the records specified in Sec. 63.123 of
subpart G except as specified in paragraphs (i)(1)(i) through (iv) of
this section. Each owner or operator subject to the storage vessel
provisions in Sec. 63.660 shall keep records as specified in
paragraphs (i)(1)(v) and (vi) of this section.
* * * * *
(ii) All references to Sec. 63.122 in Sec. 63.123 of subpart G
shall be replaced with Sec. 63.655(e).
* * * * *
(v) Each owner or operator of a Group 1 storage vessel subject to
the provisions in Sec. 63.660 shall keep records as specified in Sec.
63.1065 or Sec. 63.998, as applicable.
(vi) Each owner or operator of a Group 2 storage vessel shall keep
the records specified in Sec. 63.1065(a) of subpart WW. If a storage
vessel is determined to be Group 2 because the weight percent total
organic HAP of the stored liquid is less than or equal to 4 percent for
existing sources or 2 percent for new sources, a record of any data,
assumptions, and procedures used to make this determination shall be
retained.
* * * * *
(4) For each closed vent system that contains bypass lines that
could divert a vent stream away from the control device and either
directly to the atmosphere or to a control device that does not comply
with the requirements in Sec. 63.643(a), the owner or operator shall
keep a record of the information specified in either paragraph
(i)(4)(i) or (ii) of this section, as applicable.
(i) The owner or operator shall maintain records of periods when
flow was detected in the bypass line, including the date and time and
the duration of the flow in the bypass line. For each flow event, the
owner or operator shall maintain records sufficient to determine
whether or not the detected flow included flow of a Group 1
miscellaneous process vent stream requiring control. For periods when
the Group 1 miscellaneous process vent stream requiring control is
diverted from the control device and released either directly to the
atmosphere or to a control device that does not comply with the
requirements in Sec. 63.643(a), the owner or operator shall include an
estimate of the volume of gas, the concentration of organic HAP in the
gas and the resulting emissions of organic HAP that bypassed the
control device using process knowledge and engineering estimates.
(ii) Where a seal mechanism is used to comply with Sec.
63.644(c)(2), hourly records of flow are not required. In such cases,
the owner or operator shall record the date that the monthly visual
inspection of the seals or closure mechanisms is completed. The owner
or operator shall also record the occurrence of all periods when the
seal or closure mechanism is broken, the bypass line valve position has
changed or the key for a lock-and-key type lock has been checked out.
The owner or operator shall include an estimate of the volume of gas,
the concentration of organic HAP in the gas and the resulting mass
emissions of organic HAP from the Group 1 miscellaneous process vent
stream requiring control that bypassed the control device or records
sufficient to demonstrate that there was no flow of a Group 1
miscellaneous process vent stream requiring control during the period.
(5) The owner or operator of a heat exchange system subject to this
subpart shall comply with the recordkeeping requirements in paragraphs
(i)(5)(i) through (v) of this section and retain these records for 5
years.
* * * * *
(7) Each owner or operator subject to the delayed coking unit
decoking operations provisions in Sec. 63.657 must maintain records
specified in paragraphs (i)(7)(i) through (iii) of this section.
(i) The average pressure or temperature, as applicable, for the 5-
minute period prior to venting to the atmosphere, draining, or
deheading the coke drum for each cooling cycle for each coke drum.
(ii) If complying with the 60-cycle rolling average, each 60-cycle
rolling average pressure or temperature, as applicable, considering all
coke drum venting events in the existing affected source.
(iii) For double-quench cooling cycles:

[[Page 75252]]

(A) The date, time and duration of each pre-vent draining event.
(B) The pressure or temperature of the coke drum vessel, as
applicable, for the 15 minute period prior to the pre-vent draining.
(C) The drain water temperature at 1-minute intervals from the
start of pre-vent draining to the complete closure of the drain valve.
(8) For fenceline monitoring systems subject to Sec. 63.658, each
owner or operator shall keep the records specified in paragraphs
(i)(8)(i) through (x) of this section on an ongoing basis.
(i) Coordinates of all passive monitors, including replicate
samplers and field blanks, and if applicable, the meteorological
station. The owner or operator shall determine the coordinates using an
instrument with an accuracy of at least 3 meters. The coordinates shall
be in decimal degrees with at least five decimal places.
(ii) The start and stop times and dates for each sample, as well as
the tube identifying information.
(iii) Sampling period average temperature and barometric pressure
measurements.
(iv) For each outlier determined in accordance with Section 9.2 of
Method 325A of appendix A of this part, the sampler location of and the
concentration of the outlier and the evidence used to conclude that the
result is an outlier.
(v) For samples that will be adjusted for a background, the
location of and the concentration measured simultaneously by the
background sampler, and the perimeter samplers to which it applies.
(vi) Individual sample results, the calculated [Delta]c for benzene
for each sampling period and the two samples used to determine it,
whether background correction was used, and the annual average [Delta]c
calculated after each sampling period.
(vii) Method detection limit for each sample, including co-located
samples and blanks.
(viii) Documentation of corrective action taken each time the
action level was exceeded.
(ix) Other records as required by Methods 325A and 325B of appendix
A of this part.
(x) If a near-field source correction is used as provided in Sec.
63.658(i), records of hourly meteorological data, including
temperature, barometric pressure, wind speed and wind direction,
calculated daily unit vector wind direction and daily sigma theta, and
other records specified in the site-specific monitoring plan.
(9) For each flare subject to Sec. 63.670, each owner or operator
shall keep the records specified in paragraphs (i)(9)(i) through (xii)
of this section up-to-date and readily accessible, as applicable.
(i) Retain records of the output of the monitoring device used to
detect the presence of a pilot flame as required in Sec. 63.670(b) for
a minimum of 2 years. Retain records of each 15-minute block during
which there was at least one minute that no pilot flame is present when
regulated material is routed to a flare for a minimum of 5 years.
(ii) Retain records of daily visible emissions observations or
video surveillance images required in Sec. 63.670(h) as specified in
the paragraphs (i)(9)(ii)(A) through (C), as applicable, for a minimum
of 3 years.
(A) If visible emissions observations are performed using Method 22
at 40 CFR part 60, appendix A-7, the record must identify whether the
visible emissions observation was performed, the results of each
observation, total duration of observed visible emissions, and whether
it was a 5-minute or 2-hour observation. If the owner or operator
performs visible emissions observations more than one time during a
day, the record must also identify the date and time of day each
visible emissions observation was performed.
(B) If video surveillance camera is used, the record must include
all video surveillance images recorded, with time and date stamps.
(C) For each 2 hour period for which visible emissions are observed
for more than 5 minutes in 2 consecutive hours, the record must include
the date and time of the 2 hour period and an estimate of the
cumulative number of minutes in the 2 hour period for which emissions
were visible.
(iii) The 15-minute block average cumulative flows for flare vent
gas and, if applicable, total steam, perimeter assist air, and premix
assist air specified to be monitored under Sec. 63.670(i), along with
the date and time interval for the 15-minute block. If multiple
monitoring locations are used to determine cumulative vent gas flow,
total steam, perimeter assist air, and premix assist air, retain
records of the 15-minute block average flows for each monitoring
location for a minimum of 2 years, and retain the 15-minute block
average cumulative flows that are used in subsequent calculations for a
minimum of 5 years. If pressure and temperature monitoring is used,
retain records of the 15-minute block average temperature, pressure and
molecular weight of the flare vent gas or assist gas stream for each
measurement location used to determine the 15-minute block average
cumulative flows for a minimum of 2 years, and retain the 15-minute
block average cumulative flows that are used in subsequent calculations
for a minimum of 5 years.
(iv) The flare vent gas compositions specified to be monitored
under Sec. 63.670(j). Retain records of individual component
concentrations from each compositional analyses for a minimum of 2
years. If NHVvg analyzer is used, retain records of the 15-minute block
average values for a minimum of 5 years.
(v) Each 15-minute block average operating parameter calculated
following the methods specified in Sec. 63.670(k) through (n), as
applicable.
(vi) [Reserved]
(vii) All periods during which operating values are outside of the
applicable operating limits specified in Sec. 63.670(d) through (f)
when regulated material is being routed to the flare.
(viii) All periods during which the owner or operator does not
perform flare monitoring according to the procedures in Sec. 63.670(g)
through (j).
(ix) Records of periods when there is flow of vent gas to the
flare, but when there is no flow of regulated material to the flare,
including the start and stop time and dates of periods of no regulated
material flow.
(x) Records when the flow of vent gas exceeds the smokeless
capacity of the flare, including start and stop time and dates of the
flaring event.
(xi) Records of the root cause analysis and corrective action
analysis conducted as required in Sec. 63.670(o)(3), including an
identification of the affected facility, the date and duration of the
event, a statement noting whether the event resulted from the same root
cause(s) identified in a previous analysis and either a description of
the recommended corrective action(s) or an explanation of why
corrective action is not necessary under Sec. 63.670(o)(5)(i).
(xii) For any corrective action analysis for which implementation
of corrective actions are required in Sec. 63.670(o)(5), a description
of the corrective action(s) completed within the first 45 days
following the discharge and, for action(s) not already completed, a
schedule for implementation, including proposed commencement and
completion dates.
(10) [Reserved]
(11) For each pressure relief device subject to the pressure
release management work practice standards in Sec. 63.648(j)(3), the
owner or operator shall keep the records specified in paragraphs
(i)(11)(i) through (iii) of this section.
(i) Records of the prevention measures implemented as required in
Sec. 63.648(j)(3)(ii), if applicable.

[[Page 75253]]

(ii) Records of the number of releases during each calendar year
and the number of those releases for which the root cause was
determined to be a force majeure event. Keep these records for the
current calendar year and the past five calendar years.
(iii) For each release to the atmosphere, the owner or operator
shall keep the records specified in paragraphs (i)(11)(iii)(A) through
(D) of this section.
(A) The start and end time and date of each pressure release to the
atmosphere.
(B) Records of any data, assumptions, and calculations used to
estimate of the mass quantity of each organic HAP released during the
event.
(C) Records of the root cause analysis and corrective action
analysis conducted as required in Sec. 63.648(j)(3)(iii), including an
identification of the affected facility, the date and duration of the
event, a statement noting whether the event resulted from the same root
cause(s) identified in a previous analysis and either a description of
the recommended corrective action(s) or an explanation of why
corrective action is not necessary under Sec. 63.648(j)(7)(i).
(D) For any corrective action analysis for which implementation of
corrective actions are required in Sec. 63.648(j)(7), a description of
the corrective action(s) completed within the first 45 days following
the discharge and, for action(s) not already completed, a schedule for
implementation, including proposed commencement and completion dates.
(12) For each maintenance vent opening subject to the requirements
in Sec. 63.643(c), the owner or operator shall keep the applicable
records specified in (i)(12)(i) through (v) of this section.
(i) The owner or operator shall maintain standard site procedures
used to deinventory equipment for safety purposes (e.g., hot work or
vessel entry procedures) to document the procedures used to meet the
requirements in Sec. 63.643(c). The current copy of the procedures
shall be retained and available on-site at all times. Previous versions
of the standard site procedures, is applicable, shall be retained for
five years.
(ii) If complying with the requirements of Sec. 63.643(c)(1)(i)
and the lower explosive limit at the time of the vessel opening exceeds
10 percent, identification of the maintenance vent, the process units
or equipment associated with the maintenance vent, the date of
maintenance vent opening, and the lower explosive limit at the time of
the vessel opening.
(iii) If complying with the requirements of Sec. 63.643(c)(1)(ii)
and either the vessel pressure at the time of the vessel opening
exceeds 5 psig or the lower explosive limit at the time of the active
purging was initiated exceeds 10 percent, identification of the
maintenance vent, the process units or equipment associated with the
maintenance vent, the date of maintenance vent opening, the pressure of
the vessel or equipment at the time of discharge to the atmosphere and,
if applicable, the lower explosive limit of the vapors in the equipment
when active purging was initiated.
(iv) If complying with the requirements of Sec. 63.643(c)(1)(iii),
identification of the maintenance vent, the process units or equipment
associated with the maintenance vent, the date of maintenance vent
opening, and records used to estimate the total quantity of VOC in the
equipment at the time the maintenance vent was opened to the atmosphere
for each applicable maintenance vent opening.
(v) If complying with the requirements of Sec. 63.643(c)(1)(iv),
identification of the maintenance vent, the process units or equipment
associated with the maintenance vent, records documenting the lack of a
pure hydrogen supply, the date of maintenance vent opening, and the
lower explosive limit of the vapors in the equipment at the time of
discharge to the atmosphere for each applicable maintenance vent
opening.

0
28. Section 63.656 is amended by revising paragraph (c)(1) to read as
follows:

Sec. 63.656 Implementation and enforcement.

* * * * *
(c) * * *
(1) Approval of alternatives to the requirements in Sec. Sec.
63.640, 63.642(g) through (l), 63.643, 63.646 through 63.652, 63.654,
63.657 through 63.660, and 63.670. Where these standards reference
another subpart, the cited provisions will be delegated according to
the delegation provisions of the referenced subpart. Where these
standards reference another subpart and modify the requirements, the
requirements shall be modified as described in this subpart. Delegation
of the modified requirements will also occur according to the
delegation provisions of the referenced subpart.
* * * * *

0
29. Section 63.657 is added to read as follows:

Sec. 63.657 Delayed coking unit decoking operation standards.

(a) Except as provided in paragraphs (e) and (f) of this section,
each owner or operator of a delayed coking unit shall depressure each
coke drum to a closed blowdown system until the coke drum vessel
pressure or temperature measured at the top of the coke drum or in the
overhead line of the coke drum as near as practical to the coke drum
meets the applicable limits specified in paragraph (a)(1) or (2) of
this section prior to venting to the atmosphere, draining or deheading
the coke drum at the end of the cooling cycle.
(1) For delayed coking units at an existing affected source, meet
either:
(i) An average vessel pressure of 2 psig determined on a rolling
60-event average; or
(ii) An average vessel temperature of 220 degrees Fahrenheit
determined on a rolling 60-event average.
(2) For delayed coking units at a new affected source, meet either:
(i) A vessel pressure of 2.0 psig for each decoking event; or
(ii) A vessel temperature of 218 degrees Fahrenheit for each
decoking event.
(b) Each owner or operator of a delayed coking unit complying with
the pressure limits in paragraph (a)(1)(i) or (a)(2)(i) of this section
shall install, operate, calibrate, and maintain a monitoring system, as
specified in paragraphs (b)(1) through (5) of this section, to
determine the coke drum vessel pressure.
(1) The pressure monitoring system must be in a representative
location (at the top of the coke drum or in the overhead line as near
as practical to the coke drum) that minimizes or eliminates pulsating
pressure, vibration, and, to the extent practical, internal and
external corrosion.
(2) The pressure monitoring system must be capable of measuring a
pressure of 2.0 psig within 0.5 psig.
(3) The pressure monitoring system must be verified annually or at
the frequency recommended by the instrument manufacturer. The pressure
monitoring system must be verified following any period of more than 24
hours throughout which the pressure exceeded the maximum rated pressure
of the sensor, or the data recorder was off scale.
(4) All components of the pressure monitoring system must be
visually inspected for integrity, oxidation and galvanic corrosion
every 3 months, unless the system has a redundant pressure sensor.
(5) The output of the pressure monitoring system must be reviewed

[[Page 75254]]

daily to ensure that the pressure readings fluctuate as expected
between operating and cooling/decoking cycles to verify the pressure
taps are not plugged. Plugged pressure taps must be unplugged or
otherwise repaired prior to the next operating cycle.
(c) Each owner or operator of a delayed coking unit complying with
the temperature limits in paragraph (a)(1)(ii) or (a)(2)(ii) of this
section shall install, operate, calibrate, and maintain a continuous
parameter monitoring system to measure the coke drum vessel temperature
(at the top of the coke drum or in the overhead line as near as
practical to the coke drum) according to the requirements specified in
table 13 of this subpart.
(d) The owner or operator of a delayed coking unit shall determine
the coke drum vessel pressure or temperature, as applicable, on a 5-
minute rolling average basis while the coke drum is vented to the
closed blowdown system and shall use the last complete 5-minute rolling
average pressure or temperature just prior to initiating steps to
isolate the coke drum prior to venting, draining or deheading to
demonstrate compliance with the requirements in paragraph (a) of this
section. Pressure or temperature readings after initiating steps to
isolate the coke drum from the closed blowdown system just prior to
atmospheric venting, draining, or deheading the coke drum shall not be
used in determining the average coke drum vessel pressure or
temperature for the purpose of compliance with the requirements in
paragraph (a) of this section.
(e) The owner or operator of a delayed coking unit using the
``water overflow'' method of coke cooling must hardpipe the overflow
water or otherwise prevent exposure of the overflow water to the
atmosphere when transferring the overflow water to the overflow water
storage tank whenever the coke drum vessel temperature exceeds 220
degrees Fahrenheit. The overflow water storage tank may be an open or
fixed-roof tank provided that a submerged fill pipe (pipe outlet below
existing liquid level in the tank) is used to transfer overflow water
to the tank. The owner or operator of a delayed coking unit using the
``water overflow'' method of coke cooling shall determine the coke drum
vessel temperature as specified in paragraphs (c) and (d) of this
section regardless of the compliance method used to demonstrate
compliance with the requirements in paragraph (a) of this section.
(f) The owner or operator of a delayed coking unit may partially
drain a coke drum prior to achieving the applicable limits in paragraph
(a) of this section in order to double-quench a coke drum that did not
cool adequately using the normal cooling process steps provided that
the owner or operator meets the conditions in paragraphs (f)(1) and (2)
of this section.
(1) The owner or operator shall install, operate, calibrate, and
maintain a continuous parameter monitoring system to measure the drain
water temperature at the bottom of the coke drum or in the drain line
as near as practical to the coke drum according to the requirements
specified in table 13 of this subpart.
(2) The owner or operator must maintain the drain water temperature
below 210 degrees Fahrenheit during the partial drain associated with
the double-quench event.

0
30. Section 63.658 is added to read as follows:

Sec. 63.658 Fenceline monitoring provisions.

(a) The owner or operator shall conduct sampling along the facility
property boundary and analyze the samples in accordance with Methods
325A and 325B of appendix A of this part and paragraphs (b) through (k)
of this section.
(b) The target analyte is benzene.
(c) The owner or operator shall determine passive monitor locations
in accordance with Section 8.2 of Method 325A of appendix A of this
part.
(1) As it pertains to this subpart, known sources of VOCs, as used
in Section 8.2.1.3 in Method 325A of appendix A of this part for siting
passive monitors means a wastewater treatment unit, process unit, or
any emission source requiring control according to the requirements of
this subpart, including marine vessel loading operations. For marine
loading operations that are located offshore, one passive monitor
should be sited on the shoreline adjacent to the dock.
(2) The owner or operator may collect one or more background
samples if the owner or operator believes that an offsite upwind source
or an onsite source excluded under Sec. 63.640(g) may influence the
sampler measurements. If the owner or operator elects to collect one or
more background samples, the owner of operator must develop and submit
a site-specific monitoring plan for approval according to the
requirements in paragraph (i) of this section. Upon approval of the
site-specific monitoring plan, the background sampler(s) should be
operated co-currently with the routine samplers.
(3) The owner or operator shall collect at least one co-located
duplicate sample for every 10 field samples per sampling period and at
least two field blanks per sampling period, as described in Section 9.3
in Method 325A of appendix A of this part. The co-located duplicates
may be collected at any one of the perimeter sampling locations.
(4) The owner or operator shall follow the procedure in Section 9.6
of Method 325B of appendix A of this part to determine the detection
limit of benzene for each sampler used to collect samples, background
samples (if the owner or operator elects to do so), co-located samples
and blanks.
(d) The owner or operator shall collect and record meteorological
data according to the applicable requirements in paragraphs (d)(1)
through (3) of this section.
(1) If a near-field source correction is used as provided in
paragraph (i)(1) of this section or if an alternative test method is
used that provides time-resolved measurements, the owner or operator
shall:
(i) Use an on-site meteorological station in accordance with
Section 8.3 of Method 325A of appendix A of this part.
(ii) Collect and record hourly average meteorological data,
including temperature, barometric pressure, wind speed and wind
direction and calculate daily unit vector wind direction and daily
sigma theta.
(2) For cases other than those specified in paragraph (d)(1) of
this section, the owner or operator shall collect and record sampling
period average temperature and barometric pressure using either an on-
site meteorological station in accordance with Section 8.3 of Method
325A of appendix A of this part or, alternatively, using data from a
United States Weather Service (USWS) meteorological station provided
the USWS meteorological station is within 40 kilometers (25 miles) of
the refinery.
(3) If an on-site meteorological station is used, the owner or
operator shall follow the calibration and standardization procedures
for meteorological measurements in EPA-454/B-08-002 (incorporated by
reference--see Sec. 63.14).
(e) The owner of operator shall use a sampling period and sampling
frequency as specified in paragraphs (e)(1) through (3) of this
section.
(1) Sampling period. A 14-day sampling period shall be used, unless
a shorter sampling period is determined to be necessary under paragraph
(g) or (i) of this section. A sampling period is defined as the period
during which sampling tube is deployed at a specific sampling location
with the diffusive

[[Page 75255]]

sampling end cap in-place and does not include the time required to
analyze the sample. For the purpose of this subpart, a 14-day sampling
period may be no shorter than 13 calendar days and no longer than 15
calendar days, but the routine sampling period shall be 14 calendar
days.
(2) Base sampling frequency. Except as provided in paragraph (e)(3)
of this section, the frequency of sample collection shall be once each
contiguous 14-day sampling period, such that the beginning of the next
14-day sampling period begins immediately upon the completion of the
previous 14-day sampling period.
(3) Alternative sampling frequency for burden reduction. When an
individual monitor consistently achieves results at or below 0.9 [mu]g/
m\3\, the owner or operator may elect to use the applicable minimum
sampling frequency specified in paragraphs (e)(3)(i) through (v) of
this section for that monitoring site. When calculating [Delta]c for
the monitoring period when using this alternative for burden reduction,
zero shall be substituted for the sample result for the monitoring site
for any period where a sample is not taken.
(i) If every sample at a monitoring site is at or below 0.9 [mu]g/
m³ for 2 years (52 consecutive samples), every other
sampling period can be skipped for that monitoring site, i.e., sampling
will occur approximately once per month.
(ii) If every sample at a monitoring site that is monitored at the
frequency specified in paragraph (e)(3)(i) of this section is at or
below 0.9 [mu]g/m³ for 2 years (i.e., 26 consecutive
``monthly'' samples), five 14-day sampling periods can be skipped for
that monitoring site following each period of sampling, i.e., sampling
will occur approximately once per quarter.
(iii) If every sample at a monitoring site that is monitored at the
frequency specified in paragraph (e)(3)(ii) of this section is at or
below 0.9 [mu]g/m³ for 2 years (i.e., 8 consecutive
quarterly samples), twelve 14-day sampling periods can be skipped for
that monitoring site following each period of sampling, i.e., sampling
will occur twice a year.
(iv) If every sample at a monitoring site that is monitored at the
frequency specified in paragraph (e)(3)(iii) of this section is at or
below 0.9 [mu]g/m³ for an 2 years (i.e., 4 consecutive semi-
annual samples), only one sample per year is required for that
monitoring site. For yearly sampling, samples shall occur at least 10
months but no more than 14 months apart.
(v) If at any time a sample for a monitoring site that is monitored
at the frequency specified in paragraphs (e)(3)(i) through (iv) of this
section returns a result that is above 0.9 [mu]g/m\3\, the sampling
site must return to the original sampling requirements of contiguous
14-day sampling periods with no skip periods for one quarter (six 14-
day sampling periods). If every sample collected during this quarter is
at or below 0.9 [mu]g/m³ , the owner or operator may revert
back to the reduced monitoring schedule applicable for that monitoring
site prior to the sample reading exceeding 0.9 [mu]g/m³ If
any sample collected during this quarter is above 0.9 [mu]g/m\3\, that
monitoring site must return to the original sampling requirements of
contiguous 14-day sampling periods with no skip periods for a minimum
of two years. The burden reduction requirements can be used again for
that monitoring site once the requirements of paragraph (e)(3)(i) of
this section are met again, i.e., after 52 contiguous 14-day samples
with no results above 0.9 [mu]g/m³ .
(f) Within 45 days of completion of each sampling period, the owner
or operator shall determine whether the results are above or below the
action level as follows:
(1) The owner or operator shall determine the facility impact on
the benzene concentration ([Delta]c) for each 14-day sampling period
according to either paragraph (f)(1)(i) or (ii) of this section, as
applicable.
(i) Except when near-field source correction is used as provided in
paragraph (i) of this section, the owner or operator shall determine
the highest and lowest sample results for benzene concentrations from
the sample pool and calculate [Delta]c as the difference in these
concentrations. The owner or operator shall adhere to the following
procedures when one or more samples for the sampling period are below
the method detection limit for benzene:
(A) If the lowest detected value of benzene is below detection, the
owner or operator shall use zero as the lowest sample result when
calculating [Delta]c.
(B) If all sample results are below the method detection limit, the
owner or operator shall use the method detection limit as the highest
sample result.
(ii) When near-field source correction is used as provided in
paragraph (i) of this section, the owner or operator shall determine
[Delta]c using the calculation protocols outlined in the approved site-
specific monitoring plan and in paragraph (i) of this section.
(2) The owner or operator shall calculate the annual average
[Delta]c based on the average of the 26 most recent 14-day sampling
periods. The owner or operator shall update this annual average value
after receiving the results of each subsequent 14-day sampling period.
(3) The action level for benzene is 9 micrograms per cubic meter
([mu]g/m3) on an annual average basis. If the annual average [Delta]c
value for benzene is less than or equal to 9 [mu]g/m\3\, the
concentration is below the action level. If the annual average [Delta]c
value for benzene is greater than 9 [mu]g/m\3\, the concentration is
above the action level, and the owner or operator shall conduct a root
cause analysis and corrective action in accordance with paragraph (g)
of this section.
(g) Within 5 days of determining that the action level has been
exceeded for any annual average [Delta]c and no longer than 50 days
after completion of the sampling period, the owner or operator shall
initiate a root cause analysis to determine the cause of such
exceedance and to determine appropriate corrective action, such as
those described in paragraphs (g)(1) through (4) of this section. The
root cause analysis and initial corrective action analysis shall be
completed and initial corrective actions taken no later than 45 days
after determining there is an exceedance. Root cause analysis and
corrective action may include, but is not limited to:
(1) Leak inspection using Method 21 of part 60, appendix A-7 of
this chapter and repairing any leaks found.
(2) Leak inspection using optical gas imaging and repairing any
leaks found.
(3) Visual inspection to determine the cause of the high benzene
emissions and implementing repairs to reduce the level of emissions.
(4) Employing progressively more frequent sampling, analysis and
meteorology (e.g., using shorter sampling periods for Methods 325A and
325B of appendix A of this part, or using active sampling techniques).
(h) If, upon completion of the corrective action analysis and
corrective actions such as those described in paragraph (g) of this
section, the [Delta]c value for the next 14-day sampling period for
which the sampling start time begins after the completion of the
corrective actions is greater than 9 [mu]g/m\3\ or if all corrective
action measures identified require more than 45 days to implement, the
owner or operator shall develop a corrective action plan that describes
the corrective action(s) completed to date, additional measures that
the owner or operator proposes to employ to reduce fenceline
concentrations below the action level, and a schedule for completion of
these measures. The owner or operator shall submit the corrective
action plan to the

[[Page 75256]]

Administrator within 60 days after receiving the analytical results
indicating that the [Delta]c value for the 14-day sampling period
following the completion of the initial corrective action is greater
than 9 [mu]g/m\3\ or, if no initial corrective actions were identified,
no later than 60 days following the completion of the corrective action
analysis required in paragraph (g) of this section.
(i) An owner or operator may request approval from the
Administrator for a site-specific monitoring plan to account for
offsite upwind sources or onsite sources excluded under Sec. 63.640(g)
according to the requirements in paragraphs (i)(1) through (4) of this
section.
(1) The owner or operator shall prepare and submit a site-specific
monitoring plan and receive approval of the site-specific monitoring
plan prior to using the near-field source alternative calculation for
determining [Delta]c provided in paragraph (i)(2) of this section. The
site-specific monitoring plan shall include, at a minimum, the elements
specified in paragraphs (i)(1)(i) through (v) of this section. The
procedures in Section 12 of Method 325A of appendix A of this part are
not required, but may be used, if applicable, when determining near-
field source contributions.
(i) Identification of the near-field source or sources. For onsite
sources, documentation that the onsite source is excluded under Sec.
63.640(g) and identification of the specific provision in Sec.
63.640(g) that applies to the source.
(ii) Location of the additional monitoring stations that shall be
used to determine the uniform background concentration and the near-
field source concentration contribution.
(iii) Identification of the fenceline monitoring locations impacted
by the near-field source. If more than one near-field source is
present, identify the near-field source or sources that are expected to
contribute to the concentration at that monitoring location.
(iv) A description of (including sample calculations illustrating)
the planned data reduction and calculations to determine the near-field
source concentration contribution for each monitoring location.
(v) If more frequent monitoring or a monitoring station other than
a passive diffusive tube monitoring station is proposed, provide a
detailed description of the measurement methods, measurement frequency,
and recording frequency for determining the uniform background or near-
field source concentration contribution.
(2) When an approved site-specific monitoring plan is used, the
owner or operator shall determine [Delta]c for comparison with the 9
[mu]g/m\3\ action level using the requirements specified in paragraphs
(i)(2)(i) through (iii) of this section.
(i) For each monitoring location, calculate [Delta]ci
using the following equation.

[Delta]ci = MFCi - NFSi - UB

Where:

[Delta]ci = The fenceline concentration, corrected for
background, at measurement location i, micrograms per cubic meter
([mu]g/m\3\).
MFCi = The measured fenceline concentration at
measurement location i, [mu]g/m\3\.
NFSi = The near-field source contributing concentration
at measurement location i determined using the additional
measurements and calculation procedures included in the site-
specific monitoring plan, [mu]g/m\3\. For monitoring locations that
are not included in the site-specific monitoring plan as impacted by
a near-field source, use NFSi = 0 [mu]g/m\3\.
UB = The uniform background concentration determined using the
additional measurements included in the site-specific monitoring
plan, [mu]g/m\3\. If no additional measurements are specified in the
site-specific monitoring plan for determining the uniform background
concentration, use UB = 0 [mu]g/m\3\.

(ii) When one or more samples for the sampling period are below the
method detection limit for benzene, adhere to the following procedures:
(A) If the benzene concentration at the monitoring location used
for the uniform background concentration is below the method detection
limit, the owner or operator shall use zero for UB for that monitoring
period.
(B) If the benzene concentration at the monitoring location(s) used
to determine the near-field source contributing concentration is below
the method detection limit, the owner or operator shall use zero for
the monitoring location concentration when calculating NFSi
for that monitoring period.
(C) If a fenceline monitoring location sample result is below the
method detection limit, the owner or operator shall use the method
detection limit as the sample result.
(iii) Determine [Delta]c for the monitoring period as the maximum
value of [Delta]ci from all of the fenceline monitoring
locations for that monitoring period.
(3) The site-specific monitoring plan shall be submitted and
approved as described in paragraphs (i)(3)(i) through (iv) of this
section.
(i) The site-specific monitoring plan must be submitted to the
Administrator for approval.
(ii) The site-specific monitoring plan shall also be submitted to
the following address: U.S. Environmental Protection Agency, Office of
Air Quality Planning and Standards, Sector Policies and Programs
Division, U.S. EPA Mailroom (E143-01), Attention: Refinery Sector Lead,
109 T.W. Alexander Drive, Research Triangle Park, NC 27711. Electronic
copies in lieu of hard copies may also be submitted to
refineryrtr@epa.gov.
(iii) The Administrator shall approve or disapprove the plan in 90
days. The plan shall be considered approved if the Administrator either
approves the plan in writing, or fails to disapprove the plan in
writing. The 90-day period shall begin when the Administrator receives
the plan.
(iv) If the Administrator finds any deficiencies in the site-
specific monitoring plan and disapproves the plan in writing, the owner
or operator may revise and resubmit the site-specific monitoring plan
following the requirements in paragraphs (i)(3)(i) and (ii) of this
section. The 90-day period starts over with the resubmission of the
revised monitoring plan.
(4) The approval by the Administrator of a site-specific monitoring
plan will be based on the completeness, accuracy and reasonableness of
the request for a site-specific monitoring plan. Factors that the
Administrator will consider in reviewing the request for a site-
specific monitoring plan include, but are not limited to, those
described in paragraphs (i)(4)(i) through (v) of this section.
(i) The identification of the near-field source or sources. For
onsite sources, the documentation provided that the onsite source is
excluded under Sec. 63.640(g).
(ii) The monitoring location selected to determine the uniform
background concentration or an indication that no uniform background
concentration monitor will be used.
(iii) The location(s) selected for additional monitoring to
determine the near-field source concentration contribution.
(iv) The identification of the fenceline monitoring locations
impacted by the near-field source or sources.
(v) The appropriateness of the planned data reduction and
calculations to determine the near-field source concentration
contribution for each monitoring location.
(vi) If more frequent monitoring is proposed, the adequacy of the
description of the measurement and

[[Page 75257]]

recording frequency proposed and the adequacy of the rationale for
using the alternative monitoring frequency.
(j) The owner or operator shall comply with the applicable
recordkeeping and reporting requirements in Sec. 63.655(h) and (i).
(k) As outlined in Sec. 63.7(f), the owner or operator may submit
a request for an alternative test method. At a minimum, the request
must follow the requirements outlined in paragraphs (k)(1) through (7)
of this section.
(1) The alternative method may be used in lieu of all or a partial
number of passive samplers required in Method 325A of appendix A of
this part.
(2) The alternative method must be validated according to Method
301 in appendix A of this part or contain performance based procedures
and indicators to ensure self-validation.
(3) The method detection limit must nominally be at least an order
of magnitude below the action level, i.e., 0.9 [micro]g/m³
benzene. The alternate test method must describe the procedures used to
provide field verification of the detection limit.
(4) The spatial coverage must be equal to or better than the
spatial coverage provided in Method 325A of appendix A of this part.
(i) For path average concentration open-path instruments, the
physical path length of the measurement shall be no more than a passive
sample footprint (the spacing that would be provided by the sorbent
traps when following Method 325A). For example, if Method 325A requires
spacing monitors A and B 610 meters (2000 feet) apart, then the
physical path length limit for the measurement at that portion of the
fenceline shall be no more than 610 meters (2000 feet).
(ii) For range resolved open-path instrument or approach, the
instrument or approach must be able to resolve an average concentration
over each passive sampler footprint within the path length of the
instrument.
(iii) The extra samplers required in Sections 8.2.1.3 of Method
325A may be omitted when they fall within the path length of an open-
path instrument.
(5) At a minimum, non-integrating alternative test methods must
provide a minimum of one cycle of operation (sampling, analyzing, and
data recording) for each successive 15-minute period.
(6) For alternative test methods capable of real time measurements
(less than a 5 minute sampling and analysis cycle), the alternative
test method may allow for elimination of data points corresponding to
outside emission sources for purpose of calculation of the high point
for the two week average. The alternative test method approach must
have wind speed, direction and stability class of the same time
resolution and within the footprint of the instrument.
(7) For purposes of averaging data points to determine the [Delta]c
for the 14-day average high sample result, all results measured under
the method detection limit must use the method detection limit. For
purposes of averaging data points for the 14-day average low sample
result, all results measured under the method detection limit must use
zero.

0
31. Section 63.660 is added to read as follows:

Sec. 63.660 Storage vessel provisions.

On and after the applicable compliance date for a Group 1 storage
vessel located at a new or existing source as specified in Sec.
63.640(h), the owner or operator of a Group 1 storage vessel that is
part of a new or existing source shall comply with the requirements in
subpart WW or SS of this part according to the requirements in
paragraphs (a) through (i) of this section.
(a) As used in this section, all terms not defined in Sec. 63.641
shall have the meaning given them in subpart A, WW, or SS of this part.
The definitions of ``Group 1 storage vessel'' (paragraph (2)) and
``Storage vessel'' in Sec. 63.641 shall apply in lieu of the
definition of ``Storage vessel'' in Sec. 63.1061.
(1) An owner or operator may use good engineering judgment or test
results to determine the stored liquid weight percent total organic HAP
for purposes of group determination. Data, assumptions, and procedures
used in the determination shall be documented.
(2) When an owner or operator and the Administrator do not agree on
whether the annual average weight percent organic HAP in the stored
liquid is above or below 4 percent for a storage vessel at an existing
source or above or below 2 percent for a storage vessel at a new
source, an appropriate method (based on the type of liquid stored) as
published by EPA or a consensus-based standards organization shall be
used. Consensus-based standards organizations include, but are not
limited to, the following: ASTM International (100 Barr Harbor Drive,
P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-
1373, https://www.astm.org), the American National Standards Institute
(ANSI, 1819 L Street NW., 6th Floor, Washington, DC 20036, (202) 293-
8020, https://www.ansi.org), the American Gas Association (AGA, 400
North Capitol Street NW., 4th Floor, Washington, DC 20001, (202) 824-
7000, https://www.aga.org), the American Society of Mechanical Engineers
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763,
https://www.asme.org), the American Petroleum Institute (API, 1220 L
Street NW., Washington, DC 20005-4070, (202) 682-8000, https://www.api.org), and the North American Energy Standards Board (NAESB, 801
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, https://www.naesb.org).
(b) A floating roof storage vessel complying with the requirements
of subpart WW of this part may comply with the control option specified
in paragraph (b)(1) of this section and, if equipped with a ladder
having at least one slotted leg, shall comply with one of the control
options as described in paragraph (b)(2) of this section.
(1) In addition to the options presented in Sec. Sec.
63.1063(a)(2)(viii)(A) and (B) and 63.1064, a floating roof storage
vessel may comply with Sec. 63.1063(a)(2)(vii) using a flexible
enclosure device and either a gasketed or welded cap on the top of the
guidepole.
(2) Each opening through a floating roof for a ladder having at
least one slotted leg shall be equipped with one of the configurations
specified in paragraphs (b)(2)(i) through (iii) of this section.
(i) A pole float in the slotted leg and pole wipers for both legs.
The wiper or seal of the pole float must be at or above the height of
the pole wiper.
(ii) A ladder sleeve and pole wipers for both legs of the ladder.
(iii) A flexible enclosure device and either a gasketed or welded
cap on the top of the slotted leg.
(c) For the purposes of this subpart, references shall apply as
specified in paragraphs (c)(1) through (6) of this section.
(1) All references to ``the proposal date for a referencing
subpart'' and ``the proposal date of the referencing subpart'' in
subpart WW of this part mean June 30, 2014.
(2) All references to ``promulgation of the referencing subpart''
and ``the promulgation date of the referencing subpart'' in subpart WW
of this part mean February 1, 2016.
(3) All references to ``promulgation date of standards for an
affected source or affected facility under a referencing subpart'' in
subpart SS of this part mean February 1, 2016.
(4) All references to ``the proposal date of the relevant standard
established pursuant to CAA section 112(f)'' in

[[Page 75258]]

subpart SS of this part mean June 30, 2014.
(5) All references to ``the proposal date of a relevant standard
established pursuant to CAA section 112(d)'' in subpart SS of this part
mean July 14, 1994.
(6) All references to the ``required control efficiency'' in
subpart SS of this part mean reduction of organic HAP emissions by 95
percent or to an outlet concentration of 20 ppmv.
(d) For an uncontrolled fixed roof storage vessel that commenced
construction on or before June 30, 2014, and that meets the definition
of ``Group 1 storage vessel'', paragraph (2), in Sec. 63.641 but not
the definition of ``Group 1 storage vessel'', paragraph (1), in Sec.
63.641, the requirements of Sec. 63.982 and/or Sec. 63.1062 do not
apply until the next time the storage vessel is completely emptied and
degassed, or January 30, 2026, whichever occurs first.
(e) Failure to perform inspections and monitoring required by this
section shall constitute a violation of the applicable standard of this
subpart.
(f) References in Sec. 63.1066(a) to initial startup notification
requirements do not apply.
(g) References to the Notification of Compliance Status in Sec.
63.999(b) mean the Notification of Compliance Status required by Sec.
63.655(f).
(h) References to the Periodic Reports in Sec. Sec. 63.1066(b) and
63.999(c) mean the Periodic Report required by Sec. 63.655(g).
(i) Owners or operators electing to comply with the requirements in
subpart SS of this part for a Group 1 storage vessel must comply with
the requirements in paragraphs (i)(1) through (3) of this section.
(1) If a flare is used as a control device, the flare shall meet
the requirements of Sec. 63.670 instead of the flare requirements in
Sec. 63.987.
(2) If a closed vent system contains a bypass line, the owner or
operator shall comply with the provisions of either Sec.
63.983(a)(3)(i) or (ii) for each closed vent system that contains
bypass lines that could divert a vent stream either directly to the
atmosphere or to a control device that does not comply with the
requirements in subpart SS of this part. Except as provided in
paragraphs (i)(2)(i) and (ii) of this section, use of the bypass at any
time to divert a Group 1 storage vessel to either directly to the
atmosphere or to a control device that does not comply with the
requirements in subpart SS of this part is an emissions standards
violation. Equipment such as low leg drains and equipment subject to
Sec. 63.648 are not subject to this paragraph (i)(2).
(i) If planned routine maintenance of the control device cannot be
performed during periods that storage vessel emissions are vented to
the control device or when the storage vessel is taken out of service
for inspections or other planned maintenance reasons, the owner or
operator may bypass the control device.
(ii) Periods for which storage vessel control device may be
bypassed for planned routine maintenance of the control device shall
not exceed 240 hours per calendar year.
(3) If storage vessel emissions are routed to a fuel gas system or
process, the fuel gas system or process shall be operating at all times
when regulated emissions are routed to it. The exception in Sec.
63.984(a)(1) does not apply.

0
32. Section 63.670 is added to read as follows:

Sec. 63.670 Requirements for flare control devices.

On or before January 30, 2019, the owner or operator of a flare
used as a control device for an emission point subject to this subpart
shall meet the applicable requirements for flares as specified in
paragraphs (a) through (q) of this section and the applicable
requirements in Sec. 63.671. The owner or operator may elect to comply
with the requirements of paragraph (r) of this section in lieu of the
requirements in paragraphs (d) through (f) of this section, as
applicable.
(a) [Reserved]
(b) Pilot flame presence. The owner or operator shall operate each
flare with a pilot flame present at all times when regulated material
is routed to the flare. Each 15-minute block during which there is at
least one minute where no pilot flame is present when regulated
material is routed to the flare is a deviation of the standard.
Deviations in different 15-minute blocks from the same event are
considered separate deviations. The owner or operator shall monitor for
the presence of a pilot flame as specified in paragraph (g) of this
section.
(c) Visible emissions. The owner or operator shall specify the
smokeless design capacity of each flare and operate with no visible
emissions, except for periods not to exceed a total of 5 minutes during
any 2 consecutive hours, when regulated material is routed to the flare
and the flare vent gas flow rate is less than the smokeless design
capacity of the flare. The owner or operator shall monitor for visible
emissions from the flare as specified in paragraph (h) of this section.
(d) Flare tip velocity. For each flare, the owner or operator shall
comply with either paragraph (d)(1) or (2) of this section, provided
the appropriate monitoring systems are in-place, whenever regulated
material is routed to the flare for at least 15-minutes and the flare
vent gas flow rate is less than the smokeless design capacity of the
flare.
(1) Except as provided in paragraph (d)(2) of this section, the
actual flare tip velocity (Vtip) must be less than 60 feet
per second. The owner or operator shall monitor Vtipusing
the procedures specified in paragraphs (i) and (k) of this section.
(2) Vtip must be less than 400 feet per second and also
less than the maximum allowed flare tip velocity (Vmax) as
calculated according to the following equation. The owner or operator
shall monitor Vtip using the procedures specified in paragraphs (i) and
(k) of this section and monitor gas composition and determine
NHVvg using the procedures specified in paragraphs (j) and
(l) of this section.
[GRAPHIC] [TIFF OMITTED] TR01DE15.008

Where:

Vmax = Maximum allowed flare tip velocity, ft/sec.
NHVvg = Net heating value of flare vent gas, as
determined by paragraph (l)(4) of this section, Btu/scf.
1,212 = Constant.
850 = Constant.

(e) Combustion zone operating limits. For each flare, the owner or
operator shall operate the flare to maintain the net heating value of
flare combustion zone gas (NHVcz) at or above 270 British
thermal units per standard cubic feet (Btu/scf) determined on a 15-
minute block period basis when regulated material is routed to the
flare for at least 15-minutes. The owner or operator shall monitor and
calculate NHVcz as specified in paragraph (m) of this
section.
(f) Dilution operating limits for flares with perimeter assist air.
For each flare actively receiving perimeter assist air, the owner or
operator shall operate the flare to maintain the net heating value
dilution parameter (NHVdil) at or above 22 British thermal units per
square foot (Btu/ft²) determined on a 15-minute block period
basis when regulated material is being routed to the flare for at least
15-minutes. The owner or operator shall monitor and calculate
NHVdil as specified in paragraph (n) of this section.

[[Page 75259]]

(g) Pilot flame monitoring. The owner or operator shall
continuously monitor the presence of the pilot flame(s) using a device
(including, but not limited to, a thermocouple, ultraviolet beam
sensor, or infrared sensor) capable of detecting that the pilot
flame(s) is present.
(h) Visible emissions monitoring. The owner or operator shall
monitor visible emissions while regulated materials are vented to the
flare. An initial visible emissions demonstration must be conducted
using an observation period of 2 hours using Method 22 at 40 CFR part
60, appendix A-7. Subsequent visible emissions observations must be
conducted using either the methods in paragraph (h)(1) of this section
or, alternatively, the methods in paragraph (h)(2) of this section. The
owner or operator must record and report any instances where visible
emissions are observed for more than 5 minutes during any 2 consecutive
hours as specified in Sec. 63.655(g)(11)(ii).
(1) At least once per day, conduct visible emissions observations
using an observation period of 5 minutes using Method 22 at 40 CFR part
60, appendix A-7. If at any time the owner or operator sees visible
emissions, even if the minimum required daily visible emission
monitoring has already been performed, the owner or operator shall
immediately begin an observation period of 5 minutes using Method 22 at
40 CFR part 60, appendix A-7. If visible emissions are observed for
more than one continuous minute during any 5-minute observation period,
the observation period using Method 22 at 40 CFR part 60, appendix A-7
must be extended to 2 hours or until 5-minutes of visible emissions are
observed.
(2) Use a video surveillance camera to continuously record (at
least one frame every 15 seconds with time and date stamps) images of
the flare flame and a reasonable distance above the flare flame at an
angle suitable for visual emissions observations. The owner or operator
must provide real-time video surveillance camera output to the control
room or other continuously manned location where the camera images may
be viewed at any time.
(i) Flare vent gas, steam assist and air assist flow rate
monitoring. The owner or operator shall install, operate, calibrate,
and maintain a monitoring system capable of continuously measuring,
calculating, and recording the volumetric flow rate in the flare header
or headers that feed the flare as well as any supplemental natural gas
used. Different flow monitoring methods may be used to measure
different gaseous streams that make up the flare vent gas provided that
the flow rates of all gas streams that contribute to the flare vent gas
are determined. If assist air or assist steam is used, the owner or
operator shall install, operate, calibrate, and maintain a monitoring
system capable of continuously measuring, calculating, and recording
the volumetric flow rate of assist air and/or assist steam used with
the flare. If pre-mix assist air and perimeter assist are both used,
the owner or operator shall install, operate, calibrate, and maintain a
monitoring system capable of separately measuring, calculating, and
recording the volumetric flow rate of premix assist air and perimeter
assist air used with the flare. Continuously monitoring fan speed or
power and using fan curves is an acceptable method for continuously
monitoring assist air flow rates.
(1) The flow rate monitoring systems must be able to correct for
the temperature and pressure of the system and output parameters in
standard conditions (i.e., a temperature of 20 [deg]C
(68[emsp14][deg]F) and a pressure of 1 atmosphere).
(2) Mass flow monitors may be used for determining volumetric flow
rate of flare vent gas provided the molecular weight of the flare vent
gas is determined using compositional analysis as specified in
paragraph (j) of this section so that the mass flow rate can be
converted to volumetric flow at standard conditions using the following
equation.
[GRAPHIC] [TIFF OMITTED] TR01DE15.009

Where:

Qvol = Volumetric flow rate, standard cubic feet per
second.
Qmass = Mass flow rate, pounds per second.
385.3 = Conversion factor, standard cubic feet per pound-mole.
MWt = Molecular weight of the gas at the flow monitoring location,
pounds per pound-mole.

(3) Mass flow monitors may be used for determining volumetric flow
rate of assist air or assist steam. Use equation in paragraph (i)(2) of
this section to convert mass flow rates to volumetric flow rates. Use a
molecular weight of 18 pounds per pound-mole for assist steam and use a
molecular weight of 29 pounds per pound-mole for assist air.
(4) Continuous pressure/temperature monitoring system(s) and
appropriate engineering calculations may be used in lieu of a
continuous volumetric flow monitoring systems provided the molecular
weight of the gas is known. For assist steam, use a molecular weight of
18 pounds per pound-mole. For assist air, use a molecular weight of 29
pounds per pound-mole. For flare vent gas, molecular weight must be
determined using compositional analysis as specified in paragraph (j)
of this section.
(j) Flare vent gas composition monitoring. The owner or operator
shall determine the concentration of individual components in the flare
vent gas using either the methods provided in paragraph (j)(1) or (2)
of this section, to assess compliance with the operating limits in
paragraph (e) of this section and, if applicable, paragraphs (d) and
(f) of this section. Alternatively, the owner or operator may elect to
directly monitor the net heating value of the flare vent gas following
the methods provided in paragraphs (j)(3) of this section and, if
desired, may directly measure the hydrogen concentration in the flare
vent gas following the methods provided in paragraphs (j)(4) of this
section. The owner or operator may elect to use different monitoring
methods for different gaseous streams that make up the flare vent gas
using different methods provided the composition or net heating value
of all gas streams that contribute to the flare vent gas are
determined.
(1) Except as provided in paragraphs (j)(5) and (6) of this
section, the owner or operator shall install, operate, calibrate, and
maintain a monitoring system capable of continuously measuring (i.e.,
at least once every 15-minutes), calculating, and recording the
individual component concentrations present in the flare vent gas.
(2) Except as provided in paragraphs (j)(5) and (6) of this
section, the owner or operator shall install, operate, and maintain a
grab sampling system capable of collecting an evacuated canister sample
for subsequent compositional analysis at least once every eight hours
while there is flow of regulated material to the flare. Subsequent
compositional analysis of the samples must be performed according to
Method 18 of 40 CFR part 60, appendix A-6, ASTM D6420-99 (Reapproved
2010), ASTM D1945-03 (Reapproved 2010), ASTM D1945-14 or ASTM UOP539-12
(all incorporated by reference--see Sec. 63.14).
(3) Except as provided in paragraphs (j)(5) and (6) of this
section, the owner or operator shall install, operate, calibrate, and
maintain a calorimeter capable of continuously measuring, calculating,
and recording NHVvg at standard conditions.
(4) If the owner or operator uses a continuous net heating value
monitor according to paragraph (j)(3) of this section, the owner or
operator may, at their discretion, install, operate, calibrate, and
maintain a monitoring

[[Page 75260]]

system capable of continuously measuring, calculating, and recording
the hydrogen concentration in the flare vent gas.
(5) Direct compositional or net heating value monitoring is not
required for purchased (``pipeline quality'') natural gas streams. The
net heating value of purchased natural gas streams may be determined
using annual or more frequent grab sampling at any one representative
location. Alternatively, the net heating value of any purchased natural
gas stream can be assumed to be 920 Btu/scf.
(6) Direct compositional or net heating value monitoring is not
required for gas streams that have been demonstrated to have consistent
composition (or a fixed minimum net heating value) according to the
methods in paragraphs (j)(6)(i) through (v) of this section.
(i) The owner or operator shall submit to the Administrator a
written application for an exemption from monitoring. The application
must contain the following information:
(A) A description of the flare gas stream/system to be considered,
including submission of a portion of the appropriate piping diagrams
indicating the boundaries of the flare gas stream/system and the
affected flare(s) to be considered;
(B) A statement that there are no crossover or entry points to be
introduced into the flare gas stream/system (this should be shown in
the piping diagrams) prior to the point where the flow rate of the gas
streams is measured;
(C) An explanation of the conditions that ensure that the flare gas
net heating value is consistent and, if flare gas net heating value is
expected to vary (e.g., due to product loading of different material),
the conditions expected to produce the flare gas with the lowest net
heating value;
(D) The supporting test results from sampling the requested flare
gas stream/system for the net heating value. Sampling data must
include, at minimum, 2 weeks of daily measurement values (14 grab
samples) for frequently operated flare gas streams/systems; for
infrequently operated flare gas streams/systems, seven grab samples
must be collected unless other additional information would support
reduced sampling. If the flare gas stream composition can vary, samples
must be taken during those conditions expected to result in lowest net
heating value identified in paragraph (j)(6)(i)(C) of this section. The
owner or operator shall determine net heating value for the gas stream
using either gas composition analysis or net heating value monitor
(with optional hydrogen concentration analyzer) according to the method
provided in paragraph (l) of this section; and
(E) A description of how the 2 weeks (or seven samples for
infrequently operated flare gas streams/systems) of monitoring results
compares to the typical range of net heating values expected for the
flare gas stream/system going to the affected flare (e.g., ``the
samples are representative of typical operating conditions of the flare
gas stream going to the loading rack flare'' or ``the samples are
representative of conditions expected to yield the lowest net heating
value of the flare gas stream going to the loading rack flare'').
(F) The net heating value to be used for all flows of the flare
vent gas from the flare gas stream/system covered in the application. A
single net heating value must be assigned to the flare vent gas either
by selecting the lowest net heating value measured in the sampling
program or by determining the 95th percent confidence interval on the
mean value of all samples collected using the t-distribution statistic
(which is 1.943 for 7 grab samples or 1.771 for 14 grab samples).
(ii) The effective date of the exemption is the date of submission
of the information required in paragraph (j)(6)(i) of this section.
(iii) No further action is required unless refinery operating
conditions change in such a way that affects the exempt fuel gas
stream/system (e.g., the stream composition changes). If such a change
occurs, the owner or operator shall follow the procedures in paragraph
(j)(6)(iii)(A), (B), or (C) of this section.
(A) If the operation change results in a flare vent gas net heating
value that is still within the range of net heating values included in
the original application, the owner or operator shall determine the net
heating value on a grab sample and record the results as proof that the
net heating value assigned to the vent gas stream in the original
application is still appropriate.
(B) If the operation change results in a flare vent gas net heating
value that is lower than the net heating value assigned to the vent gas
stream in the original application, the owner or operator may submit
new information following the procedures of paragraph (j)(6)(i) of this
section within 60 days (or within 30 days after the seventh grab sample
is tested for infrequently operated process units).
(C) If the operation change results in a flare vent gas net heating
value has greater variability in the flare gas stream/system such the
owner or operator chooses not to submit new information to support an
exemption, the owner or operator must begin monitoring the composition
or net heat content of the flare vent gas stream using the methods in
this section (i.e., grab samples every 8 hours until such time a
continuous monitor, if elected, is installed).
(k) Calculation methods for cumulative flow rates and determining
compliance with Vtip operating limits. The owner or operator shall
determine Vtip on a 15-minute block average basis according
to the following requirements.
(1) The owner or operator shall use design and engineering
principles to determine the unobstructed cross sectional area of the
flare tip. The unobstructed cross sectional area of the flare tip is
the total tip area that vent gas can pass through. This area does not
include any stability tabs, stability rings, and upper steam or air
tubes because flare vent gas does not exit through them.
(2) The owner or operator shall determine the cumulative volumetric
flow of flare vent gas for each 15-minute block average period using
the data from the continuous flow monitoring system required in
paragraph (i) of this section according to the following requirements,
as applicable. If desired, the cumulative flow rate for a 15-minute
block period only needs to include flow during those periods when
regulated material is sent to the flare, but owners or operators may
elect to calculate the cumulative flow rates across the entire 15-
minute block period for any 15-minute block period where there is
regulated material flow to the flare.
(i) Use set 15-minute time periods starting at 12 midnight to 12:15
a.m., 12:15 a.m. to 12:30 a.m. and so on concluding at 11:45 p.m. to
midnight when calculating 15-minute block average flow volumes.
(ii) If continuous pressure/temperature monitoring system(s) and
engineering calculations are used as allowed under paragraph (i)(4) of
this section, the owner or operator shall, at a minimum, determine the
15-minute block average temperature and pressure from the monitoring
system and use those values to perform the engineering calculations to
determine the cumulative flow over the 15-minute block average period.
Alternatively, the owner or operator may divide the 15-minute block
average period into equal duration subperiods (e.g., three 5-minute
periods) and determine the average temperature and pressure for each
subperiod, perform engineering calculations to determine the flow for
each subperiod, then add the volumetric

[[Page 75261]]

flows for the subperiods to determine the cumulative volumetric flow of
vent gas for the 15-minute block average period.
(3) The 15-minute block average Vtip shall be calculated
using the following equation.
[GRAPHIC] [TIFF OMITTED] TR01DE15.010

Where:

Vtip = Flare tip velocity, feet per second.
Qcum = Cumulative volumetric flow over 15-minute block
average period, actual cubic feet.
Area = Unobstructed area of the flare tip, square feet.
900 = Conversion factor, seconds per 15-minute block average.

(4) If the owner or operator chooses to comply with paragraph
(d)(2) of this section, the owner or operator shall also determine the
net heating value of the flare vent gas following the requirements in
paragraphs (j) and (l) of this section and calculate Vmax
using the equation in paragraph (d)(2) of this section in order to
compare Vtip to Vmax on a 15-minute block average
basis.
(l) Calculation methods for determining flare vent gas net heating
value. The owner or operator shall determine the net heating value of
the flare vent gas (NHVvg) based on the composition
monitoring data on a 15-minute block average basis according to the
following requirements.
(1) If compositional analysis data are collected as provided in
paragraph (j)(1) or (2) of this section, the owner or operator shall
determine NHVvg of a specific sample by using the following
equation.
[GRAPHIC] [TIFF OMITTED] TR01DE15.011

Where:

NHVvg = Net heating value of flare vent gas, Btu/scf.
i = Individual component in flare vent gas.
n = Number of components in flare vent gas.
xi = Concentration of component i in flare vent gas,
volume fraction.
NHVi = Net heating value of component i according to
table 12 of this subpart, Btu/scf. If the component is not specified
in table 12 of this subpart, the heats of combustion may be
determined using any published values where the net enthalpy per
mole of offgas is based on combustion at 25 [deg]C and 1 atmosphere
(or constant pressure) with offgas water in the gaseous state, but
the standard temperature for determining the volume corresponding to
one mole of vent gas is 20 [deg]C.

(2) If direct net heating value monitoring data are collected as
provided in paragraph (j)(3) of this section but a hydrogen
concentration monitor is not used, the owner or operator shall use the
direct output of the monitoring system(s) (in Btu/scf) to determine the
NHVvg for the sample.
(3) If direct net heating value monitoring data are collected as
provided in paragraph (j)(3) of this section and hydrogen concentration
monitoring data are collected as provided in paragraph (j)(4) of this
section, the owner or operator shall use the following equation to
determine NHVvg for each sample measured via the net heating
value monitoring system.

NHVvg = NHVmeasured + 938xH2

Where:

NHVvg = Net heating value of flare vent gas, Btu/scf.

NHVmeasured = Net heating value of flare vent gas stream
as measured by the continuous net heating value monitoring system,
Btu/scf.
xH2 = Concentration of hydrogen in flare vent gas at the time the
sample was input into the net heating value monitoring system,
volume fraction.
938 = Net correction for the measured heating value of hydrogen
(1,212 - 274), Btu/scf.

(4) Use set 15-minute time periods starting at 12 midnight to 12:15
a.m., 12:15 a.m. to 12:30 a.m. and so on concluding at 11:45 p.m. to
midnight when calculating 15-minute block averages.
(5) When a continuous monitoring system is used as provided in
paragraph (j)(1) or (3) of this section and, if applicable, paragraph
(j)(4) of this section, the owner or operator may elect to determine
the 15-minute block average NHVvg using either the
calculation methods in paragraph (l)(5)(i) of this section or the
calculation methods in paragraph (l)(5)(ii) of this section. The owner
or operator may choose to comply using the calculation methods in
paragraph (l)(5)(i) of this section for some flares at the petroleum
refinery and comply using the calculation methods (l)(5)(ii) of this
section for other flares. However, for each flare, the owner or
operator must elect one calculation method that will apply at all
times, and use that method for all continuously monitored flare vent
streams associated with that flare. If the owner or operator intends to
change the calculation method that applies to a flare, the owner or
operator must notify the Administrator 30 days in advance of such a
change.
(i) Feed-forward calculation method. When calculating
NHVvg for a specific 15-minute block:
(A) Use the results from the first sample collected during an
event, (for periodic flare vent gas flow events) for the first 15-
minute block associated with that event.
(B) If the results from the first sample collected during an event
(for periodic flare vent gas flow events) are not available until after
the second 15-minute block starts, use the results from the first
sample collected during an event for the second 15-minute block
associated with that event.
(C) For all other cases, use the results that are available from
the most recent sample prior to the 15-minute block period for that 15-
minute block period for all flare vent gas steams. For the purpose of
this requirement, use the time that the results become available rather
than the time the sample was collected. For example, if a sample is
collected at 12:25 a.m. and the analysis is completed at 12:38 a.m.,
the results are available at 12:38 a.m. and these results would be used
to determine compliance during the 15-minute block period from 12:45
a.m. to 1:00 a.m.
(ii) Direct calculation method. When calculating NHVvg
for a specific 15-minute block:
(A) If the results from the first sample collected during an event
(for periodic flare vent gas flow events) are not available until after
the second 15-minute block starts, use the results from the first
sample collected during an event for the first 15-minute block
associated with that event.
(B) For all other cases, use the arithmetic average of all
NHVvg measurement data results that become available during
a 15-minute block to calculate the 15-minute block average for that
period. For the purpose of this requirement, use the time that the
results become available rather than the time the sample was collected.
For example, if a sample is collected at 12:25 a.m. and the analysis is
completed at 12:38 a.m., the results are available at 12:38 a.m. and
these results would be used to determine compliance during the 15-
minute block period from 12:30 a.m. to 12:45 a.m.
(6) When grab samples are used to determine flare vent gas
composition:
(i) Use the analytical results from the first grab sample collected
for an event for all 15-minute periods from the start of the event
through the 15-minute block prior to the 15-minute block in which a
subsequent grab sample is collected.
(ii) Use the results from subsequent grab sampling events for all
15 minute periods starting with the 15-minute block in which the sample
was collected and ending with the 15-minute block prior to the 15-
minute block in which the next grab sample is collected. For

[[Page 75262]]

the purpose of this requirement, use the time the sample was collected
rather than the time the analytical results become available.
(7) If the owner or operator monitors separate gas streams that
combine to comprise the total flare vent gas flow, the 15-minute block
average net heating value shall be determined separately for each
measurement location according to the methods in paragraphs (l)(1)
through (6) of this section and a flow-weighted average of the gas
stream net heating values shall be used to determine the 15-minute
block average net heating value of the cumulative flare vent gas.
(m) Calculation methods for determining combustion zone net heating
value. The owner or operator shall determine the net heating value of
the combustion zone gas (NHVcz) as specified in paragraph
(m)(1) or (2) of this section, as applicable.
(1) Except as specified in paragraph (m)(2) of this section,
determine the 15-minute block average NHVcz based on the 15-
minute block average vent gas and assist gas flow rates using the
following equation. For periods when there is no assist steam flow or
premix assist air flow, NHVcz = NHVvg.
[GRAPHIC] [TIFF OMITTED] TR01DE15.012

Where:

(2) Owners or operators of flares that use the feed-forward
calculation methodology in paragraph (l)(5)(i) of this section and that
monitor gas composition or net heating value in a location
representative of the cumulative vent gas stream and that directly
monitor supplemental natural gas flow additions to the flare must
determine the 15-minute block average NHVcz using the
following equation.
[GRAPHIC] [TIFF OMITTED] TR01DE15.013

Where:

NHVcz = Net heating value of combustion zone gas, Btu/
scf.
NHVvg = Net heating value of flare vent gas for the 15-
minute block period, Btu/scf.
Qvg = Cumulative volumetric flow of flare vent gas during
the 15-minute block period, scf.
QNG2 = Cumulative volumetric flow of supplemental natural
gas to the flare during the 15-minute block period, scf.
QNG1 = Cumulative volumetric flow of supplemental natural
gas to the flare during the previous 15-minute block period, scf.
For the first 15-minute block period of an event, use the volumetric
flow value for the current 15-minute block period, i.e.,
QNG1=QNG2.
NHVNG = Net heating value of supplemental natural gas to
the flare for the 15-minute block period determined according to the
requirements in paragraph (j)(5) of this section, Btu/scf.
Qs = Cumulative volumetric flow of total steam during the
15-minute block period, scf.
Qa,premix = Cumulative volumetric flow of premix assist
air during the 15-minute block period, scf.

(n) Calculation methods for determining the net heating value
dilution parameter. The owner or operator shall determine the net
heating value dilution parameter (NHVdil) as specified in
paragraph (n)(1) or (2) of this section, as applicable.
(1) Except as specified in paragraph (n)(2) of this section,
determine the 15-minute block average NHVdil based on the
15-minute block average vent gas and perimeter assist air flow rates
using the following equation only during periods when perimeter assist
air is used. For 15-minute block periods when there is no cumulative
volumetric flow of perimeter assist air, the 15-minute block average
NHVdil parameter does not need to be calculated.
[GRAPHIC] [TIFF OMITTED] TR01DE15.014

Where:

NHVdil = Net heating value dilution parameter, Btu/
ft².
NHVvg = Net heating value of flare vent gas determined
for the 15-minute block period, Btu/scf.
Qvg = Cumulative volumetric flow of flare vent gas during
the 15-minute block period, scf.
Diam = Effective diameter of the unobstructed area of the flare tip
for flare vent gas flow, ft. Use the area as determined in paragraph
(k)(1) of this section and determine the diameter as
[GRAPHIC] [TIFF OMITTED] TR01DE15.015

Qs = Cumulative volumetric flow of total steam during the
15-minute block period, scf.
Qa,premix = Cumulative volumetric flow of premix assist
air during the 15-minute block period, scf.
Qa,perimeter = Cumulative volumetric flow of perimeter
assist air during the 15-minute block period, scf.

(2) Owners or operators of flares that use the feed-forward
calculation methodology in paragraph (l)(5)(i) of this section and that
monitor gas composition or net heating value in a location
representative of the cumulative vent gas stream and that directly
monitor supplemental natural gas flow additions to the flare must
determine the 15-minute block average NHVdil using the
following equation only during periods when perimeter assist air is
used. For 15-minute block periods when there is no cumulative

[[Page 75263]]

volumetric flow of perimeter assist air, the 15-minute block average
NHVdil parameter does not need to be calculated.
[GRAPHIC] [TIFF OMITTED] TR01DE15.016

Where:

NHVdil = Net heating value dilution parameter, Btu/
ft².
NHVvg = Net heating value of flare vent gas determined
for the 15-minute block period, Btu/scf.
Qvg = Cumulative volumetric flow of flare vent gas during
the 15-minute block period, scf.
QNG2 = Cumulative volumetric flow of supplemental natural
gas to the flare during the 15-minute block period, scf.
QNG1 = Cumulative volumetric flow of supplemental natural
gas to the flare during the previous 15-minute block period, scf.
For the first 15-minute block period of an event, use the volumetric
flow value for the current 15-minute block period, i.e.,
QNG1 =QNG2.
NHVNG = Net heating value of supplemental natural gas to
the flare for the 15-minute block period determined according to the
requirements in paragraph (j)(5) of this section, Btu/scf.
Diam = Effective diameter of the unobstructed area of the flare tip
for flare vent gas flow, ft. Use the area as determined in paragraph
(k)(1) of this section and determine the diameter as
[GRAPHIC] [TIFF OMITTED] TR01DE15.017

(o) Emergency flaring provisions. The owner or operator of a flare
that has the potential to operate above its smokeless capacity under
any circumstance shall comply with the provisions in paragraphs (o)(1)
through (8) of this section.
(1) Develop a flare management plan to minimize flaring during
periods of startup, shutdown, or emergency releases. The flare
management plan must include the information described in paragraphs
(o)(1)(i) through (vii) of this section.
(i) A listing of all refinery process units, ancillary equipment,
and fuel gas systems connected to the flare for each affected flare.
(ii) An assessment of whether discharges to affected flares from
these process units, ancillary equipment and fuel gas systems can be
minimized or prevented during periods of startup, shutdown, or
emergency releases. The flare minimization assessment must (at a
minimum) consider the items in paragraphs (o)(1)(ii)(A) through (C) of
this section. The assessment must provide clear rationale in terms of
costs (capital and annual operating), natural gas offset credits (if
applicable), technical feasibility, secondary environmental impacts and
safety considerations for the selected minimization alternative(s) or a
statement, with justifications, that flow reduction could not be
achieved. Based upon the assessment, each owner or operator of an
affected flare shall identify the minimization alternatives that it has
implemented by the due date of the flare management plan and shall
include a schedule for the prompt implementation of any selected
measures that cannot reasonably be completed as of that date.
(A) Modification in startup and shutdown procedures to reduce the
quantity of process gas discharge to the flare.
(B) Implementation of prevention measures listed for pressure
relief devices in Sec. 63.648(j)(5) for each pressure relief valve
that can discharge to the flare.
(C) Installation of a flare gas recovery system or, for facilities
that are fuel gas rich, a flare gas recovery system and a co-generation
unit or combined heat and power unit.
(iii) A description of each affected flare containing the
information in paragraphs (o)(1)(iii)(A) through (G) of this section.
(A) A general description of the flare, including whether it is a
ground flare or elevated (including height), the type of assist system
(e.g., air, steam, pressure, non-assisted), whether the flare is used
on a routine basis or if it is only used during periods of startup,
shutdown or emergency release, and whether the flare is equipped with a
flare gas recovery system.
(B) The smokeless capacity of the flare based on design conditions.
Note: A single value must be provided for the smokeless capacity of the
flare.
(C) The maximum vent gas flow rate (hydraulic load capacity).
(D) The maximum supplemental gas flow rate.
(E) For flares that receive assist steam, the minimum total steam
rate and the maximum total steam rate.
(F) For flares that receive assist air, an indication of whether
the fan/blower is single speed, multi-fixed speed (e.g., high, medium,
and low speeds), or variable speeds. For fans/blowers with fixed
speeds, provide the estimated assist air flow rate at each fixed speed.
For variable speeds, provide the design fan curve (e.g., air flow rate
as a function of power input).
(G) Simple process flow diagram showing the locations of the flare
following components of the flare: Flare tip (date installed,
manufacturer, nominal and effective tip diameter, tip drawing);
knockout or surge drum(s) or pot(s) (including dimensions and design
capacities); flare header(s) and subheader(s); assist system; and
ignition system.
(iv) Description and simple process flow diagram showing all gas
lines (including flare waste gas, purge or sweep gas (as applicable),
supplemental gas) that are associated with the flare. For purge, sweep,
supplemental gas, identify the type of gas used. Designate which lines
are exempt from composition or net heating value monitoring and why
(e.g., natural gas, gas streams that have been demonstrated to have
consistent composition, pilot gas). Designate which lines are monitored
and identify on the process flow diagram the location and type of each
monitor. Designate the pressure relief devices that are vented to the
flare.
(v) For each flow rate, gas composition, net heating value or
hydrogen concentration monitor identified in paragraph (o)(1)(iv) of
this section, provide a detailed description of the manufacturer's
specifications, including, but not limited to, make, model, type,
range, precision, accuracy, calibration, maintenance and quality
assurance procedures.
(vi) For each pressure relief valve vented to the flare identified
in paragraph (o)(1)(iv) of this section, provide a detailed description
of each pressure release valve, including type of relief device
(rupture disc, valve type) diameter of the relief valve, set pressure
of the relief valve and listing of the prevention measures implemented.
This

[[Page 75264]]

information may be maintained in an electronic database on-site and
does not need to be submitted as part of the flare management plan
unless requested to do so by the Administrator.
(vii) Procedures to minimize or eliminate discharges to the flare
during the planned startup and shutdown of the refinery process units
and ancillary equipment that are connected to the affected flare,
together with a schedule for the prompt implementation of any
procedures that cannot reasonably be implemented as of the date of the
submission of the flare management plan.
(2) Each owner or operator required to develop and implement a
written flare management plan as described in paragraph (o)(1) of this
section must submit the plan to the Administrator as described in
paragraphs (o)(2)(i) through (iii) of this section.
(i) The owner or operator must develop and implement the flare
management plan no later than January 30, 2019 or at startup for a new
flare that commenced construction on or after February 1, 2016.
(ii) The owner or operator must comply with the plan as submitted
by the date specified in paragraph (o)(2)(i) of this section. The plan
should be updated periodically to account for changes in the operation
of the flare, such as new connections to the flare or the installation
of a flare gas recovery system, but the plan need be re-submitted to
the Administrator only if the owner or operator alters the design
smokeless capacity of the flare. The owner or operator must comply with
the updated plan as submitted.
(iii) All versions of the plan submitted to the Administrator shall
also be submitted to the following address: U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards, Sector
Policies and Programs Division, U.S. EPA Mailroom (E143-01), Attention:
Refinery Sector Lead, 109 T.W. Alexander Drive, Research Triangle Park,
NC 27711. Electronic copies in lieu of hard copies may also be
submitted to refineryRTR@epa.gov.
(3) The owner or operator of a flare subject to this subpart shall
conduct a root cause analysis and a corrective action analysis for each
flow event that contains regulated material and that meets either the
criteria in paragraph (o)(3)(i) or (ii) of this section.
(i) The vent gas flow rate exceeds the smokeless capacity of the
flare and visible emissions are present from the flare for more than 5
minutes during any 2 consecutive hours during the release event.
(ii) The vent gas flow rate exceeds the smokeless capacity of the
flare and the 15-minute block average flare tip velocity exceeds the
maximum flare tip velocity determined using the methods in paragraph
(d)(2) of this section.
(4) A root cause analysis and corrective action analysis must be
completed as soon as possible, but no later than 45 days after a flare
flow event meeting the criteria in paragraph (o)(3)(i) or (ii) of this
section. Special circumstances affecting the number of root cause
analyses and/or corrective action analyses are provided in paragraphs
(o)(4)(i) through (v) of this section.
(i) You may conduct a single root cause analysis and corrective
action analysis for a single continuous flare flow event that meets
both of the criteria in paragraphs (o)(3)(i) and (ii) of this section.
(ii) You may conduct a single root cause analysis and corrective
action analysis for a single continuous flare flow event regardless of
the number of 15-minute block periods in which the flare tip velocity
was exceeded or the number of 2 hour periods that contain more the 5
minutes of visible emissions.
(iii) You may conduct a single root cause analysis and corrective
action analysis for a single event that causes two or more flares that
are operated in series (i.e., cascaded flare systems) to have a flow
event meeting the criteria in paragraph (o)(3)(i) or (ii) of this
section.
(iv) You may conduct a single root cause analysis and corrective
action analysis for a single event that causes two or more flares to
have a flow event meeting the criteria in paragraph (o)(3)(i) or (ii)
of this section, regardless of the configuration of the flares, if the
root cause is reasonably expected to be a force majeure event, as
defined in this subpart.
(v) Except as provided in paragraphs (o)(4)(iii) and (iv) of this
section, if more than one flare has a flow event that meets the
criteria in paragraph (o)(3)(i) or (ii) of this section during the same
time period, an initial root cause analysis shall be conducted
separately for each flare that has a flow event meeting the criteria in
paragraph (o)(3)(i) or (ii) of this section. If the initial root cause
analysis indicates that the flow events have the same root cause(s),
the initially separate root cause analyses may be recorded as a single
root cause analysis and a single corrective action analysis may be
conducted.
(5) Each owner or operator of a flare required to conduct a root
cause analysis and corrective action analysis as specified in
paragraphs (o)(3) and (4) of this section shall implement the
corrective action(s) identified in the corrective action analysis in
accordance with the applicable requirements in paragraphs (o)(5)(i)
through (iii) of this section.
(i) All corrective action(s) must be implemented within 45 days of
the event for which the root cause and corrective action analyses were
required or as soon thereafter as practicable. If an owner or operator
concludes that no corrective action should be implemented, the owner or
operator shall record and explain the basis for that conclusion no
later than 45 days following the event.
(ii) For corrective actions that cannot be fully implemented within
45 days following the event for which the root cause and corrective
action analyses were required, the owner or operator shall develop an
implementation schedule to complete the corrective action(s) as soon as
practicable.
(iii) No later than 45 days following the event for which a root
cause and corrective action analyses were required, the owner or
operator shall record the corrective action(s) completed to date, and,
for action(s) not already completed, a schedule for implementation,
including proposed commencement and completion dates.
(6) The owner or operator shall determine the total number of
events for which a root cause and corrective action analyses was
required during the calendar year for each affected flare separately
for events meeting the criteria in paragraph (o)(3)(i) of this section
and those meeting the criteria in paragraph (o)(3)(ii) of this section.
For the purpose of this requirement, a single root cause analysis
conducted for an event that met both of the criteria in paragraphs
(o)(3)(i) and (ii) of this section would be counted as an event under
each of the separate criteria counts for that flare. Additionally, if a
single root cause analysis was conducted for an event that caused
multiple flares to meet the criteria in paragraph (o)(3)(i) or (ii) of
this section, that event would count as an event for each of the flares
for each criteria in paragraph (o)(3) of this section that was met
during that event. The owner or operator shall also determine the total
number of events for which a root cause and correct action analyses was
required and the analyses concluded that the root cause was a force
majeure event, as defined in this subpart.
(7) The following events would be a violation of this emergency
flaring work practice standard.
(i) Any flow event for which a root cause analysis was required and
the root

[[Page 75265]]

cause was determined to be operator error or poor maintenance.
(ii) Two visible emissions exceedance events meeting the criteria
in paragraph (o)(3)(i) of this section that were not caused by a force
majeure event from a single flare in a 3 calendar year period for the
same root cause for the same equipment.
(iii) Two flare tip velocity exceedance events meeting the criteria
in paragraph (o)(3)(ii) of this section that were not caused by a force
majeure event from a single flare in a 3 calendar year period for the
same root cause for the same equipment.
(iv) Three visible emissions exceedance events meeting the criteria
in paragraph (o)(3)(i) of this section that were not caused by a force
majeure event from a single flare in a 3 calendar year period for any
reason.
(v) Three flare tip velocity exceedance events meeting the criteria
in paragraph (o)(3)(ii) of this section that were not caused by a force
majeure event from a single flare in a 3 calendar year period for any
reason.
(p) Flare monitoring records. The owner or operator shall keep the
records specified in Sec. 63.655(i)(9).
(q) Reporting. The owner or operator shall comply with the
reporting requirements specified in Sec. 63.655(g)(11).
(r) Alternative means of emissions limitation. An owner or operator
may request approval from the Administrator for site-specific operating
limits that shall apply specifically to a selected flare. Site-specific
operating limits include alternative threshold values for the
parameters specified in paragraphs (d) through (f) of this section as
well as threshold values for operating parameters other than those
specified in paragraphs (d) through (f) of this section. The owner or
operator must demonstrate that the flare achieves 96.5 percent
combustion efficiency (or 98 percent destruction efficiency) using the
site-specific operating limits based on a performance evaluation as
described in paragraph (r)(1) of this section. The request shall
include information as described in paragraph (r)(2) of this section.
The request shall be submitted and followed as described in paragraph
(r)(3) of this section.
(1) The owner or operator shall prepare and submit a site-specific
test plan and receive approval of the site-specific performance
evaluation plan prior to conducting any flare performance evaluation
test runs intended for use in developing site-specific operating
limits. The site-specific performance evaluation plan shall include, at
a minimum, the elements specified in paragraphs (r)(1)(i) through (ix)
of this section. Upon approval of the site-specific performance
evaluation plan, the owner or operator shall conduct performance
evaluation test runs for the flare following the procedures described
in the site-specific performance evaluation plan.
(i) The design and dimensions of the flare, flare type (air-
assisted only, steam-assisted only, air- and steam-assisted, pressure-
assisted, or non-assisted), and description of gas being flared,
including quantity of gas flared, frequency of flaring events (if
periodic), expected net heating value of flare vent gas, minimum total
steam assist rate.
(ii) The operating conditions (vent gas compositions, vent gas flow
rates and assist flow rates, if applicable) likely to be encountered by
the flare during normal operations and the operating conditions for the
test period.
(iii) A description of (including sample calculations illustrating)
the planned data reduction and calculations to determine the flare
combustion or destruction efficiency.
(iv) Site-specific operating parameters to be monitored
continuously during the flare performance evaluation. These parameters
may include but are not limited to vent gas flow rate, steam and/or air
assist flow rates, and flare vent gas composition. If new operating
parameters are proposed for use other than those specified in
paragraphs (d) through (f) of this section, an explanation of the
relevance of the proposed operating parameter(s) as an indicator of
flare combustion performance and why the alternative operating
parameter(s) can adequately ensure that the flare achieves the required
combustion efficiency.
(v) A detailed description of the measurement methods, monitored
pollutant(s), measurement locations, measurement frequency, and
recording frequency proposed for both emission measurements and flare
operating parameters.
(vi) A description of (including sample calculations illustrating)
the planned data reduction and calculations to determine the flare
operating parameters.
(vii) The minimum number and length of test runs and range of
operating values to be evaluated during the performance evaluation. A
sufficient number of test runs shall be conducted to identify the point
at which the combustion/destruction efficiency of the flare
deteriorates.
(viii) [Reserved]
(ix) Test schedule.
(2) The request for flare-specific operating limits shall include
sufficient and appropriate data, as determined by the Administrator, to
allow the Administrator to confirm that the selected site-specific
operating limit(s) adequately ensures that the flare destruction
efficiency is 98 percent or greater or that the flare combustion
efficiency is 96.5 percent or greater at all times. At a minimum, the
request shall contain the information described in paragraphs (r)(2)(i)
through (iv) of this section.
(i) The design and dimensions of the flare, flare type (air-
assisted only, steam-assisted only, air- and steam-assisted, pressure-
assisted, or non-assisted), and description of gas being flared,
including quantity of gas flared, frequency of flaring events (if
periodic), expected net heating value of flare vent gas, minimum total
steam assist rate.
(ii) Results of each performance evaluation test run conducted,
including, at a minimum:
(A) The measured combustion/destruction efficiency.
(B) The measured or calculated operating parameters for each test
run. If operating parameters are calculated, the raw data from which
the parameters are calculated must be included in the test report.
(C) Measurement location descriptions for both emission
measurements and flare operating parameters.
(D) Description of sampling and analysis procedures (including
number and length of test runs) and any modifications to standard
procedures. If there were deviations from the approved test plan, a
detailed description of the deviations and rationale why the test
results or calculation procedures used are appropriate.
(E) Operating conditions (e.g., vent gas composition, assist rates,
etc.) that occurred during the test.
(F) Quality assurance procedures.
(G) Records of calibrations.
(H) Raw data sheets for field sampling.
(I) Raw data sheets for field and laboratory analyses.
(J) Documentation of calculations.
(iii) The selected flare-specific operating limit values based on
the performance evaluation test results, including the averaging time
for the operating limit(s), and rationale why the selected values and
averaging times are sufficiently stringent to ensure proper flare
performance. If new operating parameters or averaging times are
proposed for use other than those specified in paragraphs (d) through
(f) of this section, an explanation of why the

[[Page 75266]]

alternative operating parameter(s) or averaging time(s) adequately
ensures the flare achieves the required combustion efficiency.
(iv) The means by which the owner or operator will document on-
going, continuous compliance with the selected flare-specific operating
limit(s), including the specific measurement location and frequencies,
calculation procedures, and records to be maintained.
(3) The request shall be submitted as described in paragraphs
(r)(3)(i) through (iv) of this section.
(i) The owner or operator may request approval from the
Administrator at any time upon completion of a performance evaluation
conducted following the methods in an approved site-specific
performance evaluation plan for an operating limit(s) that shall apply
specifically to that flare.
(ii) The request must be submitted to the Administrator for
approval. The owner or operator must continue to comply with the
applicable standards for flares in this subpart until the requirements
in Sec. 63.6(g)(1) are met and a notice is published in the Federal
Register allowing use of such an alternative means of emission
limitation.
(iii) The request shall also be submitted to the following address:
U.S. Environmental Protection Agency, Office of Air Quality Planning
and Standards, Sector Policies and Programs Division, U.S. EPA Mailroom
(E143-01), Attention: Refinery Sector Lead, 109 T.W. Alexander Drive,
Research Triangle Park, NC 27711. Electronic copies in lieu of hard
copies may also be submitted to refineryrtr@epa.gov.
(iv) If the Administrator finds any deficiencies in the request,
the request must be revised to address the deficiencies and be re-
submitted for approval within 45 days of receipt of the notice of
deficiencies. The owner or operator must comply with the revised
request as submitted until it is approved.
(4) The approval process for a request for a flare-specific
operating limit(s) is described in paragraphs (r)(4)(i) through (iii)
of this section.
(i) Approval by the Administrator of a flare-specific operating
limit(s) request will be based on the completeness, accuracy and
reasonableness of the request. Factors that the EPA will consider in
reviewing the request for approval include, but are not limited to,
those described in paragraphs (r)(4)(i)(A) through (C) of this section.
(A) The description of the flare design and operating
characteristics.
(B) If a new operating parameter(s) other than those specified in
paragraphs (d) through (f) of this section is proposed, the explanation
of how the proposed operating parameter(s) serves a good indicator(s)
of flare combustion performance.
(C) The results of the flare performance evaluation test runs and
the establishment of operating limits that ensures that the flare
destruction efficiency is 98 percent or greater or that the flare
combustion efficiency is 96.5 percent or greater at all times.
(D) The completeness of the flare performance evaluation test
report.
(ii) If the request is approved by the Administrator, a flare-
specific operating limit(s) will be established at the level(s)
demonstrated in the approved request.
(iii) If the Administrator finds any deficiencies in the request,
the request must be revised to address the deficiencies and be re-
submitted for approval.

0
33. Section 63.671 is added to read as follows:

Sec. 63.671 Requirements for flare monitoring systems.

(a) Operation of CPMS. For each CPMS installed to comply with
applicable provisions in Sec. 63.670, the owner or operator shall
install, operate, calibrate, and maintain the CPMS as specified in
paragraphs (a)(1) through (8) of this section.
(1) Except for CPMS installed for pilot flame monitoring, all
monitoring equipment must meet the applicable minimum accuracy,
calibration and quality control requirements specified in table 13 of
this subpart.
(2) The owner or operator shall ensure the readout (that portion of
the CPMS that provides a visual display or record) or other indication
of the monitored operating parameter from any CPMS required for
compliance is readily accessible onsite for operational control or
inspection by the operator of the source.
(3) All CPMS must complete a minimum of one cycle of operation
(sampling, analyzing and data recording) for each successive 15-minute
period.
(4) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions and required monitoring
system quality assurance or quality control activities (including, as
applicable, calibration checks and required zero and span adjustments),
the owner or operator shall operate all CPMS and collect data
continuously at all times when regulated emissions are routed to the
flare.
(5) The owner or operator shall operate, maintain, and calibrate
each CPMS according to the CPMS monitoring plan specified in paragraph
(b) of this section.
(6) For each CPMS except for CPMS installed for pilot flame
monitoring, the owner or operator shall comply with the out-of-control
procedures described in paragraph (c) of this section.
(7) The owner or operator shall reduce data from a CPMS as
specified in paragraph (d) of this section.
(8) The CPMS must be capable of measuring the appropriate parameter
over the range of values expected for that measurement location. The
data recording system associated with each CPMS must have a resolution
that is equal to or better than the required system accuracy.
(b) CPMS monitoring plan. The owner or operator shall develop and
implement a CPMS quality control program documented in a CPMS
monitoring plan that covers each flare subject to the provisions in
Sec. 63.670 and each CPMS installed to comply with applicable
provisions in Sec. 63.670. The owner or operator shall have the CPMS
monitoring plan readily available on-site at all times and shall submit
a copy of the CPMS monitoring plan to the Administrator upon request by
the Administrator. The CPMS monitoring plan must contain the
information listed in paragraphs (b)(1) through (5) of this section.
(1) Identification of the specific flare being monitored and the
flare type (air-assisted only, steam-assisted only, air- and steam-
assisted, pressure-assisted, or non-assisted).
(2) Identification of the parameter to be monitored by the CPMS and
the expected parameter range, including worst case and normal
operation.
(3) Description of the monitoring equipment, including the
information specified in paragraphs (b)(3)(i) through (vii) of this
section.
(i) Manufacturer and model number for all monitoring equipment
components installed to comply with applicable provisions in Sec.
63.670.
(ii) Performance specifications, as provided by the manufacturer,
and any differences expected for this installation and operation.
(iii) The location of the CPMS sampling probe or other interface
and a justification of how the location meets the requirements of
paragraph (a)(1) of this section.
(iv) Placement of the CPMS readout, or other indication of
parameter values, indicating how the location meets the requirements of
paragraph (a)(2) of this section.

[[Page 75267]]

(v) Span of the CPMS. The span of the CPMS sensor and analyzer must
encompass the full range of all expected values.
(vi) How data outside of the span of the CPMS will be handled and
the corrective action that will be taken to reduce and eliminate such
occurrences in the future.
(vii) Identification of the parameter detected by the parametric
signal analyzer and the algorithm used to convert these values into the
operating parameter monitored to demonstrate compliance, if the
parameter detected is different from the operating parameter monitored.
(4) Description of the data collection and reduction systems,
including the information specified in paragraphs (b)(4)(i) through
(iii) of this section.
(i) A copy of the data acquisition system algorithm used to reduce
the measured data into the reportable form of the standard and to
calculate the applicable averages.
(ii) Identification of whether the algorithm excludes data
collected during CPMS breakdowns, out-of-control periods, repairs,
maintenance periods, instrument adjustments or checks to maintain
precision and accuracy, calibration checks, and zero (low-level), mid-
level (if applicable) and high-level adjustments.
(iii) If the data acquisition algorithm does not exclude data
collected during CPMS breakdowns, out-of-control periods, repairs,
maintenance periods, instrument adjustments or checks to maintain
precision and accuracy, calibration checks, and zero (low-level), mid-
level (if applicable) and high-level adjustments, a description of the
procedure for excluding this data when the averages calculated as
specified in paragraph (e) of this section are determined.
(5) Routine quality control and assurance procedures, including
descriptions of the procedures listed in paragraphs (b)(5)(i) through
(vi) of this section and a schedule for conducting these procedures.
The routine procedures must provide an assessment of CPMS performance.
(i) Initial and subsequent calibration of the CPMS and acceptance
criteria.
(ii) Determination and adjustment of the calibration drift of the
CPMS.
(iii) Daily checks for indications that the system is responding.
If the CPMS system includes an internal system check, the owner or
operator may use the results to verify the system is responding, as
long as the system provides an alarm to the owner or operator or the
owner or operator checks the internal system results daily for proper
operation and the results are recorded.
(iv) Preventive maintenance of the CPMS, including spare parts
inventory.
(v) Data recording, calculations and reporting.
(vi) Program of corrective action for a CPMS that is not operating
properly.
(c) Out-of-control periods. For each CPMS installed to comply with
applicable provisions in Sec. 63.670 except for CPMS installed for
pilot flame monitoring, the owner or operator shall comply with the
out-of-control procedures described in paragraphs (c)(1) and (2) of
this section.
(1) A CPMS is out-of-control if the zero (low-level), mid-level (if
applicable) or high-level calibration drift exceeds two times the
accuracy requirement of table 13 of this subpart.
(2) When the CPMS is out of control, the owner or operator shall
take the necessary corrective action and repeat all necessary tests
that indicate the system is out of control. The owner or operator shall
take corrective action and conduct retesting until the performance
requirements are below the applicable limits. The beginning of the out-
of-control period is the hour a performance check (e.g., calibration
drift) that indicates an exceedance of the performance requirements
established in this section is conducted. The end of the out-of-control
period is the hour following the completion of corrective action and
successful demonstration that the system is within the allowable
limits. The owner or operator shall not use data recorded during
periods the CPMS is out of control in data averages and calculations,
used to report emissions or operating levels, as specified in paragraph
(d)(3) of this section.
(d) CPMS data reduction. The owner or operator shall reduce data
from a CPMS installed to comply with applicable provisions in Sec.
63.670 as specified in paragraphs (d)(1) through (3) of this section.
(1) The owner or operator may round the data to the same number of
significant digits used in that operating limit.
(2) Periods of non-operation of the process unit (or portion
thereof) resulting in cessation of the emissions to which the
monitoring applies must not be included in the 15-minute block
averages.
(3) Periods when the CPMS is out of control must not be included in
the 15-minute block averages.
(e) Additional requirements for gas chromatographs. For monitors
used to determine compositional analysis for net heating value per
Sec. 63.670(j)(1), the gas chromatograph must also meet the
requirements of paragraphs (e)(1) through (3) of this section.
(1) The quality assurance requirements are in table 13 of this
subpart.
(2) The calibration gases must meet one of the following options:
(i) The owner or operator must use a calibration gas or multiple
gases that include all of compounds listed in paragraphs (e)(2)(i)(A)
through (K) of this section that may be reasonably expected to exist in
the flare gas stream and optionally include any of the compounds listed
in paragraphs (e)(2)(i)(L) through (O) of this section. All of the
calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, the owner or
operator must calibrate the instrument on all of the gases.
(A) Hydrogen.
(B) Methane.
(C) Ethane.
(D) Ethylene.
(E) Propane.
(F) Propylene.
(G) n-Butane.
(H) iso-Butane.
(I) Butene (general). It is not necessary to separately speciate
butene isomers, but the net heating value of trans-butene must be used
for co-eluting butene isomers.
(J) 1,3-Butadiene. It is not necessary to separately speciate
butadiene isomers, but you must use the response factor and net heating
value of 1,3-butadiene for co-eluting butadiene isomers.
(K) n-Pentane. Use the response factor for n-pentane to quantify
all C5+ hydrocarbons.
(L) Acetylene (optional).
(M) Carbon monoxide (optional).
(N) Propadiene (optional).
(O) Hydrogen sulfide (optional).
(ii) The owner or operator must use a surrogate calibration gas
consisting of hydrogen and C1 through C5 normal hydrocarbons. All of
the calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, the owner or
operator must calibrate the instrument on all of the gases.
(3) If the owner or operator chooses to use a surrogate calibration
gas under paragraph (e)(2)(ii) of this section, the owner or operator
must comply with paragraphs (e)(3)(i) and (ii) of this section.
(i) Use the response factor for the nearest normal hydrocarbon
(i.e., n-alkane) in the calibration mixture to quantify unknown
components detected in the analysis.
(ii) Use the response factor for n-pentane to quantify unknown

[[Page 75268]]

components detected in the analysis that elute after n-pentane.

0
34. The appendix to subpart CC is amended in table 6 by:
0
a. Revising the entries ``63.5(d)(1)(ii)'' and ``63.5(f)'';
0
b. Removing the entry ``63.6(e)(1)'';
0
c. Adding, in numerical order, the entries ``63.6(e)(1)(i) and (ii)''
and ``63.6(e)(1)(iii)'';
0
d. Revising the entries ``63.6(e)(3)(i),'' ``63.6(e)(3)(iii)-
63.6(e)(3)(ix),'' and ``63.6(f)(1)'';
0
e. Removing the entry ``63.6(f)(2) and (3)'';
0
f. Adding, in numerical order, the entries ``63.6(f)(2)'' and
``63.6(f)(3)'';
0
g. Removing the entry ``63.6(h)(1) and 63.6(h)(2)'';
0
h. Adding, in numerical order, the entries ``63.6(h)(1)'' and
``63.6(h)(2)'';
0
i. Revising the entries ``63.7(b)'' and ``63.7(e)(1)'';
0
j. Removing the entry ``63.8(a)'';
0
k. Adding, in numerical order, the entries ``63.8(a)(1) and (2),''
``63.8(a)(3),'' and ``63.8(a)(4)'';
0
l. Revising the entry ``63.8(c)(1)'';
0
m. Adding, in numerical order, the entries ``63.8(c)(1)(i)'' and
``63.8(c)(1)(iii)'';
0
n. Revising the entries ``63.8(c)(4),'' ``63.8(c)(5)-63.8(c)(8),''
``63.8(d),'' ``63.8(e),'' ``63.8(g),'' ``63.10(b)(2)(i),''
``63.10(b)(2)(ii),'' ``63.10(b)(2)(iv),'' ``63.10(b)(2)(v),'' and
``63.10(b)(2)(vii)'';
0
o. Removing the entry ``63.10(c)(9)-63.10(c)(15)'';
0
p. Adding, in numerical order, the entries ``63.10(c)(9),''
``63.10(c)(10)-63.10(c)(11),'' and ``63.10(c)(12)-63.10(c)(15)'';
0
q. Revising the entry ``63.10(d)(2)'';
0
r. Removing the entries ``63.10(d)(5)(i)'' and ``63.10(d)(5)(ii)'';
0
s. Adding, in numerical order, the entry ``63.10(d)(5)'';
0
t. Removing the entry ``63.11-63.16'';
0
u. Adding, in numerical order, the entries ``63.11'' and ``63.12-
63.16'';
0
v. Revising footnote a.
0
w. Removing footnote b.
The revisions and additions read as follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

Table 6--General Provisions Applicability to Subpart CC \a\
------------------------------------------------------------------------
Applies to subpart
Reference CC Comment
------------------------------------------------------------------------

* * * * * * *
63.5(d)(1)(ii).............. Yes................. Except that for
affected sources
subject to this
subpart, emission
estimates specified
in Sec.
63.5(d)(1)(ii)(H)
are not required,
and Sec.
63.5(d)(1)(ii)(G)
and (I) are
Reserved and do not
apply.

* * * * * * *
63.5(f)..................... Yes................. Except that the
cross-reference in
Sec. 63.5(f)(2)
to Sec.
63.9(b)(2) does not
apply.

* * * * * * *
63.6(e)(1)(i) and (ii)...... No.................. See Sec. 63.642(n)
for general duty
requirement.
63.6(e)(1)(iii)............. Yes. ....................

* * * * * * *
63.6(e)(3)(i)............... No. ....................

* * * * * * *
63.6(e)(3)(iii)-63.6(e)(3)(i No. ....................
x).
63.6(f)(1).................. No. ....................
63.6(f)(2).................. Yes................. Except the phrase
``as specified in
Sec. 63.7(c)'' in
Sec.
63.6(f)(2)(iii)(D)
does not apply
because this
subpart does not
require a site-
specific test plan.
63.6(f)(3).................. Yes................. Except the cross-
references to Sec.
63.6(f)(1) and
(e)(1)(i) are
changed to Sec.
63.642(n).

* * * * * * *
63.6(h)(1).................. No. ....................
63.6(h)(2).................. Yes................. Except Sec.
63.6(h)(2)(ii),
which is reserved.

* * * * * * *
63.7(b)..................... Yes................. Except this subpart
requires
notification of
performance test at
least 30 days
(rather than 60
days) prior to the
performance test.

* * * * * * *
63.7(e)(1).................. No.................. See Sec.
63.642(d)(3).

* * * * * * *
63.8(a)(1) and (2).......... Yes. ....................
63.8(a)(3).................. No.................. Reserved.
63.8(a)(4).................. Yes................. Except that for a
flare complying
with Sec. 63.670,
the cross-reference
to Sec. 63.11 in
this paragraph does
not include Sec.
63.11(b).

* * * * * * *
63.8(c)(1).................. Yes................. Except Sec.
63.8(c)(1)(i) and
(iii).
63.8(c)(1)(i)............... No.................. See Sec.
63.642(n).
63.8(c)(1)(iii)............. No. ....................

[[Page 75269]]

* * * * * * *
63.8(c)(4).................. Yes................. Except that for
sources other than
flares, this
subpart specifies
the monitoring
cycle frequency
specified in Sec.
63.8(c)(4)(ii) is
``once every hour''
rather than ``for
each successive 15-
minute period.''
63.8(c)(5)-63.8(c)(8)....... No.................. This subpart
specifies
continuous
monitoring system
requirements.
63.8(d)..................... No.................. This subpart
specifies quality
control procedures
for continuous
monitoring systems.
63.8(e)..................... Yes. ....................

* * * * * * *
63.8(g)..................... No.................. This subpart
specifies data
reduction
procedures in Sec.
Sec. 63.655(i)(3)
and 63.671(d).

* * * * * * *
63.10(b)(2)(i).............. No. ....................
63.10(b)(2)(ii)............. No.................. Sec. 63.655(i)
specifies the
records that must
be kept.

* * * * * * *
63.10(b)(2)(iv)............. No. ....................
63.10(b)(2)(v).............. No. ....................

* * * * * * *
63.10(b)(2)(vii)............ No.................. Sec. 63.655(i)
specifies records
to be kept for
parameters measured
with continuous
monitors.

* * * * * * *
63.10(c)(9)................. No.................. Reserved.
63.10(c)(10)-63.10(c)(11)... No.................. Sec. 63.655(i)
specifies the
records that must
be kept.
63.10(c)(12)-63.10(c)(15)... No. ....................

* * * * * * *
63.10(d)(2)................. No.................. Although Sec.
63.655(f) specifies
performance test
reporting, EPA may
approve other
timeframes for
submittal of
performance test
data.

* * * * * * *
63.10(d)(5)................. No.................. Sec. 63.655(g)
specifies the
reporting
requirements.

* * * * * * *
63.11....................... Yes................. Except that flares
complying with Sec.
63.670 are not
subject to the
requirements of
Sec. 63.11(b).
63.12-63.16................. Yes.
------------------------------------------------------------------------
\a\ Wherever subpart A of this part specifies ``postmark'' dates,
submittals may be sent by methods other than the U.S. Mail (e.g., by
fax or courier). Submittals shall be sent by the specified dates, but
a postmark is not required.

0
35. The appendix to subpart CC is amended in table 10 by:
0
a. Redesignating the entry ``Flare'' as ``Flare (if meeting the
requirements of Sec. Sec. 63.643 and 63.644)'';
0
b. Adding the entry ``Flare (if meeting the requirements of Sec. Sec.
63.670 and 63.671)'' after newly redesignated entry ``Flare (if meeting
the requirements of Sec. Sec. 63.643 and 63.644)'';
0
c. Revising the entry ``All control devices''; and
0
d. Revising footnote i.
The revisions and additions read as follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

Table 10--Miscellaneous Process Vents--Monitoring, Recordkeeping and
Reporting Requirements for Complying With 98 Weight-Percent Reduction of
Total Organic HAP Emissions or a Limit of 20 Parts per Million by Volume
------------------------------------------------------------------------
Recordkeeping and
Parameters to be reporting
Control device monitored \a\ requirements for
monitored parameters
------------------------------------------------------------------------

* * * * * * *
Flare (if meeting the The parameters 1. Records as
requirements of Sec. Sec. specified in specified in Sec.
63.670 and 63.671). Sec. 63.670. 63.655(i)(9).
2. Report information
as specified in Sec.
63.655(g)(11)--
PR.\g\
All control devices........... Presence of flow 1. Hourly records of
diverted to the whether the flow
atmosphere from indicator was
the control operating and
device (Sec. whether flow was
63.644(c)(1)) or detected at any time
during each hour.
Record and report
the times and
durations of all
periods when the
vent stream is
diverted through a
bypass line or the
monitor is not
operating--PR.\g\

[[Page 75270]]

Monthly 1. Records that
inspections of monthly inspections
sealed valves were performed.
(Sec. 2. Record and report
63.644(c)(2)). all monthly
inspections that
show the valves are
not closed or the
seal has been
changed--PR.\g\
------------------------------------------------------------------------
\a\ Regulatory citations are listed in parentheses.
* * * * * * *
\g\ PR = Periodic Reports described in Sec. 63.655(g).
* * * * * * *
\i\ Process vents that are routed to refinery fuel gas systems are not
regulated under this subpart provided that on and after January 30,
2019, any flares receiving gas from that fuel gas system are in
compliance with Sec. 63.670. No monitoring, recordkeeping, or
reporting is required for boilers and process heaters that combust
refinery fuel gas.

0
36. The appendix to subpart CC is amended by adding table 11 to read as
follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

Table 11--Compliance Dates and Requirements
----------------------------------------------------------------------------------------------------------------
Then the owner or And the owner or
If the construction/reconstruction operator must comply operator must achieve Except as provided in .
date \a\ is . . . with . . . compliance . . . . .
----------------------------------------------------------------------------------------------------------------
(1) After June 30, 2014.............. (i) Requirements for Upon initial startup or Sec. 63.640(k), (l)
new sources in Sec. February 1, 2016, and (m).
Sec. 63.640 through whichever is later.
63.642, 63.647, 63.650
through 63.653, and
63.656 through 63.660.
(ii) The new source Upon initial startup or Sec. 63.640(k), (l)
requirements in Sec. October 28, 2009, and (m).
63.654 for heat whichever is later.
exchange systems.
(2) After September 4, 2007 but on or (i) Requirements for Upon initial startup... Sec. 63.640(k), (l)
before June 30, 2014. new sources in Sec. and (m).
Sec. 63.640 through
63.653 and 63.656 \b\
\c\.
(ii) Requirements for On or before January Sec. 63.640(k), (l)
new sources in Sec. 30, 2019. and (m).
Sec. 63.640 through
63.645, Sec. Sec.
63.647 through 63.653,
and Sec. Sec.
63.656 and 63.657 \b\.
(iii) Requirements for On or before January Sec. 63.640(k), (l)
existing sources in 30, 2018. and (m).
Sec. 63.658.
(iv) Requirements for On or before April 29, Sec. 63.640(k), (l)
new sources in Sec. 2016. and (m).
63.660 \c\.
(v) The new source Upon initial startup or Sec. 63.640(k), (l)
requirements in Sec. October 28, 2009, and (m).
63.654 for heat whichever is later.
exchange systems.
(3) After July 14, 1994 but on or (i) Requirements for Upon initial startup or Sec. 63.640(k), (l)
before September 4, 2007. new sources in Sec. August 18, 1995, and (m).
Sec. 63.640 through whichever is later.
63.653 and 63.656 \d\
\e\.
(ii) Requirements for On or before January Sec. 63.640(k), (l)
new sources in Sec. 30, 2019. and (m).
Sec. 63.640 through
63.645, 63.647 through
63.653, and 63.656 and
63.657 \d\.
(iii) Requirements for On or before January Sec. 63.640(k), (l)
existing sources in 30, 2018. and (m).
Sec. 63.658.
(iv) Requirements for On or before April 29, Sec. 63.640(k), (l)
new sources in Sec. 2016. and (m).
63.660 \e\.
(v) The existing source On or before October Sec. 63.640(k), (l)
requirements in Sec. 29, 2012. and (m).
63.654 for heat
exchange systems.
(4) On or before July 14, 1994....... (i) Requirements for (a) On or before August (1) Sec. 63.640(k),
existing sources in 18, 1998. (l) and (m).
Sec. Sec. 63.640 (2) Sec. 63.6(c)(5)
through 63.653 and of subpart A of this
63.656 \f\ \g\. part or unless an
extension has been
granted by the
Administrator as
provided in Sec.
63.6(i) of subpart A
of this part.
(ii) Requirements for On or before January Sec. 63.640(k), (l)
existing sources in 30, 2019. and (m).
Sec. Sec. 63.640
through 63.645, 63.647
through 63.653, and
63.656 and 63.657 \f\.

[[Page 75271]]

(iii) Requirements for On or before January Sec. 63.640(k), (l)
existing sources in 30, 2018. and (m).
Sec. 63.658.
(iv) Requirements for On or before April 29, Sec. 63.640(k), (l)
existing sources in 2016. and (m).
Sec. 63.660 \g\.
(v) The existing source requirements On or before October Sec. 63.640(k), (l)
in Sec. 63.654 for heat exchange 29, 2012. and (m).
systems
----------------------------------------------------------------------------------------------------------------
\a\ For purposes of this table, the construction/reconstruction date means the date of construction or
reconstruction of an entire affected source or the date of a process unit addition or change meeting the
criteria in Sec. 63.640(i) or (j). If a process unit addition or change does not meet the criteria in Sec.
63.640(i) or (j), the process unit shall comply with the applicable requirements for existing sources.
\b\ Between the compliance dates in items (2)(i) and (2)(ii) of this table, the owner or operator may elect to
comply with either the requirements in item (2)(i) or item (2)(ii) of this table. The requirements in item
(2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(ii) of
this table.
\c\ Between the compliance dates in items (2)(i) and (2)(iv) of this table, the owner or operator may elect to
comply with either the requirements in item (2)(i) or item (2)(iv) of this table. The requirements in item
(2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(iv) of
this table.
\d\ Between the compliance dates in items (3)(i) and (3)(ii) of this table, the owner or operator may elect to
comply with either the requirements in item (3)(i) or item (3)(ii) of this table. The requirements in item
(3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(ii) of
this table.
\e\ Between the compliance dates in items (3)(i) and (3)(iv) of this table, the owner or operator may elect to
comply with either the requirements in item (3)(i) or item (3)(iv) of this table. The requirements in item
(3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(iv) of
this table.
\f\ Between the compliance dates in items (4)(i) and (4)(ii) of this table, the owner or operator may elect to
comply with either the requirements in item (4)(i) or item (4)(ii) of this table. The requirements in item
(4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(ii) of
this table.
\g\ Between the compliance dates in items (4)(i) and (4)(iv) of this table, the owner or operator may elect to
comply with either the requirements in item (4)(i) or item (4)(iv) of this table. The requirements in item
(4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(iv) of
this table.

0
37. The appendix to subpart CC is amended by adding table 12 to read as
follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

Table 12--Individual Component Properties
----------------------------------------------------------------------------------------------------------------
NHVi (British
MWi (pounds CMNi (mole thermal units LFLi (volume
Component Molecular formula per pound- per mole) per standard %)
mole) cubic foot)
----------------------------------------------------------------------------------------------------------------
Acetylene................... C2H2.............. 26.04 2 1,404 2.5
Benzene..................... C6H6.............. 78.11 6 3,591 1.3
1,2-Butadiene............... C4H6.............. 54.09 4 2,794 2.0
1,3-Butadiene............... C4H6.............. 54.09 4 2,690 2.0
iso-Butane.................. C4H10............. 58.12 4 2,957 1.8
n-Butane.................... C4H10............. 58.12 4 2,968 1.8
cis-Butene.................. C4H8.............. 56.11 4 2,830 1.6
iso-Butene.................. C4H8.............. 56.11 4 2,928 1.8
trans-Butene................ C4H8.............. 56.11 4 2,826 1.7
Carbon Dioxide.............. CO2............... 44.01 1 0 [infin]
Carbon Monoxide............. CO................ 28.01 1 316 12.5
Cyclopropane................ C3H6.............. 42.08 3 2,185 2.4
Ethane...................... C2H6.............. 30.07 2 1,595 3.0
Ethylene.................... C2H4.............. 28.05 2 1,477 2.7
Hydrogen.................... H2................ 2.02 0 1,212\a\ 4.0
Hydrogen Sulfide............ H2S............... 34.08 0 587 4.0
Methane..................... CH4............... 16.04 1 896 5.0
Methyl-Acetylene............ C3H4.............. 40.06 3 2,088 1.7
Nitrogen.................... N2................ 28.01 0 0 [infin]
Oxygen...................... O2................ 32.00 0 0 [infin]
Pentane+ (C5+).............. C5H12............. 72.15 5 3,655 1.4
Propadiene.................. C3H4.............. 40.06 3 2,066 2.16
Propane..................... C3H8.............. 44.10 3 2,281 2.1
Propylene................... C3H6.............. 42.08 3 2,150 2.4
Water....................... H2O............... 18.02 0 0 [infin]
----------------------------------------------------------------------------------------------------------------
\a\ The theoretical net heating value for hydrogen is 274 Btu/scf, but for the purposes of the flare requirement
in this subpart, a net heating value of 1,212 Btu/scf shall be used.

[[Page 75272]]

0
38. The appendix to subpart CC is amended by adding table 13 to read as
follows:

Appendix to Subpart CC of Part 63--Tables

* * * * *

Table 13--Calibration and Quality Control Requirements for CPMS
------------------------------------------------------------------------
Minimum accuracy Calibration
Parameter requirements requirements
------------------------------------------------------------------------
Temperature................... 1 Conduct calibration
percent over the checks at least
normal range of annually; conduct
temperature calibration checks
measured, following any period
expressed in of more than 24
degrees Celsius hours throughout
(C), or 2.8 which the
degrees C, temperature exceeded
whichever is the manufacturer's
greater. specified maximum
rated temperature or
install a new
temperature sensor.
At least quarterly,
inspect all
components for
integrity and all
electrical
connections for
continuity,
oxidation, and
galvanic corrosion,
unless the CPMS has
a redundant
temperature sensor.
Record the results of
each calibration
check and
inspection.
Locate the
temperature sensor
in a position that
provides a
representative
temperature; shield
the temperature
sensor system from
electromagnetic
interference and
chemical
contaminants.
Flow Rate for All Flows Other 5 Conduct a flow sensor
Than Flare Vent Gas. percent over the calibration check at
normal range of least biennially
flow measured or (every two years);
1.9 liters per conduct a
minute (0.5 calibration check
gallons per following any period
minute), of more than 24
whichever is hours throughout
greater, for which the flow rate
liquid flow. exceeded the
manufacturer's
specified maximum
rated flow rate or
install a new flow
sensor.
5 At least quarterly,
percent over the inspect all
normal range of components for
flow measured or leakage, unless the
280 liters per CPMS has a redundant
minute (10 cubic flow sensor.
feet per
minute),
whichever is
greater, for gas
flow.
5 Record the results of
percent over the each calibration
normal range check and
measured for inspection.
mass flow. Locate the flow
sensor(s) and other
necessary equipment
(such as
straightening vanes)
in a position that
provides
representative flow;
reduce swirling flow
or abnormal velocity
distributions due to
upstream and
downstream
disturbances.
Flare Vent Gas Flow Rate...... 20 Conduct a flow sensor
percent of flow calibration check at
rate at least biennially
velocities (every two years);
ranging from conduct a
0.03 to 0.3 calibration check
meters per following any period
second (0.1 to 1 of more than 24
feet per second). hours throughout
5 which the flow rate
percent of flow exceeded the
rate at manufacturer's
velocities specified maximum
greater than 0.3 rated flow rate or
meters per install a new flow
second (1 feet sensor.
per second). At least quarterly,
inspect all
components for
leakage, unless the
CPMS has a redundant
flow sensor.
Record the results of
each calibration
check and
inspection.
Locate the flow
sensor(s) and other
necessary equipment
(such as
straightening vanes)
in a position that
provides
representative flow;
reduce swirling flow
or abnormal velocity
distributions due to
upstream and
downstream
disturbances.
Pressure...................... 5 Review pressure
percent over the sensor readings at
normal operating least once a week
range or 0.12 for straightline
kilopascals (0.5 (unchanging)
inches of water pressure and perform
column), corrective action to
whichever is ensure proper
greater. pressure sensor
operation if
blockage is
indicated.
Using an instrument
recommended by the
sensor's
manufacturer, check
gauge calibration
and transducer
calibration
annually; conduct
calibration checks
following any period
of more than 24
hours throughout
which the pressure
exceeded the
manufacturer's
specified maximum
rated pressure or
install a new
pressure sensor.
At least quarterly,
inspect all
components for
integrity, all
electrical
connections for
continuity, and all
mechanical
connections for
leakage, unless the
CPMS has a redundant
pressure sensor.
Record the results of
each calibration
check and
inspection.
Locate the pressure
sensor(s) in a
position that
provides a
representative
measurement of the
pressure and
minimizes or
eliminates pulsating
pressure, vibration,
and internal and
external corrosion.
Net Heating Value by 2 Specify calibration
Calorimeter. percent of span. requirements in your
site specific CPMS
monitoring plan.
Calibration
requirements should
follow
manufacturer's
recommendations at a
minimum.
Temperature control
(heated and/or
cooled as necessary)
the sampling system
to ensure proper
year-round
operation.
Where feasible,
select a sampling
location at least
two equivalent
diameters downstream
from and 0.5
equivalent diameters
upstream from the
nearest disturbance.
Select the sampling
location at least
two equivalent duct
diameters from the
nearest control
device, point of
pollutant
generation, air in-
leakages, or other
point at which a
change in the
pollutant
concentration or
emission rate
occurs.

[[Page 75273]]

Net Heating Value by Gas As specified in Follow the procedure
Chromatograph. Performance in Performance
Specification 9 Specification 9 of
of 40 CFR part 40 CFR part 60,
60, appendix B appendix B, except
that a single daily
mid-level
calibration check
can be used (rather
than triplicate
analysis), the multi-
point calibration
can be conducted
quarterly (rather
than monthly), and
the sampling line
temperature must be
maintained at a
minimum temperature
of 60 [deg]C (rather
than 120 [deg]C).
Hydrogen analyzer............. 2 Specify calibration
percent over the requirements in your
concentration site specific CPMS
measured or 0.1 monitoring plan.
volume percent, Calibration
whichever is requirements should
greater. follow
manufacturer's
recommendations at a
minimum.
Select the sampling
location at least
two equivalent duct
diameters from the
nearest control
device, point of
pollutant
generation, air in-
leakages, or other
point at which a
change in the
pollutant
concentration
occurs.
------------------------------------------------------------------------

Subpart UUU---National Emission Standards for Hazardous Air
Pollutants for Petroleum Refineries: Catalytic Cracking Units,
Catalytic Reforming Units, and Sulfur Recovery Units

0
39. Section 63.1562 is amended by revising paragraphs (b)(3) and (f)(5)
to read as follows:

Sec. 63.1562 What parts of my plant are covered by this subpart?

* * * * *
(b) * * *
(3) The process vent or group of process vents on Claus or other
types of sulfur recovery plant units or the tail gas treatment units
serving sulfur recovery plants that are associated with sulfur
recovery.
* * * * *
(f) * * *
(5) Gaseous streams routed to a fuel gas system, provided that on
and after January 30, 2019, any flares receiving gas from the fuel gas
system are subject to Sec. 63.670.

0
40. Section 63.1564 is amended by:
0
a. Revising paragraphs (a)(1) and (2);
0
b. Adding paragraph (a)(5);
0
c. Removing the equation following paragraph (b)(4)(ii) and adding it
after paragraph (b)(4)(iii) introductory text;
0
d. Revising paragraphs (b)(2), (b)(4)(i) and (ii), and (b)(4)(iv); and
0
e. Adding paragraph (c)(5).
The revisions and additions read as follows:

Sec. 63.1564 What are my requirements for metal HAP emissions from
catalytic cracking units?

(a) * * *
(1) Except as provided in paragraph (a)(5) of this section, meet
each emission limitation in Table 1 of this subpart that applies to
you. If your catalytic cracking unit is subject to the NSPS for PM in
Sec. 60.102 of this chapter or is subject to Sec. 60.102a(b)(1) of
this chapter, you must meet the emission limitations for NSPS units. If
your catalytic cracking unit is not subject to the NSPS for PM, you can
choose from the four options in paragraphs (a)(1)(i) through (vi) of
this section:
(i) You can elect to comply with the NSPS for PM in Sec. 60.102 of
this chapter (Option 1a);
(ii) You can elect to comply with the NSPS for PM coke burn-off
emission limit in Sec. 60.102a(b)(1) of this chapter (Option 1b);
(iii) You can elect to comply with the NSPS for PM concentration
limit in Sec. 60.102a(b)(1) of this chapter (Option 1c);
(iv) You can elect to comply with the PM per coke burn-off emission
limit in Sec. 60.102a(b)(1) of this chapter (Option 2);
(v) You can elect to comply with the Nickel (Ni) lb/hr emission
limit (Option 3); or
(vi) You can elect to comply with the Ni per coke burn-off emission
limit (Option 4).
(2) Comply with each operating limit in Table 2 of this subpart
that applies to you. When a specific control device may be monitored
using more than one continuous parameter monitoring system, you may
select the parameter with which you will comply. You must provide
notice to the Administrator (or other designated authority) if you
elect to change the monitoring option.
* * * * *
(5) During periods of startup, shutdown and hot standby, you can
choose from the two options in paragraphs (a)(5)(i) and (ii) of this
section:
(i) You can elect to comply with the requirements in paragraphs
(a)(1) and (2) of this section, except catalytic cracking units
controlled using a wet scrubber must maintain only the liquid to gas
ratio operating limit (the pressure drop operating limit does not
apply); or
(ii) You can elect to maintain the inlet velocity to the primary
internal cyclones of the catalytic cracking unit catalyst regenerator
at or above 20 feet per second.
(b) * * *
(2) Conduct a performance test for each catalytic cracking unit
according to the requirements in Sec. 63.1571 and under the conditions
specified in Table 4 of this subpart.
* * * * *
(4) * * *
(i) If you elect Option 1b or Option 2 in paragraph (a)(1)(ii) or
(iv) of this section, compute the PM emission rate (lb/1,000 lb of coke
burn-off) for each run using Equations 1, 2, and 3 (if applicable) of
this section and the site-specific opacity limit, if applicable, using
Equation 4 of this section as follows:
[GRAPHIC] [TIFF OMITTED] TR01DE15.018

Where:

Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from catalyst
regenerator before adding air or gas streams. Example: You may
measure upstream or downstream of an

[[Page 75274]]

electrostatic precipitator, but you must measure upstream of a
carbon monoxide boiler, dscm/min (dscf/min). You may use the
alternative in either Sec. 63.1573(a)(1) or (2), as applicable, to
calculate Qr;
Qa = Volumetric flow rate of air to catalytic cracking
unit catalyst regenerator, as determined from instruments in the
catalytic cracking unit control room, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in regenerator
exhaust, percent by volume (dry basis);
%CO = Carbon monoxide concentration in regenerator exhaust, percent
by volume (dry basis);
%O2 = Oxygen concentration in regenerator exhaust,
percent by volume (dry basis);
K1 = Material balance and conversion factor, 0.2982 (kg-
min)/(hr-dscm-%) (0.0186 (lb-min)/(hr-dscf-%));
K2 = Material balance and conversion factor, 2.088 (kg-
min)/(hr-dscm) (0.1303 (lb-min)/(hr-dscf));
K3 = Material balance and conversion factor, 0.0994 (kg-
min)/(hr-dscm-%) (0.0062 (lb-min)/(hr-dscf-%));
Qoxy = Volumetric flow rate of oxygen-enriched air stream
to regenerator, as determined from instruments in the catalytic
cracking unit control room, dscm/min (dscf/min); and
%Oxy = Oxygen concentration in oxygen-enriched air
stream, percent by volume (dry basis).
[GRAPHIC] [TIFF OMITTED] TR01DE15.019

Where:

E = Emission rate of PM, kg/1,000 kg (lb/1,000 lb) of coke burn-off;
Cs = Concentration of PM, g/dscm (lb/dscf);
Qsd = Volumetric flow rate of the catalytic cracking unit
catalyst regenerator flue gas as measured by Method 2 in appendix A-
1 to part 60 of this chapter, dscm/hr (dscf/hr);
Rc = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr);
and
K = Conversion factor, 1.0 (kg²/g)/(1,000 kg) (1,000 lb/
(1,000 lb)).

[GRAPHIC] [TIFF OMITTED] TR01DE15.020

Where:

Es = Emission rate of PM allowed, kg/1,000 kg (1b/1,000
lb) of coke burn-off in catalyst regenerator;
1.0 = Emission limitation, kg coke/1,000 kg (lb coke/1,000 lb);
A = Allowable incremental rate of PM emissions. Before August 1,
2017, A = 0.18 g/million cal (0.10 lb/million Btu). On or after
August 1, 2017, A = 0 g/million cal (0 lb/million Btu);
H = Heat input rate from solid or liquid fossil fuel, million cal/hr
(million Btu/hr). Make sure your permitting authority approves
procedures for determining the heat input rate;
Rc = Coke burn-off rate, kg coke/hr (1,000 lb coke/hr)
determined using Equation 1 of this section; and
K' = Conversion factor to units to standard, 1.0 (kg2/g)/
(1,000 kg) (103 lb/(1,000 lb)).

[GRAPHIC] [TIFF OMITTED] TR01DE15.021

Where:

Opacity Limit = Maximum permissible hourly average opacity, percent,
or 10 percent, whichever is greater;
Opacityst = Hourly average opacity measured during the
source test, percent; and
PMEmRst = PM emission rate measured during the source
test, lb/1,000 lb coke burn.

(ii) If you elect Option 1c in paragraph (a)(1)(iii) of this
section, the PM concentration emission limit, determine the average PM
concentration from the initial performance test used to certify your PM
CEMS.
* * * * *
(iv) If you elect Option 4 in paragraph (a)(1)(vi) of this section,
the Ni per coke burn-off emission limit, compute your Ni emission rate
using Equations 1 and 8 of this section and your site-specific Ni
operating limit (if you use a continuous opacity monitoring system)
using Equations 9 and 10 of this section as follows:
[GRAPHIC] [TIFF OMITTED] TR01DE15.022

Where:

ENi2 = Normalized mass emission rate of Ni, mg/kg coke
(lb/1,000 lb coke).
[GRAPHIC] [TIFF OMITTED] TR01DE15.023

[[Page 75275]]

Where:

Opacity2 = Opacity value for use in Equation 10 of this
section, percent, or 10 percent, whichever is greater; and
NiEmR2st = Average Ni emission rate calculated as the
arithmetic average Ni emission rate using Equation 8 of this section
for each of the performance test runs, mg/kg coke.

[GRAPHIC] [TIFF OMITTED] TR01DE15.024

Where:

Ni Operating Limit2 = Maximum permissible hourly average
Ni operating limit, percent-ppmw-acfm-hr/kg coke, i.e., your site-
specific Ni operating limit; and
Rc,st = Coke burn rate from Equation 1 of this section,
as measured during the initial performance test, kg coke/hr.

* * * * *
(c) * * *
(5) If you elect to comply with the alternative limit in paragraph
(a)(5)(ii) of this section during periods of startup, shutdown, and hot
standby, demonstrate continuous compliance by:
(i) Collecting the volumetric flow rate from the catalyst
regenerator (in acfm) and determining the average flow rate for each
hour. For events lasting less than one hour, determine the average flow
rate during the event.
(ii) Determining the cumulative cross-sectional area of the primary
internal cyclone inlets in square feet (ft²) using design
drawings of the primary (first-stage) internal cyclones to determine
the inlet cross-sectional area of each primary internal cyclone and
summing the cross-sectional areas for all primary internal cyclones in
the catalyst regenerator or, if primary cyclones. If all primary
internal cyclones are identical, you may alternatively determine the
inlet cross-sectional area of one primary internal cyclone using design
drawings and multiply that area by the total number of primary internal
cyclones in the catalyst regenerator.
(iii) Calculating the inlet velocity to the primary internal
cyclones in square feet per second (ft²/sec) by dividing the
average volumetric flow rate (acfm) by the cumulative cross-sectional
area of the primary internal cyclone inlets (ft²) and by 60
seconds/minute (for unit conversion).
(iv) Maintaining the inlet velocity to the primary internal
cyclones at or above 20 feet per second for each hour during the
startup, shutdown, or hot standby event or, for events lasting less
than 1 hour, for the duration of the event.
0
41. Section 63.1565 is amended by revising paragraph (a)(1)
introductory text and adding paragraph (a)(5) to read as follows:

Sec. 63.1565 What are my requirements for organic HAP emissions from
catalytic cracking units?

(a) * * *
(1) Except as provided in paragraph (a)(5) of this section, meet
each emission limitation in Table 8 of this subpart that applies to
you. If your catalytic cracking unit is subject to the NSPS for carbon
monoxide (CO) in Sec. 60.103 of this chapter or is subject to Sec.
60.102a(b)(4) of this chapter, you must meet the emission limitations
for NSPS units. If your catalytic cracking unit is not subject to the
NSPS for CO, you can choose from the two options in paragraphs
(a)(1)(i) through (ii) of this section:
* * * * *
(5) During periods of startup, shutdown and hot standby, you can
choose from the two options in paragraphs (a)(5)(i) and (ii) of this
section:
(i) You can elect to comply with the requirements in paragraphs
(a)(1) and (2) of this section; or
(ii) You can elect to maintain the oxygen (O2)
concentration in the exhaust gas from your catalyst regenerator at or
above 1 volume percent (dry basis).
* * * * *

0
42. Section 63.1566 is amended by revising paragraphs (a)(1)
introductory text, (a)(1)(i), and (a)(4) to read as follows:

Sec. 63.1566 What are my requirements for organic HAP emissions from
catalytic reforming units?

(a) * * *
(1) Meet each emission limitation in Table 15 of this subpart that
applies to you. You can choose from the two options in paragraphs
(a)(1)(i) and (ii) of this section.
(i) You can elect to vent emissions of total organic compounds
(TOC) to a flare (Option 1). On and after January 30, 2019, the flare
must meet the requirements of Sec. 63.670. Prior to January 30, 2019,
the flare must meet the control device requirements in Sec. 63.11(b)
or the requirements of Sec. 63.670.
* * * * *
(4) The emission limitations in Tables 15 and 16 of this subpart do
not apply to emissions from process vents during passive depressuring
when the reactor vent pressure is 5 pounds per square inch gauge (psig)
or less. The emission limitations in Tables 15 and 16 of this subpart
do apply to emissions from process vents during active purging
operations (when nitrogen or other purge gas is actively introduced to
the reactor vessel) or active depressuring (using a vacuum pump,
ejector system, or similar device) regardless of the reactor vent
pressure.
* * * * *

0
43. Section 63.1568 is amended by revising paragraphs (a)(1)
introductory text and (a)(1)(i) and adding paragraph (a)(4) to read as
follows:

Sec. 63.1568 What are my requirements for HAP emissions from sulfur
recovery units?

(a) * * *
(1) Meet each emission limitation in Table 29 of this subpart that
applies to you. If your sulfur recovery unit is subject to the NSPS for
sulfur oxides in Sec. 60.104 or Sec. 60.102a(f)(1) of this chapter,
you must meet the emission limitations for NSPS units. If your sulfur
recovery unit is not subject to one of these NSPS for sulfur oxides,
you can choose from the options in paragraphs (a)(1)(i) through (ii) of
this section:
(i) You can elect to meet the NSPS requirements in Sec.
60.104(a)(2) or Sec. 60.102a(f)(1) of this chapter (Option 1); or
* * * * *
(4) During periods of startup and shutdown, you can choose from the
three options in paragraphs (a)(4)(i) through (iii) of this section.
(i) You can elect to comply with the requirements in paragraphs
(a)(1) and (2) of this section.
(ii) You can elect to send any startup or shutdown purge gases to a
flare. On and after January 30, 2019, the flare must meet the
requirements of Sec. 63.670. Prior to January 30, 2019, the flare must
meet the design and operating requirements in Sec. 63.11(b) or the
requirements of Sec. 63.670.
(iii) You can elect to send any startup or shutdown purge gases to
a thermal oxidizer or incinerator operated at a

[[Page 75276]]

minimum hourly average temperature of 1,200 degrees Fahrenheit in the
firebox and a minimum hourly average outlet oxygen (O2)
concentration of 2 volume percent (dry basis).
* * * * *

0
44. Section 63.1570 is amended by revising paragraphs (a) through (d)
and removing paragraph (g) to read as follows:

Sec. 63.1570 What are my general requirements for complying with this
subpart?

(a) You must be in compliance with all of the non-opacity standards
in this subpart at all times.
(b) You must be in compliance with the opacity and visible emission
limits in this subpart at all times.
(c) At all times, you must operate and maintain any affected
source, including associated air pollution control equipment and
monitoring equipment, in a manner consistent with safety and good air
pollution control practices for minimizing emissions. The general duty
to minimize emissions does not require you to make any further efforts
to reduce emissions if levels required by the applicable standard have
been achieved. Determination of whether a source is operating in
compliance with operation and maintenance requirements will be based on
information available to the Administrator which may include, but is
not limited to, monitoring results, review of operation and maintenance
procedures, review of operation and maintenance records, and inspection
of the source.
(d) During the period between the compliance date specified for
your affected source and the date upon which continuous monitoring
systems have been installed and validated and any applicable operating
limits have been set, you must maintain a log that documents the
procedures used to minimize emissions from process and emissions
control equipment according to the general duty in paragraph (c) of
this section.
* * * * *

0
45. Section 63.1571 is amended by:
0
a. Adding paragraphs (a)(5) and (6);
0
b. Revising paragraph (b)(1);
0
c. Removing paragraph (b)(4);
0
d. Redesignating paragraph (b)(5) as paragraph (b)(4); and
0
e. Revising the first sentence of paragraph (d)(2) and paragraph
(d)(4).
The revisions and additions read as follows:

Sec. 63.1571 How and when do I conduct a performance test or other
initial compliance demonstration?

(a) * * *
(5) Periodic performance testing for PM or Ni. Except as provided
in paragraphs (a)(5)(i) and (ii) of this section, conduct a periodic
performance test for PM or Ni for each catalytic cracking unit at least
once every 5 years according to the requirements in Table 4 of this
subpart. You must conduct the first periodic performance test no later
than August 1, 2017.
(i) Catalytic cracking units monitoring PM concentration with a PM
CEMS are not required to conduct a periodic PM performance test.
(ii) Conduct a performance test annually if you comply with the
emission limits in Item 1 (NSPS subpart J) or Item 4 (Option 1a) in
Table 1 of this subpart and the PM emissions measured during the most
recent performance source test are greater than 0.80 g/kg coke burn-
off.
(6) One-time performance testing for HCN. Conduct a performance
test for HCN from each catalytic cracking unit no later than August 1,
2017 according to the applicable requirements in paragraphs (a)(6)(i)
and (ii) of this section.
(i) If you conducted a performance test for HCN for a specific
catalytic cracking unit between March 31, 2011 and February 1, 2016,
you may submit a request to the Administrator to use the previously
conducted performance test results to fulfill the one-time performance
test requirement for HCN for each of the catalytic cracking units
tested according to the requirements in paragraphs (a)(6)(i)(A) through
(D) of this section.
(A) The request must include a copy of the complete source test
report, the date(s) of the performance test and the test methods used.
If available, you must also indicate whether the catalytic cracking
unit catalyst regenerator was operated in partial or complete
combustion mode during the test, the control device configuration,
including whether platinum or palladium combustion promoters were used
during the test, and the CO concentration (measured using CO CEMS or
manual test method) for each test run.
(B) You must submit a separate request for each catalytic cracking
unit tested and you must submit each request to the Administrator no
later than March 30, 2016.
(C) The Administrator will evaluate each request with respect to
the completeness of the request, the completeness of the submitted test
report and the appropriateness of the test methods used. The
Administrator will notify the facility within 60 days of receipt of the
request if it is approved or denied. If the Administrator fails to
respond to the facility within 60 days of receipt of the request, the
request will be automatically approved.
(D) If the request is approved, you do not need to conduct an
additional HCN performance test. If the request is denied, you must
conduct an additional HCN performance test following the requirements
in (a)(6)(ii) of this section.
(ii) Unless you receive approval to use a previously conducted
performance test to fulfill the one-time performance test requirement
for HCN for your catalytic cracking unit as provided in paragraph
(a)(6)(i) of this section, conduct a performance test for HCN for each
catalytic cracking unit no later than August 1, 2017 according to
following requirements:
(A) Select sampling port location, determine volumetric flow rate,
conduct gas molecular weight analysis and measure moisture content as
specified in either Item 1 of Table 4 of this subpart or Item 1 of
Table 11 of this subpart.
(B) Measure HCN concentration using Method 320 of appendix A of
this part. The method ASTM D6348-03 (Reapproved 2010) including Annexes
A1 through A8 (incorporated by reference--see Sec. 63.14) is an
acceptable alternative to EPA Method 320 of appendix A of this part.
The method ASTM D6348-12e1 (incorporated by reference--see Sec. 63.14)
is an acceptable alternative to EPA Method 320 of appendix A of this
part with the following two caveats:
(1) The test plan preparation and implementation in the Annexes to
ASTM D6348-03 (Reapproved 2010), Sections A1 through A8 are mandatory;
and
(2) In ASTM D6348-03 (Reapproved 2010) Annex A5 (Analyte Spiking
Technique), the percent (%) R must be determined for each target
analyte (Equation A5.5). In order for the test data to be acceptable
for a compound, %R must be 70% >= R <= 130%. If the %R value does not
meet this criterion for a target compound, the test data is not
acceptable for that compound and the test must be repeated for that
analyte (i.e., the sampling and/or analytical procedure should be
adjusted before a retest). The %R value for each compound must be
reported in the test report, and all field measurements must be
corrected with the calculated %R value for that compound by using the
following equation:

[[Page 75277]]

Reported Result = (Measured Concentration in the Stack x 100//% R.

(C) Measure CO concentration as specified in either Item 2 or 3a of
Table 11 of this subpart.
(D) Record and include in the test report an indication of whether
the catalytic cracking unit catalyst regenerator was operated in
partial or complete combustion mode and the control device
configuration, including whether platinum or palladium combustion
promoters were used during the test.
(b) * * *
(1) Performance tests shall be conducted according to the
provisions of Sec. 63.7(e) except that performance tests shall be
conducted at maximum representative operating capacity for the process.
During the performance test, you must operate the control device at
either maximum or minimum representative operating conditions for
monitored control device parameters, whichever results in lower
emission reduction. You must not conduct a performance test during
startup, shutdown, periods when the control device is bypassed or
periods when the process, monitoring equipment or control device is not
operating properly. You may not conduct performance tests during
periods of malfunction. You must record the process information that is
necessary to document operating conditions during the test and include
in such record an explanation to support that the test was conducted at
maximum representative operating capacity. Upon request, you must make
available to the Administrator such records as may be necessary to
determine the conditions of performance tests.
* * * * *
(d) * * *
(2) If you must meet the HAP metal emission limitations in Sec.
63.1564, you elect the option in paragraph (a)(1)(iv) in Sec. 63.1564
(Ni per coke burn-off), and you use continuous parameter monitoring
systems, you must establish an operating limit for the equilibrium
catalyst Ni concentration based on the laboratory analysis of the
equilibrium catalyst Ni concentration from the initial performance
test. * * *
* * * * *
(4) Except as specified in paragraph (d)(3) of this section, if you
use continuous parameter monitoring systems, you may adjust one of your
monitored operating parameters (flow rate, total power and secondary
current, pressure drop, liquid-to-gas ratio) from the average of
measured values during the performance test to the maximum value (or
minimum value, if applicable) representative of worst-case operating
conditions, if necessary. This adjustment of measured values may be
done using control device design specifications, manufacturer
recommendations, or other applicable information. You must provide
supporting documentation and rationale in your Notification of
Compliance Status, demonstrating to the satisfaction of your permitting
authority, that your affected source complies with the applicable
emission limit at the operating limit based on adjusted values.
* * * * *

0
46. Section 63.1572 is amended by revising paragraphs (c) introductory
text, (c)(1), (3), and (4) and (d)(1) and (2) to read as follows:

Sec. 63.1572 What are my monitoring installation, operation, and
maintenance requirements?

* * * * *
(c) Except for flare monitoring systems, you must install, operate,
and maintain each continuous parameter monitoring system according to
the requirements in paragraphs (c)(1) through (5) of this section. For
flares, on and after January 30, 2019, you must install, operate,
calibrate, and maintain monitoring systems as specified in Sec. Sec.
63.670 and 63.671. Prior to January 30, 2019, you must either meet the
monitoring system requirements in paragraphs (c)(1) through (5) of this
section or meet the requirements in Sec. Sec. 63.670 and 63.671.
(1) You must install, operate, and maintain each continuous
parameter monitoring system according to the requirements in Table 41
of this subpart. You must also meet the equipment specifications in
Table 41 of this subpart if pH strips or colormetric tube sampling
systems are used. You must install, operate, and maintain each
continuous parameter monitoring system according to the requirements in
Table 41 of this subpart. You must meet the requirements in Table 41 of
this subpart for BLD systems. Alternatively, before August 1, 2017, you
may install, operate, and maintain each continuous parameter monitoring
system in a manner consistent with the manufacturer's specifications or
other written procedures that provide adequate assurance that the
equipment will monitor accurately.
* * * * *
(3) Each continuous parameter monitoring system must have valid
hourly average data from at least 75 percent of the hours during which
the process operated, except for BLD systems.
(4) Each continuous parameter monitoring system must determine and
record the hourly average of all recorded readings and if applicable,
the daily average of all recorded readings for each operating day,
except for BLD systems. The daily average must cover a 24-hour period
if operation is continuous or the number of hours of operation per day
if operation is not continuous, except for BLD systems.
* * * * *
(d) * * *
(1) You must conduct all monitoring in continuous operation (or
collect data at all required intervals) at all times the affected
source is operating.
(2) You may not use data recorded during required quality assurance
or control activities (including, as applicable, calibration checks and
required zero and span adjustments) for purposes of this regulation,
including data averages and calculations, for fulfilling a minimum data
availability requirement, if applicable. You must use all the data
collected during all other periods in assessing the operation of the
control device and associated control system.

0
47. Section 63.1573 is amended by:
0
a. Redesignating paragraphs (b), (c), (d), (e), and (f) as paragraphs
(c), (d), (e), (f), and (g);
0
b. Adding paragraph (b); and
0
c. Revising newly redesignated paragraphs (c) introductory text, (d)
introductory text, (f) introductory text, and (g)(1) introductory text.
The revisions and additions read as follows:

Sec. 63.1573 What are my monitoring alternatives?

* * * * *
(b) What is the approved alternative for monitoring pressure drop?
You may use this alternative to a continuous parameter monitoring
system for pressure drop if you operate a jet ejector type wet scrubber
or other type of wet scrubber equipped with atomizing spray nozzles.
You shall:
(1) Conduct a daily check of the air or water pressure to the spray
nozzles;
(2) Maintain records of the results of each daily check; and
(3) Repair or replace faulty (e.g., leaking or plugged) air or
water lines within 12 hours of identification of an abnormal pressure
reading.
(c) What is the approved alternative for monitoring pH or
alkalinity levels? You may use the alternative in

[[Page 75278]]

paragraph (c)(1) or (2) of this section for a catalytic reforming unit.
* * * * *
(d) Can I use another type of monitoring system? You may use an
automated data compression system. An automated data compression system
does not record monitored operating parameter values at a set frequency
(e.g., once every hour) but records all values that meet set criteria
for variation from previously recorded values. You must maintain a
record of the description of the monitoring system and data recording
system, including the criteria used to determine which monitored values
are recorded and retained, the method for calculating daily averages,
and a demonstration that the system meets all of the criteria in
paragraphs (d)(1) through (5) of this section:
* * * * *
(f) How do I request to monitor alternative parameters? You must
submit a request for review and approval or disapproval to the
Administrator. The request must include the information in paragraphs
(f)(1) through (5) of this section.
* * * * *
(g) * * *
(1) You may request alternative monitoring requirements according
to the procedures in this paragraph if you meet each of the conditions
in paragraphs (g)(1)(i) through (iii) of this section:
* * * * *

0
48. Section 63.1574 is amended by revising paragraphs (a)(3)
introductory text and (f)(1) to read as follows:

Sec. 63.1574 What notifications must I submit and when?

(a) * * *
(3) If you are required to conduct an initial performance test,
performance evaluation, design evaluation, opacity observation, visible
emission observation, or other initial compliance demonstration, you
must submit a notification of compliance status according to Sec.
63.9(h)(2)(ii). You can submit this information in an operating permit
application, in an amendment to an operating permit application, in a
separate submission, or in any combination. In a State with an approved
operating permit program where delegation of authority under section
112(l) of the CAA has not been requested or approved, you must provide
a duplicate notification to the applicable Regional Administrator. If
the required information has been submitted previously, you do not have
to provide a separate notification of compliance status. Just refer to
the earlier submissions instead of duplicating and resubmitting the
previously submitted information.
* * * * *
(f) * * *
(1) You must submit the plan to your permitting authority for
review and approval along with your notification of compliance status.
While you do not have to include the entire plan in your permit under
part 70 or 71 of this chapter, you must include the duty to prepare and
implement the plan as an applicable requirement in your part 70 or 71
operating permit. You must submit any changes to your permitting
authority for review and approval and comply with the plan as submitted
until the change is approved.
* * * * *

0
49. Section 63.1575 is amended by:
0
a. Revising paragraphs (d) introductory text and (d)(1) and (2);
0
b. Adding paragraph (d)(4);
0
c. Revising paragraph (e) introductory text;
0
d. Removing and reserving paragraph (e)(1);
0
e. Revising paragraphs (e)(4) and (6) and (f)(1) and (2);
0
f. Removing and reserving paragraph (h); and
0
g. Adding paragraph (k).
The revisions and additions read as follows:

Sec. 63.1575 What reports must I submit and when?

* * * * *
(d) For each deviation from an emission limitation and for each
deviation from the requirements for work practice standards that occurs
at an affected source where you are not using a continuous opacity
monitoring system or a continuous emission monitoring system to comply
with the emission limitation or work practice standard in this subpart,
the semiannual compliance report must contain the information in
paragraphs (c)(1) through (3) of this section and the information in
paragraphs (d)(1) through (4) of this section.
(1) The total operating time of each affected source during the
reporting period and identification of the sources for which there was
a deviation.
(2) Information on the number, date, time, duration, and cause of
deviations (including unknown cause, if applicable).
* * * * *
(4) The applicable operating limit or work practice standard from
which you deviated and either the parameter monitor reading during the
deviation or a description of how you deviated from the work practice
standard.
(e) For each deviation from an emission limitation occurring at an
affected source where you are using a continuous opacity monitoring
system or a continuous emission monitoring system to comply with the
emission limitation, you must include the information in paragraphs
(c)(1) through (3) of this section, in paragraphs (d)(1) through (3) of
this section, and in paragraphs (e)(2) through (13) of this section.
* * * * *
(4) An estimate of the quantity of each regulated pollutant emitted
over the emission limit during the deviation, and a description of the
method used to estimate the emissions.
* * * * *
(6) A breakdown of the total duration of the deviations during the
reporting period and into those that are due to control equipment
problems, process problems, other known causes, and other unknown
causes.
* * * * *
(f) * * *
(1) You must include the information in paragraph (f)(1)(i) or (ii)
of this section, if applicable.
(i) If you are complying with paragraph (k)(1) of this section, a
summary of the results of any performance test done during the
reporting period on any affected unit. Results of the performance test
include the identification of the source tested, the date of the test,
the percentage of emissions reduction or outlet pollutant concentration
reduction (whichever is needed to determine compliance) for each run
and for the average of all runs, and the values of the monitored
operating parameters.
(ii) If you are not complying with paragraph (k)(1) of this
section, a copy of any performance test done during the reporting
period on any affected unit. The report may be included in the next
semiannual compliance report. The copy must include a complete report
for each test method used for a particular kind of emission point
tested. For additional tests performed for a similar emission point
using the same method, you must submit the results and any other
information required, but a complete test report is not required. A
complete test report contains a brief process description; a simplified
flow diagram showing affected processes, control equipment, and
sampling point locations; sampling site data; description of sampling
and analysis procedures and any modifications to standard procedures;
quality assurance procedures; record of operating conditions during the
test; record of

[[Page 75279]]

preparation of standards; record of calibrations; raw data sheets for
field sampling; raw data sheets for field and laboratory analyses;
documentation of calculations; and any other information required by
the test method.
(2) Any requested change in the applicability of an emission
standard (e.g., you want to change from the PM standard to the Ni
standard for catalytic cracking units or from the HCl concentration
standard to percent reduction for catalytic reforming units) in your
compliance report. You must include all information and data necessary
to demonstrate compliance with the new emission standard selected and
any other associated requirements.
* * * * *
(k) Electronic submittal of performance test and CEMS performance
evaluation data. For performance tests or CEMS performance evaluations
conducted on and after February 1, 2016, if required to submit the
results of a performance test or CEMS performance evaluation, you must
submit the results according to the procedures in paragraphs (k)(1) and
(2) of this section.
(1) Within 60 days after the date of completing each performance
test as required by this subpart, you must submit the results of the
performance tests following the procedure specified in either paragraph
(k)(1)(i) or (ii) of this section.
(i) For data collected using test methods supported by the EPA's
Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site
(https://www.epa.gov/ttn/chief/ert/) at the time of the test,
you must submit the results of the performance test to the EPA via the
Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can
be accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).) Performance test data must be submitted in a file
format generated through use of the EPA's ERT or an alternate
electronic file format consistent with the extensible markup language
(XML) schema listed on the EPA's ERT Web site. If you claim that some
of the performance test information being submitted is confidential
business information (CBI), you must submit a complete file generated
through the use of the EPA's ERT or an alternate electronic file
consistent with the XML schema listed on the EPA's ERT Web site,
including information claimed to be CBI, on a compact disc, flash drive
or other commonly used electronic storage media to the EPA. The
electronic storage media must be clearly marked as CBI and mailed to
U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement
Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same
ERT or alternate file with the CBI omitted must be submitted to the EPA
via the EPA's CDX as described earlier in this paragraph (k)(1)(i).
(ii) For data collected using test methods that are not supported
by the EPA's ERT as listed on the EPA's ERT Web site at the time of the
test, you must submit the results of the performance test to the
Administrator at the appropriate address listed in Sec. 63.13.
(2) Within 60 days after the date of completing each CEMS
performance evaluation required by Sec. 63.1571(a) and (b), you must
submit the results of the performance evaluation following the
procedure specified in either paragraph (k)(2)(i) or (ii) of this
section.
(i) For performance evaluations of continuous monitoring systems
measuring relative accuracy test audit (RATA) pollutants that are
supported by the EPA's ERT as listed on the EPA's ERT Web site at the
time of the evaluation, you must submit the results of the performance
evaluation to the EPA via the CEDRI. (CEDRI is accessed through the
EPA's CDX.) Performance evaluation data must be submitted in a file
format generated through the use of the EPA's ERT or an alternate file
format consistent with the XML schema listed on the EPA's ERT Web site.
If you claim that some of the performance evaluation information being
submitted is CBI, you must submit a complete file generated through the
use of the EPA's ERT or an alternate electronic file consistent with
the XML schema listed on the EPA's ERT Web site, including information
claimed to be CBI, on a compact disc, flash drive or other commonly
used electronic storage media to the EPA. The electronic storage media
must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI
Office, Attention: Group Leader, Measurement Policy Group, MD C404-02,
4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate file
with the CBI omitted must be submitted to the EPA via the EPA's CDX as
described earlier in this paragraph (k)(2)(i).
(ii) For any performance evaluations of continuous monitoring
systems measuring RATA pollutants that are not supported by the EPA's
ERT as listed on the EPA's ERT Web site at the time of the evaluation,
you must submit the results of the performance evaluation to the
Administrator at the appropriate address listed in Sec. 63.13.

0
50. Section 63.1576 is amended by revising paragraphs (a)(2) and (b)(3)
and (5) to read as follows:

Sec. 63.1576 What records must I keep, in what form, and for how
long?

(a) * * *
(2) The records specified in paragraphs (a)(2)(i) through (iv) of
this section.
(i) Record the date, time, and duration of each startup and/or
shutdown period, recording the periods when the affected source was
subject to the standard applicable to startup and shutdown.
(ii) In the event that an affected unit fails to meet an applicable
standard, record the number of failures. For each failure record the
date, time and duration of each failure.
(iii) For each failure to meet an applicable standard, record and
retain a list of the affected sources or equipment, an estimate of the
volume of each regulated pollutant emitted over any emission limit and
a description of the method used to estimate the emissions.
(iv) Record actions taken to minimize emissions in accordance with
Sec. 63.1570(c) and any corrective actions taken to return the
affected unit to its normal or usual manner of operation.
* * * * *
(b) * * *
(3) The performance evaluation plan as described in Sec.
63.8(d)(2) for the life of the affected source or until the affected
source is no longer subject to the provisions of this part, to be made
available for inspection, upon request, by the Administrator. If the
performance evaluation plan is revised, you must keep previous (i.e.,
superseded) versions of the performance evaluation plan on record to be
made available for inspection, upon request, by the Administrator, for
a period of 5 years after each revision to the plan. The program of
corrective action should be included in the plan required under Sec.
63.8(d)(2).
* * * * *
(5) Records of the date and time that each deviation started and
stopped.
* * * * *

0
51. Section 63.1579 is amended by:
0
a. Revising the introductory text;
0
b. Adding, in alphabetical order, a new definition of ``Hot standby'';
and
0
c. Revising the definitions of ``Deviation'' and ``PM''.
The revisions read as follows:

Sec. 63.1579 What definitions apply to this subpart?

Terms used in this subpart are defined in the Clean Air Act (CAA),
in 40 CFR 63.2, the General Provisions of

[[Page 75280]]

this part (Sec. Sec. 63.1 through 63.15), and in this section as
listed. If the same term is defined in subpart A of this part and in
this section, it shall have the meaning given in this section for
purposes of this subpart.
* * * * *
Deviation means any instance in which an affected source subject to
this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this
subpart, including but not limited to any emission limit, operating
limit, or work practice standard; or
(2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit.
* * * * *
Hot standby means periods when the catalytic cracking unit is not
receiving fresh or recycled feed oil but the catalytic cracking unit is
maintained at elevated temperatures, typically using torch oil in the
catalyst regenerator and recirculating catalyst, to prevent a complete
shutdown and cold restart of the catalytic cracking unit.
* * * * *
PM means, for the purposes of this subpart, emissions of
particulate matter that serve as a surrogate measure of the total
emissions of particulate matter and metal HAP contained in the
particulate matter, including but not limited to: Antimony, arsenic,
beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and
selenium as measured by Methods 5, 5B or 5F in appendix A-3 to part 60
of this chapter or by an approved alternative method.
* * * * *

0
52. Table 1 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1564(a)(1), you shall meet each emission
limitation in the following table that applies to you.

Table 1 to Subpart UUU of Part 63--Metal HAP Emission Limits for
Catalytic Cracking Units
------------------------------------------------------------------------
You shall meet the following
For each new or existing catalytic emission limits for each
cracking unit . . . catalyst regenerator vent . . .
------------------------------------------------------------------------
1. Subject to new source performance PM emissions must not exceed
standard (NSPS) for PM in 40 CFR 1.0 gram per kilogram (g/kg)
60.102 and not electing Sec. (1.0 lb/1,000 lb) of coke burn-
60.100(e). off, and the opacity of
emissions must not exceed 30
percent, except for one 6-
minute average opacity reading
in any 1-hour period. Before
August 1, 2017, if the
discharged gases pass through
an incinerator or waste heat
boiler in which you burn
auxiliary or in supplemental
liquid or solid fossil fuel,
the incremental rate of PM
emissions must not exceed 43.0
grams per Gigajoule (g/GJ) or
0.10 pounds per million
British thermal units (lb/
million Btu) of heat input
attributable to the liquid or
solid fossil fuel; and the
opacity of emissions must not
exceed 30 percent, except for
one 6-minute average opacity
reading in any 1-hour period.
2. Subject to NSPS for PM in 40 CFR PM emissions must not exceed
60.102a(b)(1)(i); or 40 CFR 60.102 and 1.0 g/kg (1.0 lb PM/1,000 lb)
electing Sec. 60.100(e). of coke burn-off or, if a PM
CEMS is used, 0.040 grain per
dry standard cubic feet (gr/
dscf) corrected to 0 percent
excess air.
3. Subject to NSPS for PM in 40 CFR PM emissions must not exceed
60.102a(b)(1)(ii). 0.5 g/kg coke burn-off (0.5 lb/
1000 lb coke burn-off) or, if
a PM CEMS is used, 0.020 gr/
dscf corrected to 0 percent
excess air.
4. Option 1a: Elect NSPS subpart J PM emissions must not exceed
requirements for PM per coke burn the limits specified in Item 1
limit and 30% opacity, not subject to of this table.
the NSPS for PM in 40 CFR 60.102 or
60.102a(b)(1).
5. Option 1b: Elect NSPS subpart Ja PM emissions must not exceed
requirements for PM per coke burn-off 1.0 g/kg (1.0 lb PM/1000 lb)
limit, not subject to the NSPS for PM of coke burn-off.
in 40 CFR 60.102 or 60.102a(b)(1).
6. Option 1c: Elect NSPS subpart Ja PM emissions must not exceed
requirements for PM concentration 0.040 gr/dscf corrected to 0
limit, not subject to the NSPS for PM percent excess air.
in 40 CFR 60.102 or 60.102a(b)(1).
7. Option 2: PM per coke burn-off PM emissions must not exceed
limit, not subject to the NSPS for PM 1.0 g/kg (1.0 lb PM/1000 lb)
in 40 CFR 60.102 or 60.102a(b)(1). of coke burn-off in the
catalyst regenerator.
8. Option 3: Ni lb/hr limit, not Nickel (Ni) emissions must not
subject to the NSPS for PM in 40 CFR exceed 13,000 milligrams per
60.102 or 60.102a(b)(1). hour (mg/hr) (0.029 lb/hr).
9. Option 4: Ni per coke burn-off Ni emissions must not exceed
limit, not subject to the NSPS for PM 1.0 mg/kg (0.001 lb/1,000 lb)
in 40 CFR 60.102 or 60.102a(b)(1). of coke burn-off in the
catalyst regenerator.
------------------------------------------------------------------------

0
53. Table 2 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1564(a)(2), you shall meet each operating
limit in the following table that applies to you.

Table 2 to Subpart UUU of Part 63--Operating Limits for Metal HAP Emissions From Catalytic Cracking Units
----------------------------------------------------------------------------------------------------------------
For this type of
For each new or existing catalytic continuous monitoring For this type of You shall meet this
cracking unit . . . system . . . control device . . . operating limit . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to the NSPS for PM in 40 Continuous opacity Any.................... Maintain the 3-hour
CFR 60.102 and not electing Sec. monitoring system. rolling average
60.100(e). opacity of emissions
from your catalyst
regenerator vent no
higher than 20
percent.

[[Page 75281]]

2. Subject to NSPS for PM in 40 CFR a. PM CEMS............. Any.................... Not applicable.
60.102a(b)(1)(i) or electing Sec.
60.100(e).
b. Continuous opacity Cyclone or Maintain the 3-hour
monitoring system used electrostatic rolling average
to comply with a site- precipitator. opacity of emissions
specific opacity limit. from your catalyst
regenerator vent no
higher than the site-
specific opacity limit
established during the
performance test.
c. Continuous parameter Electrostatic i. Maintain the daily
monitoring systems. precipitator. average coke burn-off
rate or daily average
flow rate no higher
than the limit
established in the
performance test.
ii. Maintain the 3-hour
rolling average total
power and secondary
current above the
limit established in
the performance test.
d. Continuous parameter Wet scrubber........... i. Maintain the 3-hour
monitoring systems. rolling average liquid-
to-gas ratio above the
limit established in
the performance test.
ii. Except for periods
of startup, shutdown,
and hot standby,
maintain the 3-hour
rolling average
pressure drop above
the limit established
in the performance
test.\1\
e. Bag leak detection Fabric filter.......... Maintain particulate
(BLD) system. loading below the BLD
alarm set point
established in the
initial adjustment of
the BLD system or
allowable seasonal
adjustments.
3. Subject to NSPS for PM in 40 CFR Any.................... Any.................... The applicable
60.102a(b)(1)(ii). operating limits in
Item 2 of this table.
4. Option 1a: Elect NSPS subpart J Any.................... Any.................... See Item 1 of this
requirements for PM per coke burn table.
limit, not subject to the NSPS for
PM in 40 CFR 60.102 or 60.102a(b)(1).
5. Option 1b: Elect NSPS subpart Ja Any.................... Any.................... The applicable
requirements for PM per coke burn- operating limits in
off limit, not subject to the NSPS Item 2.b, 2.c, 2.d,
for PM in 40 CFR 60.102 or and 2.e of this table.
60.102a(b)(1).
6. Option 1c: Elect NSPS subpart Ja PM CEMS................ Any.................... Not applicable.
requirements for PM concentration
limit, not subject to the NSPS for
PM in 40 CFR 60.102 or 60.102a(b)(1).
7. Option 2: PM per coke burn-off a. Continuous opacity Cyclone, fabric filter, See Item 2.b of this
limit not subject to the NSPS for PM monitoring system used or electrostatic table. Alternatively,
in 40 CFR 60.102 or 60.102a(b)(1). to comply with a site- precipitator. before August 1, 2017,
specific opacity limit. you may maintain the
hourly average opacity
of emissions from your
catalyst generator
vent no higher than
the site-specific
opacity limit
established during the
performance test.
b. Continuous parameter i. Electrostatic (1) See Item 2.c.i of
monitoring systems. precipitator. this table.
(2) See item 2.c.ii of
this table.
Alternatively, before
August 1, 2017, you
may maintain the daily
average voltage and
secondary current
above the limit
established in the
performance test.

[[Page 75282]]

ii. Wet scrubber....... (1) See Item 2.d.i of
this table.
Alternatively, before
August 1, 2017, you
may maintain the daily
average liquid-to-gas
ratio above the limit
established in the
performance test.
(2) See Item 2.d.ii of
the table.
Alternatively, before
August 1, 2017, you
may maintain the daily
average pressure drop
above the limit
established in the
performance test (not
applicable to a wet
scrubber of the non-
venturi jet-ejector
design).
c. Bag leak detection Fabric filter.......... See item 2.e of this
(BLD) system. table.
8. Option 3: Ni lb/hr limit not a. Continuous opacity Cyclone, fabric filter, Maintain the 3-hour
subject to the NSPS for PM in 40 CFR monitoring system. or electrostatic rolling average Ni
60.102. precipitator. operating value no
higher than the limit
established during the
performance test.
Alternatively, before
August 1, 2017, you
may maintain the daily
average Ni operating
value no higher than
the limit established
during the performance
test.
b. Continuous parameter i. Electrostatic (1) See Item 2.c.i of
monitoring systems. precipitator. this table.
(2) Maintain the
monthly rolling
average of the
equilibrium catalyst
Ni concentration no
higher than the limit
established during the
performance test.
(3) See Item 2.c.ii of
this table.
Alternatively, before
August 1, 2017, you
may maintain the daily
average voltage and
secondary current (or
total power input)
above the established
during the performance
test.
ii. Wet scrubber....... (1) Maintain the
monthly rolling
average of the
equilibrium catalyst
Ni concentration no
higher than the limit
established during the
performance test.
(2) See Item 2.d.i of
this table.
Alternatively, before
August 1, 2017, you
may maintain the daily
average liquid-to-gas
ratio above the limit
established during the
performance test.
(3) See Item 2.d.ii of
this table.
Alternatively, before
August 1, 2017, you
may maintain the daily
average pressure drop
above the limit
established during the
performance test (not
applicable to a non-
venturi wet scrubber
of the jet-ejector
design).
c. Bag leak detection Fabric filter.......... See item 2.e of this
(BLD) system. table.

[[Page 75283]]

9. Option 4: Ni per coke burn-off a. Continuous opacity Cyclone, fabric filter, Maintain the 3-hour
limit not subject to the NSPS for PM monitoring system. or electrostatic rolling average Ni
in 40 CFR 60.102. precipitator. operating value no
higher than Ni
operating limit
established during the
performance test.
Alternatively, before
August 1, 2017, you
may elect to maintain
the daily average Ni
operating value no
higher than the Ni
operating limit
established during the
performance test.
b. Continuous parameter i. Electrostatic (1) Maintain the
monitoring systems. precipitator. monthly rolling
average of the
equilibrium catalyst
Ni concentration no
higher than the limit
established during the
performance test.
(2) See Item 2.c.ii of
this table.
Alternatively, before
August 1, 2017, you
may maintain the daily
average voltage and
secondary current (or
total power input)
above the limit
established during the
performance test.
ii. Wet scrubber....... (1) Maintain the
monthly rolling
average of the
equilibrium catalyst
Ni concentration no
higher than the limit
established during the
performance test.
(2) See Item 2.d.i of
this table.
Alternatively, before
August 1, 2017, you
may maintain the daily
average liquid-to-gas
ratio above the limit
established during the
performance test.
(3) See Item 2.d.ii of
this table.
Alternatively, before
August 1, 2017, you
may maintain the daily
average pressure drop
above the limit
established during the
performance test (not
applicable to a non-
venturi wet scrubber
of the jet-ejector
design).
c. Bag leak detection Fabric filter.......... See item 2.e of this
(BLD) system. table.
10. During periods of startup, Any.................... Any.................... Meet the requirements
shutdown, or hot standby. in Sec.
63.1564(a)(5).
----------------------------------------------------------------------------------------------------------------
\1\ If you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray
nozzles, you can use the alternative in Sec. 63.1573(b), and comply with the daily inspections,
recordkeeping, and repair provisions, instead of a continuous parameter monitoring system for pressure drop
across the scrubber.

0
54. Table 3 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1564(b)(1), you shall meet each requirement
in the following table that applies to you.

Table 3 to Subpart UUU of Part 63--Continuous Monitoring Systems for
Metal HAP Emissions From Catalytic Cracking Units
------------------------------------------------------------------------
If you use this
For each new or existing type of control You shall install,
catalytic cracking unit . . . device for your operate, and maintain
vent . . . a . . .
------------------------------------------------------------------------
1. Subject to the NSPS for PM Any.............. Continuous opacity
in 40 CFR 60.102 and not monitoring system to
electing Sec. 60.100(e). measure and record
the opacity of
emissions from each
catalyst regenerator
vent.

[[Page 75284]]

2. Subject to NSPS for PM in a. Cyclone....... Continuous opacity
40 CFR 60.102a(b)(1)(i); or b. Electrostatic monitoring system to
in Sec. 60.102 and electing precipitator. measure and record
Sec. 60.100(e); electing to the opacity of
meet the PM per coke burn-off emissions from each
limit. catalyst regenerator
vent.
Continuous opacity
monitoring system to
measure and record
the opacity of
emissions from each
catalyst regenerator
vent; or continuous
parameter monitoring
systems to measure
and record the coke
burn-off rate or the
gas flow rate
entering or exiting
the control
device,\1\ the
voltage, current,
and secondary
current to the
control device.
c. Wet scrubber.. Continuous parameter
monitoring system to
measure and record
the pressure drop
across the
scrubber,\2\ the
coke burn-off rate
or the gas flow rate
entering or exiting
the control
device,\3\ and total
liquid (or scrubbing
liquor) flow rate to
the control device.
d. Fabric Filter. Continuous bag leak
detection system to
measure and record
increases in
relative particulate
loading from each
catalyst regenerator
vent.
3. Subject to NSPS for PM in Any.............. Continuous emission
40 CFR 60.102a(b)(1)(i); or monitoring system to
in Sec. 60.102 and electing measure and record
Sec. 60.100(e); electing to the concentration of
meet the PM concentration PM and oxygen from
limit. each catalyst
regenerator vent.
4. Subject to NSPS for PM in Any.............. The applicable
40 CFR 60.102a(b)(1)(ii) continuous
electing to meet the PM per monitoring systems
coke burn-off limit. in item 2 of this
table.
5. Subject to NSPS for PM in Any.............. See item 3 of this
40 CFR 60.102a(b)(1)(ii) table.
electing to meet the PM
concentration limit.
6. Option 1a: Elect NSPS Any.............. See item 1 of this
subpart J, PM per coke burn- table.
off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.120a(b)(1).
7. Option 1b: Elect NSPS Any.............. The applicable
subpart Ja, PM per coke burn- continuous
off limit, not subject to the monitoring systems
NSPS for PM in 40 CFR 60.102 in item 2 of this
or 60.120a(b)(1). table.
8. Option 1c: Elect NSPS Any.............. See item 3 of this
subpart Ja, PM concentration table.
limit not subject to the NSPS
for PM in 40 CFR 60.102 or
60.120a(b)(1).
9. Option 2: PM per coke burn- Any.............. The applicable
off limit, not subject to the continuous
NSPS for PM in 40 CFR 60.102 monitoring systems
or 60.120a(b)(1). in item 2 of this
table.
10. Option 3: Ni lb/hr limit a. Cyclone....... Continuous opacity
not subject to the NSPS for monitoring system to
PM in 40 CFR 60.102 or measure and record
60.102a(b)(1). the opacity of
emissions from each
catalyst regenerator
vent and continuous
parameter monitoring
system to measure
and record the gas
flow rate entering
or exiting the
control device.\1\
b. Electrostatic Continuous opacity
precipitator. monitoring system to
measure and record
the opacity of
emissions from each
catalyst regenerator
vent and continuous
parameter monitoring
system to measure
and record the gas
flow rate entering
or exiting the
control device \1\;
or continuous
parameter monitoring
systems to measure
and record the coke
burn-off rate or the
gas flow rate
entering or exiting
the control device
\1\ and the voltage
and current (to
measure the total
power to the system)
and secondary
current to the
control device.
c. Wet scrubber.. Continuous parameter
monitoring system to
measure and record
the pressure drop
across the
scrubber,\2\ gas
flow rate entering
or exiting the
control device,\1\
and total liquid (or
scrubbing liquor)
flow rate to the
control device.
d. Fabric Filter. Continuous bag leak
detection system to
measure and record
increases in
relative particulate
loading from each
catalyst regenerator
vent or the
monitoring systems
specified in item
10.a of this table.
11. Option 4: Ni per coke burn- a. Cyclone....... Continuous opacity
off limit not subject to the monitoring system to
NSPS for PM in 40 CFR 60.102 measure and record
or 60.102a(b)(1). the opacity of
emissions from each
catalyst regenerator
vent and continuous
parameter monitoring
system to measure
and record the coke
burn-off rate and
the gas flow rate
entering or exiting
the control
device.\1\

[[Page 75285]]

b. Electrostatic Continuous opacity
precipitator. monitoring system to
measure and record
the opacity of
emissions from each
catalyst regenerator
vent and continuous
parameter monitoring
system to measure
and record the coke
burn-off rate and
the gas flow rate
entering or exiting
the control device
\1\; or continuous
parameter monitoring
systems to measure
and record the coke
burn-off rate or the
gas flow rate
entering or exiting
the control device
\1\ and voltage and
current (to measure
the total power to
the system) and
secondary current to
the control device.
c. Wet scrubber.. Continuous parameter
monitoring system to
measure and record
the pressure drop
across the
scrubber,\2\ gas
flow rate entering
or exiting the
control device,\1\
and total liquid (or
scrubbing liquor)
flow rate to the
control device.
d. Fabric Filter. Continuous bag leak
detection system to
measure and record
increases in
relative particulate
loading from each
catalyst regenerator
vent or the
monitoring systems
specified in item
11.a of this table.
12. Electing to comply with Any.............. Continuous parameter
the operating limits in Sec. monitoring system to
63.1566(a)(5)(iii) during measure and record
periods of startup, shutdown, the gas flow rate
or hot standby. exiting the catalyst
regenerator.\1\
------------------------------------------------------------------------
\1\ If applicable, you can use the alternative in Sec. 63.1573(a)(1)
instead of a continuous parameter monitoring system for gas flow rate.
\2\ If you use a jet ejector type wet scrubber or other type of wet
scrubber equipped with atomizing spray nozzles, you can use the
alternative in Sec. 63.1573(b) instead of a continuous parameter
monitoring system for pressure drop across the scrubber.

0
55. Table 4 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. Sec. 63.1564(b)(2) and 63.1571(a)(5), you shall
meet each requirement in the following table that applies to you.

Table 4 to Subpart UUU of Part 63--Requirements for Performance Tests for Metal HAP Emissions From Catalytic
Cracking Units
----------------------------------------------------------------------------------------------------------------
For each new or existing catalytic
cracking unit catalyst regenerator You must . . . Using . . . According to these
vent . . . requirements . . .
----------------------------------------------------------------------------------------------------------------
1. Any............................... a. Select sampling Method 1 or 1A in Sampling sites must be
port's location and appendix A-1 to part located at the outlet
the number of traverse 60 of this chapter. of the control device
ports. or the outlet of the
regenerator, as
applicable, and prior
to any releases to the
atmosphere.
b. Determine velocity Method 2, 2A, 2C, 2D, .......................
and volumetric flow or 2F in appendix A-1
rate. to part 60 of this
chapter, or Method 2G
in appendix A-2 to
part 60 of this
chapter, as applicable.
c. Conduct gas Method 3, 3A, or 3B in .......................
molecular weight appendix A-2 to part
analysis. 60 of this chapter, as
applicable.
d. Measure moisture Method 4 in appendix A- .......................
content of the stack 3 to part 60 of this
gas. chapter.
e. If you use an .......................
electrostatic
precipitator, record
the total number of
fields in the control
system and how many
operated during the
applicable performance
test.
f. If you use a wet .......................
scrubber, record the
total amount (rate) of
water (or scrubbing
liquid) and the amount
(rate) of make-up
liquid to the scrubber
during each test run.

[[Page 75286]]

2. Subject to the NSPS for PM in 40 a. Measure PM emissions Method 5, 5B, or 5F (40 You must maintain a
CFR 60.102 and not elect Sec. CFR part 60, appendix sampling rate of at
60.100(e). A-3) to determine PM least 0.15 dry
emissions and standard cubic meters
associated moisture per minute (dscm/min)
content for units (0.53 dry standard
without wet scrubbers. cubic feet per minute
Method 5 or 5B (40 CFR (dscf/min)).
part 60, appendix A-3)
to determine PM
emissions and
associated moisture
content for unit with
wet scrubber.
b. Compute coke burn- Equations 1, 2, and 3 .......................
off rate and PM of Sec. 63.1564 (if
emission rate (lb/ applicable).
1,000 lb of coke burn-
off).
c. Measure opacity of Continuous opacity You must collect
emissions. monitoring system. opacity monitoring
data every 10 seconds
during the entire
period of the Method
5, 5B, or 5F
performance test and
reduce the data to 6-
minute averages.
3. Subject to the NSPS for PM in 40 a. Measure PM emissions Method 5, 5B, or 5F (40 You must maintain a
CFR 60.102a(b)(1) or elect Sec. CFR part 60, appendix sampling rate of at
60.100(e), electing the PM for coke A-3) to determine PM least 0.15 dscm/min
burn-off limit. emissions and (0.53 dscf/min).
associated moisture
content for units
without wet scrubbers.
Method 5 or 5B (40 CFR
part 60, appendix A-3)
to determine PM
emissions and
associated moisture
content for unit with
wet scrubber.
b. Compute coke burn- Equations 1, 2, and 3 .......................
off rate and PM of Sec. 63.1564 (if
emission rate (lb/ applicable).
1,000 lb of coke burn-
off).
c. Establish site- Continuous opacity If you elect to comply
specific limit if you monitoring system. with the site-specific
use a COMS. opacity limit in Sec.
63.1564(b)(4)(i), you
must collect opacity
monitoring data every
10 seconds during the
entire period of the
Method 5, 5B, or 5F
performance test. For
site specific opacity
monitoring, reduce the
data to 6-minute
averages; determine
and record the average
opacity for each test
run; and compute the
site-specific opacity
limit using Equation 4
of Sec. 63.1564.
4. Subject to the NSPS for PM in 40 a. Measure PM emissions Method 5, 5B, or 5F (40 You must maintain a
CFR 60.102a(b)(1) or elect Sec. CFR part 60, appendix sampling rate of at
60.100(e). A-3) to determine PM least 0.15 dscm/min
emissions and (0.53 dscf/min).
associated moisture
content for units
without wet scrubbers.
Method 5 or 5B (40 CFR
part 60, appendix A-3)
to determine PM
emissions and
associated moisture
content for unit with
wet scrubber.
5. Option 1a: Elect NSPS subpart J See item 2 of this ....................... .......................
requirements for PM per coke burn- table.
off limit, not subject to the NSPS
for PM in 40 CFR 60.102 or
60.102a(b)(1).
6. Option 1b: Elect NSPS subpart Ja See item 3 of this
requirements for PM per coke burn- table.
off limit, not subject to the NSPS
for PM in 40 CFR 60.102 or
60.102a(b)(1).

[[Page 75287]]

7. Option 1c: Elect NSPS requirements See item 4 of this
for PM concentration, not subject to table.
the NSPS for PM in 40 CFR 60.102 or
60.102a(b)(1).
8. Option 2: PM per coke burn-off See item 3 of this
limit, not subject to the NSPS for table.
PM in 40 CFR 60.102 or 60.102a(b)(1).
9. Option 3: Ni lb/hr limit, not a. Measure Method 29 (40 CFR part
subject to the NSPS for PM in 40 CFR concentration of Ni. 60, appendix A-8).
60.102 or 60.102a(b)(1). ....................... Equation 5 of Sec.
b. Compute Ni emission 63.1564.
rate (lb/hr).
c. Determine the XRF procedure in You must obtain 1
equilibrium catalyst appendix A to this sample for each of the
Ni concentration. subpart1; or EPA 3 test runs; determine
Method 6010B or 6020 and record the
or EPA Method 7520 or equilibrium catalyst
7521 in SW-8462; or an Ni concentration for
alternative to the SW- each of the 3 samples;
846 method and you may adjust the
satisfactory to the laboratory results to
Administrator. the maximum value
using Equation 2 of
Sec. 63.1571.
d. If you use a i. Equations 6 and 7 of (1) You must collect
continuous opacity Sec. 63.1564 using opacity monitoring
monitoring system, data from continuous data every 10 seconds
establish your site- opacity monitoring during the entire
specific Ni operating system, gas flow rate, period of the initial
limit. results of equilibrium Ni performance test;
catalyst Ni reduce the data to 6-
concentration minute averages; and
analysis, and Ni determine and record
emission rate from the average opacity
Method 29 test. from all the 6-minute
averages for each test
run.
(2) You must collect
gas flow rate
monitoring data every
15 minutes during the
entire period of the
initial Ni performance
test; measure the gas
flow as near as
practical to the
continuous opacity
monitoring system; and
determine and record
the hourly average
actual gas flow rate
for each test run.
10. Option 4: Ni per coke burn-off a. Measure Method 29 (40 CFR part
limit, not subject to the NSPS for concentration of Ni. 60, appendix A-8).
PM in 40 CFR 60.102 or 60.102a(b)(1). ....................... Equations 1 and 8 of
b. Compute Ni emission Sec. 63.1564.
rate (lb/1,000 lb of
coke burn-off).
c. Determine the See item 6.c. of this You must obtain 1
equilibrium catalyst table. sample for each of the
Ni concentration. 3 test runs; determine
and record the
equilibrium catalyst
Ni concentration for
each of the 3 samples;
and you may adjust the
laboratory results to
the maximum value
using Equation 2 of
Sec. 63.1571.
d. If you use a i. Equations 9 and 10 (1) You must collect
continuous opacity of Sec. 63.1564 with opacity monitoring
monitoring system, data from continuous data every 10 seconds
establish your site- opacity monitoring during the entire
specific Ni operating system, coke burn-off period of the initial
limit. rate, results of Ni performance test;
equilibrium catalyst reduce the data to 6-
Ni concentration minute averages; and
analysis, and Ni determine and record
emission rate from the average opacity
Method 29 test. from all the 6-minute
averages for each test
run.

[[Page 75288]]

(2) You must collect
gas flow rate
monitoring data every
15 minutes during the
entire period of the
initial Ni performance
test; measure the gas
flow rate as near as
practical to the
continuous opacity
monitoring system; and
determine and record
the hourly average
actual gas flow rate
for each test run.
e. Record the catalyst .......................
addition rate for each
test and schedule for
the 10-day period
prior to the test.
11. If you elect item 5 Option 1b in a. Establish each Data from the .......................
Table 1, item 7 Option 2 in Table 1, operating limit in continuous parameter
item 8 Option 3 in Table 1, or item Table 2 of this monitoring systems and
9 Option 4 in Table 1 of this subpart that applies applicable performance
subpart and you use continuous to you. test methods.
parameter monitoring systems.
b. Electrostatic i. Data from the (1) You must collect
precipitator or wet continuous parameter gas flow rate
scrubber: Gas flow monitoring systems and monitoring data every
rate. applicable performance 15 minutes during the
test methods. entire period of the
initial performance
test; determine and
record the average gas
flow rate for each
test run.
(2) You must determine
and record the 3-hr
average gas flow rate
from the test runs.
Alternatively, before
August 1, 2017, you
may determine and
record the maximum
hourly average gas
flow rate from all the
readings.
c. Electrostatic i. Data from the (1) You must collect
precipitator: Total continuous parameter voltage, current, and
power (voltage and monitoring systems and secondary current
current) and secondary applicable performance monitoring data every
current. test methods. 15 minutes during the
entire period of the
performance test; and
determine and record
the average voltage,
current, and secondary
current for each test
run. Alternatively,
before August 1, 2017,
you may collect
voltage and secondary
current (or total
power input)
monitoring data every
15 minutes during the
entire period of the
initial performance
test.
(2) You must determine
and record the 3-hr
average total power to
the system for the
test runs and the 3-hr
average secondary
current from the test
runs. Alternatively,
before August 1, 2017,
you may determine and
record the minimum
hourly average voltage
and secondary current
(or total power input)
from all the readings.

[[Page 75289]]

d. Electrostatic Results of analysis for You must determine and
precipitator or wet equilibrium catalyst record the average
scrubber: Equilibrium Ni concentration. equilibrium catalyst
catalyst Ni Ni concentration for
concentration. the 3 runs based on
the laboratory
results. You may
adjust the value using
Equation 1 or 2 of
Sec. 63.1571 as
applicable.
e. Wet scrubber: i. Data from the (1) You must collect
Pressure drop (not continuous parameter pressure drop
applicable to non- monitoring systems and monitoring data every
venturi scrubber of applicable performance 15 minutes during the
jet ejector design). test methods. entire period of the
initial performance
test; and determine
and record the average
pressure drop for each
test run.
(2) You must determine
and record the 3-hr
average pressure drop
from the test runs.
Alternatively, before
August 1, 2017, you
may determine and
record the minimum
hourly average
pressure drop from all
the readings.
f. Wet scrubber: Liquid- i. Data from the (1) You must collect
to-gas ratio. continuous parameter gas flow rate and
monitoring systems and total water (or
applicable performance scrubbing liquid) flow
test methods. rate monitoring data
every 15 minutes
during the entire
period of the initial
performance test;
determine and record
the average gas flow
rate for each test
run; and determine the
average total water
(or scrubbing liquid)
flow for each test
run.
(2) You must determine
and record the hourly
average liquid-to-gas
ratio from the test
runs. Alternatively,
before August 1, 2017,
you may determine and
record the hourly
average gas flow rate
and total water (or
scrubbing liquid) flow
rate from all the
readings.
(3) You must determine
and record the 3-hr
average liquid-to-gas
ratio. Alternatively,
before August 1, 2017,
you may determine and
record the minimum
liquid-to-gas ratio.
g. Alternative i. Data from the (1) You must collect
procedure for gas flow continuous parameter air flow rate
rate. monitoring systems and monitoring data or
applicable performance determine the air flow
test methods. rate using control
room instrumentation
every 15 minutes
during the entire
period of the initial
performance test.
(2) You must determine
and record the 3-hr
average rate of all
the readings from the
test runs.
Alternatively, before
August 1, 2017, you
may determine and
record the hourly
average rate of all
the readings.
(3) You must determine
and record the maximum
gas flow rate using
Equation 1 of Sec.
63.1573.
----------------------------------------------------------------------------------------------------------------
\1\ Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure).

[[Page 75290]]

\2\ EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively
Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, and EPA Method
7521, Nickel Atomic Absorption, Direct Aspiration are included in ``Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' EPA Publication SW-846, Revision 5 (April 1998). The SW-846 and Updates (document
number 955-001-00000-1) are available for purchase from the Superintendent of Documents, U.S. Government
Publishing Office, Washington, DC 20402, (202) 512-1800; and from the National Technical Information Services
(NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487-4650. Copies may be inspected at the EPA Docket
Center, William Jefferson Clinton (WJC) West Building, (Air Docket), Room 3334, 1301 Constitution Ave. NW.,
Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington,
DC.

0
56. Table 5 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1564(b)(5), you shall meet each requirement
in the following table that applies to you.

Table 5 to Subpart UUU of Part 63--Initial Compliance With Metal HAP
Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
For each new and existing For the following
catalytic cracking unit emission limit . You have demonstrated
catalyst regenerator vent . . . . initial compliance if
. . . .
------------------------------------------------------------------------
1. Subject to the NSPS for PM PM emissions must You have already
in 40 CFR 60.102 and not not exceed 1.0 g/ conducted a
electing Sec. 60.100(e). kg (1.0 lb/1,000 performance test to
lb) of coke burn- demonstrate initial
off, and the compliance with the
opacity of NSPS and the
emissions must measured PM emission
not exceed 30 rate is less than or
percent, except equal to 1.0 g/kg
for one 6-minute (1.0 lb/1,000 lb) of
average opacity coke burn-off in the
reading in any 1- catalyst
hour period. regenerator. As part
Before August 1, of the Notification
2017, if the of Compliance
discharged gases Status, you must
pass through an certify that your
incinerator or vent meets the PM
waste heat limit. You are not
boiler in which required to do
you burn another performance
auxiliary or test to demonstrate
supplemental initial compliance.
liquid or solid You have already
fossil fuel, the conducted a
incremental rate performance test to
of PM must not demonstrate initial
exceed 43.0 g/GJ compliance with the
or 0.10 lb/ NSPS and the average
million Btu of hourly opacity is no
heat input more than 30
attributable to percent, except that
the liquid or one 6-minute average
solid fossil in any 1-hour period
fuel; and the can exceed 30
opacity of percent. As part of
emissions must the Notification of
not exceed 30 Compliance Status,
percent, except you must certify
for one 6-minute that your vent meets
average opacity the 30 percent
reading in any 1- opacity limit. As
hour period. part of your
Notification of
Compliance Status,
you certify that
your continuous
opacity monitoring
system meets the
requirements in Sec.
63.1572.
2. Subject to NSPS for PM in PM emissions must You have already
40 CFR 60.102a(b)(1)(i); or not exceed 1.0 g/ conducted a
in Sec. 60.102 and electing kg (1.0 lb PM/ performance test to
Sec. 60.100(e); electing to 1,000 lb) of demonstrate initial
meet the PM per coke burn-off coke burn-off. compliance with the
limit. NSPS and the
measured PM emission
rate is less than or
equal to 1.0 g/kg
(1.0 lb/1,000 lb) of
coke burn-off in the
catalyst
regenerator. As part
of the Notification
of Compliance
Status, you must
certify that your
vent meets the PM
limit. You are not
required to do
another performance
test to demonstrate
initial compliance.
As part of your
Notification of
Compliance Status,
you certify that
your BLD; CO2, O2,
or CO monitor; or
continuous opacity
monitoring system
meets the
requirements in Sec.
63.1572.
3. Subject to NSPS for PM in PM emissions must You have already
40 CFR 60.102a(b)(1)(i), not exceed 0.5 g/ conducted a
electing to meet the PM per kg (0.5 lb PM/ performance test to
coke burn-off limit. 1,000 lb) of demonstrate initial
coke burn-off). compliance with the
NSPS and the
measured PM emission
rate is less than or
equal to 1.0 g/kg
(1.0 lb/1,000 lb) of
coke burn-off in the
catalyst
regenerator. As part
of the Notification
of Compliance
Status, you must
certify that your
vent meets the PM
limit. You are not
required to do
another performance
test to demonstrate
initial compliance.
As part of your
Notification of
Compliance Status,
you certify that
your BLD; CO2, O2,
or CO monitor; or
continuous opacity
monitoring system
meets the
requirements in Sec.
63.1572.
4. Subject to NSPS for PM in If a PM CEMS is You have already
40 CFR 60.102a(b)(1)(i), used, 0.040 conducted a
electing to meet the PM grain per dry performance test to
concentration limit. standard cubic demonstrate initial
feet (gr/dscf) compliance with the
corrected to 0 NSPS and the
percent excess measured PM
air. concentration is
less than or equal
to 0.040 grain per
dry standard cubic
feet (gr/dscf)
corrected to 0
percent excess air.
As part of the
Notification of
Compliance Status,
you must certify
that your vent meets
the PM limit. You
are not required to
do another
performance test to
demonstrate initial
compliance. As part
of your Notification
of Compliance
Status, you certify
that your PM CEMS
meets the
requirements in Sec.
63.1572.

[[Page 75291]]

5. Subject to NSPS for PM in If a PM CEMS is You have already
40 CFR 60.102a(b)(1)(ii), used, 0.020 gr/ conducted a
electing to meet the PM dscf corrected performance test to
concentration limit. to 0 percent demonstrate initial
excess air. compliance with the
NSPS and the
measured PM
concentration is
less than or equal
to 0.020 gr/dscf
corrected to 0
percent excess air.
As part of the
Notification of
Compliance Status,
you must certify
that your vent meets
the PM limit. You
are not required to
do another
performance test to
demonstrate initial
compliance. As part
of your Notification
of Compliance
Status, you certify
that your PM CEMS
meets the
requirements in Sec.
63.1572.
6. Option 1a: Elect NSPS PM emissions must The average PM
subpart J requirements for PM not exceed 1.0 emission rate,
per coke burn-off limit, not gram per measured using EPA
subject to the NSPS for PM in kilogram (g/kg) Method 5, 5B, or 5F
40 CFR 60.102 or (1.0 lb/1,000 (for a unit without
60.102a(b)(1). lb) of coke burn- a wet scrubber) or 5
off, and the or 5B (for a unit
opacity of with a wet scrubber)
emissions must (40 CFR part 60,
not exceed 30 appendix A-3), over
percent, except the period of the
for one 6-minute initial performance
average opacity test, is no higher
reading in any 1- than 1.0 g/kg coke
hour period. burn-off (1.0 lb/
Before August 1, 1,000 lb) in the
2017, PM catalyst
emission must regenerator. The PM
not exceed 1.0 g/ emission rate is
kg (1.0 lb/1,000 calculated using
lb) of coke burn- Equations 1, 2, and
off in the 3 of Sec. 63.1564.
catalyst As part of the
regenerator; if Notification of
the discharged Compliance Status,
gases pass you must certify
through an that your vent meets
incinerator or the PM limit. The
waste heat average hourly
boiler in which opacity is no more
you burn than 30 percent,
auxiliary or except that one 6-
supplemental minute average in
liquid or solid any 1-hour period
fossil fuel, the can exceed 30
incremental rate percent. As part of
of PM must not the Notification of
exceed 43.0 g/GJ Compliance Status,
(0.10 lb/million you must certify
Btu) of heat that your vent meets
input the 30 percent
attributable to opacity limit. If
the liquid or you use a continuous
solid fossil opacity monitoring
fuel; and the system, your
opacity of performance
emissions must evaluation shows the
not exceed 30 system meets the
percent, except applicable
for one 6-minute requirements in Sec.
average opacity 63.1572.
reading in any 1-
hour period.
7. Option 1b: Elect NSPS PM emissions must The average PM
subpart Ja requirements for not exceed 1.0 g/ emission rate,
PM per coke burn-off limit, kg (1.0 lb/1,000 measured using EPA
not subject to the NSPS for lb) of coke burn- Method 5, 5B, or 5F
PM in 40 CFR 60.102 or off. (for a unit without
60.102a(b)(1). a wet scrubber) or 5
or 5B (for a unit
with a wet scrubber)
(40 CFR part 60,
appendix A-3), over
the period of the
initial performance
test, is no higher
than 1.0 g/kg coke
burn-off (1.0 lb/
1,000 lb) in the
catalyst
regenerator. The PM
emission rate is
calculated using
Equations 1, 2, and
3 of Sec. 63.1564.
If you use a BLD;
CO2, O2, CO monitor;
or continuous
opacity monitoring
system, your
performance
evaluation shows the
system meets the
applicable
requirements in Sec.
63.1572.
8. Option 1c: Elect NSPS PM emissions must The average PM
subpart Ja requirements for not exceed 0.040 concentration,
PM concentration limit, not gr/dscf measured using EPA
subject to the NSPS for PM in corrected to 0 Method 5, 5B, or 5F
40 CFR 60.102 or percent excess (for a unit without
60.102a(b)(1). air. a wet scrubber) or
Method 5 or 5B (for
a unit with a wet
scrubber) (40 CFR
part 60, appendix A-
3), over the period
of the initial
performance test, is
less than or equal
to 0.040 gr/dscf
corrected to 0
percent excess air.
Your performance
evaluation shows
your PM CEMS meets
the applicable
requirements in Sec.
63.1572.
9. Option 2: PM per coke burn- PM emissions must The average PM
off limit, not subject to the not exceed 1.0 g/ emission rate,
NSPS for PM in 40 CFR 60.102 kg (1.0 lb/1,000 measured using EPA
or 60.102a(b)(1). lb) of coke burn- Method 5, 5B, or 5F
off. (for a unit without
a wet scrubber) or 5
or 5B (for a unit
with a wet scrubber)
(40 CFR part 60,
appendix A-3), over
the period of the
initial performance
test, is no higher
than 1.0 g/kg coke
burn-off (1.0 lb/
1,000 lb) in the
catalyst
regenerator. The PM
emission rate is
calculated using
Equations 1, 2, and
3 of Sec. 63.1564.
If you use a BLD;
CO2, O2, CO monitor;
or continuous
opacity monitoring
system, your
performance
evaluation shows the
system meets the
applicable
requirements in Sec.
63.1572.
10. Option 3: Ni lb/hr limit, Nickel (Ni) The average Ni
not subject to the NSPS for emissions from emission rate,
PM in 40 CFR 60.102 or your catalyst measured using
60.102a(b)(1). regenerator vent Method 29 (40 CFR
must not exceed part 60, appendix A-
13,000 mg/hr 8) over the period
(0.029 lb/hr). of the initial
performance test, is
not more than 13,000
mg/hr (0.029 lb/hr).
The Ni emission rate
is calculated using
Equation 5 of Sec.
63.1564; and if you
use a BLD; CO2, O2,
or CO monitor; or
continuous opacity
monitoring system,
your performance
evaluation shows the
system meets the
applicable
requirements in Sec.
63.1572.

[[Page 75292]]

11. Option 4: Ni per coke burn- Ni emissions from The average Ni
off limit not subject to the your catalyst emission rate,
NSPS for PM. regenerator vent measured using
must not exceed Method 29 (40 CFR
1.0 mg/kg (0.001 part 60, appendix A-
lb/1,000 lb) of 8) over the period
coke burn-off in of the initial
the catalyst performance test, is
regenerator. not more than 1.0 mg/
kg (0.001 lb/1,000
lb) of coke burn-off
in the catalyst
regenerator. The Ni
emission rate is
calculated using
Equation 8 of Sec.
63.1564; and if you
use a BLD; CO2, O2,
or CO monitor; or
continuous opacity
monitoring system,
your performance
evaluation shows the
system meets the
applicable
requirements in Sec.
63.1572.
------------------------------------------------------------------------

0
57. Table 6 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1564(c)(1), you shall meet each requirement
in the following table that applies to you.

Table 6 to Subpart UUU of Part 63--Continuous Compliance With Metal HAP
Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
Subject to this
emission limit You shall demonstrate
For each new and existing for your catalyst continuous compliance
catalytic cracking unit . . . regenerator vent by . . .
. . .
------------------------------------------------------------------------
1. Subject to the NSPS for PM a. PM emissions i. Determining and
in 40 CFR 60.102 and not must not exceed recording each day
electing Sec. 60.100(e). 1.0 g/kg (1.0 lb/ the average coke
1,000 lb) of burn-off rate
coke burn-off, (thousands of
and the opacity kilograms per hour)
of emissions using Equation 1 in
must not exceed Sec. 63.1564 and
30 percent, the hours of
except for one 6- operation for each
minute average catalyst
opacity reading regenerator.
in any 1-hour
period. Before
August 1, 2017,
if the
discharged gases
pass through an
incinerator or
waste heat
boiler in which
you burn
auxiliary or
supplemental
liquid or solid
fossil fuel, the
incremental rate
of PM must not
exceed 43.0 g/GJ
(0.10 lb/million
Btu) of heat
input
attributable to
the liquid or
solid fossil
fuel; and the
opacity of
emissions must
not exceed 30
percent, except
for one 6-minute
average opacity
reading in any 1-
hour period.
ii. Conducting a
performance test
before August 1,
2017 and thereafter
following the
testing frequency in
Sec. 63.1571(a)(5)
as applicable to
your unit.
iii. Collecting the
continuous opacity
monitoring data for
each catalyst
regenerator vent
according to Sec.
63.1572 and
maintaining each 6-
minute average at or
below 30 percent,
except that one 6-
minute average
during a 1-hour
period can exceed 30
percent.
iv. Before August 1,
2017, if applicable,
determining and
recording each day
the rate of
combustion of liquid
or solid fossil
fuels (liters/hour
or kilograms/hour)
and the hours of
operation during
which liquid or
solid fossil-fuels
are combusted in the
incinerator-waste
heat boiler; if
applicable,
maintaining the
incremental rate of
PM at or below 43 g/
GJ (0.10 lb/million
Btu) of heat input
attributable to the
solid or liquid
fossil fuel.
2. Subject to NSPS for PM in PM emissions must Determining and
40 CFR 60.102a(b)(1)(i), not exceed 1.0 g/ recording each day
electing to meet the PM per kg (1.0 lb PM/ the average coke
coke burn-off limit. 1,000 lb) of burn-off rate
coke burn-off. (thousands of
kilograms per hour)
using Equation 1 in
Sec. 63.1564 and
the hours of
operation for each
catalyst
regenerator;
maintaining PM
emission rate below
1.0 g/kg (1.0 lb PM/
1,000 lb) of coke
burn-off; and
conducting a
performance test
once every year.
3. Subject to NSPS for PM in PM emissions must Determining and
40 CFR 60.102a(b)(1)(ii), not exceed 0.5 g/ recording each day
electing to meet the PM per kg coke burn-off the average coke
coke burn-off limit. (0.5 lb/1000 lb burn-off rate
coke burn-off). (thousands of
kilograms per hour)
using Equation 1 in
Sec. 63.1564 and
the hours of
operation for each
catalyst
regenerator;
maintaining PM
emission rate below
0.5 g/kg (0.5 lb/
1,000 lb) of coke
burn-off; and
conducting a
performance test
once every year.

[[Page 75293]]

4. Subject to NSPS for PM in If a PM CEMS is Maintaining PM
40 CFR 60.102a(b)(1)(i), used, 0.040 concentration below
electing to meet the PM grain per dry 0.040 gr/dscf
concentration limit. standard cubic corrected to 0
feet (gr/dscf) percent excess air.
corrected to 0
percent excess
air.
5. Subject to NSPS for PM in If a PM CEMS is Maintaining PM
40 CFR 60.102a(b)(1)(ii), used, 0.020 gr/ concentration below
electing to meet the PM dscf corrected 0.020 gr/dscf
concentration limit. to 0 percent corrected to 0
excess air. percent excess air.
6. Option 1a: Elect NSPS See item 1 of See item 1 of this
subpart J requirements for PM this table. table.
per coke burn-off limit, not
subject to the NSPS for PM in
40 CFR 60.102 or
60.102a(b)(1).
7. Option 1b: Elect NSPS PM emissions must See item 2 of this
subpart Ja requirements for not exceed 1.0 g/ table.
PM per coke burn-off limit kg (1.0 lb PM/
and 30% opacity, not subject 1,000 lb) of
to the NSPS for PM in 40 CFR coke burn-off.
60.102 or 60.102a(b)(1).
8. Option 1c: Elect NSPS PM emissions must See item 4 of this
subpart Ja requirements for not exceed 0.040 table.
PM concentration limit, not gr/dscf
subject to the NSPS for PM in corrected to 0
40 CFR 60.102 or percent excess
60.102a(b)(1). air.
9. Option 2: PM per coke burn- PM emissions must Determining and
off limit, not subject to the not exceed 1.0 g/ recording each day
NSPS for PM in 40 CFR 60.102 kg (1.0 lb PM/ the average coke
or 60.102a(b)(1). 1,000 lb) of burn-off rate and
coke burn-off. the hours of
operation and the
hours of operation
for each catalyst
regenerator by
Equation 1 of Sec.
63.1564 (you can use
process data to
determine the
volumetric flow
rate); maintaining
PM emission rate
below 1.0 g/kg (1.0
lb PM/1,000 lb) of
coke burn-off; and
conducting a
performance test
before August 1,
2017 and thereafter
following the
testing frequency in
Sec. 63.1571(a)(5)
as applicable to
your unit.
10. Option 3: Ni lb/hr limit, Ni emissions must Maintaining Ni
not subject to the NSPS for not exceed emission rate below
PM in 40 CFR 60.102 or 13,000 mg/hr 13,000 mg/hr (0.029
60.102a(b)(1). (0.029 lb/hr). lb/hr); and
conducting a
performance test
before August 1,
2017 and thereafter
following the
testing frequency in
Sec. 63.1571(a)(5)
as applicable to
your unit.
11. Option 4: Ni per coke burn- Ni emissions must Determining and
off limit, not subject to the not exceed 1.0 recording each day
NSPS for PM in 40 CFR 60.102 mg/kg (0.001 lb/ the average coke
or 60.102a(b)(1). 1,000 lb) of burn-off rate
coke burn-off in (thousands of
the catalyst kilograms per hour)
regenerator. and the hours of
operation for each
catalyst regenerator
by Equation 1 of
Sec. 63.1564 (you
can use process data
to determine the
volumetric flow
rate); and
maintaining Ni
emission rate below
1.0 mg/kg (0.001 lb/
1,000 lb) of coke
burn-off in the
catalyst
regenerator; and
conducting a
performance test
before August 1,
2017 and thereafter
following the
testing frequency in
Sec. 63.1571(a)(5)
as applicable to
your unit.
------------------------------------------------------------------------

0
58. Table 7 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1564(c)(1), you shall meet each requirement
in the following table that applies to you.

Table 7 to Subpart UUU of Part 63--Continuous Compliance With Operating Limits for Metal HAP Emissions From
Catalytic Cracking Units
----------------------------------------------------------------------------------------------------------------
You shall demonstrate
For each new or existing catalytic If you use . . . For this operating continuous compliance
cracking unit . . . limit . . . by . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to NSPS for PM in 40 CFR Continuous opacity The 3-hour average Collecting the
60.102 and not electing Sec. monitoring system. opacity of emissions continuous opacity
60.100(e). from your catalyst monitoring data for
regenerator vent must each regenerator vent
not exceed 20 percent. according to Sec.
63.1572 and maintain
each 3-hour rolling
average opacity of
emissions no higher
than 20 percent.

[[Page 75294]]

2. Subject to NSPS for PM in 40 CFR a. Continuous opacity The average opacity Collecting the hourly
60.102a(b)(1); or 40 CFR 60.102 and monitoring system, must not exceed the and 3-hr rolling
elect Sec. 60.100(e), electing to used for site-specific opacity established average opacity
meet the PM per coke burn-off limit. opacity limit--Cyclone during the performance monitoring data
or electrostatic test. according to Sec.
precipitator. 63.1572; maintaining
the 3-hr rolling
average opacity at or
above the site-
specific limit
established during the
performance test.
b. Continuous i. The average gas flow Collecting the hourly
parametric monitoring rate entering or and daily average coke
systems--electrostatic exiting the control burn-off rate or
precipitator. device must not exceed average gas flow rate
the operating limit monitoring data
established during the according to Sec.
performance test. 63.1572; and
maintaining the daily
average coke burn-off
rate or average gas
flow rate at or below
the limit established
during the performance
test.
ii. The average total Collecting the hourly
power and secondary and 3-hr rolling
current to the control average total power
device must not fall and secondary current
below the operating monitoring data
limit established according to Sec.
during the performance 63.1572; and
test. maintaining the 3-hr
rolling average total
power and secondary
current at or above
the limit established
during the performance
test.
c. Continuous i. The average liquid- Collecting the hourly
parametric monitoring to-gas ratio must not and 3-hr rolling
systems--wet scrubber. fall below the average gas flow rate
operating limit and scrubber liquid
established during the flow rate monitoring
performance test. data according to Sec.
63.1572; determining
and recording the 3-hr
liquid-to-gas ratio;
and maintaining the 3-
hr rolling average
liquid-to-gas ratio at
or above the limit
established during the
performance test.

ii. Except for periods Collecting the hourly
of startup, shutdown and 3-hr rolling
and hot standby, the average pressure drop
average pressure drop monitoring data
across the scrubber according to Sec.
must not fall below 63.1572; and except
the operating limit for periods of
established during the startup, shutdown and
performance test. hot standby,
maintaining the 3-hr
rolling average
pressure drop at or
above the limit
established during the
performance test.
d. BLD--fabric filter.. Increases in relative Collecting and
particulate. maintaining records of
BLD system output;
determining the cause
of the alarm within 1
hour of the alarm; and
alleviating the cause
of the alarm within 3
hours by corrective
action.
3. Subject to NSPS for PM in 40 CFR PM CEMS................ Not applicable......... Complying with Table 6
60.102a(b)(1), electing to meet the of this subpart, item
PM concentration limit. 4 or 5.
4. Option 1a: Elect NSPS subpart J Continuous opacity The 3-hour average Collecting the 3-hr
requirements for PM per coke burn- monitoring system. opacity of emissions rolling average
off limit, not subject to the NSPS from your catalyst continuous opacity
for PM in 40 CFR 60.102 or regenerator vent must monitoring system data
60.102a(b)(1). not exceed 20 percent. according to Sec.
63.1572; and
maintaining the 3-hr
rolling average
opacity no higher than
20 percent.
5. Option 1b: Elect NSPS subpart Ja a. Continuous opacity The opacity of Collecting the 3-hr
requirements for PM per coke burn- monitoring system. emissions from your rolling average
off limit, not subject to the NSPS catalyst regenerator continuous opacity
for PM in 40 CFR 60.102 or vent must not exceed monitoring system data
60.102a(b)(1). the site-specific according to Sec.
opacity operating 63.1572; maintaining
limit established the 3-hr rolling
during the performance average opacity at or
test. below the site-
specific limit.

[[Page 75295]]

b. Continuous See item 2.b of this See item 2.b of this
parametric monitoring table. table.
systems--electrostatic
precipitator.
c. Continuous See item 2.c of this See item 2.c of this
parametric monitoring table. table.
systems--wet scrubber.
d. BLD--fabric filter.. See item 2.d of this See item 2.d of this
table. table.
6. Option 1c: Elect NSPS subpart Ja PM CEMS................ Not applicable......... Complying with Table 6
requirements for PM concentration of this subpart, item
limit, not subject to the NSPS for 4.
PM in 40 CFR 60.102 or 60.102a(b)(1).
7. Option 2: PM per coke burn-off a. Continuous opacity The opacity of Collecting the hourly
limit, not subject to the NSPS for monitoring system. emissions from your and 3-hr rolling
PM in 40 CFR 60.102 or 60.102a(b)(1). catalyst regenerator average continuous
vent must not exceed opacity monitoring
the site-specific system data according
opacity operating to Sec. 63.1572; and
limit established maintaining the 3-hr
during the performance rolling average
test. opacity at or below
the site-specific
limit established
during the performance
test. Alternatively,
before August 1, 2017,
collecting the hourly
average continuous
opacity monitoring
system data according
to Sec. 63.1572; and
maintaining the hourly
average opacity at or
below the site-
specific limit.
b. Continuous parameter i. The average coke Collecting the hourly
monitoring systems-- burn-off rate or and daily average coke
electrostatic average gas flow rate burn-off rate or gas
precipitator. entering or exiting flow rate monitoring
the control device data according to Sec.
must not exceed the 63.1572; and
operating limit maintaining the daily
established during the coke burn-off rate or
performance test. average gas flow rate
at or below the limit
established during the
performance test.
ii. The average total Collecting the hourly
power (voltage and and 3-hr rolling
current) and secondary average total power
current to the control and secondary current
device must not fall monitoring data
below the operating according to Sec.
limit established 63.1572; and
during the performance maintaining the 3-hr
test. rolling average total
power and secondary
current at or above
the limit established
during the performance
test. Alternatively,
before August 1, 2017,
collecting the hourly
and daily average
voltage and secondary
current (or total
power input)
monitoring data
according to Sec.
63.1572; and
maintaining the daily
average voltage and
secondary current (or
total power input) at
or above the limit
established during the
performance test.

[[Page 75296]]

c. Continuous parameter i. The average liquid- Collecting the hourly
monitoring systems-- to-gas ratio must not and 3-hr rolling
wet scrubber. fall below the average gas flow rate
operating limit and scrubber liquid
established during the flow rate monitoring
performance test. data according to Sec.
63.1572; determining
and recording the 3-hr
liquid-to-gas ratio;
and maintaining the 3-
hr rolling average
liquid-to-gas ratio at
or above the limit
established during the
performance test.
Alternatively, before
August 1, 2017,
collecting the hourly
average gas flow rate
and water (or
scrubbing liquid) flow
rate monitoring data
according to Sec.
63.1572 \1\;
determining and
recording the hourly
average liquid-to-gas
ratio; determining and
recording the daily
average liquid-to-gas
ratio; and maintaining
the daily average
liquid-to-gas ratio
above the limit
established during the
performance test.
ii. Except for periods Collecting the hourly
of startup, shutdown and 3-hr rolling
and hot standby, the average pressure drop
average pressure drop monitoring data
across the scrubber according to Sec.
must not fall below 63.1572; and except
the operating limit for periods of
established during the startup, shutdown and
performance test. hot standby,
maintaining the 3-hr
rolling average
pressure drop at or
above the limit
established during the
performance test.
Alternatively, before
August 1, 2017,
collecting the hourly
and daily average
pressure drop
monitoring data
according to Sec.
63.1572; and
maintaining the daily
average pressure drop
above the limit
established during the
performance test.
d. BLD--fabric filter.. See item 2.d of this See item 2.d of this
table. table.
8. Option 3: Ni lb/hr limit not a. Continuous opacity i. The daily average Ni (1) Collecting the
subject to the NSPS for PM in 40 CFR monitoring system. operating value must hourly average
60.102. not exceed the site- continuous opacity
specific Ni operating monitoring system data
limit established according to Sec.
during the performance 63.1572; determining
test. and recording
equilibrium catalyst
Ni concentration at
least once a week \2\;
collecting the hourly
average gas flow rate
monitoring data
according to Sec.
63.1572 \1\; and
determining and
recording the hourly
average Ni operating
value using Equation
11 of Sec. 63.1564.

[[Page 75297]]

(2) Determining and
recording the 3-hour
rolling average Ni
operating value and
maintaining the 3-hour
rolling average Ni
operating value below
the site-specific Ni
operating limit
established during the
performance test.
Alternatively, before
August 1, 2017,
determining and
recording the daily
average Ni operating
value and maintaining
the daily average Ni
operating value below
the site-specific Ni
operating limit
established during the
performance test.
b. Continuous parameter i. The average gas flow See item 7.b.i of this
monitoring systems-- rate entering or table.
electrostatic exiting the control
precipitator. device must not exceed
the operating limit
established during the
performance test.
ii. The average total See item 7.b.ii of this
power (voltage and table.
current) and secondary
current must not fall
below the level
established in the
performance test.
iii. The monthly Determining and
rolling average of the recording the
equilibrium catalyst equilibrium catalyst
Ni concentration must Ni concentration at
not exceed the level least once a week \2\;
established during the determining and
performance test. recording the monthly
rolling average of the
equilibrium catalyst
Ni concentration once
each week using the
weekly or most recent
value; and maintaining
the monthly rolling
average below the
limit established in
the performance test.
c. Continuous parameter i. The average liquid- See item 7.c.i of this
monitoring systems-- to-gas ratio must not table.
wet scrubber. fall below the
operating limit
established during the
performance test..
ii. Except for periods See item 7.c.ii of this
of startup, shutdown table.
and hot standby, the
average pressure drop
must not fall below
the operating limit
established in the
performance test.
iii. The monthly Determining and
rolling average recording the
equilibrium catalyst equilibrium catalyst
Ni concentration must Ni concentration at
not exceed the level least once a week \2\;
established during the determining and
performance test. recording the monthly
rolling average of
equilibrium catalyst
Ni concentration once
each week using the
weekly or most recent
value; and maintaining
the monthly rolling
average below the
limit established in
the performance test.
d. BLD--fabric filter.. i. Increases in See item 7.d of this
relative particulate. table.

[[Page 75298]]

ii. The monthly rolling Determining and
average of the recording the
equilibrium catalyst equilibrium catalyst
Ni concentration must Ni concentration at
not exceed the level least once a week \2\;
established during the determining and
performance test. recording the monthly
rolling average of the
equilibrium catalyst
Ni concentration once
each week using the
weekly or most recent
value; and maintaining
the monthly rolling
average below the
limit established in
the performance test.
9. Option 4: Ni per coke burn-off a. Continuous opacity i. The daily average Ni (1) Collecting the
limit not subject to the NSPS for PM monitoring system. operating value must hourly average
in 40 CFR 60.102. not exceed the site- continuous opacity
specific Ni operating monitoring system data
limit established according to Sec.
during the performance 63.1572; collecting
test. the hourly average
coke burn rate and
hourly average gas
flow rate monitoring
data according to Sec.
63.15721;
determining and
recording equilibrium
catalyst Ni
concentration at least
once a week \2\; and
determining and
recording the hourly
average Ni operating
value using Equation
12 of Sec. 63.1564.
(2) Determining and
recording the 3-hour
rolling average Ni
operating value and
maintaining the 3-hour
rolling average Ni
operating value below
the site-specific Ni
operating limit
established during the
performance test
Alternatively, before
August 1, 2017,
determining and
recording the daily
average Ni operating
value and maintaining
the daily average Ni
operating value below
the site-specific Ni
operating limit
established during the
performance test.
b. Continuous parameter i. The average gas flow See item 7.b.i of this
monitoring systems-- rate to the control table.
electrostatic device must not exceed
precipitator. the level established
in the performance
test.
ii. The average voltage See item 7.b.ii of this
and secondary current table.
(or total power input)
must not fall below
the level established
in the performance
test.
iii. The monthly See item 8.b.iii of
rolling average this table.
equilibrium catalyst
Ni concentration must
not exceed the level
established during the
performance test.
c. Continuous parameter i. The average liquid- See item 7.c.i of this
monitoring systems-- to-gas ratio must not table.
wet scrubber. fall below the
operating limit
established during the
performance test.
ii. Except for periods See item 7.c.ii of this
of startup, shutdown table.
and hot standby, the
daily average pressure
drop must not fall
below the operating
limit established in
the performance test.

[[Page 75299]]

iii. The monthly See item 8.c.iii of
rolling average this table.
equilibrium catalyst
Ni concentration must
not exceed the level
established during the
performance test.
d. BLD--fabric filter.. i. See item 2.d of this See item 2.d of this
table. table.
ii. The monthly rolling Determining and
average of the recording the
equilibrium catalyst equilibrium catalyst
Ni concentration must Ni concentration at
not exceed the level least once a week \2\;
established during the determining and
performance test. recording the monthly
rolling average of the
equilibrium catalyst
Ni concentration once
each week using the
weekly or most recent
value; and maintaining
the monthly rolling
average below the
limit established in
the performance test.
10. During periods of startup, Any control device, if The inlet velocity Meeting the
shutdown, or hot standby. elected. limit to the primary requirements in Sec.
internal cyclones of 63.1564(c)(5).
the catalytic cracking
unit catalyst
regenerator in Sec.
63.1564(a)(5)(ii).
----------------------------------------------------------------------------------------------------------------
\1\ If applicable, you can use the alternative in Sec. 63.1573(a)(1) for gas flow rate instead of a continuous
parameter monitoring system if you used the alternative method in the initial performance test.
\2\ The equilibrium catalyst Ni concentration must be measured by the procedure, Determination of Metal
Concentration on Catalyst Particles (Instrumental Analyzer Procedure) in appendix A to this subpart; or by EPA
Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled
Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, or EPA Method 7521,
Nickel Atomic Absorption, Direct Aspiration; or by an alternative to EPA Method 6010B, 6020, 7520, or 7521
satisfactory to the Administrator. The EPA Methods 6010B, 6020, 7520, and 7521 are included in ``Test Methods
for Evaluating Solid Waste, Physical/Chemical Methods,'' EPA Publication SW-846, Revision 5 (April 1998). The
SW-846 and Updates (document number 955-001-00000-1) are available for purchase from the Superintendent of
Documents, U.S. Government Publishing Office, Washington, DC 20402, (202) 512-1800; and from the National
Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487-4650. Copies may
be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334,
1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street
NW., Suite 700, Washington, DC. These methods are also available at https://www.epa.gov/epaoswer/hazwaste/test/main.htm.

0
59. Table 8 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1565(a)(1), you shall meet each emission
limitation in the following table that applies to you.

Table 8 to Subpart UUU of Part 63--Organic HAP Emission Limits for
Catalytic Cracking Units
------------------------------------------------------------------------
You shall meet the following
For each new and existing catalytic emission limit for each
cracking unit . . . catalyst regenerator vent . .
.
------------------------------------------------------------------------
1. Subject to the NSPS for carbon CO emissions from the catalyst
monoxide (CO) in 40 CFR 60.103 or regenerator vent or CO boiler
60.102a(b)(4). serving the catalytic cracking
unit must not exceed 500 parts
per million volume (ppmv) (dry
basis).
2. Not subject to the NSPS for CO in 40 a. CO emissions from the
CFR 60.103 or 60.102a(b)(4). catalyst regenerator vent or
CO boiler serving the
catalytic cracking unit must
not exceed 500 ppmv (dry
basis).
b. If you use a flare to meet
the CO limit, then on and
after January 30, 2019, the
flare must meet the
requirements of Sec. 63.670.
Prior to January 30, 2019, the
flare must meet the
requirements for control
devices in Sec. 63.11(b) and
visible emissions must not
exceed a total of 5 minutes
during any 2 consecutive
hours, or the flare must meet
the requirements of Sec.
63.670.
------------------------------------------------------------------------

0
60. Table 9 to subpart UUU of part 63 is revised to read as follows:

As stated in Sec. 63.1565(a)(2), you shall meet each operating
limit in the following table that applies to you.

[[Page 75300]]

Table 9 to Subpart UUU of Part 63--Operating Limits for Organic HAP Emissions From Catalytic Cracking Units
----------------------------------------------------------------------------------------------------------------
For this type of
For each new or existing catalytic continuous monitoring For this type of You shall meet this
cracking unit . . . system . . . control device . . . operating limit . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to the NSPS for carbon Continuous emission Not applicable......... Not applicable.
monoxide (CO) in 40 CFR 60.103 or monitoring system.
60.102a(b)(4).
2. Not subject to the NSPS for CO in a. Continuous emission Not applicable......... Not applicable.
40 CFR 60.103 or 60.102a(b)(4). monitoring system.
b. Continuous parameter i. Thermal incinerator. Maintain the daily
monitoring systems. average combustion
zone temperature above
the limit established
during the performance
test; and maintain the
daily average oxygen
concentration in the
vent stream (percent,
dry basis) above the
limit established
during the performance
test.
ii. Boiler or process Maintain the daily
heater with a design average combustion
heat input capacity zone temperature above
under 44 MW or a the limit established
boiler or process in the performance
heater in which all test.
vent streams are not
introduced into the
flame zone.
iii. Flare............. On and after January
30, 2019, the flare
must meet the
requirements of Sec.
63.670. Prior to
January 30, 2019, the
flare pilot light must
be present at all
times and the flare
must be operating at
all times that
emissions may be
vented to it, or the
flare must meet the
requirements of Sec.
63.670.
3. During periods of startup, Any.................... Any.................... Meet the requirements
shutdown or hot standby. in Sec.
63.1565(a)(5).
----------------------------------------------------------------------------------------------------------------

0
61. Table 10 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1565(b)(1), you shall meet each requirement
in the following table that applies to you.

Table 10 to Subpart UUU of Part 63--Continuous Monitoring Systems for
Organic HAP Emissions From Catalytic Cracking Units
------------------------------------------------------------------------
You shall install,
And you use this operate, and
For each new or existing type of control maintain this type
catalytic cracking unit . . . device for your of continuous
vent . . . monitoring system
. . .
------------------------------------------------------------------------
1. Subject to the NSPS for Not applicable.... Continuous
carbon monoxide (CO) in 40 CFR emission
60.103 or 60.102a(b)(4). monitoring system
to measure and
record the
concentration by
volume (dry
basis) of CO
emissions from
each catalyst
regenerator vent.
2. Not subject to the NSPS for a. Thermal Continuous
CO in 40 CFR 60.103 or incinerator. emission
60.102a(b)(4). monitoring system
to measure and
record the
concentration by
volume (dry
basis) of CO
emissions from
each catalyst
regenerator vent;
or continuous
parameter
monitoring
systems to
measure and
record the
combustion zone
temperature and
oxygen content
(percent, dry
basis) in the
incinerator vent
stream.
b. Process heater Continuous
or boiler with a emission
design heat input monitoring system
capacity under 44 to measure and
MW or process record the
heater or boiler concentration by
in which all vent volume (dry
streams are not basis) of CO
introduced into emissions from
the flame zone. each catalyst
regenerator vent;
or continuous
parameter
monitoring
systems to
measure and
record the
combustion zone
temperature.

[[Page 75301]]

c. Flare.......... On and after
January 30, 2019,
the monitoring
systems required
in Sec. Sec.
63.670 and
63.671. Prior to
January 30, 2019,
monitoring device
such as a
thermocouple, an
ultraviolet beam
sensor, or
infrared sensor
to continuously
detect the
presence of a
pilot flame, or
the monitoring
systems required
in Sec. Sec.
63.670 and
63.671.
d. No control Continuous
device. emission
monitoring system
to measure and
record the
concentration by
volume (dry
basis) of CO
emissions from
each catalyst
regenerator vent.
3. During periods of startup, Any............... Continuous
shutdown or hot standby parameter
electing to comply with the monitoring system
operating limit in Sec. to measure and
63.1565(a)(5)(ii). record the
concentration by
volume (dry
basis) of oxygen
from each
catalyst
regenerator vent.
------------------------------------------------------------------------

0
62. Table 11 to subpart UUU of part 63 is amended by revising the entry
for item 3 to read as follows:
* * * * *

Table 11 to Subpart UUU of Part 63--Requirements for Performance Tests for Organic HAP Emissions From Catalytic
Cracking Units Not Subject to New Source Performance Standard (NSPS) for Carbon Monoxide (CO)
----------------------------------------------------------------------------------------------------------------
According to these
For . . . You must . . . Using . . . requirements . . .
----------------------------------------------------------------------------------------------------------------

* * * * * *
3. Each catalytic cracking unit a. Measure the CO Method 10, 10A, or 10B .......................
catalyst regenerator vent if you use concentration (dry in appendix A-4 to
continuous parameter monitoring basis) of emissions part 60 of this
systems. exiting the control chapter, as applicable.
device.
b. Establish each Data from the .......................
operating limit in continuous parameter
Table 9 of this monitoring systems.
subpart that applies
to you.
c. Thermal incinerator Data from the Collect temperature
combustion zone continuous parameter monitoring data every
temperature. monitoring systems. 15 minutes during the
entire period of the
CO initial performance
test; and determine
and record the minimum
hourly average
combustion zone
temperature from all
the readings.
d. Thermal incinerator: Data from the Collect oxygen
oxygen, content continuous parameter concentration
(percent, dry basis) monitoring systems. (percent, dry basis)
in the incinerator monitoring data every
vent stream. 15 minutes during the
entire period of the
CO initial performance
test; and determine
and record the minimum
hourly average percent
excess oxygen
concentration from all
the readings.
e. If you use a process Data from the Collect the temperature
heater or boiler with continuous parameter monitoring data every
a design heat input monitoring systems. 15 minutes during the
capacity under 44 MW entire period of the
or process heater or CO initial performance
boiler in which all test; and determine
vent streams are not and record the minimum
introduced into the hourly average
flame zone, establish combustion zone
operating limit for temperature from all
combustion zone the readings.
temperature.

[[Page 75302]]

f. If you use a flare, Method 22 (40 CFR part On and after January
conduct visible 60, appendix A-7). 30, 2019, meet the
emission observations. requirements of Sec.
63.670. Prior to
January 30, 2019,
maintain a 2-hour
observation period;
and record the
presence of a flame at
the pilot light over
the full period of the
test or meet the
requirements of Sec.
63.670.
g. If you use a flare, 40 CFR 63.11(b)(6) On and after January
determine that the through (8). 30, 2019, the flare
flare meets the must meet the
requirements for net requirements of Sec.
heating value of the 63.670. Prior to
gas being combusted January 30, 2019, the
and exit velocity. flare must meet the
control device
requirements in Sec.
63.11(b) or the
requirements of Sec.
63.670.
----------------------------------------------------------------------------------------------------------------

0
63. Table 12 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1565(b)(4), you shall meet each requirement
in the following table that applies to you.

Table 12 to Subpart UUU of Part 63--Initial Compliance With Organic HAP
Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
For the following
For each new and existing emission limit . You have demonstrated
catalytic cracking unit . . . . . initial compliance if
. . .
------------------------------------------------------------------------
1. Subject to the NSPS for CO emissions from You have already
carbon monoxide (CO) in 40 your catalyst conducted a
CFR 60.103, 60.100(e), or regenerator vent performance test to
60.102a(b)(4). or CO boiler demonstrate initial
serving the compliance with the
catalytic NSPS and the
cracking unit measured CO
must not exceed emissions are less
500 ppmv (dry than or equal to 500
basis). ppm (dry basis). As
part of the
Notification of
Compliance Status,
you must certify
that your vent meets
the CO limit. You
are not required to
conduct another
performance test to
demonstrate initial
compliance. You have
already conducted a
performance
evaluation to
demonstrate initial
compliance with the
applicable
performance
specification. As
part of your
Notification of
Compliance Status,
you must certify
that your continuous
emission monitoring
system meets the
applicable
requirements in Sec.
63.1572. You are
not required to
conduct another
performance
evaluation to
demonstrate initial
compliance.
2. Not subject to the NSPS for a. CO emissions i. If you use a
CO in 40 CFR 60.103 from your continuous parameter
60.102a(b)(4). catalyst monitoring system,
regenerator vent the average CO
or CO boiler emissions measured
serving the by Method 10 over
catalytic the period of the
cracking unit initial performance
must not exceed test are less than
500 ppmv (dry or equal to 500 ppmv
basis). (dry basis).
ii. If you use a
continuous emission
monitoring system,
the hourly average
CO emissions over
the 24-hour period
for the initial
performance test are
not more than 500
ppmv (dry basis);
and your performance
evaluation shows
your continuous
emission monitoring
system meets the
applicable
requirements in Sec.
63.1572.
b. If you use a On and after January
flare, visible 30, 2019, the flare
emissions must meets the
not exceed a requirements of Sec.
total of 5 63.670. Prior to
minutes during January 30, 2019,
any 2 operating visible emissions,
hours. measured by Method
22 during the 2-hour
observation period
during the initial
performance test,
are no higher than 5
minutes, or the
flare meets the
requirements of Sec.
63.670.
------------------------------------------------------------------------

0
64. Table 13 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1565(c)(1), you shall meet each requirement
in the following table that applies to you.

[[Page 75303]]

Table 13 to Subpart UUU of Part 63--Continuous Compliance With Organic HAP Emission Limits for Catalytic
Cracking Units
----------------------------------------------------------------------------------------------------------------
Subject to this
For each new and existing catalytic emission limit for your You shall demonstrate
cracking unit . . . catalyst regenerator If you must . . . continuous compliance
vent . . . by . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to the NSPS for carbon CO emissions from your Continuous emission Collecting the hourly
monoxide (CO) in 40 CFR 60.103, catalyst regenerator monitoring system. average CO monitoring
60.100(e), or 60.102a(b)(4). vent or CO boiler data according to Sec.
serving the catalytic 63.1572; and
cracking unit must not maintaining the hourly
exceed 500 ppmv (dry average CO
basis). concentration at or
below 500 ppmv (dry
basis).
2. Not subject to the NSPS for CO in a. CO emissions from Continuous emission Same as item 1.
40 CFR 60.103 or 60.102a(b)(4). your catalyst monitoring system.
regenerator vent or CO
boiler serving the
catalytic cracking
unit must not exceed
500 ppmv (dry basis).
b. CO emissions from Continuous parameter Maintaining the hourly
your catalyst monitoring system. average CO
regenerator vent or CO concentration below
boiler serving the 500 ppmv (dry basis).
catalytic cracking
unit must not exceed
500 ppmv (dry basis).
c. Visible emissions Control device-flare... On and after January
from a flare must not 30, 2019, meeting the
exceed a total of 5 requirements of Sec.
minutes during any 2- 63.670. Prior to
hour period. January 30, 2019,
maintaining visible
emissions below a
total of 5 minutes
during any 2-hour
operating period, or
meeting the
requirements of Sec.
63.670.
----------------------------------------------------------------------------------------------------------------

0
65. Table 14 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1565(c)(1), you shall meet each requirement
in the following table that applies to you.

Table 14 to Subpart UUU of Part 63--Continuous Compliance With Operating Limits for Organic HAP Emissions From
Catalytic Cracking Units
----------------------------------------------------------------------------------------------------------------
You shall demonstrate
For each new existing catalytic If you use . . . For this operating continuous compliance
cracking unit . . . limit . . . by . . .
----------------------------------------------------------------------------------------------------------------
1. Subject to NSPS for carbon Continuous emission Not applicable......... Complying with Table 13
monoxide (CO) in 40 CFR 60.103, monitoring system. of this subpart, item
60.100(e), 60.102a(b)(4). 1.
2. Not subject to the NSPS for CO in a. Continuous emission Not applicable......... Complying with Table 13
40 CFR 60.103 or 60.102a(b)(4). monitoring system. of this subpart, item
2.a.
b. Continuous parameter i. The daily average Collecting the hourly
monitoring systems-- combustion zone and daily average
thermal incinerator. temperature must not temperature monitoring
fall below the level data according to Sec.
established during the 63.1572; and
performance test. maintaining the daily
average combustion
zone temperature above
the limit established
during the performance
test.
ii. The daily average Collecting the hourly
oxygen concentration and daily average
in the vent stream oxygen concentration
(percent, dry basis) monitoring data
must not fall below according to Sec.
the level established 63.1572; and
during the performance maintaining the daily
test. average oxygen
concentration above
the limit established
during the performance
test.
c. Continuous parameter The daily combustion Collecting the average
monitoring systems-- zone temperature must hourly and daily
boiler or process not fall below the temperature monitoring
heater with a design level established in data according to Sec.
heat input capacity the performance test. 63.1572; and
under 44 MW or boiler maintaining the daily
or process heater in average combustion
which all vent streams zone temperature above
are not introduced the limit established
into the flame zone. during the performance
test.

[[Page 75304]]

d. Continuous parameter The flare pilot light On and after January
monitoring system-- must be present at all 30, 2019, meeting the
flare. times and the flare requirements of Sec.
must be operating at 63.670. Prior to
all times that January 30, 2019,
emissions may be collecting the flare
vented to it. monitoring data
according to Sec.
63.1572 and recording
for each 1-hour period
whether the monitor
was continuously
operating and the
pilot light was
continuously present
during each 1-hour
period, or meeting the
requirements of Sec.
63.670.
3. During periods of startup, Any control device..... The oxygen Collecting the hourly
shutdown or hot standby electing to concentration limit in average oxygen
comply with the operating limit in Sec. concentration
Sec. 63.1565(a)(5)(ii). 63.1565(a)(5)(ii). monitoring data
according to Sec.
63.1572 and
maintaining the hourly
average oxygen
concentration at or
above 1 volume percent
(dry basis).
----------------------------------------------------------------------------------------------------------------

0
66. Table 15 to subpart UUU of part 63 is amended by revising the entry
for item 1 to read as follows:
* * * * *

Table 15 to Subpart UUU of Part 63--Organic HAP Emission Limits for
Catalytic Reforming Units
------------------------------------------------------------------------
You shall meet this
emission limit
during initial
For each applicable process vent for a new or catalyst
existing catalytic reforming unit . . . depressuring and
catalyst purging
operations . . .
------------------------------------------------------------------------
1. Option 1....................................... On and after January
30, 2019, vent
emissions to a
flare that meets
the requirements of
Sec. 63.670.
Prior to January
30, 2019, vent
emissions to a
flare that meets
the requirements
for control devices
in Sec. 63.11(b)
and visible
emissions from a
flare must not
exceed a total of 5
minutes during any
2-hour operating
period, or vent
emissions to a
flare that meets
the requirements of
Sec. 63.670.

* * * * * * *
------------------------------------------------------------------------

0
67. Table 16 to subpart UUU of part 63 is amended by revising the entry
for item 1 to read as follows:
* * * * *

Table 16 to Subpart UUU of Part 63--Operating Limits for Organic HAP
Emissions From Catalytic Reforming Units
------------------------------------------------------------------------
You shall meet this
operating limit
For each new or existing For this type of during initial
catalytic reforming unit . . . control device . catalyst depressuring
. . and purging
operations. . .
------------------------------------------------------------------------
1. Option 1: Vent to flare.... Flare............ On and after January
30, 2019, the flare
must meet the
requirements of Sec.
63.670. Prior to
January 30, 2019,
the flare pilot
light must be
present at all times
and the flare must
be operating at all
times that emissions
may be vented to it,
or the flare must
meet the
requirements of Sec.
63.670.

* * * * * * *
------------------------------------------------------------------------

0
68. Table 17 to subpart UUU of part 63 is amended by revising the entry
for item 1 to read as follows:
* * * * *

[[Page 75305]]

Table 17 to Subpart UUU of Part 63--Continuous Monitoring Systems for
Organic HAP Emissions From Catalytic Reforming Units
------------------------------------------------------------------------
You shall install and
For each applicable process If you use this operate this type of
vent for a new or existing type of control continuous monitoring
catalytic reforming unit . . device . . . system . . .
.
------------------------------------------------------------------------
1. Option 1: Vent to a flare.. Flare............ On and after January
30, 2019, the
monitoring systems
required in Sec.
Sec. 63.670 and
63.671. Prior to
January 30, 2019,
monitoring device
such as a
thermocouple, an
ultraviolet beam
sensor, or infrared
sensor to
continuously detect
the presence of a
pilot flame, or the
monitoring systems
required in Sec.
Sec. 63.670 and
63.671.

* * * * * * *
------------------------------------------------------------------------

0
69. Table 18 to subpart UUU of part 63 is amended by revising the
column headings and the entry for item 1 to read as follows:
* * * * *

Table 18 to Subpart UUU of Part 63--Requirements for Performance Tests for Organic HAP Emissions From Catalytic
Reforming Units
----------------------------------------------------------------------------------------------------------------
For each new or existing catalytic According to these
reforming unit . . . You must . . . Using . . . requirements . . .
----------------------------------------------------------------------------------------------------------------
1. Option 1: Vent to a flare......... a. Conduct visible Method 22 (40 CFR part On and after January
emission observations. 60, appendix A-7). 30, 2019, the flare
must meet the
requirements of Sec.
63.670. Prior to
January 30, 2019, 2-
hour observation
period. Record the
presence of a flame at
the pilot light over
the full period of the
test, or the
requirements of Sec.
63.670.
b. Determine that the 40 CFR 63.11(b)(6) On and after January
flare meets the through (8). 30, 2019, the flare
requirements for net must meet the
heating value of the requirements of Sec.
gas being combusted 63.670. Prior to
and exit velocity. January 30, 2019, the
flare must meet the
control device
requirements in Sec.
63.11(b) or the
requirements of Sec.
63.670.

* * * * * * *
----------------------------------------------------------------------------------------------------------------

0
70. Table 19 to subpart UUU of part 63 is amended by revising the entry
for item 1 to read as follows:
* * * * *

Table 19 to Subpart UUU of Part 63--Initial Compliance With Organic HAP
Emission Limits for Catalytic Reforming Units
------------------------------------------------------------------------
For each applicable process
vent for a new or existing For the following You have
catalytic reforming unit . . emission limit . . . demonstrated initial
. compliance if . . .
------------------------------------------------------------------------
Option 1.................... Visible emissions On and after January
from a flare must 30, 2019, the flare
not exceed a total meets the
of 5 minutes during requirements of
any 2 consecutive Sec. 63.670.
hours. Prior to January
30, 2019, visible
emissions, measured
using Method 22
over the 2-hour
observation period
of the performance
test, do not exceed
a total of 5
minutes, or the
flare meets the
requirements of
Sec. 63.670.

* * * * * * *
------------------------------------------------------------------------

0
71. Table 20 to subpart UUU of part 63 is amended by revising the entry
for item 1 to read as follows:
* * * * *

[[Page 75306]]

Table 20 to Subpart UUU of Part 63--Continuous Compliance With Organic
HAP Emission Limits for Catalytic Reforming Units
------------------------------------------------------------------------
You shall
demonstrate
For each applicable process continuous
vent for a new or existing For this emission compliance during
catalytic reforming unit . . limit . . . initial catalyst
. depressuring and
catalyst purging
operations by . . .
------------------------------------------------------------------------
1. Option 1................. Vent emissions from On and after January
your process vent 30, 2019, meeting
to a flare. the requirements of
Sec. 63.670.
Prior to January
30, 2019,
maintaining visible
emissions from a
flare below a total
of 5 minutes during
any 2 consecutive
hours, or meeting
the requirements of
Sec. 63.670.

* * * * * * *
------------------------------------------------------------------------

0
72. Table 21 to subpart UUU of part 63 is amended by revising the entry
for item 1 to read as follows:
* * * * *

Table 21 to Subpart UUU of Part 63--Continuous Compliance With Operating Limits for Organic HAP Emissions From
Catalytic Reforming Units
----------------------------------------------------------------------------------------------------------------
You shall demonstrate
continuous compliance
For each applicable process vent for For this operating during initial catalyst
a new or existing catalytic reforming If you use . . . limit . . . depressuring and
unit . . . purging operations by
. . .
----------------------------------------------------------------------------------------------------------------
1. Option 1.......................... Flare.................. The flare pilot light On and after January
must be present at all 30, 2019, meeting the
times and the flare requirements of Sec.
must be operating at 63.670. Prior to
all times that January 30, 2019,
emissions may be collecting flare
vented to it. monitoring data
according to Sec.
63.1572 and recording
for each 1-hour period
whether the monitor
was continuously
operating and the
pilot light was
continuously present
during each 1-hour
period, or meeting the
requirements of Sec.
63.670.

* * * * * * *
----------------------------------------------------------------------------------------------------------------

0
73. Table 22 to subpart UUU of part 63 is amended by revising the
entries for items 2 and 3 to read as follows:
* * * * *

Table 22 to Subpart UUU of Part 63--Inorganic HAP Emission Limits for
Catalytic Reforming Units
------------------------------------------------------------------------
You shall meet this emission
limit for each applicable
catalytic reforming unit
For . . . process vent during coke burn-
off and catalyst rejuvenation
. . .
------------------------------------------------------------------------

* * * * * * *
2. Each existing cyclic or continuous Reduce uncontrolled emissions
catalytic reforming unit. of HCl by 97 percent by weight
or to a concentration of 10
ppmv (dry basis), corrected to
3 percent oxygen.
3. Each new semi-regenerative, cyclic, Reduce uncontrolled emissions
or continuous catalytic reforming unit. of HCl by 97 percent by weight
or to a concentration of 10
ppmv (dry basis), corrected to
3 percent oxygen.
------------------------------------------------------------------------

0
74. Table 24 to subpart UUU of part 63 is amended by revising the
entries for items 2 through 4 and footnote 2 to read as follows:
* * * * *

[[Page 75307]]

Table 24 to Subpart UUU of Part 63--Continuous Monitoring Systems for
Inorganic HAP Emissions From Catalytic Reforming Units
------------------------------------------------------------------------
You shall install and operate
If you use this type of control device this type of continuous
for your vent . . . monitoring system . . .
------------------------------------------------------------------------

* * * * * * *
2. Internal scrubbing system or no Colormetric tube sampling
control device (e.g., hot regen system to measure the HCl
system) to meet HCl outlet concentration in the catalyst
concentration limit. regenerator exhaust gas during
coke burn-off and catalyst
rejuvenation. The colormetric
tube sampling system must meet
the requirements in Table 41
of this subpart.
3. Internal scrubbing system to meet Continuous parameter monitoring
HCl percent reduction standard. system to measure and record
the gas flow rate entering or
exiting the internal scrubbing
system during coke burn-off
and catalyst rejuvenation; and
continuous parameter
monitoring system to measure
and record the total water (or
scrubbing liquid) flow rate
entering the internal
scrubbing system during coke
burn-off and catalyst
rejuvenation; and continuous
parameter monitoring system to
measure and record the pH or
alkalinity of the water (or
scrubbing liquid) exiting the
internal scrubbing system
during coke burn-off and
catalyst rejuvenation.\2\
4. Fixed-bed gas-solid adsorption Continuous parameter monitoring
system. system to measure and record
the temperature of the gas
entering or exiting the
adsorption system during coke
burn-off and catalyst
rejuvenation; and colormetric
tube sampling system to
measure the gaseous HCl
concentration in the
adsorption system exhaust and
at a point within the
absorbent bed not to exceed 90
percent of the total length of
the absorbent bed during coke
burn-off and catalyst
rejuvenation. The colormetric
tube sampling system must meet
the requirements in Table 41
of this subpart.

* * * * * * *
------------------------------------------------------------------------
* * * * * * *
\2\ If applicable, you can use the alternative in Sec. 63.1573(c)(1)
instead of a continuous parameter monitoring system for pH of the
water (or scrubbing liquid) or the alternative in Sec. 63.1573(c)(2)
instead of a continuous parameter monitoring system for alkalinity of
the water (or scrubbing liquid).

* * * * *
0
75. Table 25 to subpart UUU of part 63 is amended by revising the
entries for items 2.a and 4.a and footnote 1 to read as follows:
* * * * *

Table 25 to Subpart UUU of Part 63--Requirements for Performance Tests for Inorganic HAP Emissions From
Catalytic Reforming Units
----------------------------------------------------------------------------------------------------------------
For each new and existing catalytic According to these
reforming unit using . . . You shall . . . Using . . . requirements . . .
----------------------------------------------------------------------------------------------------------------

* * * * * * *
2. Wet scrubber...................... a. Establish operating i. Data from continuous Measure and record the
limit for pH level or parameter monitoring pH or alkalinity of
alkalinity. systems. the water (or
scrubbing liquid)
exiting scrubber every
15 minutes during the
entire period of the
performance test.
Determine and record
the minimum hourly
average pH or
alkalinity level from
the recorded values.
ii. Alternative pH Measure and record the
procedure in Sec. pH of the water (or
63.1573(b)(1). scrubbing liquid)
exiting the scrubber
during coke burn-off
and catalyst
rejuvenation using pH
strips at least three
times during each test
run. Determine and
record the average pH
level for each test
run. Determine and
record the minimum
test run average pH
level.

[[Page 75308]]

iii. Alternative Measure and record the
alkalinity method in alkalinity of the
Sec. 63.1573(c)(2). water (or scrubbing
liquid) exiting the
scrubber during coke
burn-off and catalyst
rejuvenation using
discrete titration at
least three times
during each test run.
Determine and record
the average alkalinity
level for each test
run. Determine and
record the minimum
test run average
alkalinity level.

* * * * * * *
4. Internal scrubbing system meeting a. Establish operating i. Data from continuous Measure and record the
HCl percent reduction standard. limit for pH level or parameter monitoring pH alkalinity of the
alkalinity. system. water (or scrubbing
liquid) exiting the
internal scrubbing
system every 15
minutes during the
entire period of the
performance test.
Determine and record
the minimum hourly
average pH or
alkalinity level from
the recorded values.
ii. Alternative pH Measure and in record
method in Sec. pH of the water (or
63.1573(c)(1). scrubbing liquid)
exiting the internal
scrubbing system
during coke burn-off
and catalyst
rejuvenation using pH
strips at least three
times during each test
run. Determine and
record the average pH
level for each test
run. Determine and
record the minimum
test run average pH
level.
iii. Alternative Measure and record the
alkalinity method in alkalinity water (or
Sec. 63.1573(c)(2). scrubbing liquid)
exiting the internal
scrubbing system
during coke burn-off
and catalyst
rejuvenation using
discrete titration at
least three times
during each test run.
Determine and record
the average alkalinity
level for each test
run. Determine and
record the minimum
test run average
alkalinity level.

* * * * * * *
----------------------------------------------------------------------------------------------------------------
\1\ The EPA Methods 5050, 9056, 9212 and 9253 are included in ``Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' EPA Publication SW-846, Revision 5 (April 1998). The SW-846 and Updates (document
number 955-001-00000-1) are available for purchase from the Superintendent of Documents, U.S. Government
Printing Office, Washington, DC 20402, (202) 512-1800; and from the National Technical Information Services
(NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487-4650. Copies may be inspected at the EPA Docket
Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW.,
Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington,
DC. These methods are also available at https://www.epa.gov/epaoswer/hazwaste/test/main.htm.

0
76. Table 28 to subpart UUU of part 63 is amended by revising the entry
for item 5 and footnotes 1 and 3 to read as follows:
* * * * *

Table 28 to Subpart UUU of Part 63--Continuous Compliance With Operating
Limits for Inorganic HAP Emissions From Catalytic Reforming Units
------------------------------------------------------------------------
You shall
demonstrate
For each new and existing continuous
catalytic reforming unit For this operating compliance during
using this type of control limit . . . coke burn-off and
device or system . . . catalyst
rejuvenation by . .
.
------------------------------------------------------------------------

[[Page 75309]]

* * * * * * *
5. Moving-bed gas-solid a. The daily average Collecting the
adsorption system (e.g., temperature of the hourly and daily
ChlorsorbTM System). gas entering or average temperature
exiting the monitoring data
adsorption system according to Sec.
must not exceed the 63.1572; and
limit established maintaining the
during the daily average
performance test. temperature below
the operating limit
established during
the performance
test.
b. The weekly Collecting samples
average chloride of the sorbent
level on the exiting the
sorbent entering adsorption system
the adsorption three times per
system must not week (on non-
exceed the design consecutive days);
or manufacturer's and analyzing the
recommended limit samples for total
(1.35 weight chloride\3\; and
percent for the determining and
Chlorsorb\TM\ recording the
System). weekly average
chloride
concentration; and
maintaining the
chloride
concentration below
the design or
manufacturer's
recommended limit
(1.35 weight
percent for the
Chlorsorb\TM\
System).
c. The weekly Collecting samples
average chloride of the sorbent
level on the exiting the
sorbent exiting the adsorption system
adsorption system three times per
must not exceed the week (on non-
design or consecutive days);
manufacturer's and analyzing the
recommended limit samples for total
(1.8 weight percent chloride
for the concentration; and
Chlorsorb\TM\ determining and
System). recording the
weekly average
chloride
concentration; and
maintaining the
chloride
concentration below
the design or
manufacturer's
recommended limit
(1.8 weight percent
Chlorsorb\TM\
System).
------------------------------------------------------------------------
\1\ If applicable, you can use either alternative in Sec. 63.1573(c)
instead of a continuous parameter monitoring system for pH or
alkalinity if you used the alternative method in the initial
performance test.
* * * * * * *
\3\ The total chloride concentration of the sorbent material must be
measured by the procedure, ``Determination of Metal Concentration on
Catalyst Particles (Instrumental Analyzer Procedure)'' in appendix A
to this subpart; or by using EPA Method 5050, Bomb Preparation Method
for Solid Waste, combined either with EPA Method 9056, Determination
of Inorganic Anions by Ion Chromatography, or with EPA Method 9253,
Chloride (Titrimetric, Silver Nitrate); or by using EPA Method 9212,
Potentiometric Determination of Chloride in Aqueous Samples with Ion-
Selective Electrode, and using the soil extraction procedures listed
within the method. The EPA Methods 5050, 9056, 9212 and 9253 are
included in ``Test Methods for Evaluating Solid Waste, Physical/
Chemical Methods,'' EPA Publication SW-846, Revision 5 (April 1998).
The SW-846 and Updates (document number 955-001-00000-1) are available
for purchase from the Superintendent of Documents, U.S. Government
Printing Office, Washington, DC 20402, (202) 512-1800; and from the
National Technical Information Services (NTIS), 5285 Port Royal Road,
Springfield, VA 22161, (703) 487-4650. Copies may be inspected at the
EPA Docket Center, William Jefferson Clinton (WJC) West Building, (Air
Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at
the Office of the Federal Register, 800 North Capitol Street NW.,
Suite 700, Washington, DC. These methods are also available at https://www.epa.gov/epaoswer/hazwaste/test/main.htm.

0
77. Table 29 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1568(a)(1), you shall meet each emission
limitation in the following table that applies to you.

Table 29 to Subpart UUU of Part 63--HAP Emission Limits for Sulfur
Recovery Units
------------------------------------------------------------------------
You shall meet this emission
For . . . limit for each process vent . .
.
------------------------------------------------------------------------
1. Subject to NSPS. Each new or a. 250 ppmv (dry basis) of
existing Claus sulfur recovery unit sulfur dioxide (SO2) at zero
part of a sulfur recovery plant with percent excess air, or
design capacity greater than 20 long concentration determined using
tons per day (LTD) and subject to the Equation 1 of 40 CFR
NSPS for sulfur oxides in 40 CFR 60.102a(f)(1)(i), if you use
60.104(a)(2) or 60.102a(f)(1). an oxidation control system or
if you use a reduction control
system followed by
incineration.
b. 300 ppmv of reduced sulfur
compounds calculated as ppmv
SO2 (dry basis) at zero
percent excess air, or
concentration determined using
Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use a
reduction control system
without incineration.
2. Option 1: Elect NSPS. Each new or a. 250 ppmv (dry basis) of SO2
existing sulfur recovery unit (Claus at zero percent excess air, or
or other type, regardless of size) not concentration determined using
subject to the NSPS for sulfur oxides Equation 1 of 40 CFR
in 40 CFR 60.104(a)(2) or 60.102a(f)(1)(i), if you use
60.102a(f)(1). an oxidation control system or
if you use a reduction control
system followed by
incineration.
b. 300 ppmv of reduced sulfur
compounds calculated as ppmv
SO2 (dry basis) at zero
percent excess air, or
concentration determined using
Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use a
reduction control system
without incineration.
3. Option 2: TRS limit. Each new or 300 ppmv of total reduced
existing sulfur recovery unit (Claus sulfur (TRS) compounds,
or other type, regardless of size) not expressed as an equivalent SO2
subject to the NSPS for sulfur oxides concentration (dry basis) at
in 40 CFR 60.104(a)(2) or zero percent oxygen.
60.102a(f)(1).
------------------------------------------------------------------------

[[Page 75310]]

0
78. Table 30 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1568(a)(2), you shall meet each operating
limit in the following table that applies to you.

Table 30 to Subpart UUU of Part 63--Operating Limits for HAP Emissions
From Sulfur Recovery Units
------------------------------------------------------------------------
You shall meet this
For . . . If use this type of operating limit . .
control device . . . .
------------------------------------------------------------------------
1. Subject to NSPS. Each new Not applicable...... Not applicable.
or existing Claus sulfur
recovery unit part of a
sulfur recovery plant with
design capacity greater
than 20 LTD and subject to
the NSPS for sulfur oxides
in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
2. Option 1: Elect NSPS. Not applicable...... Not applicable.
Each new or existing sulfur
recovery unit (Claus or
other type, regardless of
size) not subject to the
NSPS for sulfur oxides in
40 CFR 60.104(a)(2) or
60.102a(f)(1).
3. Option 2: TRS limit, if Not applicable...... Not applicable.
using continuous emissions
monitoring systems. Each
new or existing sulfur
recovery unit (Claus or
other type, regardless of
size) not subject to the
NSPS for sulfur oxides in
40 CFR 60.104(a)(2) or
60.102a(f)(1).
4. Option 2: TRS limit, if Thermal incinerator. Maintain the daily
using continuous parameter average combustion
monitoring systems. Each zone temperature
new or existing sulfur above the limit
recovery unit (Claus or established during
other type, regardless of the performance
size) not subject to the test; and maintain
NSPS for sulfur oxides in the daily average
40 CFR 60.104(a)(2) or oxygen
60.102a(f)(1). concentration in
the vent stream
(percent, dry
basis) above the
limit established
during the
performance test.
5. Startup or shutdown Flare............... On and after January
option 1: Electing to 30, 2019, meet the
comply with Sec. applicable
63.1568(a)(4)(ii). Each new requirements of
or existing sulfur recovery Sec. 63.670.
unit (Claus or other type, Prior to January
regardless of size) during 30, 2019, meet the
periods of startup or applicable
shutdown. requirements of
either Sec.
63.11(b) or Sec.
63.670.
6. Startup or shutdown Thermal incinerator Maintain the hourly
option 2: Electing to or thermal oxidizer. average combustion
comply with Sec. zone temperature at
63.1568(a)(4)(iii). Each or above 1,200
new or existing sulfur degrees Fahrenheit
recovery unit (Claus or and maintain the
other type, regardless of hourly average
size) during startup or oxygen
shutdown events. concentration in
the exhaust gas
stream at or above
2 volume percent
(dry basis).
------------------------------------------------------------------------

0
79. Table 31 to subpart UUU is revised to read as follows:
As stated in Sec. 63.1568(b)(1), you shall meet each requirement
in the following table that applies to you.

Table 31 to Subpart UUU of Part 63--Continuous Monitoring Systems for
HAP Emissions From Sulfur Recovery Units
------------------------------------------------------------------------
You shall install
and operate this
For . . . For this limit . . . continuous
monitoring system .
. .
------------------------------------------------------------------------
1. Subject to NSPS. Each new a. 250 ppmv (dry Continuous emission
or existing Claus sulfur basis) of SO2 at monitoring system
recovery unit part of a zero percent excess to measure and
sulfur recovery plant with air if you use an record the hourly
design capacity greater oxidation or average
than 20 LTD and subject to reduction control concentration of
the NSPS for sulfur oxides system followed by SO2 (dry basis) at
in 40 CFR 60.104(a)(2) or incineration. zero percent excess
60.102a(f)(1). air for each
exhaust stack. This
system must include
an oxygen monitor
for correcting the
data for excess
air.

[[Page 75311]]

b. 300 ppmv of Continuous emission
reduced sulfur monitoring system
compounds to measure and
calculated as ppmv record the hourly
SO2 (dry basis) at average
zero percent excess concentration of
air if you use a reduced sulfur and
reduction control oxygen (O2)
system without emissions.
incineration. Calculate the
reduced sulfur
emissions as SO2
(dry basis) at zero
percent excess air.
Exception: You can
use an instrument
having an air or
SO2 dilution and
oxidation system to
convert the reduced
sulfur to SO2 for
continuously
monitoring and
recording the
concentration (dry
basis) at zero
percent excess air
of the resultant
SO2 instead of the
reduced sulfur
monitor. The
monitor must
include an oxygen
monitor for
correcting the data
for excess oxygen.
c. If you use i. Complete either
Equation 1 of 40 item 1.a or item
CFR 1.b; and
60.102a(f)(1)(i) to ii. Either a
set your emission continuous emission
limit. monitoring system
to measure and
record the O2
concentration for
the inlet air/
oxygen supplied to
the system or a
continuous
parameter
monitoring system
to measure and
record the
volumetric gas flow
rate of ambient air
and purchased
oxygen-enriched
gas.
2. Option 1: Elect NSPS. a. 250 ppmv (dry Continuous emission
Each new or existing sulfur basis) of SO2 at monitoring system
recovery unit (Claus or zero percent excess to measure and
other type, regardless of air if you use an record the hourly
size) not subject to the oxidation or average
NSPS for sulfur oxides in reduction control concentration of
40 CFR 60.104(a)(2) or system followed by SO2 (dry basis), at
60.102a(f)(1). incineration. zero percent excess
air for each
exhaust stack. This
system must include
an oxygen monitor
for correcting the
data for excess
air.
b. 300 ppmv of Continuous emission
reduced sulfur monitoring system
compounds to measure and
calculated as ppmv record the hourly
SO2 (dry basis) at average
zero percent excess concentration of
air if you use a reduced sulfur and
reduction control O2 emissions for
system without each exhaust stack.
incineration. Calculate the
reduced sulfur
emissions as SO2
(dry basis), at
zero percent excess
air. Exception: You
can use an
instrument having
an air or O2
dilution and
oxidation system to
convert the reduced
sulfur to SO2 for
continuously
monitoring and
recording the
concentration (dry
basis) at zero
percent excess air
of the resultant
SO2 instead of the
reduced sulfur
monitor. The
monitor must
include an oxygen
monitor for
correcting the data
for excess oxygen.
c. If you use i. Complete either
Equation 1 of 40 item 2.a or item
CFR 2.b; and
60.102a(f)(1)(i) to ii. Either a
set your emission continuous emission
limit. monitoring system
to measure and
record the O2
concentration for
the inlet air/
oxygen supplied to
the system, or a
continuous
parameter
monitoring system
to measure and
record the
volumetric gas flow
rate of ambient air
and purchased
oxygen-enriched
gas.
3. Option 2: TRS limit. Each a. 300 ppmv of total i. Continuous
new or existing sulfur reduced sulfur emission monitoring
recovery unit (Claus or (TRS) compounds, system to measure
other type, regardless of expressed as an and record the
size) not subject to the equivalent SO2 hourly average
NSPS for sulfur oxides in concentration (dry concentration of
40 CFR 60.104(a)(2) or basis) at zero TRS for each
60.102a(f)(1). percent oxygen. exhaust stack; this
monitor must
include an oxygen
monitor for
correcting the data
for excess oxygen;
or
ii. Continuous
parameter
monitoring systems
to measure and
record the
combustion zone
temperature of each
thermal incinerator
and the oxygen
content (percent,
dry basis) in the
vent stream of the
incinerator.

[[Page 75312]]

4. Startup or shutdown Any................. On and after January
option 1: electing to 30, 2019,
comply with Sec. monitoring systems
63.1568(a)(4)(ii). Each new as specified in
or existing sulfur recovery Sec. Sec. 63.670
unit (Claus or other type, and 63.671. Prior
regardless of size) during to January 30,
periods of startup or 2019, either
shutdown. continuous
parameter
monitoring systems
following the
requirements in
Sec. 63.11 (to
detect the presence
of a flame; to
measure and record
the net heating
value of the gas
being combusted;
and to measure and
record the
volumetric flow of
the gas being
combusted) or
monitoring systems
as specified in
Sec. Sec. 63.670
and 63.671.
5. Startup or shutdown Any................. Continuous parameter
option 2: electing to monitoring systems
comply with Sec. to measure and
63.1568(a)(4)(iii). Each record the firebox
new or existing sulfur temperature of each
recovery unit (Claus or thermal incinerator
other type, regardless of or oxidizer and the
size) during periods of oxygen content
startup or shutdown. (percent, dry
basis) in the
exhaust vent from
the incinerator or
oxidizer.
------------------------------------------------------------------------

0
80. Table 32 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1568(b)(2) and (3), you shall meet each
requirement in the following table that applies to you.

Table 32 to Subpart UUU of Part 63--Requirements for Performance Tests for HAP Emissions From Sulfur Recovery
Units Not Subject to the New Source Performance Standards for Sulfur Oxides
----------------------------------------------------------------------------------------------------------------
According to these
For . . . You must . . . Using . . . requirements . . .
----------------------------------------------------------------------------------------------------------------
1. Option 1: Elect NSPS. Each new and a. Measure SO2 Data from continuous Collect SO2 monitoring
existing sulfur recovery unit. concentration (for an emission monitoring data every 15 minutes
oxidation or reduction system. for 24 consecutive
system followed by operating hours.
incineration) or Reduce the data to 1-
measure the hour averages computed
concentration of from four or more data
reduced sulfur (or SO2 points equally spaced
if you use an over each 1-hour
instrument to convert period.
the reduced sulfur to
SO2) for a reduction
control system without
incineration.
b. Measure O2 i. Data from continuous Collect O2 monitoring
concentration for the emission monitoring data every 15 minutes
inlet air/oxygen system; or for 24 consecutive
supplied to the operating hours.
system, if using Reduce the data to 1-
Equation 1 of 40 CFR hour averages computed
60.102a(f)1)(i) to set from four or more data
your emission limit. points equally spaced
You may use either an over each 1-hour
O2 CEMS method in item period; and average
1.b.i of this table or over the 24-hour
the flow monitor in period for input to
item 1.b.ii of this Equation 1 of 40 CFR
table. 60.102a(f)(1)(i).
ii. Data from flow Collect gas flow rate
monitor for ambient monitoring data every
air and purchased 15 minutes for 24
oxygen-enriched gas. consecutive operating
hours. Reduce the data
to 1-hour averages
computed from 4 or
more data points
equally spaced over
each 1-hour period;
calculate the hourly
O2 percent using
Equation 10 of 40 CFR
60.106a(a)(6)(iv); and
average over the 24-
hour period for input
to Equation 1 of 40
CFR 60.102a(f)(1)(i).
2. Option 2: TRS limit, using CEMS. Measure the Data from continuous Collect TRS data every
Each new and existing sulfur concentration of emission monitoring 15 minutes for 24
recovery unit. reduced sulfur (or SO2 system. consecutive operating
if you use an hours. Reduce the data
instrument to convert to 1-hour averages
the reduced sulfur to computed from four or
SO2). more data points
equally spaced over
each 1-hour period.

[[Page 75313]]

3. Option 2: TRS limit, if using a. Select sampling Method 1 or 1A in Sampling sites must be
continuous parameter monitoring port's location and Appendix A-1 to part located at the outlet
systems. Each new and existing the number of traverse 60 of this chapter. of the control device
sulfur recovery unit. ports. and prior to any
releases to the
atmosphere.
b. Determine velocity Method 2, 2A, 2C, 2D, .......................
and volumetric flow or 2F in appendix A-1
rate. to part 60 of this
chapter, or Method 2G
in appendix A-2 to
part 60 of this
chapter, as applicable.
c. Conduct gas Method 3, 3A, or 3B in Take the samples
molecular weight appendix A-2 to part simultaneously with
analysis; obtain the 60 of this chapter, as reduced sulfur or
oxygen concentration applicable. moisture samples.
needed to correct the
emission rate for
excess air.
d. Measure moisture Method 4 in appendix A- Make your sampling time
content of the stack 3 to part 60 of this for each Method 4
gas. chapter. sample equal to that
for 4 Method 15
samples.
e. Measure the Method 15 or 15A in If the cross-sectional
concentration of TRS. appendix A-5 to part area of the duct is
60 of this chapter, as less than 5 square
applicable. meters (m2) or 54
square feet, you must
use the centroid of
the cross section as
the sampling point. If
the cross-sectional
area is 5 m2 or more
and the centroid is
more than 1 meter (m)
from the wall, your
sampling point may be
at a point no closer
to the walls than 1 m
or 39 inches. Your
sampling rate must be
at least 3 liters per
minute or 0.10 cubic
feet per minute to
ensure minimum
residence time for the
sample inside the
sample lines.
f. Calculate the SO2 The arithmetic average .......................
equivalent for each of the SO2 equivalent
run after correcting for each sample during
for moisture and the run.
oxygen.
g. Correct the reduced Equation 1 of Sec. .......................
sulfur samples to zero 63.1568.
percent excess air.
h. Establish each Data from the .......................
operating limit in continuous parameter
Table 30 of this monitoring system.
subpart that applies
to you.
i. Measure thermal Data from the Collect temperature
incinerator: continuous parameter monitoring data every
combustion zone monitoring system. 15 minutes during the
temperature. entire period of the
performance test; and
determine and record
the minimum hourly
average temperature
from all the readings.
j. Measure thermal Data from the Collect oxygen
incinerator: oxygen continuous parameter concentration
concentration monitoring system. (percent, dry basis)
(percent, dry basis) data every 15 minutes
in the vent stream. during the entire
period of the
performance test; and
determine and record
the minimum hourly
average percent excess
oxygen concentration.
----------------------------------------------------------------------------------------------------------------

0
81. Table 33 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1568(b)(5), you shall meet each requirement
in the following table that applies to you.

[[Page 75314]]

Table 33 to Subpart UUU of Part 63--Initial Compliance With HAP Emission
Limits for Sulfur Recovery Units
------------------------------------------------------------------------
You have
For . . . For the following demonstrated initial
emission limit . . . compliance if . . .
------------------------------------------------------------------------
1. Subject to NSPS: Each new a. 250 ppmv (dry You have already
or existing Claus sulfur basis) SO2 at zero conducted a
recovery unit part of a percent excess air, performance test to
sulfur recovery plant with or concentration demonstrate initial
design capacity greater determined using compliance with the
than 20 LTD and subject to Equation 1 of 40 NSPS and each 12-
the NSPS for sulfur oxides CFR hour rolling
in 40 CFR 60.104(a)(2) or 60.102a(f)(1)(i), average
60.102a(f)(1). if you use an concentration of
oxidation or SO2 emissions
reduction control measured by the
system followed by continuous emission
incineration. monitoring system
is less than or
equal to 250 ppmv
(dry basis) at zero
percent excess air,
or the
concentration
determined using
Equation 1 of 40
CFR
60.102a(f)(1)(i).
As part of the
Notification of
Compliance Status,
you must certify
that your vent
meets the SO2
limit. You are not
required to do
another performance
test to demonstrate
initial compliance.
You have already
conducted a
performance
evaluation to
demonstrate initial
compliance with the
applicable
performance
specification. As
part of your
Notification of
Compliance Status,
you must certify
that your
continuous emission
monitoring system
meets the
applicable
requirements in
Sec. 63.1572. You
are not required to
do another
performance
evaluation to
demonstrate initial
compliance.
b. 300 ppmv of You have already
reduced sulfur conducted a
compounds performance test to
calculated as ppmv demonstrate initial
SO2 (dry basis) at compliance with the
zero percent excess NSPS and each 12-
air, or hour rolling
concentration average
determined using concentration of
Equation 1 of 40 reduced sulfur
CFR compounds measured
60.102a(f)(1)(i), by your continuous
if you use a emission monitoring
reduction control system is less than
system without or equal to 300
incineration. ppmv, calculated as
ppmv SO2 (dry
basis) at zero
percent excess air,
or the
concentration
determined using
Equation 1 of 40
CFR
60.102a(f)(1)(i).
As part of the
Notification of
Compliance Status,
you must certify
that your vent
meets the SO2
limit. You are not
required to do
another performance
test to demonstrate
initial compliance.
You have already
conducted a
performance
evaluation to
demonstrate initial
compliance with the
applicable
performance
specification. As
part of your
Notification of
Compliance Status,
you must certify
that your
continuous emission
monitoring system
meets the
applicable
requirements in
Sec. 63.1572. You
are not required to
do another
performance
evaluation to
demonstrate initial
compliance.
2. Option 1: Elect NSPS. a. 250 ppmv (dry Each 12-hour rolling
Each new or existing sulfur basis) of SO2 at average
recovery unit (Claus or zero percent excess concentration of
other type, regardless of air, or SO2 emissions
size) not subject to the concentration measured by the
NSPS for sulfur oxides in determined using continuous emission
40 CFR 60.104(a)(2) or Equation 1 of 40 monitoring system
60.102a(f)(1). CFR during the initial
60.102a(f)(1)(i), performance test is
if you use an less than or equal
oxidation or to 250 ppmv (dry
reduction control basis) at zero
system followed by percent excess air,
incineration. or the
concentration
determined using
Equation 1 of 40
CFR
60.102a(f)(1)(i);
and your
performance
evaluation shows
the monitoring
system meets the
applicable
requirements in
Sec. 63.1572.
b. 300 ppmv of Each 12-hour rolling
reduced sulfur average
compounds concentration of
calculated as ppmv reduced sulfur
SO2 (dry basis) at compounds measured
zero percent excess by the continuous
air, or emission monitoring
concentration system during the
determined using initial performance
Equation 1 of 40 test is less than
CFR or equal to 300
60.102a(f)(1)(i), ppmv, calculated as
if you use a ppmv SO2 (dry
reduction control basis) at zero
system without percent excess air,
incineration. or the
concentration
determined using
Equation 1 of 40
CFR
60.102a(f)(1)(i);
and your
performance
evaluation shows
the continuous
emission monitoring
system meets the
applicable
requirements in
Sec. 63.1572.

[[Page 75315]]

3. Option 2: TRS limit. Each 300 ppmv of TRS If you use
new or existing sulfur compounds expressed continuous
recovery unit (Claus or as an equivalent parameter
other type, regardless of SO2 concentration monitoring systems,
size) not subject to the (dry basis) at zero the average
NSPS for sulfur oxides in percent oxygen. concentration of
40 CFR 60.104(a)(2) or TRS emissions
60.102a(f)(1). measured using
Method 15 during
the initial
performance test is
less than or equal
to 300 ppmv
expressed as
equivalent SO2
concentration (dry
basis) at zero
percent oxygen. If
you use a
continuous emission
monitoring system,
each 12-hour
rolling average
concentration of
TRS emissions
measured by the
continuous emission
monitoring system
during the initial
performance test is
less than or equal
to 300 ppmv
expressed as an
equivalent SO2 (dry
basis) at zero
percent oxygen; and
your performance
evaluation shows
the continuous
emission monitoring
system meets the
applicable
requirements in
Sec. 63.1572.
------------------------------------------------------------------------

0
82. Table 34 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1568(c)(1), you shall meet each requirement
in the following table that applies to you.

Table 34 to Subpart UUU of Part 63--Continuous Compliance With HAP
Emission Limits for Sulfur Recovery Units
------------------------------------------------------------------------
You shall
For this emission demonstrate
For . . . limit . . . continuous
compliance by . . .
------------------------------------------------------------------------
1. Subject to NSPS. Each new a. 250 ppmv (dry Collecting the
or existing Claus sulfur basis) of SO2 at hourly average SO2
recovery unit part of a zero percent excess monitoring data
sulfur recovery plant with air, or (dry basis, percent
design capacity greater concentration excess air) and, if
than 20 LTD and subject to determined using using Equation 1 of
the NSPS for sulfur oxides Equation 1 of 40 40 CFR
in 40 CFR 60.104(a)(2) or CFR 60.102a(f)(1)(i),
60.102a(f)(1). 60.102a(f)(1)(i), collecting the
if you use an hourly O2
oxidation or concentration or
reduction control flow monitoring
system followed by data according to
incineration. Sec. 63.1572;
determining and
recording each 12-
hour rolling
average
concentration of
SO2; maintaining
each 12-hour
rolling average
concentration of
SO2 at or below the
applicable emission
limitation; and
reporting any 12-
hour rolling
average
concentration of
SO2 greater than
the applicable
emission limitation
in the semiannual
compliance report
required by Sec.
63.1575.
b. 300 ppmv of Collecting the
reduced sulfur hourly average
compounds reduced sulfur (and
calculated as ppmv air or O2 dilution
SO2 (dry basis) at and oxidation)
zero percent excess monitoring data
air, or and, if using
concentration Equation 1 of 40
determined using CFR
Equation 1 of 40 60.102a(f)(1)(i),
CFR collecting the
60.102a(f)(1)(i), hourly O2
if you use a concentration or
reduction control flow monitoring
system without data according to
incineration. Sec. 63.1572;
determining and
recording each 12-
hour rolling
average
concentration of
reduced sulfur;
maintaining each 12-
hour rolling
average
concentration of
reduced sulfur at
or below the
applicable emission
limitation; and
reporting any 12-
hour rolling
average
concentration of
reduced sulfur
greater than the
applicable emission
limitation in the
semiannual
compliance report
required by Sec.
63.1575.

[[Page 75316]]

2. Option 1: Elect NSPS. a. 250 ppmv (dry Collecting the
Each new or existing sulfur basis) of SO2 at hourly average SO2
recovery unit (Claus or zero percent excess data (dry basis,
other type, regardless of air, or percent excess air)
size) not subject to the concentration and, if using
NSPS for sulfur oxides in determined using Equation 1 of 40
40 CFR 60.104(a)(2) or Equation 1 of 40 CFR
60.102a(f)(1). CFR 60.102a(f)(1)(i),
60.102a(f)(1)(i), collecting the
if you use an hourly O2
oxidation or concentration or
reduction control flow monitoring
system followed by data according to
incineration. Sec. 63.1572;
determining and
recording each 12-
hour rolling
average
concentration of
SO2; maintaining
each 12-hour
rolling average
concentration of
SO2 at or below the
applicable emission
limitation; and
reporting any 12-
hour rolling
average
concentration of
SO2 greater than
the applicable
emission limitation
in the semiannual
compliance report
required by Sec.
63.1575.
b. 300 ppmv of Collecting the
reduced sulfur hourly average
compounds reduced sulfur (and
calculated as ppmv air or O2 dilution
SO2 (dry basis) at and oxidation)
zero percent excess monitoring data
air, or and, if using
concentration Equation 1 of 40
determined using CFR
Equation 1 of 40 60.102a(f)(1)(i),
CFR collecting the
60.102a(f)(1)(i), hourly O2
if you use a concentration or
reduction control flow monitoring
system without data according to
incineration. Sec. 63.1572;
determining and
recording each 12-
hour rolling
average
concentration of
reduced sulfur;
maintaining each 12-
hour rolling
average
concentration of
reduced sulfur at
or below the
applicable emission
limitation; and
reporting any 12-
hour rolling
average
concentration of
reduced sulfur
greater than the
applicable emission
limitation in the
semiannual
compliance report
required by Sec.
63.1575.
3. Option 2: TRS limit. Each 300 ppmv of TRS i. If you use
new or existing sulfur compounds, continuous
recovery unit (Claus or expressed as an SO2 parameter
other type, regardless of concentration (dry monitoring systems,
size) not subject to the basis) at zero collecting the
NSPS for sulfur oxides in percent oxygen or hourly average TRS
40 CFR 60.104(a)(2) or reduced sulfur monitoring data
60.102a(f)(1). compounds according to Sec.
calculated as ppmv 63.1572 and
SO2 (dry basis) at maintaining each 12-
zero percent excess hour average
air. concentration of
TRS at or below the
applicable emission
limitation; or
ii. If you use a
continuous emission
monitoring system,
collecting the
hourly average TRS
monitoring data
according to Sec.
63.1572,
determining and
recording each 12-
hour rolling
average
concentration of
TRS; maintaining
each 12-hour
rolling average
concentration of
TRS at or below the
applicable emission
limitation; and
reporting any 12-
hour rolling
average TRS
concentration
greater than the
applicable emission
limitation in the
semiannual
compliance report
required by Sec.
63.1575.
------------------------------------------------------------------------

0
83. Table 35 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1568(c)(1), you shall meet each requirement
in the following table that applies to you.

Table 35 to Subpart UUU of Part 63--Continuous Compliance With Operating
Limits for HAP Emissions From Sulfur Recovery Units
------------------------------------------------------------------------
You shall
For this operating demonstrate
For . . . limit . . . continuous
compliance by . . .
------------------------------------------------------------------------
1. Subject to NSPS. Each new Not applicable...... Meeting the
or existing Claus sulfur requirements of
recovery unit part of a Table 34 of this
sulfur recovery plant with subpart.
design capacity greater
than 20 LTD and subject to
the NSPS for sulfur oxides
in 40 CFR 60.104(a)(2) or
60.102a(f)(1).

[[Page 75317]]

2. Option 1: Elect NSPS. Not applicable...... Meeting the
Each new or existing sulfur requirements of
recovery unit (Claus or Table 34 of this
other type, regardless of subpart.
size) not subject to the
NSPS for sulfur oxides in
40 CFR 60.104(a)(2) or
60.102a(f)(1).
3. Option 2: TRS limit. Each a. Maintain the Collecting the
new or existing sulfur daily average hourly and daily
recovery unit (Claus or combustion zone average temperature
other type, regardless of temperature above monitoring data
size) not subject to the the level according to Sec.
NSPS for sulfur oxides in established during 63.1572; and
40 CFR 60.104(a)(2) or the performance maintaining the
60.102a(f)(1). test. daily average
combustion zone
temperature at or
above the limit
established during
the performance
test
b. The daily average Collecting the
oxygen hourly and daily
concentration in average O2
the vent stream monitoring data
(percent, dry according to Sec.
basis) must not 63.1572; and
fall below the maintaining the
level established average O2
during the concentration above
performance test.. the level
established during
the performance
test.
4. Startup or shutdown Using a flare On and after January
option 1: Electing to meeting the 30, 2019, complying
comply with Sec. requirements in with the applicable
63.1568(a)(4)(ii). Each new Sec. 63.11(b) or requirements of
or existing sulfur recovery Sec. 63.670. Sec. 63.670.
unit (Claus or other type, Prior to January
regardless of size) during 30, 2019, complying
periods of startup or with the applicable
shutdown. requirements of
either Sec.
63.11(b) or Sec.
63.670.
5. Startup or shutdown a. Minimum hourly Collecting
option 2: Electing to average temperature continuous (at
comply with Sec. of 1,200 degrees least once every 15
63.1568(a)(4)(iii). Each Fahrenheit. minutes) and hourly
new or existing sulfur average temperature
recovery unit (Claus or monitoring data
other type, regardless of according to Sec.
size) during periods of 63.1572; and
startup or shutdown. maintaining the
daily average
firebox temperature
at or above 1,200
degrees Fahrenheit.
b. Minimum hourly Collecting
average outlet continuous (at
oxygen least once every 15
concentration of 2 minutes) and hourly
volume percent (dry average O2
basis). monitoring data
according to Sec.
63.1572; and
maintaining the
average O2
concentration at or
above 2 volume
percent (dry
basis).
------------------------------------------------------------------------

0
84. Table 40 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1572(a)(1) and (b)(1), you shall meet each
requirement in the following table that applies to you.

Table 40 to Subpart UUU of Part 63--Requirements for Installation,
Operation, and Maintenance of Continuous Opacity Monitoring Systems and
Continuous Emission Monitoring Systems
------------------------------------------------------------------------
This type of continuous opacity or Must meet these requirements .
emission monitoring system . . . . .
------------------------------------------------------------------------
1. Continuous opacity monitoring system Performance specification 1 (40
CFR part 60, appendix B).
2. PM CEMS; this monitor must include The requirements in 40 CFR
an O2 monitor for correcting the data 60.105a(d).
for excess air.
3. CO continuous emission monitoring Performance specification 4 (40
system. CFR part 60, appendix B); span
value of 1,000 ppm; and
procedure 1 (40 CFR part 60,
appendix F) except relative
accuracy test audits are
required annually instead of
quarterly.
4. CO continuous emission monitoring Performance specification 4 (40
system used to demonstrate emissions CFR part 60, appendix B); and
average under 50 ppm (dry basis). span value of 100 ppm.
5. SO2 continuous emission monitoring Performance specification 2 (40
system for sulfur recovery unit with CFR part 60, appendix B); span
oxidation control system or reduction value of 500 ppm SO2, or if
control system; this monitor must using Equation 1 of 40 CFR
include an O2 monitor for correcting 60.102a(f)(1)(i), span value
the data for excess air. of two times the limit at the
highest O2 concentration; use
Methods 6 or 6C (40 CFR part
60, appendix A-4) for
certifying the SO2 monitor and
Methods 3A or 3B (40 CFR part
60, appendix A-2) for
certifying the O2 monitor; and
procedure 1 (40 CFR part 60,
appendix F) except relative
accuracy test audits are
required annually instead of
quarterly.

[[Page 75318]]

6. Reduced sulfur and O2 continuous Performance specification 5 (40
emission monitoring system for sulfur CFR part 60, appendix B),
recovery unit with reduction control except calibration drift
system not followed by incineration; specification is 2.5 percent
this monitor must include an O2 of the span value instead of 5
monitor for correcting the data for percent; span value is 450 ppm
excess air unless exempted. reduced sulfur, or if using
Equation 1 of 40 CFR
60.102a(f)(1)(i), span value
of two times the limit at the
highest O2 concentration; use
Methods 15 or 15A (40 CFR part
60, appendix A-5) for
certifying the reduced sulfur
monitor and Methods 3A or 3B
(40 CFR part 60, appendix A-2)
for certifying the O2 monitor;
if Method 3A or 3B yields O2
concentrations below 0.25
percent during the performance
evaluation, the O2
concentration can be assumed
to be zero and the O2 monitor
is not required; and procedure
1 (40 CFR part 60, appendix
F), except relative accuracy
test audits, are required
annually instead of quarterly.
7. Instrument with an air or O2 Performance specification 5 (40
dilution and oxidation system to CFR part 60, appendix B); span
convert reduced sulfur to SO2 for value of 375 ppm SO2 or if
continuously monitoring the using Equation 1 of 40 CFR
concentration of SO2 instead of 60.102a(f)(1)(i), span value
reduced sulfur monitor and O2 monitor. of two times the limit at the
highest O2 concentration; use
Methods 15 or 15A (40 CFR part
60, appendix A-5) for
certifying the reduced sulfur
monitor and 3A or 3B (40 CFR
part 60, appendix A-2) for
certifying the O2 monitor; and
procedure 1 (40 CFR part 60,
appendix F), except relative
accuracy test audits, are
required annually instead of
quarterly.
8. TRS continuous emission monitoring Performance specification 5 (40
system for sulfur recovery unit; this CFR part 60, appendix B).
monitor must include an O2 monitor for
correcting the data for excess air.
9. O2 monitor for oxygen concentration. If necessary due to
interferences, locate the
oxygen sensor prior to the
introduction of any outside
gas stream; performance
specification 3 (40 CFR part
60, appendix B; and procedure
1 (40 CFR part 60, appendix
F), except relative accuracy
test audits, are required
annually instead of quarterly.
------------------------------------------------------------------------

0
85. Table 41 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1572(c)(1), you shall meet each requirement
in the following table that applies to you.

Table 41 to Subpart UUU of Part 63--Requirements for Installation,
Operation, and Maintenance of Continuous Parameter Monitoring Systems
------------------------------------------------------------------------
If you use . . . You shall . . .
------------------------------------------------------------------------
1. pH strips............... Use pH strips with an accuracy of 10 percent.
2. pH meter................ Locate the pH sensor in a position that
provides a representative measurement of
pH; ensure the sample is properly mixed
and representative of the fluid to be
measured.
Use a pH sensor with an accuracy of at
least 0.2 pH units.
Check the pH meter's calibration on at
least one point at least once daily; check
the pH meter's calibration on at least two
points at least once quarterly; at least
monthly, inspect all components for
integrity and all electrical components
for continuity; record the results of each
calibration check and inspection.
3. Colormetric tube Use a colormetric tube sampling system with
sampling system. a printed numerical scale in ppmv, a
standard measurement range of 1 to 10 ppmv
(or 1 to 30 ppmv if applicable), and a
standard deviation for measured values of
no more than 15 percent.
System must include a gas detection pump
and hot air probe if needed for the
measurement range.
4. CO2, O2, and CO monitors a. Locate the concentration sensor so that
for coke burn-off rate. it provides a representative measurement
of the content of the exit gas stream;
ensure the sample is properly mixed and
representative of the gas to be measured.
Use a sensor with an accuracy of at least
1 percent of the range of the
sensor or to a nominal gas concentration
of 0.5 percent, whichever is
greater.
Use a monitor that is able to measure
concentration on a dry basis or is able to
correct for moisture content and record on
a dry basis.
Conduct calibration checks at least
annually; conduct calibration checks
following any period of more than 24 hours
throughout which the sensor reading
exceeds the manufacturer's specified
maximum operating range or install a new
sensor; at least quarterly, inspect all
components for integrity and all
electrical connections for continuity;
record the results of each calibration and
inspection.
b. As an alternative, the requirements in
40 CFR 60.105a(b)(2) may be used.
5. BLD..................... Follow the requirements in 40 CFR
60.105a(c).
6. Voltage, secondary Use meters with an accuracy of at least
current, or total power 5 percent over the operating
input sensors. range.

[[Page 75319]]

Each time that the unit is not operating,
confirm that the meters read zero. Conduct
a calibration check at least annually;
conduct calibration checks following any
period of more than 24 hours throughout
which the meter reading exceeds the
manufacturer's specified maximum operating
range; at least monthly, inspect all
components of the continuous parameter
monitoring system for integrity and all
electrical connections for continuity;
record the results of each calibration
check and inspection.
7. Pressure/Pressure Locate the pressure sensor(s) in a position
drop\1\ sensors. that provides a representative measurement
of the pressure and minimizes or
eliminates pulsating pressure, vibration,
and internal and external corrosion.
Use a gauge with an accuracy of at least
5 percent over the normal
operating range or 0.12 kilopascals (0.5
inches of water column), whichever is
greater.
Review pressure sensor readings at least
once a week for straightline (unchanging)
pressure and perform corrective action to
ensure proper pressure sensor operation if
blockage is indicated; using an instrument
recommended by the sensor's manufacturer,
check gauge calibration and transducer
calibration annually; conduct calibration
checks following any period of more than
24 hours throughout which the pressure
exceeded the manufacturer's specified
maximum rated pressure or install a new
pressure sensor; at least quarterly,
inspect all components for integrity, all
electrical connections for continuity, and
all mechanical connections for leakage,
unless the CPMS has a redundant pressure
sensor; record the results of each
calibration check and inspection.
8. Air flow rate, gas flow Locate the flow sensor(s) and other
rate, or total water (or necessary equipment (such as straightening
scrubbing liquid) flow vanes) in a position that provides
rate sensors. representative flow; reduce swirling flow
or abnormal velocity distributions due to
upstream and downstream disturbances. If
you elect to comply with Option 3 (Ni lb/
hr) or Option 4 (Ni lb/1,000 lb of coke
burn-off) for the HAP metal emission
limitations in Sec. 63.1564, install the
continuous parameter monitoring system for
gas flow rate as close as practical to the
continuous opacity monitoring system; and
if you don't use a continuous opacity
monitoring system, install the continuous
parameter monitoring system for gas flow
rate as close as practical to the control
device.
Use a flow rate sensor with an accuracy of
at least 5 percent over the
normal range of flow measured, or 1.9
liter per minute (0.5 gallons per minute),
whichever is greater, for liquid flow.
Use a flow rate sensor with an accuracy of
at least 5 percent over the
normal range of flow measured, or 280
liters per minute (10 cubic feet per
minute), whichever is greater, for gas
flow.
Conduct a flow sensor calibration check at
least biennially (every two years);
conduct a calibration check following any
period of more than 24 hours throughout
which the flow rate exceeded the
manufacturer's specified maximum rated
flow rate or install a new flow sensor; at
least quarterly, inspect all components
for leakage, unless the CPMS has a
redundant flow sensor; record the results
of each calibration check and inspection.
9. Temperature sensors..... Locate the temperature sensor in the
combustion zone, or in the ductwork
immediately downstream of the combustion
zone before any substantial heat exchange
occurs or in the ductwork immediately
downstream of the regenerator; locate the
temperature sensor in a position that
provides a representative temperature;
shield the temperature sensor system from
electromagnetic interference and chemical
contaminants.
Use a temperature sensor with an accuracy
of at least 1 percent over the
normal range of temperature measured,
expressed in degrees Celsius (C), or 2.8
degrees C, whichever is greater.
Conduct calibration checks at least
annually; conduct calibration checks
following any period of more than 24 hours
throughout which the temperature exceeded
the manufacturer's specified maximum rated
temperature or install a new temperature
sensor; at least quarterly, inspect all
components for integrity and all
electrical connections for continuity,
oxidation, and galvanic corrosion, unless
the CPMS has a redundant temperature
sensor; record the results of each
calibration check and inspection.
10. Oxygen content sensors Locate the oxygen sensor so that it
\2\. provides a representative measurement of
the oxygen content of the exit gas stream;
ensure the sample is properly mixed and
representative of the gas to be measured.
Use an oxygen sensor with an accuracy of at
least 1 percent of the range
of the sensor or to a nominal gas
concentration of 0.5 percent,
whichever is greater.
Conduct calibration checks at least
annually; conduct calibration checks
following any period of more than 24 hours
throughout which the sensor reading
exceeds the manufacturer's specified
maximum operating range or install a new
oxygen sensor; at least quarterly, inspect
all components for integrity and all
electrical connections for continuity;
record the results of each calibration and
inspection.
------------------------------------------------------------------------
\1\ Not applicable to non-venturi wet scrubbers of the jet-ejector
design.
\2\ This does not replace the requirements for oxygen monitors that are
required to use continuous emissions monitoring systems. The
requirements in this table apply to oxygen sensors that are continuous
parameter monitors, such as those that monitor combustion zone oxygen
concentration and regenerator exit oxygen concentration.

0
86. Table 43 to subpart UUU is revised to read as follows:
As stated in Sec. 63.1575(a), you shall meet each requirement in
the following table that applies to you.

[[Page 75320]]

Table 43 to Subpart UUU of Part 63--Requirements for Reports
------------------------------------------------------------------------
You shall submit
You must submit . . . The report must the report . . .
contain . . .
------------------------------------------------------------------------
1. A compliance report........ If there are no Semiannually
deviations from any according to
emission limitation the
or work practice requirements in
standard that applies Sec.
to you, a statement 63.1575(b).
that there were no
deviations from the
standards during the
reporting period and
that no continuous
opacity monitoring
system or continuous
emission monitoring
system was
inoperative,
inactive, out-of-
control, repaired, or
adjusted; if you have
a deviation from any
emission limitation
or work practice
standard during the
reporting period, the
report must contain
the information in
Sec. 63.1575(c)
through (e).
2. Performance test and CEMS On and after January Within 60 days
performance evaluation data. 30, 2019, the after the date
information specified of completing
in Sec. each test
63.1575(k)(1). according to
the
requirements in
Sec.
63.1575(k).
------------------------------------------------------------------------

0
87. Table 44 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1577, you shall meet each requirement in the
following table that applies to you.

Table 44 to Subpart UUU of Part 63--Applicability of NESHAP General Provisions to Subpart UUU
----------------------------------------------------------------------------------------------------------------
Applies to subpart
Citation Subject UUU Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 63.1(a)(1)-(4)............. General Applicability..... Yes.................. .........................
Sec. 63.1(a)(5)................. [Reserved]................ Not applicable....... .........................
Sec. 63.1(a)(6)................. .......................... Yes.................. Except the correct mail
drop (MD) number is C404-
04.
Sec. 63.1(a)(7)-(9)............. [Reserved]................ Not applicable....... .........................
Sec. 63.1(a)(10)-(12)........... .......................... Yes.................. Except that this subpart
specifies calendar or
operating day.
Sec. 63.1(b)(1)................. Initial Applicability Yes.................. .........................
Determination for this
part.
Sec. 63.1(b)(2)................. [Reserved]................ Not applicable....... .........................
Sec. 63.1(b)(3)................. .......................... Yes.................. .........................
Sec. 63.1(c)(1)................. Applicability of this part Yes.................. .........................
after a Relevant Standard
has been set under this
part.
Sec. 63.1(c)(2)................. .......................... No................... Area sources are not
subject to this subpart.
Sec. 63.1(c)(3)-(4)............. [Reserved]................ Not applicable....... .........................
Sec. 63.1(c)(5)................. .......................... Yes.................. .........................
Sec. 63.1(d).................... [Reserved]................ Not applicable....... .........................
Sec. 63.1(e).................... Applicability of Permit Yes.................. .........................
Program.
Sec. 63.2....................... Definitions............... Yes.................. Sec. 63.1579 specifies
that if the same term is
defined in subparts A
and UUU of this part, it
shall have the meaning
given in this subpart.
Sec. 63.3....................... Units and Abbreviations... Yes.................. .........................
Sec. 63.4(a)(1)-(2)............. Prohibited Activities..... Yes.................. .........................
Sec. 63.4(a)(3)-(5)............. [Reserved]................ Not applicable....... .........................
Sec. 63.4(b)-(c)................ Circumvention and Yes.................. .........................
Fragmentation.
Sec. 63.5(a).................... Construction and Yes.................. .........................
Reconstruction.
Sec. 63.5(b)(1)................. .......................... Yes.................. .........................
Sec. 63.5(b)(2)................. [Reserved]................ Not applicable....... .........................
Sec. 63.5(b)(3)-(4)............. .......................... Yes.................. In Sec. 63.5(b)(4),
replace the reference to
Sec. 63.9(b) with Sec.
63.9(b)(4) and (5).
Sec. 63.5(b)(5)................. [Reserved]................ Not applicable....... .........................
Sec. 63.5(b)(6)................. .......................... Yes.................. .........................
Sec. 63.5(c).................... [Reserved]................ Not applicable....... .........................
Sec. 63.5(d)(1)(i).............. Application for Approval Yes.................. Except this subpart
of Construction or specifies the
Reconstruction--General application is submitted
Application Requirements. as soon as practicable
before startup but not
later than 90 days after
the promulgation date if
construction or
reconstruction had
commenced and initial
startup had not occurred
before promulgation.

[[Page 75321]]

Sec. 63.5(d)(1)(ii)............. .......................... Yes.................. Except that emission
estimates specified in
Sec. 63.5(d)(1)(ii)(H)
are not required, and
Sec. 63.5(d)(1)(ii)(G)
and (I) are Reserved and
do not apply.
Sec. 63.5(d)(1)(iii)............ .......................... No................... This subpart specifies
submission of
notification of
compliance status.
Sec. 63.5(d)(2)................. .......................... Yes.................. .........................
Sec. 63.5(d)(3)................. .......................... Yes.................. .........................
Sec. 63.5(d)(4)................. .......................... Yes.................. .........................
Sec. 63.5(e).................... Approval of Construction Yes.................. .........................
or Reconstruction.
Sec. 63.5(f)(1)................. Approval of Construction Yes.................. .........................
or Reconstruction Based
on State Review.
Sec. 63.5(f)(2)................. .......................... Yes.................. Except that the cross-
reference to Sec.
63.9(b)(2) does not
apply.
Sec. 63.6(a).................... Compliance with Standards Yes.................. .........................
and Maintenance--
Applicability.
Sec. 63.6(b)(1)-(4)............. Compliance Dates for New Yes.................. .........................
and Reconstructed Sources.
Sec. 63.6(b)(5)................. .......................... Yes.................. Except that this subpart
specifies different
compliance dates for
sources.
Sec. 63.6(b)(6)................. [Reserved]................ Not applicable....... .........................
Sec. 63.6(b)(7)................. Compliance Dates for New Yes.................. .........................
and Reconstructed Area
Sources That Become Major.
Sec. 63.6(c)(1)-(2)............. Compliance Dates for Yes.................. Except that this subpart
Existing Sources. specifies different
compliance dates for
sources subject to Tier
II gasoline sulfur
control requirements.
Sec. 63.6(c)(3)-(4)............. [Reserved]................ Not applicable....... .........................
Sec. 63.6(c)(5)................. Compliance Dates for Yes.................. .........................
Existing Area Sources
That Become Major.
Sec. 63.6(d).................... [Reserved]................ Not applicable....... .........................
Sec. 63.6(e)(1)(i).............. General Duty to Minimize No................... See Sec. 63.1570(c) for
Emissions. general duty
requirement.
Sec. 63.6(e)(1)(ii)............. Requirement to Correct No................... .........................
Malfunctions as Soon as
Possible.
Sec. 63.6(e)(1)(iii)............ Compliance with Standards Yes.................. .........................
and Maintenance
Requirements.
Sec. 63.6(e)(2)................. [Reserved]................ Not Applicable....... .........................
Sec. 63.6(e)(3)(i).............. Startup, Shutdown, and No................... .........................
Malfunction Plan
Requirements.
Sec. 63.6(e)(3)(ii)............. [Reserved]................ Not applicable....... .........................
Sec. 63.6(e)(3)(iii)-(ix)....... .......................... No................... .........................
Sec. 63.6(f)(1)................. SSM Exemption............. No................... .........................
Sec. 63.6(f)(2)(i)-(iii)(C)..... Compliance with Standards Yes.................. .........................
and Maintenance
Requirements.
Sec. 63.6(f)(2)(iii)(D)......... .......................... Yes.................. .........................
Sec. 63.6(f)(2)(iv)-(v)......... .......................... Yes.................. .........................
Sec. 63.6(f)(3)................. .......................... Yes.................. Except the cross-
references to Sec.
63.6(f)(1) and (e)(1)(i)
are changed to Sec.
63.1570(c).
Sec. 63.6(g).................... Alternative Standard...... Yes.................. .........................
Sec. 63.6(h)(1)................. SSM Exemption for Opacity/ No................... .........................
VE Standards.
Sec. 63.6(h)(2)(i).............. Determining Compliance No................... This subpart specifies
with Opacity/VE Standards. methods.
Sec. 63.6(h)(2)(ii)............. [Reserved]................ Not applicable....... .........................
Sec. 63.6(h)(2)(iii)............ .......................... Yes.................. .........................
Sec. 63.6(h)(3)................. [Reserved]................ Not applicable....... .........................
Sec. 63.6(h)(4)................. Notification of Opacity/VE Yes.................. Applies to Method 22 (40
Observation Date. CFR part 60, appendix A-
7) tests.
Sec. 63.6(h)(5)................. Conducting Opacity/VE No................... .........................
Observations.
Sec. 63.6(h)(6)................. Records of Conditions Yes.................. Applies to Method 22 (40
During Opacity/VE CFR part 60, appendix A-
Observations. 7) observations.
Sec. 63.6(h)(7)(i).............. Report COM Monitoring Data Yes.................. .........................
from Performance Test.
Sec. 63.6(h)(7)(ii)............. Using COM Instead of No................... .........................
Method 9.

[[Page 75322]]

Sec. 63.6(h)(7)(iii)............ Averaging Time for COM Yes.................. .........................
during Performance Test.
Sec. 63.6(h)(7)(iv)............. COM Requirements.......... Yes.................. .........................
Sec. 63.6(h)(7)(v).............. COMS Results and Visual Yes.................. .........................
Observations.
Sec. 63.6(h)(8)................. Determining Compliance Yes.................. .........................
with Opacity/VE Standards.
Sec. 63.6(h)(9)................. Adjusted Opacity Standard. Yes.................. .........................
Sec. 63.6(i)(1)-(14)............ Extension of Compliance... Yes.................. Extension of compliance
under Sec. 63.6(i)(4)
not applicable to a
facility that installs
catalytic cracking feed
hydrotreating and
receives an extended
compliance date under
Sec. 63.1563(c).
Sec. 63.6(i)(15)................ [Reserved]................ Not applicable....... .........................
Sec. 63.6(i)(16)................ .......................... Yes.................. .........................
Sec. 63.6(j).................... Presidential Compliance Yes.................. .........................
Exemption.
Sec. 63.7(a)(1)................. Performance Test Yes.................. Except that this subpart
Requirements specifies the applicable
Applicability. test and demonstration
procedures.
Sec. 63.7(a)(2)................. Performance Test Dates.... Yes.................. Except test results must
be submitted in the
Notification of
Compliance Status report
due 150 days after the
compliance date.
Sec. 63.7(a)(3)................. Section 114 Authority..... Yes.................. .........................
Sec. 63.7(a)(4)................. Force Majeure............. Yes.................. .........................
Sec. 63.7(b).................... Notifications............. Yes.................. Except that this subpart
specifies notification
at least 30 days prior
to the scheduled test
date rather than 60
days.
Sec. 63.7(c).................... Quality Assurance Program/ Yes.................. Except that when this
Site-Specific Test Plan. subpart specifies to use
40 CFR part 60, appendix
F, out of control
periods are to be
defined as specified in
part 60, appendix F.
Sec. 63.7(d).................... Performance Test Yes.................. .........................
Facilities.
Sec. 63.7(e)(1)................. Performance Testing....... No................... See Sec. 63.1571(b)(1).
Sec. 63.7(e)(2)-(4)............. Conduct of Tests.......... Yes.................. .........................
Sec. 63.7(f).................... Alternative Test Method... Yes.................. .........................
Sec. 63.7(g).................... Data Analysis, Yes.................. Except performance test
Recordkeeping, Reporting. reports must be
submitted with
notification of
compliance status due
150 days after the
compliance date, and
Sec. 63.7(g)(2) is
reserved and does not
apply.
Sec. 63.7(h).................... Waiver of Tests........... Yes.................. .........................
Sec. 63.8(a)(1)................. Monitoring Requirements- Yes.................. .........................
Applicability.
Sec. 63.8(a)(2)................. Performance Specifications Yes.................. .........................
Sec. 63.8(a)(3)................. [Reserved]................ Not applicable....... .........................
Sec. 63.8(a)(4)................. Monitoring with Flares.... Yes.................. Except that for a flare
complying with Sec.
63.670, the cross-
reference to Sec.
63.11 in this paragraph
does not include Sec.
63.11(b).
Sec. 63.8(b)(1)................. Conduct of Monitoring..... Yes.................. .........................
Sec. 63.8(b)(2)-(3)............. Multiple Effluents and Yes.................. This subpart specifies
Multiple Monitoring the required monitoring
Systems. locations.
Sec. 63.8(c)(1)................. Monitoring System Yes.................. .........................
Operation and Maintenance.
Sec. 63.8(c)(1)(i).............. General Duty to Minimize No................... See Sec. 63.1570(c).
Emissions and CMS
Operation.
Sec. 63.8(c)(1)(ii)............. Keep Necessary Parts for Yes.................. .........................
CMS.
Sec. 63.8(c)(1)(iii)............ Requirement to Develop SSM No................... .........................
Plan for CMS.

[[Page 75323]]

Sec. 63.8(c)(2)-(3)............. Monitoring System Yes.................. Except that this subpart
Installation. specifies that for
continuous parameter
monitoring systems,
operational status
verification includes
completion of
manufacturer written
specifications or
installation, operation,
and calibration of the
system or other written
procedures that provide
adequate assurance that
the equipment will
monitor accurately.
Sec. 63.8(c)(4)................. Continuous Monitoring Yes.................. .........................
System Requirements.
Sec. 63.8(c)(5)................. COMS Minimum Procedures... Yes.................. .........................
Sec. 63.8(c)(6)................. CMS Requirements.......... Yes.................. .........................
Sec. 63.8(c)(7)-(8)............. CMS Requirements.......... Yes.................. .........................
Sec. 63.8(d)(1)-(2)............. Quality Control Program Yes.................. .........................
for CMS.
Sec. 63.8(d)(3)................. Written Procedures for CMS No................... .........................
Sec. 63.8(e).................... CMS Performance Evaluation Yes.................. Except that results are
to be submitted as part
of the Notification
Compliance Status due
150 days after the
compliance date.
Sec. 63.8(f)(1)-(5)............. Alternative Monitoring Yes.................. Except that this subpart
Methods. specifies procedures for
requesting alternative
monitoring systems and
alternative parameters.
Sec. 63.8(f)(6)................. Alternative to Relative Yes.................. Applicable to continuous
Accuracy Test. emission monitoring
systems if performance
specification requires a
relative accuracy test
audit.
Sec. 63.8(g)(1)-(4)............. Reduction of Monitoring Yes.................. Applies to continuous
Data. opacity monitoring
system or continuous
emission monitoring
system.
Sec. 63.8(g)(5)................. Data Reduction............ No................... This subpart specifies
requirements.
Sec. 63.9(a).................... Notification Requirements-- Yes.................. Duplicate Notification of
Applicability. Compliance Status report
to the Regional
Administrator may be
required.
Sec. 63.9(b)(1)-(2)............. Initial Notifications..... Yes.................. Except that notification
of construction or
reconstruction is to be
submitted as soon as
practicable before
startup but no later
than 30 days after the
effective date if
construction or
reconstruction had
commenced but startup
had not occurred before
the effective date.
Sec. 63.9(b)(3)................. [Reserved]................ Not applicable....... .........................
Sec. 63.9(b)(4)-(5)............. Initial Notification Yes.................. Except Sec.
Information. 63.9(b)(4)(ii)-(iv),
which are reserved and
do not apply.
Sec. 63.9(c).................... Request for Extension of Yes.................. .........................
Compliance.
Sec. 63.9(d).................... New Source Notification Yes.................. .........................
for Special Compliance
Requirements.
Sec. 63.9(e).................... Notification of Yes.................. Except that notification
Performance Test. is required at least 30
days before test.
Sec. 63.9(f).................... Notification of VE/Opacity Yes.................. .........................
Test.
Sec. 63.9(g).................... Additional Notification Yes.................. .........................
Requirements for Sources
with Continuous
Monitoring Systems.
Sec. 63.9(h).................... Notification of Compliance Yes.................. Except that this subpart
Status. specifies the
notification is due no
later than 150 days
after compliance date,
and except that the
reference to Sec.
63.5(d)(1)(ii)(H) in
Sec. 63.9(h)(5) does
not apply.
Sec. 63.9(i).................... Adjustment of Deadlines... Yes.................. .........................
Sec. 63.9(j).................... Change in Previous Yes.................. .........................
Information.
63.10(a).......................... Recordkeeping and Yes.................. .........................
Reporting Applicability.
Sec. 63.10(b)(1)................ General Recordkeeping Yes.................. .........................
Requirements.

[[Page 75324]]

Sec. 63.10(b)(2)(i)............. Recordkeeping of No................... .........................
Occurrence and Duration
of Startups and Shutdowns.
Sec. 63.10(b)(2)(ii)............ Recordkeeping of No................... See Sec. 63.1576(a)(2)
Malfunctions. for recordkeeping of (1)
date, time and duration;
(2) listing of affected
source or equipment, and
an estimate of the
volume of each regulated
pollutant emitted over
the standard; and (3)
actions taken to
minimize emissions and
correct the failure.
Sec. 63.10(b)(2)(iii)........... Maintenance Records....... Yes.................. .........................
Sec. 63.10(b)(2)(iv)-(v)........ Actions Taken to Minimize No................... .........................
Emissions During SSM.
Sec. 63.10(b)(2)(vi)............ Recordkeeping for CMS Yes.................. .........................
Malfunctions.
Sec. 63.10(b)(2)(vii)-(xiv)..... Other CMS Requirements.... Yes.................. .........................
Sec. 63.10(b)(3)................ Recordkeeping for Yes.................. .........................
Applicability
Determinations..
Sec. 63.10(c)(1)-(6)............ Additional Records for Yes.................. Except Sec. 63.10(c)(2)-
Continuous Monitoring (4), which are Reserved
Systems. and do not apply.
Sec. 63.10(c)(7)-(8)............ Additional Recordkeeping Yes.................. .........................
Requirements for CMS--
Identifying Exceedances
and Excess Emissions.
Sec. 63.10(c)(9)................ [Reserved]................ Not applicable....... .........................
Sec. 63.10(c)(10)............... Recording Nature and Cause No................... See Sec. 63.1576(a)(2)
of Malfunctions. for malfunctions
recordkeeping
requirements.
Sec. 63.10(c)(11)............... Recording Corrective No................... See Sec. 63.1576(a)(2)
Actions. for malfunctions
recordkeeping
requirements.
Sec. 63.10(c)(12)-(14).......... Additional CMS Yes.................. .........................
Recordkeeping
Requirements.
Sec. 63.10(c)(15)............... Use of SSM Plan........... No................... .........................
Sec. 63.10(d)(1)................ General Reporting Yes.................. .........................
Requirements.
Sec. 63.10(d)(2)................ Performance Test Results.. No................... This subpart requires
performance test results
to be reported as part
of the Notification of
Compliance Status due
150 days after the
compliance date.
Sec. 63.10(d)(3)................ Opacity or VE Observations Yes.................. .........................
Sec. 63.10(d)(4)................ Progress Reports.......... Yes.................. .........................
Sec. 63.10(d)(5)................ SSM Reports............... No................... See Sec. 63.1575(d) for
CPMS malfunction
reporting and Sec.
63.1575(e) for COMS and
CEMS malfunction
reporting.
Sec. 63.10(e)(1)-(2)............ Additional CMS Reports.... Yes.................. Except that reports of
performance evaluations
must be submitted in
Notification of
Compliance Status.
Sec. 63.10(e)(3)................ Excess Emissions/CMS No................... This subpart specifies
Performance Reports. the applicable
requirements.
Sec. 63.10(e)(4)................ COMS Data Reports......... Yes.................. .........................
Sec. 63.10(f)................... Recordkeeping/Reporting Yes.................. .........................
Waiver.
Sec. 63.11(a)................... Control Device and Work Yes.................. .........................
Practice Requirements
Applicability.
Sec. 63.11(b)................... Flares.................... Yes.................. Except that flares
complying with Sec.
63.670 are not subject
to the requirements of
Sec. 63.11(b).
Sec. 63.11(c)-(e)............... Alternative Work Practice Yes.................. .........................
for Monitoring Equipment
for Leaks.
Sec. 63.12...................... State Authority and Yes.................. .........................
Delegations.
Sec. 63.13...................... Addresses................. Yes.................. .........................
Sec. 63.14...................... Incorporation by Reference Yes.................. .........................
Sec. 63.15...................... Availability of Yes.................. .........................
Information and
Confidentiality.
Sec. 63.16...................... Performance Track Yes.................. .........................
Provisions.
----------------------------------------------------------------------------------------------------------------

[[Page 75325]]

0
88. Appendix A to subpart UUU of part 63 is amended by revising the
first sentence of section 2.1 and section 7.1.3 to read as follows:

Appendix A to Subpart UUU of Part 63--Determination of Metal
Concentration on Catalyst Particles (Instrumental Analyzer Procedure)

* * * * *
2.1 A representative sample of catalyst particles is collected,
prepared, and analyzed for analyte concentration using either energy
or wavelength dispersive X-ray fluorescent (XRF) spectrometry
instrumental analyzers. * * *
* * * * *
7.1.3 Low-Range Calibration Standard. Concentration equivalent
to 1 to 20 percent of the span. The concentration of the low-range
calibration standard should be selected so that it is less than
either one-fourth of the applicable concentration limit or of the
lowest concentration anticipated in the catalyst samples.
* * * * *

0
89. Appendix A to part 63 is amended by adding Method 325A and Method
325B in numerical order to read as follows:

Appendix A to Part 63--Test Methods Pollutant Measurement Methods From
Various Waste Media

* * * * *
Method 325A--Volatile Organic Compounds from Fugitive and Area
Sources:

Sampler Deployment and VOC Sample Collection

1.0 Scope and Application

1.1 This method describes collection of volatile organic
compounds (VOCs) at or inside a facility property boundary or from
fugitive and area emission sources using passive (diffusive) tube
samplers (PS). The concentration of airborne VOCs at or near these
potential fugitive- or area-emission sources may be determined using
this method in combination with Method 325B. Companion Method 325B
(Sampler Preparation and Analysis) describes preparation of sampling
tubes, shipment and storage of exposed sampling tubes, and analysis
of sampling tubes collected using either this passive sampling
procedure or alternative active (pumped) sampling methods.
1.2 This method may be used to determine the average
concentration of the select VOCs using the corresponding uptake
rates listed in Method 325B, Table 12.1. Additional compounds or
alternative sorbents must be evaluated as described in Addendum A of
Method 325B or by one of the following national/international
standard methods: ISO 16017-2:2003(E), ASTM D6196-03 (Reapproved
2009), or BS EN 14662-4:2005 (all incorporated by reference--see
Sec. 63.14), or reported in the peer-reviewed open literature.
1.3 Methods 325A and 325B are valid for the measurement of
benzene. Supporting literature (References 1-8) indicates that
benzene can be measured by flame ionization detection or mass
spectrometry over a concentration range of approximately 0.5
micrograms per cubic meter ([micro]g/m³) to at least 500
[micro]g/m\3\ when industry standard (3.5 inch long x 0.25 inch
outside diameter (o.d.) x 5 mm inner diameter (i.d.)) inert-coated
stainless steel sorbent tubes packed with Carbograph^TM 1
TD, Carbopack^TM B, or Carbopack^TM X or
equivalent are used and when samples are accumulated over a period
of 14 days.
1.4 This method may be applied to screening average airborne VOC
concentrations at facility property boundaries or monitoring
perimeters over an extended period of time using multiple sampling
periods (e.g., 26 x 14-day sampling periods). The duration of each
sampling period is normally 14 days.
1.5 This method requires the collection of local meteorological
data (wind speed and direction, temperature, and barometric
pressure). Although local meteorology is a component of this method,
non-regulatory applications of this method may use regional
meteorological data. Such applications risk that the results may not
identify the precise source of the emissions.

2.0 Summary of the Method

2.1 Principle of the Method

The diffusive passive sampler collects VOC from air for a
measured time period at a rate that is proportional to the
concentration of vapor in the air at that location.
2.1.1 This method describes the deployment of prepared passive
samplers, including determination of the number of passive samplers
needed for each survey and placement of samplers along or inside the
facility property boundary depending on the size and shape of the
site or linear length of the boundary.
2.1.2 The rate of sampling is specific to each compound and
depends on the diffusion constants of that VOC and the sampler
dimensions/characteristics as determined by prior calibration in a
standard atmosphere (Reference 1).
2.1.3 The gaseous VOC target compounds migrate through a
constant diffusion barrier (e.g., an air gap of fixed dimensions) at
the sampling end of the diffusion sampling tube and adsorb onto the
sorbent.
2.1.4 Heat and a flow of inert carrier gas are then used to
extract (desorb) the retained VOCs back from the sampling end of the
tube and transport/transfer them to a gas chromatograph (GC)
equipped with a chromatographic column to separate the VOCs and a
detector to determine the quantity of target VOCs.
2.1.5 Gaseous or liquid calibration standards loaded onto the
sampling ends of clean sorbent tubes must be used to calibrate the
analytical equipment.
2.1.6 This method requires the use of field blanks to ensure
sample integrity associated with shipment, collection, and storage
of the passive samples. It also requires the use of field duplicates
to validate the sampling process.
2.1.7 At the end of each sampling period, the passive samples
are collected, sealed, and shipped to a laboratory for analysis of
target VOCs by thermal desorption gas chromatography, as described
in Method 325B.

2.2 Application of Diffusive Sampling

2.2.1 This method requires deployment of passive sampling tubes
on a monitoring perimeter encompassing all known emission sources at
a facility and collection of local meteorological data. It may be
used to determine average concentration of VOC at a facility's
``fenceline'' using time integrated passive sampling (Reference 2).
2.2.2 Collecting samples and meteorological data at
progressively higher frequencies may be employed to resolve shorter
term concentration fluctuations and wind conditions that could
introduce interfering emissions from other sources.
2.2.3 This passive sampling method provides a low cost approach
to screening of fugitive or area emissions compared to active
sampling methods that are based on pumped sorbent tubes or time
weighted average canister sampling.
2.2.3.1 Additional passive sampling tubes may be deployed at
different distances from the facility property boundary or from the
geometric center of the fugitive emission source.
2.2.3.2 Additional meteorological measurements may also be
collected as needed to perform preliminary gradient-based assessment
of the extent of the pollution plume at ground level and the effect
of ``background'' sources contributing to airborne VOC
concentrations at the location.
2.2.4 Time-resolved concentration measurements coupled with
time-resolved meteorological monitoring may be used to generate data
needed for source apportionment procedures and mass flux
calculations.

3.0 Definitions

(See also Section 3.0 of Method 325B.)
3.1 Fenceline means the property boundary of a facility or
internal monitoring perimeter established in accordance with the
requirements in Section 8.2 of this method.
3.2 Passive sampler (PS) means a specific type of sorbent tube
(defined in this method) that has a fixed dimension air (diffusion)
gap at the sampling end and is sealed at the other end.
3.3 Passive sampling refers to the activity of quantitatively
collecting VOC on sorbent tubes using the process of diffusion.
3.4 PSi is the annual average for all PS concentration results
from location i.
3.5 PSi3 is the set of annual average concentration results for
PSi and two sorbent tubes nearest to the PS location i.
3.6 PSip is the concentration from the sorbent tube at location
i for the test period or episode p.
3.7 Sampling period is the length of time each passive sampler
is exposed during field monitoring. The sampling period for this
method is 14 days.
3.8 Sorbent tube (Also referred to as tube, PS tube, adsorbent
tube, and sampling tube) is an inert coated stainless steel tube.
Standard PS tube dimensions for this method

[[Page 75326]]

are 3.5-inch (89 mm) long x 0.25-inch (6.4 mm) o.d. with an i.d. of
5 mm, a cross-sectional area of 19.6 mm² and an air gap
of 15 mm. The central portion of the tube is packed with solid
adsorbent material contained between 2 x 100-mesh stainless steel
gauzes and terminated with a diffusion cap at the sampling end of
the tube. These axial passive samplers are installed under a
protective hood during field deployment.

Note: Glass and glass- (or fused silica-) lined stainless steel
sorbent tubes (typically 4 mm i.d.) are also available in various
lengths to suit different makes of thermal desorption equipment, but
these are rarely used for passive sampling because it is more
difficult to adequately define the diffusive air gap in glass or
glass-line tubing. Such tubes are not recommended for this method.

4.0 Sampling Interferences

4.1 General Interferences

Passive tube samplers should be sited at a distance beyond the
influence of possible obstructions such as trees, walls, or
buildings at the monitoring site. Complex topography and physical
site obstructions, such as bodies of water, hills, buildings, and
other structures that may prevent access to a planned PS location
must be taken into consideration. You must document and report
siting interference with the results of this method.

4.2 Background Interference

Nearby or upwind sources of target emissions outside the
facility being tested can contribute to background concentrations.
Moreover, because passive samplers measure continuously, changes in
wind direction can cause variation in the level of background
concentrations from interfering sources during the monitoring
period. This is why local meteorological information, particularly
wind direction and speed, is required to be collected throughout the
monitoring period. Interfering sources can include neighboring
industrial facilities, transportation facilities, fueling
operations, combustion sources, short-term transient sources,
residential sources, and nearby highways or roads. As PS data are
evaluated, the location of potential interferences with respect to
PS locations and local wind conditions should be considered,
especially when high PS concentration values are observed.

4.3 Tube Handling

You must protect the PS tubes from gross external contamination
during field sampling. Analytical thermal desorption equipment used
to analyze PS tubes must desorb organic compounds from the interior
of PS tubes and exclude contamination from external sampler surfaces
in the analytical/sample flow path. If the analytical equipment does
not comply with this requirement, you must wear clean, white, cotton
or powder-free nitrile gloves to handle sampling tubes to prevent
contamination of the external sampler surfaces. Sampling tubes must
be capped with two-piece, brass, 0.25 inch, long-term storage caps
fitted with combined polytetrafluoroethylene ferrules (see Section
6.1 and Method 325B) to prevent ingress of airborne contaminants
outside the sampling period. When not being used for field
monitoring, the capped tubes must be stored in a clean, air-tight,
shipping container to prevent the collection of VOCs (see Section
6.4.2 of Method 325B).

4.4 Local Weather Conditions and Airborne Particulates

Although air speeds are a constraint for many forms of passive
samplers, axial tube PS devices have such a slow inherent uptake
rate that they are largely immune to these effects (References 4,5).
Passive samplers must nevertheless be deployed under non-emitting
weatherproof hoods to moderate the effect of local weather
conditions such as solar heating and rain. The cover must not impede
the ingress of ambient air. Sampling tubes should also be orientated
vertically and pointing downwards, to minimize accumulation of
particulates.

4.5 Temperature

The normal working range for field sampling for sorbent packing
is 0-40 [deg]C (References 6,7). Note that most published passive
uptake rate data for sorbent tubes is quoted at 20 [deg]C. Note also
that, as a rough guide, an increase in temperature of 10 [deg]C will
reduce the collection capacity for a given analyte on a given
sorbent packing by a factor of 2, but the uptake rate will not
change significantly (Reference 4).

5.0 Safety

This method does not purport to include all safety issues or
procedures needed when deploying or collecting passive sampling
tubes. Precautions typical of field air sampling projects are
required. Tripping, falling, electrical, and weather safety
considerations must all be included in plans to deploy and collect
passive sampling tubes.

6.0 Sampling Equipment and Supplies, and Pre-Deployment Planning

This section describes the equipment and supplies needed to
deploy passive sampling monitoring equipment at a facility property
boundary. Details of the passive sampling tubes themselves and
equipment required for subsequent analysis are described in Method
325B.

6.1 Passive Sampling Tubes

The industry standard PS tubes used in this method must meet the
specific configuration and preparation requirements described in
Section 3.0 of this method and Section 6.1 of Method 325B.

Note: The use of PS tubes packed with various sorbent materials
for monitoring a wide variety of organic compounds in ambient air
has been documented in the literature (References 4-10). Other
sorbents may be used in standard passive sampling tubes for
monitoring additional target compound(s) once their uptake rate and
performance has been demonstrated following procedures in Addendum A
to Method 325B. Guidance on sorbent selection can also be obtained
from relevant national and international standard methods such as
ASTM D6196-03 (Reapproved 2009) (Reference 14) and ISO 16017-
2:2003(E) (Reference 13) (both incorporated by reference--see Sec.
63.14).

6.2 Passive or Diffusive Sampling Cap

One diffusive sampling cap is required per PS tube. The cap fits
onto the sampling end of the tube during air monitoring. The other
end of the tube remains sealed with the long-term storage cap. Each
diffusive sampling cap is fitted with a stainless steel gauze, which
defines the outer limit of the diffusion air gap.

6.3 Sorbent Tube Protection Cover

A simple weatherproof hood, suitable for protecting passive
sampling tubes from the worst of the weather (see Section 4.4)
consists of an inverted cone/funnel constructed of an inert, non-
outgassing material that fits over the diffusive tube, with the open
(sampling) end of the tube projecting just below the cone opening.
An example is shown in Figure 6.1 (Adapted from Reference 13).

[[Page 75327]]

[GRAPHIC] [TIFF OMITTED] TR01DE15.025

6.4 Thermal Desorption Apparatus

If the analytical thermal desorber that will subsequently be
used to analyze the passive sampling tubes does not meet the
requirement to exclude outer surface contaminants from the sample
flow path (see Section 6.6 of Method 325B), then clean, white,
cotton or powder-free nitrile gloves must be used for handling the
passive sampling tubes during field deployment.

6.5 Sorbent Selection

Sorbent tube configurations, sorbents or other VOC not listed in
this method must be evaluated according to Method 325B, Addendum A
or ISO 16017-2:2003(E) (Reference 13) (incorporated by reference--
see Sec. 63.14). The supporting evaluation and verification data
described in Method 325B, Addendum A for configurations or compounds
different from the ones described in this method must meet the
performance requirements of Method 325A/B and must be submitted with
the test plan for your measurement program.

7.0 Reagents and Standards

No reagents or standards are needed for the field deployment and
collection of passive sampling tubes. Specifications for sorbents,
gas and liquid phase standards, preloaded standard tubes, and
carrier gases are covered in Section 7 of Method 325B.

8.0 Sample Deployment, Recovery, and Storage

Pre-deployment and planning steps are required before field
deployment of passive sampling tubes. These activities include but
are not limited to conducting a site visit, determining suitable and
required monitoring locations, and determining the monitoring
frequency to be used.

8.1 Conducting the Site Visit

8.1.1 Determine the size and shape of the facility footprint in
order to determine the required number of monitoring locations.
8.1.2 Identify obstacles or obstructions (buildings, roads,
fences), hills and other terrain issues (e.g., bodies of water or
swamp land) that could interfere with air parcel flow to the sampler
or that prevent reasonable access to the location. You may use the
general guidance in Section 4.1 of this method during the site visit
to identify sampling locations. You must evaluate the placement of
each passive sampler to determine if the conditions in this section
are met.
8.1.3 Identify to the extent possible and record potential off-
site source interferences (e.g., neighboring industrial facilities,
transportation facilities, fueling operations, combustion sources,
short-term transient sources, residential sources, nearby highways).
8.1.4 Identify the closest available meteorological station.
Identify potential locations for one or more on-site or near-site
meteorological station(s) following the guidance in EPA-454/B-08-002
(Reference 11) (incorporated by reference--see Sec. 63.14).

8.2 Determining Sampling Locations (References 2, 3)

8.2.1 The number and placement of the passive samplers depends
on the size, the shape of the facility footprint or the linear
distance around the facility, and the proximity of emission sources
near the property boundaries. Aerial photographs or site maps may be
used to determine the size (acreage) and shape of the facility or
the length of the monitoring perimeter. Place passive samplers on an
internal monitoring perimeter on or inside the facility boundary
encompassing all emission sources at the facility at different
angles circling the geometric center of the facility or at different
distances based on the monitoring perimeter length of the facility.

Note: In some instances, permanent air monitoring stations may
already be located in close proximity to the facility. These
stations may be operated and maintained by the site, or local or
state regulatory agencies. If access to the station is possible, a
PS may be deployed adjacent to other air monitoring instrumentation.
A comparison of the pollutant concentrations measured with the PS to
concentrations measured by site instrumentation may be used as an
optional data quality indicator to assess the accuracy of PS
results.

8.2.1.1 The monitoring perimeter may be located between the
property boundary and any potential emission source near the
property boundary, as long as the distance from the source to the
monitoring perimeter is at least 50 meters (162 feet). If a
potential emissions source is within 50 meters (162 feet) of the
property boundary, the property boundary shall be used as the
monitoring perimeter near that source.
8.2.1.2 Samplers need only be placed around the monitoring
perimeter and not along internal roads or other right of ways that
may bisect the facility.
8.2.1.3 Extra samplers must be placed near known sources of VOCs
if the potential emission source is within 50 meters (162 feet) of
the boundary and the source location is between two monitors.
Measure the distance (x) between the two monitors and place another
monitor halfway between (x/2) the two monitors. For example, in
Figure 8.1, the facility added three additional monitors (i.e.,
light shaded sampler locations) and in Figure 8.2, the facility
added two additional monitors to provide sufficient coverage of all
area sources.
BILLING CODE 6560-50-P

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[GRAPHIC] [TIFF OMITTED] TR01DE15.026

8.2.2 Option 1 for Determining Sampling Locations.
8.2.2.1 For facilities with a regular (circular, triangular,
rectangular, or square) shape, determine the geographic center of
the facility.

[[Page 75329]]

8.2.2.1.1 For facilities with an area of less than or equal to
750 acres, measure angles of 30 degrees from the center point for a
total of twelve 30 degree measurements evenly spaced (1
degree).
8.2.2.1.2 For facilities covering an area greater than 750 acres
but less than or equal to 1,500 acres, measure angles of 20 degrees
from the center point for a total of eighteen 20 degree measurements
evenly spaced (1 degree). Figure 8.1 shows the monitor
placement around the property boundary of a facility with an area
between 750 and 1,500 acres. Monitor placements are represented with
black dots along the property boundary.
8.2.2.1.3 For facilities covering an area greater than 1,500
acres, measure angles of 15 degrees from the center point for a
total of twenty-four 15 degree measurements evenly spaced (1 degree).
8.2.2.1.4 Locate each sampling point where the measured angle
intersects the outer monitoring perimeter.
8.2.2.2 For irregularly shaped facilities, divide the area into
a set of connecting subarea circles, triangles or rectangles to
determine sampling locations. The subareas must be defined such that
a circle can reasonably encompass the subarea. Then determine the
geometric center point of each of the subareas.
8.2.2.2.1 If a subarea is less than or equal to 750 acres (e.g.,
Figure 8.3), measure angles of 30 degrees from the center point for
a total of twelve 30 degree measurements (1 degree).
[GRAPHIC] [TIFF OMITTED] TR01DE15.027

8.2.2.2.2 If a subarea is greater than 750 acres but less than
or equal to 1,500 acres (e.g., Figure 8.4), measure angles of 20
degrees from the center point for a total of eighteen 20 degree
measurements (1 degree).
8.2.2.2.3 If a subarea is greater than 1,500 acres, measure
angles of 15 degrees from the center for a total of twenty-four 15
degree measurements (1 degree).
8.2.2.2.4 Locate each sampling point where the measured angle
intersects the outer monitoring perimeter. Sampling points need not
be placed closer than 152 meters (500 feet) apart (or 76 meters (250
feet) if known sources are within 50 meters (162 feet) of the
monitoring perimeter), as long as a minimum of 3 monitoring
locations are used for each subarea.
8.2.2.2.5 Sampling sites are not needed at the intersection of
an inner boundary with an adjacent subarea. The sampling location
must be sited where the measured angle intersects the subarea's
outer monitoring perimeter.

[[Page 75330]]

[GRAPHIC] [TIFF OMITTED] TR01DE15.028

8.2.3 Option 2 for Determining Sampling Locations.
8.2.3.1 For facilities with a monitoring perimeter length of
less than 7,315 meters (24,000 feet), a minimum of twelve sampling
locations evenly spaced 10 percent of the location
interval is required.
8.2.3.2 For facilities with a monitoring perimeter length
greater than 7,315 meters (24,000 feet), sampling locations are
spaced 610 76 meters (2,000 250 feet)
apart.

8.3 Siting a Meteorological Station

A meteorological station is required at or near the facility you
are monitoring. A number of commercially available meteorological
stations can be used. Information on meteorological instruments can
be found in EPA-454/R-99-005 (Reference 11) (incorporated by
reference--see Sec. 63.14). Some important considerations for
siting of meteorological stations are detailed below.
8.3.1 Place meteorological stations in locations that represent
conditions affecting the transport and dispersion of pollutants in
the area of interest. Complex terrain may require the use of more
than one meteorological station.
8.3.2 Deploy wind instruments over level, open terrain at a
height of 10 meters (33 feet). If possible, locate wind instruments
at a distance away from nearby structures that is equal to at least
10 times the height of the structure.
8.3.3 Protect meteorological instruments from thermal radiation
and adequately ventilate them using aspirated shields. The
temperature sensor must be located at a distance away from any
nearby structures that is equal to at least four times the height of
the structure. Temperature sensors must be located at least 30
meters (98 feet) from large paved areas.
8.3.4 Collect and record meteorological data, including wind
speed, wind direction, temperature and barometric pressure on an
hourly basis. Calculate average unit vector wind direction, sigma
theta, temperature and barometric pressure per sampling period to
enable calculation of concentrations at standard conditions. Supply
this information to the laboratory.
8.3.5 Identify and record the location of the meteorological
station by its GPS coordinate.

8.4 Monitoring Frequency

8.4.1 Sample collection may be performed for periods up to 14
days.
8.4.2 A site screening protocol that meets method requirements
may be performed by collecting samples for a year where each PS
accumulates VOC for a 14-day sampling period. Study results are
accumulated for the sampling periods (typically 26) over the course
of one calendar year. To the extent practical, sampling tubes should
be changed at approximately the same time of day at each of the
monitoring sites.

8.5 Passive Sampler Deployment

8.5.1 Clean (conditioned) sorbent tubes must be prepared and
packaged by the laboratory as described in Method 325B and must be
deployed for sampling within 30 days of conditioning.
8.5.2 Allow the tubes to equilibrate with ambient temperature
(approximately 30 minutes to 1 hour) at the monitoring location
before removing them from their storage/shipping container for
sample collection.
8.5.3 If there is any risk that the analytical equipment will
not meet the requirement to exclude contamination on outer tube
surfaces from the sample flow path (see Section 6.6 of Method 325B),
sample handlers must wear clean, white, cotton or powder-free
nitrile gloves during PS deployment and collection and throughout
any other tube handling operations.
8.5.4 Inspect the sampling tubes immediately prior to
deployment. Ensure that they are intact, securely capped, and in
good condition. Any suspect tubes (e.g., tubes that appear to have
leaked sorbent) should be removed from the sampling set.
8.5.5 Secure passive samplers so the bottom of the diffusive
sampling cap is 1.5 to 3 meters (4.9 to 9.8 feet) above ground using
a pole or other secure structure at each sampling location. Orient
the PS vertically and with the sampling end pointing downward to
avoid ingress of particulates.

Note: Duplicate sampling assemblies must be deployed in at
least one monitoring location for every 10 monitoring locations
during each field monitoring period.

8.5.6 Protect the PS from rain and excessive wind velocity by
placing them under the type of protective hood described in Section
6.1.3 or equivalent.
8.5.7 Remove the storage cap on the sampling end of the tube and
replace it with a diffusive sampling cap at the start of the
sampling period. Make sure the diffusion cap is properly seated and
store the removed storage caps in the empty tube shipping container.
8.5.8 Record the start time and location details for each
sampler on the field sample data sheet (see example in Section
17.0.).

[[Page 75331]]

8.5.9 Expose the sampling tubes for the required sampling
period-normally 14-days.
8.5.10 Field blank tubes (see Section 9.3 of Method 325B) are
stored outside the shipping container at representative sampling
locations around the site, but with both long-term storage caps kept
in place throughout the monitoring exercise. Collect at least two
field blanks sorbent samples per sampling period to ensure sample
integrity associated with shipment, collection, and storage.

8.6 Sorbent Tube Recovery and Meteorological Data Collection

Recover deployed sampling tubes and field blanks as follows:
8.6.1 After the sampling period is complete, immediately replace
the diffusion end cap on each sampled tube with a long-term storage
end cap. Tighten the seal securely by hand and then tighten an
additional quarter turn with an appropriate tool. Record the stop
date and time and any additional relevant information on the sample
data sheet.
8.6.2 Place the sampled tubes, together with the field blanks,
in the storage/shipping container. Label the storage container, but
do not use paints, markers, or adhesive labels to identify the
tubes. TD-compatible electronic (radio frequency identification
(RFID)) tube labels are available commercially and are compatible
with some brands of thermal desorber. If used, these may be
programmed with relevant tube and sample information, which can be
read and automatically transcribed into the sequence report by the
TD system.

Note: Sampled tubes must not be placed in the same shipping
container as clean conditioned sampling tubes.

8.6.3 Sampled tubes may be shipped at ambient temperature to a
laboratory for sample analysis.
8.6.4 Specify whether the tubes are field blanks or were used
for sampling and document relevant information for each tube using a
Chain of Custody form (see example in Section 17.0) that accompanies
the samples from preparation of the tubes through receipt for
analysis, including the following information: Unique tube
identification numbers for each sampled tube; the date, time, and
location code for each PS placement; the date, time, and location
code for each PS recovery; the GPS reference for each sampling
location; the unique identification number of the duplicate sample
(if applicable); and problems or anomalies encountered.
8.6.5 If the sorbent tubes are supplied with electronic (e.g.,
RFID) tags, it is also possible to allocate a sample identifier to
each PS tube. In this case, the recommended format for the
identification number of each sampled tube is AA-BB-CC-DD-VOC,
where:

AA = Sequence number of placement on route (01, 02, 03 . . .)
BB = Sampling location code (01, 02, 03 . . .)
CC = 14-day sample period number (01 to 26)
DD = Sample code (SA = sample, DU = duplicate, FB = field blank)
VOC = 3-letter code for target compound(s) (e.g., BNZ for benzene or
BTX for benzene, toluene, and xylenes)

Note: Sampling start and end times/dates can also be logged
using RFID tube tags.

9.0 Quality Control

9.1 Most quality control checks are carried out by the
laboratory and associated requirements are in Section 9.0 of Method
325B, including requirements for laboratory blanks, field blanks,
and duplicate samples.
9.2 Evaluate for potential outliers the laboratory results for
neighboring sampling tubes collected over the same time period. A
potential outlier is a result for which one or more PS tube does not
agree with the trend in results shown by neighboring PS tubes--
particularly when data from those locations have been more
consistent during previous sampling periods. Accidental
contamination by the sample handler must be documented before any
result can be eliminated as an outlier. Rare but possible examples
of contamination include loose or missing storage caps or
contaminated storage/shipping containers. Review data from the same
and neighboring monitoring locations for the subsequent sampling
periods. If the anomalous result is not repeated for that monitoring
location, the episode can be ascribed to transient contamination and
the data in question must be flagged for potential elimination from
the dataset.

9.3 Duplicates and Field Blanks

9.3.1 Collect at least one co-located/duplicate sample for every
10 field samples to determine precision of the measurements.
9.3.2 Collect at least two field blanks sorbent samples per
sampling period to ensure sample integrity associated with shipment,
collection, and storage. You must use the entire sampling apparatus
for field blanks including unopened sorbent tubes mounted in
protective sampling hoods. The tube closures must not be removed.
Field blanks must be placed in two different quadrants (e.g.,
90[deg] and 270[deg]) and remain at the sampling location for the
sampling period.

10.0 Calibration and Standardization

Follow the calibration and standardization procedures for
meteorological measurements in EPA-454/B-08-002 March 2008
(Reference 11) (incorporated by reference--see Sec. 63.14). Refer
to Method 325B for calibration and standardization procedures for
analysis of the passive sampling tubes.

11.0 Analytical Procedures

Refer to Method 325B, which provides details for the preparation
and analysis of sampled passive monitoring tubes (preparation of
sampling tubes, shipment and storage of exposed sampling tubes, and
analysis of sampling tubes).

12.0 Data Analysis, Calculations and Documentation

12.1 Calculate Annual Average Fenceline Concentration.

After a year's worth of sampling at the facility fenceline (for
example, 26 14-day samples), the average (PSi) may be
calculated for any specified period at each PS location using
Equation 12.1.
[GRAPHIC] [TIFF OMITTED] TR01DE15.029

Where:
PSi = Annual average for location i.
PSip = Sampling period specific concentration from Method
325B.
i = Location of passive sampler (0 to 360[deg]).
p = The sampling period.
N = The number of sampling periods in the year (e.g., for 14-day
sampling periods, from 1 to 26).

Note: PSip is a function of sampling location-
specific factors such as the contribution from facility sources,
unusual localized meteorological conditions, contribution from
nearby interfering sources, the background caused by integrated far-
field sources and measurement error due to deployment, handling,
siting, or analytical errors.

12.2 Identify Sampling Locations of Interest

If data from neighboring sampling locations are significantly
different, then you may add extra sampling points to isolate
background contributions or identify facility-specific ``hot
spots.''

12.3 Evaluate Trends

You may evaluate trends and patterns in the PS data over
multiple sampling periods to determine if elevated concentrations of
target compounds are due to operations on the facility or if
contributions from background sources are significant.
12.3.1 Obtain meteorological data including wind speed and wind
direction or unit vector wind data from the on-site meteorological
station. Use this meteorological data to determine the prevailing
wind direction and speed during the periods of elevated
concentrations.
12.3.2 As an option you may perform preliminary back trajectory
calculations (https://ready.arl.noaa.gov/HYSPLIT.php) to aid in
identifying the source of the background contribution to elevated
target compound concentrations.

[[Page 75332]]

12.3.3 Information on published or documented events on- and
off-site may also be included in the associated sampling period
report to explain elevated concentrations if relevant. For example,
you would describe if there was a chemical spill on site, or an
accident on an adjacent road.
12.3.4 Additional monitoring for shorter periods (See section
8.4) may be necessary to allow better discrimination/resolution of
contributing emission sources if the measured trends and associated
meteorology do not provide a clear assessment of facility
contribution to the measured fenceline concentration.
12.3.5 Additional records necessary to calculate sampling period
average target compound concentration can be found in Section 12.1
of Method 325B.

13.0 Method Performance

Method performance requirements are described in Method 325B.

14.0 Pollution Prevention

[Reserved]

15.0 Waste Management

[Reserved]

16.0 References

1. Ambient air quality--Standard method for measurement of benzene
concentrations--Part 4: Diffusive sampling followed by thermal
desorption and gas chromatography, BS EN 14662-4:2005.
2. Thoma, E.D., Miller, C.M., Chung, K.C., Parsons, N.L. and Shine,
B.C. Facility Fence Line Monitoring using Passive Samplers, J. Air &
Waste Mange. Assoc. 2011, 61:834-842.
3. Quality Assurance Handbook for Air Pollution C Systems, Volume
II: Ambient Air Quality Monitoring Program, EPA-454/B-13-003, May
2013. Available at https://www.epa.gov/ttnamti1/files/ambient/pm25/qa/QA-Handbook-Vol-II.pdf.
4. Brown, R.H., Charlton, J. and Saunders, K.J.: The development of
an improved diffusive sampler. Am. Ind. Hyg. Assoc. J. 1981, 42(12):
865-869.
5. Brown, R. H. Environmental use of diffusive samplers: evaluation
of reliable diffusive uptake rates for benzene, toluene and xylene.
J. Environ. Monit. 1999, 1 (1), 115-116.
6. Ballach, J.; Greuter, B.; Schultz, E.; Jaeschke, W. Variations of
uptake rates in benzene diffusive sampling as a function of ambient
conditions. Sci. Total Environ. 1999, 244, 203-217.
7. Brown, R. H. Monitoring the ambient environment with diffusive
samplers: theory and practical considerations. J Environ. Monit.
2000, 2 (1), 1-9.
8. Buzica, D.; Gerboles, M.; Plaisance, H. The equivalence of
diffusive samplers to reference methods for monitoring
O3, benzene and NO2 in ambient air. J.
Environ. Monit. 2008, 10 (9), 1052-1059.
9. Woolfenden, E. Sorbent-based sampling methods for volatile and
semi-volatile organic compounds in air. Part 2. Sorbent selection
and other aspects of optimizing air monitoring methods. J.
Chromatogr. A 2010, 1217, (16), 2685-94.
10. Pfeffer, H. U.; Breuer, L. BTX measurements with diffusive
samplers in the vicinity of a cokery: Comparison between ORSA-type
samplers and pumped sampling. J. Environ. Monit. 2000, 2 (5), 483-
486.
11. US EPA. 2000. Meteorological Monitoring Guidance for Regulatory
Modeling Applications. EPA-454/R-99-005. Office of Air Quality
Planning and Standards, Research Triangle Park, NC. February 2000.
Available at https://www.epa.gov/scram001/guidance/met/mmgrma.pdf.
12. Quality Assurance Handbook for Air Pollution Measurement
Systems. Volume IV: Meteorological Measurements Version 2.0 Final,
EPA-454/B-08-002 March 2008. Available at https://www.epa.gov/ttnamti1/files/ambient/met/Volume%20IV_Meteorological_Measurements.pdf.
13. ISO 16017-2:2003(E), Indoor, ambient and workplace air--Sampling
and analysis of volatile organic compounds by sorbent tube/thermal
desorption/capillary gas chromatography. Part 2: Diffusive sampling.
14. ASTM D6196-03 (Reapproved 2009): Standard practice for selection
of sorbents, sampling, and thermal desorption analysis procedures
for volatile organic compounds in air.

17.0 Tables, Diagrams, Flowcharts and Validation Data

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[[Page 75334]]

Method 325B--Volatile Organic Compounds from Fugitive and Area Sources:

Sampler Preparation and Analysis

1.0 Scope and Application

1.1 This method describes thermal desorption/gas chromatography
(TD/GC) analysis of volatile organic compounds (VOCs) from fugitive
and area emission sources collected onto sorbent tubes using passive
sampling. It could also be applied to the TD/GC analysis of VOCs
collected using active (pumped) sampling onto sorbent tubes. The
concentration of airborne VOCs at or near potential fugitive- or
area-emission sources may be determined using this method in
combination with Method 325A. Companion Method 325A (Sampler
Deployment and VOC Sample Collection) describes procedures for
deploying the sorbent tubes and passively collecting VOCs.
1.2 The preferred GC detector for this method is a mass
spectrometer (MS), but flame ionization detectors (FID) may also be
used. Other conventional GC detectors such as electron capture
(ECD), photoionization (PID), or flame photometric (FPD) may also be
used if they are selective and sensitive to the target compound(s)
and if they meet the method performance criteria provided in this
method.
1.3 There are 97 VOCs listed as hazardous air pollutants in
Title III of the Clean Air Act Amendments of 1990. Many of these VOC
are candidate compounds for this method. Compounds with known uptake
rates for Carbograph^TM 1 TD, Carbopack^TM B, or
Carbopack^TM X are listed in Table 12.1. This method
provides performance criteria to demonstrate acceptable performance
of the method (or modifications of the method) for monitoring one or
more of the compounds listed Table 12.1. If standard passive
sampling tubes are packed with other sorbents or used for other
analytes than those listed in Table 12.1, then method performance
and relevant uptake rates should be verified according to Addendum A
to this method or by one of the following national/international
standard methods: ISO 16017-2:2003(E), ASTM D6196-03 (Reapproved
2009), or BS EN 14662-4:2005 (all incorporated by reference--see
Sec. 63.14), or reported in the peer-reviewed open literature.
1.4 The analytical approach using TD/GC/MS is based on
previously published EPA guidance in Compendium Method TO-17 (https://www.epa.gov/ttnamti1/airtox.html#compendium) (Reference 1), which
describes active (pumped) sampling of VOCs from ambient air onto
tubes packed with thermally stable adsorbents.
1.5 Inorganic gases not suitable for analysis by this method
include oxides of carbon, nitrogen and sulfur, ozone
(O3), and other diatomic permanent gases. Other
pollutants not suitable for this analysis method include particulate
pollutants, (i.e., fumes, aerosols, and dusts), compounds too labile
(reactive) for conventional GC analysis, and VOCs that are more
volatile than propane.

2.0 Summary of Method

2.1 This method provides procedures for the preparation,
conditioning, blanking, and shipping of sorbent tubes prior to
sample collection.
2.2 Laboratory and field personnel must have experience of
sampling trace-level VOCs using sorbent tubes (References 2,5) and
must have experience operating thermal desorption/GC/multi-detector
instrumentation.
2.3 Key steps of this method as implemented for each sample tube
include: Stringent leak testing under stop flow, recording ambient
temperature conditions, adding internal standards, purging the tube,
thermally desorbing the sampling tube, refocusing on a focusing
trap, desorbing and transferring/injecting the VOCs from the
secondary trap into the capillary GC column for separation and
analysis.
2.4 Water management steps incorporated into this method
include: (a) Selection of hydrophobic sorbents in the sampling tube;
(b) optional dry purging of sample tubes prior to analysis; and (c)
additional selective elimination of water during primary (tube)
desorption (if required) by selecting trapping sorbents and
temperatures such that target compounds are quantitatively retained
while water is purged to vent.

3.0 Definitions

(See also Section 3.0 of Method 325A).
3.1 Blanking is the desorption and confirmatory analysis of
conditioned sorbent tubes before they are sent for field sampling.
3.2 Breakthrough volume and associated relation to passive
sampling. Breakthrough volumes, as applied to active sorbent tube
sampling, equate to the volume of air containing a constant
concentration of analyte that may be passed through a sorbent tube
at a given temperature before a detectable level (5 percent) of the
input analyte concentration elutes from the tube. Although
breakthrough volumes are directly related to active rather than
passive sampling, they provide a measure of the strength of the
sorbent-sorbate interaction and therefore also relate to the
efficiency of the passive sampling process. The best direct measure
of passive sampling efficiency is the stability of the uptake rate.
Quantitative passive sampling is compromised when the sorbent no
longer acts as a perfect sink--i.e., when the concentration of a
target analyte immediately above the sorbent sampling surface no
longer approximates to zero. This causes a reduction in the uptake
rate over time. If the uptake rate for a given analyte on a given
sorbent tube remains relatively constant --i.e., if the uptake rate
determined for 48 hours is similar to that determined for 7 or 14
days--the user can be confident that passive sampling is occurring
at a constant rate. As a general rule of thumb, such ideal passive
sampling conditions typically exist for analyte:sorbent combinations
where the breakthrough volume exceeds 100 L (Reference 4).
3.3 Continuing calibration verification sample (CCV). Single
level calibration samples run periodically to confirm that the
analytical system continues to generate sample results within
acceptable agreement to the current calibration curve.
3.4 Focusing trap is a cooled, secondary sorbent trap integrated
into the analytical thermal desorber. It typically has a smaller
i.d. and lower thermal mass than the original sample tube allowing
it to effectively refocus desorbed analytes and then heat rapidly to
ensure efficient transfer/injection into the capillary GC analytical
column.
3.5 High Resolution Capillary Column Chromatography uses fused
silica capillary columns with an inner diameter of 320 [mu]m or less
and with a stationary phase film thickness of 5 [mu]m or less.
3.6 h is time in hours.
3.7 i.d. is inner diameter.
3.8 min is time in minutes.
3.9 Method Detection Limit is the lowest level of analyte that
can be detected in the sample matrix with 99% confidence.
3.10 MS-SCAN is the mode of operation of a GC quadrupole mass
spectrometer detector that measures all ions over a given mass range
over a given period of time.
3.11 MS-SIM is the mode of operation of a GC quadrupole mass
spectrometer detector that measures only a single ion or a selected
number of discrete ions for each analyte.
3.12 o.d. is outer diameter.
3.13 ppbv is parts per billion by volume.
3.14 Thermal desorption is the use of heat and a flow of inert
(carrier) gas to extract volatiles from a solid matrix. No solvent
is required.
3.15 Total ion chromatogram is the chromatogram produced from a
mass spectrometer detector collecting full spectral information.
3.16 Two-stage thermal desorption is the process of thermally
desorbing analytes from a sorbent tube, reconcentrating them on a
focusing trap (see Section 3.4), which is then itself rapidly heated
to ``inject'' the concentrated compounds into the GC analyzer.
3.17 VOC is volatile organic compound.

4.0 Analytical Interferences

4.1 Interference from Sorbent Artifacts. Artifacts may include
target analytes as well as other VOC that co-elute
chromatographically with the compounds of interest or otherwise
interfere with the identification or quantitation of target
analytes.
4.1.1 Sorbent decomposition artifacts are VOCs that form when
sorbents degenerate, e.g., when exposed to reactive species during
sampling. For example, benzaldehyde, phenol, and acetophenone
artifacts are reported to be formed via oxidation of the polymeric
sorbent Tenax[supreg] when sampling high concentration (100-500 ppb)
ozone atmospheres (Reference 5).
4.1.2 Preparation and storage artifacts are VOCs that were not
completely cleaned from the sorbent tube during conditioning or that
are an inherent feature of that sorbent at a given temperature.
4.2 Humidity. Moisture captured during sampling can interfere
with VOC analysis. Passive sampling using tubes packed with
hydrophobic sorbents, like those described in this method, minimizes
water retention. However, if water interference is found to be an
issue under extreme conditions, one or more of the water management
steps described in Section 2.4 can be applied.
4.3 Contamination from Sample Handling. The type of analytical
thermal

[[Page 75335]]

desorption equipment selected should exclude the possibility of
outer tube surface contamination entering the sample flow path (see
Section 6.6). If the available system does not meet this
requirement, sampling tubes and caps must be handled only while
wearing clean, white cotton or powder free nitrile gloves to prevent
contamination with body oils, hand lotions, perfumes, etc.

5.0 Safety

5.1 This method does not address all of the safety concerns
associated with its use. It is the responsibility of the user of
this standard to establish appropriate field and laboratory safety
and health practices prior to use.
5.2 Laboratory analysts must exercise extreme care in working
with high-pressure gas cylinders.
5.3 Due to the high temperatures involved, operators must use
caution when conditioning and analyzing tubes.

6.0 Equipment and Supplies

6.1 Tube Dimensions and Materials. The sampling tubes for this
method are 3.5-inches (89 mm) long, \1/4\ inch (6.4 mm) o.d., and 5
mm i.d. passive sampling tubes (see Figure 6.1). The tubes are made
of inert-coated stainless steel with the central section (up to 60
mm) packed with sorbent, typically supported between two 100 mesh
stainless steel gauze. The tubes have a cross sectional area of 19.6
square mm (5 mm i.d.). When used for passive sampling, these tubes
have an internal diffusion (air) gap (DG) of 1.5 cm between the
sorbent retaining gauze at the sampling end of the tube, and the
gauze in the diffusion cap.
[GRAPHIC] [TIFF OMITTED] TR01DE15.031

6.2 Tube Conditioning Apparatus

6.2.1 Freshly packed or newly purchased tubes must be
conditioned as described in Section 9 using an appropriate dedicated
tube conditioning unit or the thermal desorber. Note that the
analytical TD system should be used for tube conditioning if it
supports a dedicated tube conditioning mode in which effluent from
contaminated tubes is directed to vent without passing through key
parts of the sample flow path such as the focusing trap.
6.2.2 Dedicated tube conditioning units must be leak-tight to
prevent air ingress, allow precise and reproducible temperature
selection (5 [deg]C), offer a temperature range at least
as great as that of the thermal desorber, and support inert gas
flows in the range up to 100 mL/min.

Note: For safety and to avoid laboratory contamination, effluent
gases from freshly packed or highly contaminated tubes should be
passed through a charcoal filter during the conditioning process to
prevent desorbed VOCs from polluting the laboratory atmosphere.

6.3 Tube Labeling

6.3.1 Label the sample tubes with a unique permanent
identification number and an indication of the sampling end of the
tube. Labeling options include etching and TD-compatible electronic
(radio frequency identification (RFID)) tube labels.
6.3.2 To avoid contamination, do not make ink markings of any
kind on clean sorbent tubes or apply adhesive labels.

Note: TD-compatible electronic (RFID) tube labels are available
commercially and are compatible with some brands of thermal
desorber. If used, these may be programmed with relevant tube and
sample information, which can be read and automatically transcribed
into the sequence report by the TD system (see Section 8.6 of Method
325A).

6.4 Blank and Sampled Tube Storage Apparatus

6.4.1 Long-term storage caps. Seal clean, blank and sampled
sorbent tubes using inert, long-term tube storage caps comprising
non-greased, 2-piece, 0.25-inch, metal SwageLok[supreg]-type screw
caps fitted with combined polytetrafluoroethylene ferrules.
6.4.2 Storage and transportation containers. Use clean glass
jars, metal cans or rigid, non-emitting polymer boxes.

Note: You may add a small packet of new activated charcoal or
charcoal/silica gel to the shipping container for storage and
transportation of batches of conditioned sorbent tubes prior to use.
Coolers without ice packs make suitable shipping boxes for
containers of tubes because the coolers help to insulate the samples
from extreme temperatures (e.g., if left in a parked vehicle).

6.5 Unheated GC Injection Unit for Loading Standards Onto Blank Tubes

A suitable device has a simple push fit or finger-tightening
connector for attaching the sampling end of blank sorbent tubes
without damaging the tube. It also has a means of controlling
carrier gas flow through the injector and attached sorbent tube at
50-100 mL/min and includes a low emission septum cap that allows the
introduction of gas or liquid standards via appropriate syringes.
Reproducible and quantitative transfer of higher boiling compounds
in liquid standards is facilitated if the injection unit allows the
tip of the syringe to just touch the sorbent retaining gauze inside
the tube.

6.6 Thermal Desorption Apparatus

The manual or automated thermal desorption system must heat
sorbent tubes while a controlled flow of inert (carrier) gas passes
through the tube and out of the sampling end. The apparatus must
also incorporate a focusing trap to quantitatively refocus compounds
desorbed from the tube. Secondary desorption of the focusing trap
should be fast/efficient enough to transfer the compounds into the
high resolution capillary GC column without band broadening and
without any need for further pre- or on-column focusing. Typical TD
focusing traps comprise small sorbent traps (Reference 16) that are
electrically-cooled using multistage Peltier cells (References 17,
18). The direction of gas flow during trap desorption should be the
reverse of that used for focusing to extend the compatible analyte
volatility range. Closed cycle coolers offer another cryogen-free
trap cooling option. Other TD system requirements and operational
stages are described in Section 11 and in Figures 17-2 through 17-4.

6.7 Thermal Desorber--GC Interface

6.7.1 The interface between the thermal desorber and the GC must
be heated uniformly and the connection between the transfer line
insert and the capillary GC analytical column itself must be leak
tight.
6.7.2 A portion of capillary column can alternatively be
threaded through the heated transfer line/TD interface and connected
directly to the thermal desorber.

Note: Use of a metal syringe-type needle or unheated length of
fused silica pushed through the septum of a conventional GC

[[Page 75336]]

injector is not permitted as a means of interfacing the thermal
desorber to the chromatograph. Such connections result in cold
spots, cause band broadening and are prone to leaks.

6.8 GC/MS Analytical Components

6.8.1 The GC system must be capable of temperature programming
and operation of a high resolution capillary column. Depending on
the choice of column (e.g., film thickness) and the volatility of
the target compounds, it may be necessary to cool the GC oven to
subambient temperatures (e.g., -50 [deg]C) at the start of the run
to allow resolution of very volatile organic compounds.
6.8.2 All carrier gas lines supplying the GC must be constructed
from clean stainless steel or copper tubing. Non-
polytetrafluoroethylene thread sealants. Flow controllers, cylinder
regulators, or other pneumatic components fitted with rubber
components are not suitable.

6.9 Chromatographic Columns

High-resolution, fused silica or equivalent capillary columns
that provide adequate separation of sample components to permit
identification and quantitation of target compounds must be used.

Note: 100-percent methyl silicone or 5-percent phenyl, 95-
percent methyl silicone fused silica capillary columns of 0.25- to
0.32-mm i.d. of varying lengths and with varying thicknesses of
stationary phase have been used successfully for non-polar and
moderately polar compounds. However, given the diversity of
potential target lists, GC column choice is left to the operator,
subject to the performance criteria of this method.

6.10 Mass Spectrometer

Linear quadrupole, magnetic sector, ion trap or time-of-flight
mass spectrometers may be used provided they meet specified
performance criteria. The mass detector must be capable of
collecting data from 35 to 300 atomic mass units (amu) every 1
second or less, utilizing 70 volts (nominal) electron energy in the
electron ionization mode, and producing a mass spectrum that meets
all the instrument performance acceptance criteria in Section 9 when
50 [eta]g or less of p-bromofluorobenzene is analyzed.

7.0 Reagents and Standards

7.1 Sorbent Selection

7.1.1 Use commercially packed tubes meeting the requirements of
this method or prepare tubes in the laboratory using sieved sorbents
of particle size in the range 20 to 80 mesh that meet the retention
and quality control requirements of this method.
7.1.2 This passive air monitoring method can be used without the
evaluation specified in Addendum A if the type of tubes described in
Section 6.1 are packed with 4-6 cm (typically 400-650 mg) of the
sorbents listed in Table 12.1 and used for the respective target
analytes.

Note: Although Carbopack^TM X is the optimum sorbent
choice for passive sampling of 1,3-butadiene, recovery of compounds
with vapor pressure lower than benzene may be difficult to achieve
without exceeding sorbent maximum temperature limitations (see Table
8.1). See ISO 16017-2:2003(E) or ASTM D6196-03 (Reapproved 2009)
(both incorporated by reference--see Sec. 63.14) for more details
on sorbent choice for air monitoring using passive sampling tubes.

7.1.3 If standard passive sampling tubes are packed with other
sorbents or used for analytes other than those tabulated in Section
12.0, method performance and relevant uptake rates should be
verified according to Addendum A to this method or by following the
techniques described in one of the following national/international
standard methods: ISO 16017-2:2003(E), ASTM D6196-03 (Reapproved
2009), or BS EN 14662-4:2005 (all incorporated by reference--see
Sec. 63.14)--or reported in the peer-reviewed open literature. A
summary table and the supporting evaluation data demonstrating the
selected sorbent meets the requirements in Addendum A to this method
must be submitted to the regulatory authority as part of a request
to use an alternative sorbent.
7.1.4 Passive (diffusive) sampling and thermal desorption
methods that have been evaluated at relatively high atmospheric
concentrations (i.e., mid-ppb to ppm) and published for use in
workplace air and industrial/mobile source emissions testing
(References 9-20) may be applied to this procedure. However, the
validity of any shorter term uptake rates must be verified and
adjusted if necessary for the longer monitoring periods required by
this method by following procedures described in Addendum A to this
method or those presented in national/international standard
methods: ISO 16017-2:2003(E), ASTM D6196-03 (Reapproved 2009), or BS
EN 14662-4:2005 (all incorporated by reference-see Sec. 63.14).
7.1.5 Suitable sorbents for passive sampling must have
breakthrough volumes of at least 20 L (preferably >100 L) for the
compounds of interest and must quantitatively release the analytes
during desorption without exceeding maximum temperatures for the
sorbent or instrumentation.
7.1.6 Repack/replace the sorbent tubes or demonstrate tube
performance following the requirements in Addendum A to this method
at least every 2 years or every 50 uses, whichever occurs first.

7.2 Gas Phase Standards

7.2.1 Static or dynamic standard atmospheres may be used to
prepare calibration tubes and/or to validate passive sampling uptake
rates and can be generated from pure chemicals or by diluting
concentrated gas standards. The standard atmosphere must be stable
at ambient pressure and accurate to 10 percent of the
target gas concentration. It must be possible to maintain standard
atmosphere concentrations at the same or lower levels than the
target compound concentration objectives of the test. Test
atmospheres used for validation of uptake rates must also contain at
least 35 percent relative humidity.

Note: Accurate, low-(ppb-) level gas-phase VOC standards are
difficult to generate from pure materials and may be unstable
depending on analyte polarity and volatility. Parallel monitoring of
vapor concentrations with alternative methods, such as pumped
sorbent tubes or sensitive/selective on-line detectors, may be
necessary to minimize uncertainty. For these reasons, standard
atmospheres are rarely used for routine calibration.

7.2.2 Concentrated, pressurized gas phase standards. Accurate
(5 percent or better), concentrated gas phase standards
supplied in pressurized cylinders may also be used for calibration.
The concentration of the standard should be such that a 0.5-5.0 mL
volume contains approximately the same mass of analytes as will be
collected from a typical air sample.
7.2.3 Follow manufacturer's guidelines concerning storage
conditions and recertification of the concentrated gas phase
standard. Gas standards must be recertified a minimum of once every
12 months.

7.3 Liquid Standards

Target analytes can also be introduced to the sampling end of
sorbent tubes in the form of liquid calibration standards.
7.3.1 The concentration of liquid standards must be such that an
injection of 0.5-2 [micro]l of the solution introduces the same mass
of target analyte that is expected to be collected during the
passive air sampling period.
7.3.2 Solvent Selection. The solvent selected for the liquid
standard must be pure (contaminants <10 percent of minimum analyte
levels) and must not interfere chromatographically with the
compounds of interest.
7.3.3 If liquid standards are sourced commercially, follow
manufacturer's guidelines concerning storage conditions and shelf
life of unopened and opened liquid stock standards.

Note: Commercial VOC standards are typically supplied in
volatile or non-interfering solvents such as methanol.

7.3.4 Working standards must be stored at 6 [deg]C or less and
used or discarded within two weeks of preparation.

7.4 Gas Phase Internal Standards

7.4.1 Gas-phase deuterated or fluorinated organic compounds may
be used as internal standards for MS-based systems.
7.4.2 Typical compounds include deuterated toluene,
perfluorobenzene and perfluorotoluene.
7.4.3 Use multiple internal standards to cover the volatility
range of the target analytes.
7.4.4 Gas-phase standards must be obtained in pressurized
cylinders and containing vendor certified gas concentrations
accurate to 5 percent. The concentration should be such
that the mass of internal standard components introduced is similar
to those of the target analytes collected during field monitoring.

7.5 Preloaded Standard Tubes

Certified, preloaded standard tubes, accurate within 5 percent for each analyte at the microgram level and 10 percent at the nanogram level, are available commercially

[[Page 75337]]

and may be used for auditing and quality control purposes. (See
Section 9.5 for audit accuracy evaluation criteria.) Certified
preloaded tubes may also be used for routine calibration.

Note: Proficiency testing schemes are also available for TD/GC/
MS analysis of sorbent tubes preloaded with common analytes such as
benzene, toluene, and xylene.

7.6 Carrier Gases

Use inert, 99.999-percent or higher purity helium as carrier
gas. Oxygen and organic filters must be installed in the carrier gas
lines supplying the analytical system according to the
manufacturer's instructions. Keep records of filter and oxygen
scrubber replacement.

8.0 Sorbent Tube Handling (Before and After Sampling)

8.1 Sample Tube Conditioning

8.1.1 Sampling tubes must be conditioned using the apparatus
described in Section 6.2.
8.1.2 New tubes should be conditioned for 2 hours to supplement
the vendor's conditioning procedure. Recommended temperatures for
tube conditioning are given in Table 8.1.
8.1.3 After conditioning, the blank must be verified on each new
sorbent tube and on 10 percent of each batch of reconditioned tubes.
See Section 9.0 for acceptance criteria.

Table 8.1--Example Sorbent Tube Conditioning Parameters
----------------------------------------------------------------------------------------------------------------
Maximum Conditioning
Sampling sorbent temperature temperature Carrier gas
([deg]C) ([deg]C) flow rate
----------------------------------------------------------------------------------------------------------------
Carbotrap[supreg] C............................................. >400 350 100 mL/min
CarbopackTM C
Anasorb[supreg] GCB2
CarbographTM 1 TD
Carbotrap[supreg]
CarbopackTM B
Anasorb[supreg] GCB1
Tenax[supreg] TA 350 330 100 mL/min
CarbopackTM X...................................................
----------------------------------------------------------------------------------------------------------------

8.2 Capping, Storage and Shipment of Conditioned Tubes

8.2.1 Conditioned tubes must be sealed using long-term storage
caps (see Section 6.4) pushed fully down onto both ends of the PS
sorbent tube, tightened by hand and then tighten an additional
quarter turn using an appropriate tool.
8.2.2 The capped tubes must be kept in appropriate containers
for storage and transportation (see Section 6.4.2). Containers of
sorbent tubes may be stored and shipped at ambient temperature and
must be kept in a clean environment.
8.2.3 You must keep batches of capped tubes in their shipping
boxes or wrap them in uncoated aluminum foil before placing them in
their storage container, especially before air freight, because the
packaging helps hold caps in position if the tubes get very cold.

8.3 Calculating the Number of Tubes Required for a Monitoring Exercise

8.3.1 Follow guidance given in Method 325A to determine the
number of tubes required for site monitoring.
8.3.2 The following additional samples will also be required:
Laboratory blanks as specified in Section 9.1.2 (one per analytical
sequence minimum), field blanks as specified in Section 9.3.2 (two
per sampling period minimum), CCV tubes as specified in Section
10.9.4. (at least one per analysis sequence or every 24 hours), and
duplicate samples as specified in Section 9.4 (at least one
duplicate sample is required for every 10 sampling locations during
each monitoring period).

8.4 Sample Collection

8.4.1 Allow the tubes to equilibrate with ambient temperature
(approximately 30 minutes to 1 hour) at the monitoring location
before removing them from their storage/shipping container for
sample collection.
8.4.2 Tubes must be used for sampling within 30 days of
conditioning (Reference 4).
8.4.3 During field monitoring, the long-term storage cap at the
sampling end of the tube is replaced with a diffusion cap and the
whole assembly is arranged vertically, with the sampling end
pointing downward, under a protective hood or shield--See Section
6.1 of Method 325A for more details.

8.5 Sample Storage

8.5.1 After sampling, tubes must be immediately resealed with
long-term storage caps and placed back inside the type of storage
container described in Section 6.4.2.
8.5.2 Exposed tubes may not be placed in the same container as
clean tubes. They should not be taken back out of the container
until ready for analysis and after they have had time to equilibrate
with ambient temperature in the laboratory.
8.5.3 Sampled tubes must be inspected before analysis to
identify problems such as loose or missing caps, damaged tubes,
tubes that appear to be leaking sorbent or container contamination.
Any and all such problems must be documented together with the
unique identification number of the tube or tubes concerned.
Affected tubes must not be analyzed but must be set aside.
8.5.4 Intact tubes must be analyzed within 30 days of the end of
sample collection (within one week for limonene, carene, bis-
chloromethyl ether, labile sulfur or nitrogen-containing compounds,
and other reactive VOCs).

Note: Ensure ambient temperatures stay below 23 [deg]C during
transportation and storage. Refrigeration is not normally required
unless the samples contain reactive compounds or cannot be analyzed
within 30 days. If refrigeration is used, the atmosphere inside the
refrigerator must be clean and free of organic solvents.

9.0 Quality Control

9.1 Laboratory Blank

The analytical system must be demonstrated to be contaminant
free by performing a blank analysis at the beginning of each
analytical sequence to demonstrate that the secondary trap and TD/
GC/MS analytical equipment are free of any significant interferents.
9.1.1 Laboratory blank tubes must be prepared from tubes that
are identical to those used for field sampling.
9.1.2 Analysis of at least one laboratory blank is required per
analytical sequence. The laboratory blank must be stored in the
laboratory under clean, controlled ambient temperature conditions.
9.1.3 Laboratory blank/artifact levels must meet the
requirements of Section 9.2.2 (see also Table 17.1). If the
laboratory blank does not meet requirements, stop and perform
corrective actions and then re-analyze laboratory blank to ensure it
meets requirements.

9.2 Tube Conditioning

9.2.1 Conditioned tubes must be demonstrated to be free of
contaminants and interference by running 10 percent of the blank
tubes selected at random from each conditioned batch under standard
sample analysis conditions (see Section 8.1).
9.2.2 Confirm that artifacts and background contamination are <=
0.2 ppbv or less than three times the detection limit of the
procedure or less than 10 percent of the target compound(s) mass
that would be collected if airborne concentrations were at the
regulated limit value, whichever is larger. Only tubes that meet
these criteria can be

[[Page 75338]]

used for field monitoring, field or laboratory blanks, or for system
calibration.
9.2.3 If unacceptable levels of VOCs are observed in the tube
blanks, then the processes of tube conditioning and checking the
blanks must be repeated.

9.3 Field Blanks

9.3.1 Field blank tubes must be prepared from tubes that are
identical to those used for field sampling--i.e., they should be
from the same batch, have a similar history, and be conditioned at
the same time.
9.3.2 Field blanks must be shipped to the monitoring site with
the sampling tubes and must be stored at the sampling location
throughout the monitoring exercise. The field blanks must be
installed under a protective hood/cover at the sampling location,
but the long-term storage caps must remain in place throughout the
monitoring period (see Method 325A). The field blanks are then
shipped back to the laboratory in the same container as the sampled
tubes. One field blank tube is required for every 10 sampled tubes
on a monitoring exercise and no less than two field blanks should be
collected, regardless of the size of the monitoring study.
9.3.3 Field blanks must contain no greater than one-third of the
measured target analyte or compliance limit for field samples (see
Table 17.1). If either field blank fails, flag all data that do not
meet this criterion with a note that the associated results are
estimated and likely to be biased high due to field blank
background.

9.4 Duplicate Samples

Duplicate (co-located) samples collected must be analyzed and
reported as part of method quality control. They are used to
evaluate sampling and analysis precision. Relevant performance
criteria are given in Section 9.9.

9.5 Method Performance Criteria

Unless otherwise noted, monitoring method performance
specifications must be demonstrated for the target compounds using
the procedures described in Addendum A to this method and the
statistical approach presented in Method 301.

9.6 Method Detection Limit

Determine the method detection limit under the analytical
conditions selected (see Section 11.3) using the procedure in
Section 15 of Method 301. The method detection limit is defined for
each system by making seven replicate measurements of a
concentration of the compound of interest within a factor of five of
the detection limit. Compute the standard deviation for the seven
replicate concentrations, and multiply this value by three. The
results should demonstrate that the method is able to detect
analytes such as benzene at concentrations as low as 50 ppt or 1/3rd
(preferably 1/10th) of the lowest concentration of interest,
whichever is larger.

Note: Determining the detection limit may be an iterative
process as described in 40 CFR part 136, Appendix B.

9.7 Analytical Bias

Analytical bias must be demonstrated to be within 30 percent using Equation 9.1. Analytical bias must be
demonstrated during initial setup of this method and as part of the
CCV carried out with every sequence of 10 samples or less (see
Section 9.14). Calibration standard tubes (see Section 10.0) may be
used for this purpose.

[GRAPHIC] [TIFF OMITTED] TR01DE15.032

Eq. 9.1Where:

Spiked Value = A known mass of VOCs added to the tube.
Measured Value = Mass determined from analysis of the tube.

9.8 Analytical Precision

Demonstrate an analytical precision within 20
percent using Equation 9.2. Analytical precision must be
demonstrated during initial setup of this method and at least once
per year. Calibration standard tubes may be used (see Section 10.0)
and data from CCV may also be applied for this purpose.
[GRAPHIC] [TIFF OMITTED] TR01DE15.033

Eq. 9.2Where:

A1 = A measurement value taken from one spiked tube.
A2 = A measurement value taken from a second spiked tube.
A = The average of A1 and A2.

9.9 Field Replicate Precision

Use Equation 9.3 to determine and report replicate precision for
duplicate field samples (see Section 9.4). The level of agreement
between duplicate field samples is a measure of the precision
achievable for the entire sampling and analysis procedure. Flag data
sets for which the duplicate samples do not agree within 30 percent.
[GRAPHIC] [TIFF OMITTED] TR01DE15.034

Eq. 9.3Where:
F1 = A measurement value (mass) taken from one of the two field
replicate tubes used in sampling.
F2 = A measurement value (mass) taken from the second of two field
replicate tubes used in sampling.
F = The average of F1 and F2.

9.10 Desorption Efficiency and Compound Recovery

The efficiency of the thermal desorption method must be
determined.
9.10.1 Quantitative (>95 percent) compound recovery must be
demonstrated by repeat analyses on a same standard tube.
9.10.2 Compound recovery through the TD system can also be
demonstrated by comparing the calibration check sample response
factor obtained from direct GC injection of liquid standards with
that obtained from thermal desorption analysis response factor using
the same column under identical conditions.
9.10.3 If the relative response factors obtained for one or more
target compounds introduced to the column via thermal desorption
fail to meet the criteria in Section 9.10.1, you must adjust the TD
parameters to meet the criteria and repeat the experiment. Once the
thermal desorption conditions have been optimized, you must repeat
this test each time the analytical system is recalibrated to
demonstrate continued method performance.

9.11 Audit Samples

Certified reference standard samples must be used to audit this
procedure (if available). Accuracy within 30 percent must be

[[Page 75339]]

demonstrated for relevant ambient air concentrations (0.5 to 25
ppb).

9.12 Mass Spectrometer Tuning Criteria

Tune the mass spectrometer (if used) according to manufacturer's
specifications. Verify the instrument performance by analyzing a 50
[eta]g injection of bromofluorobenzene. Prior to the beginning of
each analytical sequence or every 24 hours during continuous GC/MS
operation for this method demonstrate that the bromofluorobenzene
tuning performance criteria in Table 9.1 have been met.

Table 9.1--GC/MS Tuning Criteria \1\
----------------------------------------------------------------------------------------------------------------
Target mass Rel. to mass Lower limit % Upper limit %
----------------------------------------------------------------------------------------------------------------
50.............................................................. 95 8 40
75.............................................................. 95 30 66
95.............................................................. 95 100 100
96.............................................................. 95 5 9
173............................................................. 174 0 2
174............................................................. 95 50 120
175............................................................. 174 4 9
176............................................................. 174 93 101
177............................................................. 176 5 9
----------------------------------------------------------------------------------------------------------------
\1\ All ion abundances must be normalized to m/z 95, the nominal base peak, even though the ion abundance of m/z
174 may be up to 120 percent that of m/z 95.

9.13 Routine CCV at the Start of a Sequence

Run CCV before each sequence of analyses and after every tenth
sample to ensure that the previous multi-level calibration (see
Section 10.6.3) is still valid.
9.13.1 The sample concentration used for the CCV should be near
the mid-point of the multi-level calibration range.
9.13.2 Quantitation software must be updated with response
factors determined from the CCV standard. The percent deviation
between the initial calibration and the CCV for all compounds must
be within 30 percent.

9.14 CCV at the End of a Sequence

Run another CCV after running each sequence of samples. The
initial CCV for a subsequent set of samples may be used as the final
CCV for a previous analytical sequence, provided the same analytical
method is used and the subsequent set of samples is analyzed
immediately (within 4 hours) after the last CCV.

9.15 Additional Verification

Use a calibration check standard from a second, separate source
to verify the original calibration at least once every three months.

9.16 Integration Method

Document the procedure used for integration of analytical data
including field samples, calibration standards and blanks.

9.17 QC Records

Maintain all QC reports/records for each TD/GC/MS analytical
system used for application of this method. Routine quality control
requirements for this method are listed below and summarized in
Table 17.1.

10.0 Calibration and Standardization

10.1 Calibrate the analytical system using standards covering
the range of analyte masses expected from field samples.
10.2 Analytical results for field samples must fall within the
calibrated range of the analytical system to be valid.
10.3 Calibration standard preparation must be fully traceable to
primary standards of mass and/or volume, and/or be confirmed using
an independent certified reference method.
10.3.1 Preparation of calibration standard tubes from standard
atmospheres.
10.3.1.1 Subject to the requirements in Section 7.2.1, low-level
standard atmospheres may be introduced to clean, conditioned sorbent
tubes in order to produce calibration standards.
10.3.1.2 The standard atmosphere generator or system must be
capable of producing sufficient flow at a constant rate to allow the
required analyte mass to be introduced within a reasonable time
frame and without affecting the concentration of the standard
atmosphere itself.
10.3.1.3 The sampling manifold may be heated to minimize risk of
condensation but the temperature of the gas delivered to the sorbent
tubes may not exceed 100[emsp14][deg]F.
10.3.1.4 The flow rates passed through the tube should be in the
order of 50-100 mL/min and the volume of standard atmosphere sampled
from the manifold or chamber must not exceed the breakthrough volume
of the sorbent at the given temperature.
10.4 Preparation of calibration standard tubes from concentrated
gas standards.
10.4.1 If a suitable concentrated gas standard (see Section
7.2.2) can be obtained, follow the manufacturer's recommendations
relating to suitable storage conditions and product lifetime.
10.4.2 Introduce precise 0.5 to 500.0 mL aliquots of the
standard to the sampling end of conditioned sorbent tubes in a 50-
100 mL/min flow of pure carrier gas.

Note: This can be achieved by connecting the sampling end of the
tube to an unheated GC injector (see Section 6.6) and introducing
the aliquot of gas using a suitable gas syringe. Gas sample valves
could alternatively be used to meter the standard gas volume.

10.4.3 Each sorbent tube should be left connected to the flow of
gas for 2 minutes after standard introduction. As soon as each
spiked tube is removed from the injection unit, seal it with long-
term storage caps and place it in an appropriate tube storage/
transportation container if it is not to be analyzed within 24
hours.
10.5 Preparation of calibration standard tubes from liquid
standards.
10.5.1 Suitable standards are described in Section 7.3.
10.5.2 Introduce precise 0.5 to 2 [micro]l aliquots of liquid
standards to the sampling end of sorbent tubes in a flow (50-100 mL/
min) of carrier gas using a precision syringe and an unheated
injector (Section 6.5). The flow of gas should be sufficient to
completely vaporize the liquid standard.

Note: If the analytes of interest are higher boiling than n-
decane, reproducible analyte transfer to the sorbent bed is
optimized by allowing the tip of the syringe to gently touch the
sorbent retaining gauze at the sampling end of the tube.

10.5.3 Each sorbent tube is left connected to the flow of gas
for 5 minutes after liquid standard introduction.
10.5.3.1 As soon as each spiked tube is removed from the
injection unit, seal it with long-term storage caps and place it in
an appropriate tube storage container if it is not to be analyzed
within 24 hours.

Note: In cases where it is possible to selectively purge the
solvent from the tube while all target analytes are quantitatively
retained, a larger 2 [micro]L injection may be made for optimum
accuracy. However, if the solvent cannot be selectively purged and
will be present during analysis, the injection volume should be as
small as possible (e.g., 0.5 [micro]L) to minimize solvent
interference.

Note: This standard preparation technique requires the entire
liquid plug including the tip volume be brought into the syringe
barrel. The volume in the barrel is recorded, the syringe is
inserted into the septum of the spiking apparatus. The liquid is
then quickly injected. Any remaining liquid in the syringe tip is
brought back into the syringe barrel. The volume in the barrel is
recorded and the amount spiked onto the tube is the difference
between the before spiking volume and the after spiking volume. A
bias occurs with this method when sample is drawn continuously up
into the syringe to the specified volume

[[Page 75340]]

and the calibration solution in the syringe tip is ignored.

10.6 Preparation of calibration standard tubes from multiple
standards.
10.6.1 If it is not possible to prepare one standard containing
all the compounds of interest (e.g., because of chemical reactivity
or the breadth of the volatility range), standard tubes can be
prepared from multiple gas or liquid standards.
10.6.2 Follow the procedures described in Sections 10.4 and
10.5, respectively, for introducing each gas and/or liquid standard
to the tube and load those containing the highest boiling compounds
of interest first and the lightest species last.
10.7 Additional requirements for preparation of calibration
tubes.
10.7.1 Storage of Calibration Standard Tubes
10.7.1.1 Seal tubes with long-term storage caps immediately
after they have been disconnected from the standard loading manifold
or injection apparatus.
10.7.1.2 Calibration standard tubes may be stored for no longer
than 30 days and should be refrigerated if there is any risk of
chemical interaction or degradation. Audit standards (see section
9.11) are exempt from this criteria and may be stored for the shelf-
life specified on their certificates.
10.8 Keep records for calibration standard tubes to include the
following:
10.8.1 The stock number of any commercial liquid or gas
standards used.
10.8.2 A chromatogram of the most recent blank for each tube
used as a calibration standard together with the associated
analytical conditions and date of cleaning.
10.8.3 Date of standard loading.
10.8.4 List of standard components, approximate masses and
associated confidence levels.
10.8.5 Example analysis of an identical standard with associated
analytical conditions.
10.8.6 A brief description of the method used for standard
preparation.
10.8.7 The standard's expiration date.
10.9 TD/GC/MS using standard tubes to calibrate system response.
10.9.1 Verify that the TD/GC/MS analytical system meets the
instrument performance criteria given in Section 9.1.
10.9.2 The prepared calibration standard tubes must be analyzed
using the analytical conditions applied to field samples (see
Section 11.0) and must be selected to ensure quantitative transfer
and adequate chromatographic resolution of target compounds,
surrogates, and internal standards in order to enable reliable
identification and quantitation of compounds of interest. The
analytical conditions should also be sufficiently stringent to
prevent buildup of higher boiling, non-target contaminants that may
be collected on the tubes during field monitoring.
10.9.3 Calibration range. Each TD/GC/MS system must be
calibrated at five concentrations that span the monitoring range of
interest before being used for sample analysis. This initial multi-
level calibration determines instrument sensitivity under the
analytical conditions selected and the linearity of GC/MS response
for the target compounds. One of the calibration points must be
within a factor of five of the detection limit for the compounds of
interest.
10.9.4 One of the calibration points from the initial
calibration curve must be at the same concentration as the daily CCV
standard (e.g., the mass collected when sampling air at typical
concentrations).
10.9.5 Calibration frequency. Each GC/MS system must be
recalibrated with a full 5-point calibration curve following
corrective action (e.g., ion source cleaning or repair, column
replacement) or if the instrument fails the daily calibration
acceptance criteria.
10.9.5.1 CCV checks must be carried out on a regular routine
basis as described in Section 9.14.
10.9.5.2 Quantitation ions for the target compounds are shown in
Table 10.1. Use the primary ion unless interferences are present, in
which case you should use a secondary ion.

Table 10.1--Clean Air Act Volatile Organic Compounds for Passive Sorbent Sampling
--------------------------------------------------------------------------------------------------------------------------------------------------------
Vapor Characteristic ion(s)
Compound CAS No. BP ([deg]C) pressure MW \b\ ----------------------------------
(mmHg) \a\ Primary Secondary
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,1-Dichloroethene................................... 75-35-4 32 500 96.9 61 96
3-Chloropropene...................................... 107-05-1 44.5 340 76.5 76 41, 39, 78
1,1,2-Trichloro-1,2,2-trifluoroethane-1,1- 75-34-3 57.0 230 99 63 65, 83, 85, 98,
Dichloroethane...................................... 100
1,2-Dichloroethane................................... 107-06-2 83.5 61.5 99 62 98
1,1,1-Trichloroethane................................ 71-55-6 74.1 100 133.4 97 99, 61
Benzene.............................................. 71-43-2 80.1 76.0 78 78 .................
Carbon tetrachloride................................. 56-23-5 76.7 90.0 153.8 117 119
1,2-Dichloropropane.................................. 78-87-5 97.0 42.0 113 63 112
Trichloroethene...................................... 79-01-6 87.0 20.0 131.4 95 97, 130, 132
1,1,2-Trichloroethane................................ 79-00-5 114 19.0 133.4 83 97, 85
Toluene.............................................. 108-88-3 111 22.0 92 92 91
Tetrachloroethene.................................... 127-18-4 121 14.0 165.8 164 129, 131, 166
Chlorobenzene........................................ 108-90-7 132 8.8 112.6 112 77, 114
Ethylbenzene......................................... 100-41-4 136 7.0 106 91 106
m,p-Xylene........................................... 108-38-3, 106- 138 6.5 106.2 106 91
42-3
Styrene.............................................. 100-42-5 145 6.6 104 104 78
o-Xylene............................................. 95-47-6 144 5.0 106.2 106 91
p-Dichlorobenzene.................................... 106-46-7 173 0.60 147 146 111, 148
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Pressure in millimeters of mercury.
\b\ Molecular weight.

11.0 Analytical Procedure

11.1 Preparation for Sample Analysis

11.1.1 Each sequence of analyses must be ordered as follows:
11.1.1.1 CCV.
11.1.1.2 A laboratory blank.
11.1.1.3 Field blank.
11.1.1.4 Sample(s).
11.1.1.5 Field blank.
11.1.1.6 CCV after 10 field samples.
11.1.1.7 CCV at the end of the sample batch.

11.2 Pre-desorption System Checks and Procedures

11.2.1 Ensure all sample tubes and field blanks are at ambient
temperature before removing them from the storage container.
11.2.2 If using an automated TD/GC/MS analyzer, remove the long-
term storage caps from the tubes, replace them with appropriate
analytical caps, and load them into the system in the sequence
described in Section 11.1. Alternatively, if using a manual system,
uncap and analyze each tube, one at a time, in the sequence
described in Section 11.1.
11.2.3 The following thermal desorption system integrity checks
and procedures are required before each tube is analyzed.

[[Page 75341]]

Note: Commercial thermal desorbers should implement these steps
automatically.

11.2.3.1 Tube leak test: Each tube must be leak tested as soon
as it is loaded into the carrier gas flow path before analysis to
ensure data integrity.
11.2.3.2 Conduct the leak test at the GC carrier gas pressure,
without heat or gas flow applied. Tubes that fail the leak test
should not be analyzed, but should be resealed and stored intact. On
automated systems, the instrument should continue to leak test and
analyze subsequent tubes after a given tube has failed. Automated
systems must also store and record which tubes in a sequence have
failed the leak test. Information on failed tubes should be
downloaded with the batch of sequence information from the
analytical system.
11.2.3.3 Leak test the sample flow path. Leak check the sample
flow path of the thermal desorber before each analysis without heat
or gas flow applied to the sample tube. Stop the automatic sequence
of tube desorption and GC analysis if any leak is detected in the
main sample flow path. This process may be carried out as a separate
step or as part of Section 11.2.3.2.

11.2.4 Optional Dry Purge

11.2.4.1 Tubes may be dry purged with a flow of pure dry gas
passing into the tube from the sampling end, to remove water vapor
and other very volatile interferents if required.

11.2.5 Internal Standard (IS) Addition

11.2.5.1 Use the internal standard addition function of the
automated thermal desorber (if available) to introduce a precise
aliquot of the internal standard to the sampling end of each tube
after the leak test and shortly before primary (tube) desorption).

Note: This step can be combined with dry purging the tube
(Section 11.2.4) if required.

11.2.5.2 If the analyzer does not have a facility for automatic
IS addition, gas or liquid internal standard can be manually
introduced to the sampling end of tubes in a flow of carrier gas
using the types of procedure described in Sections 10.3 and 10.4,
respectively.
11.2.6 Pre-purge. Each tube should be purged to vent with
carrier gas flowing in the desorption direction (i.e., flowing into
the tube from the non-sampling end) to remove oxygen before heat is
applied. This is to prevent analyte and sorbent oxidation and to
prevent deterioration of key analyzer components such as the GC
column and mass spectrometer (if applicable). A series of schematics
illustrating these steps is presented in Figures 17.2 and 17.3.

11.3 Analytical Procedure

11.3.1 Steps Required for Thermal Desorption

11.3.1.1 Ensure that the pressure and purity of purge and
carrier gases supplying the TD/GC/MS system, meet manufacturer
specifications and the requirements of this method.
11.3.1.2 Ensure also that the analytical method selected meets
the QC requirements of this method (Section 9) and that all the
analytical parameters are at set point.
11.3.1.3 Conduct predesorption system checks (see Section 11.2).
11.3.1.4 Desorb the sorbent tube under conditions demonstrated
to achieve >95 percent recovery of target compounds (see Section
9.5.2).

Note: Typical tube desorption conditions range from 280-350
[deg]C for 5-15 minutes with a carrier gas flow of 30-100 mL/min
passing through the tube from the non-sampling end such that
analytes are flushed out of the tube from the sampling end. Desorbed
VOCs are concentrated (refocused) on a secondary, cooled sorbent
trap integrated into the analytical equipment (see Figure 17.4). The
focusing trap is typically maintained at a temperature between -30
and +30 [deg]C during focusing. Selection of hydrophobic sorbents
for focusing and setting a trapping temperature of +25 to 27 [deg]C
aid analysis of humid samples because these settings allow selective
elimination of any residual water from the system, prior to GC/MS
analysis.

Note: The transfer of analytes from the tube to the focusing
trap during primary (tube) desorption can be carried out splitless
or under controlled split conditions (see Figure 17.4) depending on
the masses of target compounds sampled and the requirements of the
system--sensitivity, required calibration range, column overload
limitations, etc. Instrument controlled sample splits must be
demonstrated by showing the reproducibility using calibration
standards. Field and laboratory blank samples must be analyzed at
the same split as the lowest calibration standard. During secondary
(trap) desorption the focusing trap is heated rapidly (typically at
rates >40 [deg]C/s) with inert (carrier) gas flowing through the
trap (3-100 mL/min) in the reverse direction to that used during
focusing.

11.3.1.5 The split conditions selected for optimum field sample
analysis must also be demonstrated on representative standards.

Note: Typical trap desorption temperatures are in the range
250-360 [deg]C, with a ``hold'' time of 1-3 minutes at the highest
temperature. Trap desorption automatically triggers the start of GC
analysis. The trap desorption can also be carried out under
splitless conditions (i.e., with everything desorbed from the trap
being transferred to the analytical column and GC detector) or, more
commonly, under controlled split conditions (see Figure 17.4). The
selected split ratio depends on the masses of target compounds
sampled and the requirements of the system--sensitivity, required
calibration range, column overload limitations, etc. If a split is
selected during both primary (trap) desorption and secondary (trap)
desorption, the overall split ratio is the product of the two. Such
`double' split capability gives optimum flexibility for
accommodating concentrated samples as well as trace-level samples on
the TD/GC/MS analytical system. High resolution capillary columns
and most GC/MS detectors tend to work best with approximately 20-200
ng per compound per tube to avoid saturation. The overall split
ratio must be adjusted such that, when it is applied to the sample
mass that is expected to be collected during field monitoring, the
amount reaching the column will be attenuated to fall within this
range. As a rule of thumb this means that ~20 ng samples will
require splitless or very low split analysis, ~2 [micro]g samples
will require a split ratio in the order of ~50:1 and 200 [micro]g
samples will require a double split method with an overall split
ratio in the order of 2,000:1.

11.3.1.6 Analyzed tubes must be resealed with long-term storage
caps immediately after analysis (manual systems) or after completion
of a sequence (automated systems). This prevents contamination,
minimizing the extent of tube reconditioning required before
subsequent reuse.

11.3.2 GC/MS Analytical Procedure

11.3.2.1 Heat/cool the GC oven to its starting set point.
11.3.2.2 If using a GC/MS system, it can be operated in either
MS-Scan or MS-SIM mode (depending on required sensitivity levels and
the type of mass spectrometer selected). As soon as trap desorption
and transfer of analytes into the GC column triggers the start of
the GC/MS analysis, collect mass spectral data over a range of
masses from 35 to 300 amu. Collect at least 10 data points per
eluting chromatographic peak in order to adequately integrate and
quantify target compounds.
11.3.2.3 Use secondary ion quantitation only when there are
sample matrix interferences with the primary ion. If secondary ion
quantitation is performed, flag the data and document the reasons
for the alternative quantitation procedure.
11.3.2.4 Data reduction is performed by the instruments post
processing program that is automatically accessed after data
acquisition is completed at the end of the GC run. The concentration
of each target compound is calculated using the previously
established response factors for the CCV analyzed in Section
11.1.1.6.
11.3.2.5 Whenever the thermal desorption--GC/MS analytical
method is changed or major equipment maintenance is performed, you
must conduct a new five-level calibration (see Section 10.6.3).
System calibration remains valid as long as results from subsequent
CCV are within 30 percent of the most recent 5-point calibration
(see Section 10.9.5). Include relevant CCV data in the supporting
information in the data report for each set of samples.
11.3.2.6 Document, flag and explain all sample results that
exceed the calibration range. Report flags and provide documentation
in the analytical results for the affected sample(s).

12.0 Data Analysis, Calculations, and Reporting

12.1 Recordkeeping Procedures for Sorbent Tubes

12.1.1 Label sample tubes with a unique identification number as
described in Section 6.3.
12.1.2 Keep records of the tube numbers and sorbent lots used
for each sampling period.
12.1.3 Keep records of sorbent tube packing if tubes are
manually prepared in the

[[Page 75342]]

laboratory and not supplied commercially. These records must include
the masses and/or bed lengths of sorbent(s) contained in each tube,
the maximum allowable temperature for that tube and the date each
tube was packed. If a tube is repacked at any stage, record the date
of tube repacking and any other relevant information required in
Section 12.1.
12.1.4 Keep records of the conditioning and blanking of tubes.
These records must include, but are not limited to, the unique
identification number and measured background resulting from the
tube conditioning.
12.1.5 Record the location, dates, tube identification and times
associated with each sample collection. Record this information on a
Chain of Custody form that is sent to the analytical laboratory.
12.1.6 Field sampling personnel must complete and send a Chain
of Custody to the analysis laboratory (see Section 8.6.4 of Method
325A for what information to include and Section 17.0 of this method
for an example form). Duplicate copies of the Chain of Custody must
be included with the sample report and stored with the field test
data archive.
12.1.7 Field sampling personnel must also keep records of the
unit vector wind direction, sigma theta, temperature and barometric
pressure averages for the sampling period. See Section 8.3.4 of
Method 325A.
12.1.8 Laboratory personnel must record the sample receipt date,
and analysis date.
12.1.9 Laboratory personnel must maintain records of the
analytical method and sample results in electronic or hardcopy in
sufficient detail to reconstruct the calibration, sample, and
quality control results from each sampling period.

12.2 Calculations

12.2.1 Complete the calculations in this section to determine
compliance with calibration quality control criteria (see also Table
17.1).
12.2.1.1 Response factor (RF). Calculate the RF using Equation
12.1:
[GRAPHIC] [TIFF OMITTED] TR01DE15.035

Where:

As = Peak area for the characteristic ion of the analyte.
Ais = Peak area for the characteristic ion of the
internal standard.
Ms = Mass of the analyte.
Mis = Mass of the internal standard.

12.2.1.2 Standard deviation of the response factors
(SDRF). Calculate the SDRF using Equation 12.2:
[GRAPHIC] [TIFF OMITTED] TR01DE15.036

Where:

RFi = RF for each of the calibration compounds.
RF = Mean RF for each compound from the initial calibration.
n = Number of calibration standards.

12.2.1.3 Percent deviation (%DEV). Calculate the %DEV using
Equation 12.3:
[GRAPHIC] [TIFF OMITTED] TR01DE15.037

Where:

SDRF = Standard deviation.
RF = Mean RF for each compound from the initial calibration.

12.2.1.4 Relative percent difference (RPD). Calculate the RPD
using Equation 12.4:
[GRAPHIC] [TIFF OMITTED] TR01DE15.038

Where:

R1, R2 = Values that are being compared (i.e., response factors in
CCV).

12.2.2 Determine the equivalent concentration of compounds in
atmospheres as follows.
12.2.3 Correct target concentrations determined at the sampling
site temperature and atmospheric pressure to standard conditions (25
[deg]C and 760 mm mercury) using Equation 12.5 (Reference 21).
[GRAPHIC] [TIFF OMITTED] TR01DE15.039

Where:

tss = The average temperature during the collection
period at the sampling site (K).
Pss = The average pressure at the sampling site during
the collection period (mm Hg).
U = The diffusive uptake rate (sampling rate) (mL/min).

[[Page 75343]]

12.2.4 For passive sorbent tube samples, calculate the
concentration of the target compound(s) in the sampled air, in
[mu]g/m³ by using Equation 12.6 (Reference 22).
[GRAPHIC] [TIFF OMITTED] TR01DE15.040

Where:

Cm = The concentration of target compound in the air
sampled ([mu]g/m³).
mmeas = The mass of the compound as measured in the
sorbent tube ([mu]g).
UNTP = The diffusive uptake rate corrected for local
conditions (sampling rate) (mL/min).
t = The exposure time (minutes).

Note: Diffusive uptake rates for common VOCs, using carbon
sorbents packed into sorbent tubes of the dimensions specified in
Section 6.1, are listed in Table 12.1. Adjust analytical conditions
to keep expected sampled masses within range (see Sections 11.3.1.3
to 11.3.1.5). Best possible method detection limits are typically in
the order of 0.1 ppb for 1,3-butadiene and 0.05 ppb for volatile
aromatics such as benzene for 14-day monitoring. However, actual
detection limits will depend upon the analytical conditions
selected.

Table 12.1--Validated Sorbents and Uptake Rates (mL/min) for Selected Clean Air Act Compounds
----------------------------------------------------------------------------------------------------------------
Compound Carbopack\TM\ X\a\ Carbograph\TM\ 1 TD Carbopack\TM\ B
----------------------------------------------------------------------------------------------------------------
1,1-Dichloroethene............... 0.57 not available.............. not available.
0.14
3-Chloropropene.................. 0.51 not available.............. not available.
0.3
1,1-Dichloroethane............... 0.57 not available.............. not available.
0.1
1,2-Dichloroethane............... 0.57 not available.............. not available.
0.08
1,1,1-Trichloroethane............ 0.51 not available.............. not available.
0.1
Benzene.......................... 0.67 0.63 0.07\b\.. 0.63 0.07\b\.
0.06
Carbon tetrachloride............. 0.51 not available.............. not available.
0.06
1,2-Dichloropropane.............. 0.52 not available.............. not available.
0.1
Trichloroethene.................. 0.5 not available.............. not available.
0.05
1,1,2-Trichloroethane............ 0.49 not available.............. not available.
0.13
Toluene.......................... 0.52 0.56 0.06\c\.. 0.56 0.06\c\.
0.14
Tetrachloroethene................ 0.48 not available.............. not available.
0.05
Chlorobenzene.................... 0.51 not available.............. not available.
0.06
Ethylbenzene..................... 0.46 not available.............. 0.50\c\.
0.07
m,p-Xylene....................... 0.46 0.47 0.04\c\.. 0.47 0.04\c\.
0.09
Styrene.......................... 0.5 not available.............. not available.
0.14
o-Xylene......................... 0.46 0.47 0.04\c\.. 0.47 0.04\c\.
0.12
p-Dichlorobenzene................ 0.45 not available.............. not available.
0.05
----------------------------------------------------------------------------------------------------------------
\a\ Reference 3, McClenny, J. Environ. Monit. 7:248-256. Based on 24-hour duration.
\b\ Reference 24, BS EN 14662-4:2005 (incorporated by reference--see Sec. 63.14). Based on 14-day duration.
\c\ Reference 25, ISO 16017-2:2003(E) (incorporated by reference--see Sec. 63.14). Based on 14-day duration.

13.0 Method Performance

The performance of this procedure for VOC not listed in Table
12.1 is determined using the procedure in Addendum A of this Method
or by one of the following national/international standard methods:
ISO 16017-2:2003(E), ASTM D6196-03 (Reapproved 2009), or BS EN
14662-4:2005 (all incorporated by reference--see Sec. 63.14).
13.1 The valid range for measurement of VOC is approximately 0.5
[micro]g/m\3\ to 5 mg/m\3\ in air, collected over a 14-day sampling
period. The upper limit of the useful range depends on the split
ratio selected (Section 11.3.1) and the dynamic range of the
analytical system. The lower limit of the useful range depends on
the noise from the analytical instrument detector and on the blank
level of target compounds or interfering compounds on the sorbent
tube (see Section 13.3).
13.2 Diffusive sorbent tubes compatible with passive sampling
and thermal desorption methods have been evaluated at relatively
high atmospheric concentrations (i.e., mid-ppb to ppm) and published
for use in workplace air and industrial/mobile source emissions
(References 15-16, 21-22).
13.3 Best possible detection limits and maximum quantifiable
concentrations of air pollutants range from sub-part-per-trillion
(sub-ppt) for halogenated species such as CCl4 and the freons using
an electron capture detector (ECD), SIM Mode GC/MS, triple quad MS
or GC/TOF MS to sub-ppb for volatile hydrocarbons collected over 72
hours followed by analysis using GC with quadrupole MS operated in
the full SCAN mode.
13.3.1 Actual detection limits for atmospheric monitoring vary
depending on several key factors. These factors are:
Minimum artifact levels.
GC detector selection.
Time of exposure for passive sorbent tubes.
Selected analytical conditions, particularly column
resolution and split ratio.

14.0 Pollution Prevention

This method involves the use of ambient concentrations of
gaseous compounds that post little or no danger of pollution to the
environment.

15.0 Waste Management

Dispose of expired calibration solutions as hazardous materials.
Exercise standard laboratory environmental practices to minimize the
use and disposal of laboratory solvents.

16.0 References

1. Winberry, W. T. Jr., et al., Determination of Volatile Organic
Compounds in Ambient Air Using Active Sampling onto Sorbent Tubes:
Method TO-17r, Second Edition, U.S. Environmental Protection Agency,
Research Triangle Park, NC 27711, January 1999. https://www.epa.gov/ttnamti1/airtox.html#compendium
2. Ciccioli, P., Brancaleoni, E., Cecinato, A., Sparapini, R., and
Frattoni, M., ``Identification and Determination of Biogenic and
Anthropogenic VOCs in Forest Areas of Northern and Southern Europe
and a Remote Site of the Himalaya Region by High-resolution GC-MS,''
J. of Chrom., 643, pp 55-69, 1993.
3. McClenny, W.A., K.D. Oliver, H.H. Jacumin, Jr., E.H. Daughtrey,
Jr., D.A. Whitaker. 2005. 24 h diffusive sampling of toxic VOCs in
air onto Carbopack\TM\ X solid adsorbent followed by thermal

[[Page 75344]]

desorption/GC/MS analysis--laboratory studies. J. Environ. Monit.
7:248-256.
4. Markes International (www.markes.com/publications): Thermal
desorption Technical Support Note 2: Prediction of uptake rates for
diffusive tubes.
5. Ciccioli, P., Brancaleoni, E., Cecinato, A., DiPalo, C.,
Brachetti, A., and Liberti, A., ``GC Evaluation of the Organic
Components Present in the Atmosphere at Trace Levels with the Aid of
Carbopack^TM B for Preconcentration of the Sample,'' J. of
Chrom., 351, pp 433-449, 1986.
6. Broadway, G. M., and Trewern, T., ``Design Considerations for the
Optimization of a Packed Thermal Desorption Cold Trap for Capillary
Gas Chromatography,'' Proc. 13th Int'l Symposium on Capil. Chrom.,
Baltimore, MD, pp 310-320, 1991.
7. Broadway, G. M., ``An Automated System for use Without Liquid
Cryogen for the Determination of VOC's in Ambient Air,'' Proc. 14th
Int'l. Symposium on Capil. Chrom., Baltimore, MD, 1992.
8. Gibitch, J., Ogle, L., and Radenheimer, P., ``Analysis of Ozone
Precursor Compounds in Houston, Texas Using Automated Continuous
GCs,'' in Proceedings of the Air and Waste Management Association
Conference: Measurement of Toxic and Related Air Pollutants, Air and
Waste Management Association, Pittsburgh, PA, May 1995.
9. Vandendriessche, S., and Griepink, B., ``The Certification of
Benzene, Toluene and m-Xylene Sorbed on Tenax[supreg] TA in Tubes,''
CRM-112 CEC, BCR, EUR12308 EN, 1989.
10. MDHS 2 (Acrylonitrile in Air), ``Laboratory Method Using Porous
Polymer Adsorption Tubes, and Thermal Desorption with Gas
Chromatographic Analysis,'' Methods for the Determination of
Hazardous Substances (MDHS), UK Health and Safety Executive,
Sheffield, UK.
11. MDHS 22 (Benzene in Air), ``Laboratory Method Using Porous
Polymer Adsorbent Tubes, Thermal Desorption and Gas
Chromatography,'' Method for the Determination of Hazardous
Substances (MDHS), UK Health and Safety Executive, Sheffield, UK.
12. MDHS 23 (Glycol Ether and Glycol Acetate Vapors in Air),
``Laboratory Method Using Tenax[supreg] Sorbent Tubes, Thermal
Desorption and Gas Chromatography,'' Method for the Determination of
Hazardous Substances (MDHS), UK Health and Safety Executive,
Sheffield, UK.
13. MDHS 40 (Toluene in air), ``Laboratory Method Using Pumped
Porous Polymer Adsorbent Tubes, Thermal Desorption and Gas
Chromatography,'' Method for the Determination of Hazardous
Substances (MDHS), UK Health and Safety Executive, Sheffield, UK.
14. MDHS 60 (Mixed Hydrocarbons (C to C) in Air), ``Laboratory
Method Using Pumped Porous Polymer 3 10 and Carbon Sorbent Tubes,
Thermal Desorption and Gas Chromatography,'' Method for the
Determination of Hazardous Substances (MDHS), UK Health and Safety
Executive, Sheffield, UK.
15. Price, J. A., and Saunders, K. J., ``Determination of Airborne
Methyl tert-Butyl Ether in Gasoline Atmospheres,'' Analyst, Vol.
109, pp. 829-834, July 1984.
16. Coker, D. T., van den Hoed, N., Saunders, K. J., and Tindle, P.
E., ``A Monitoring Method for Gasoline Vapour Giving Detailed
Composition,'' Ann. Occup, Hyg., Vol 33, No. 11, pp 15-26, 1989.
17. DFG, ``Analytische Methoden zur prufing gesundheitsschadlicher
Arbeistsstoffe,'' Deutsche Forschungsgemeinschaft, Verlag Chemie,
Weinheim FRG, 1985.
18. NNI, ``Methods in NVN Series (Luchtkwaliteit;
Werkplekatmasfeer),'' Nederlands Normailsatie--Institut, Delft, The
Netherlands, 1986-88.
19. ``Sampling by Solid Adsorption Techniques,'' Standards
Association of Australia Organic Vapours, Australian Standard 2976,
1987.
20. Woolfenden, E. A., ``Monitoring VOCs in Air Using Pumped
Sampling onto Sorbent Tubes Followed by Thermal Desorption-capillary
GC Analysis: Summary of Reported Data and Practical Guidelines for
Successful Application,'' J. Air & Waste Manage. Assoc., Vol. 47,
1997, pp. 20-36.
21. Validation Guidelines for Air Sampling Methods Utilizing
Chromatographic Analysis, OSHA T-005, Version 3.0, May 2010, https://www.osha.gov/dts/sltc/methods/chromguide/chromguide.pdf.
22. ASTM D4597-10, Standard Practice for Sampling Workplace
Atmospheres to collect Gases or Vapors with Solid Sorbent Diffusive
Samplers.
23. Martin, https://www.hsl.gov.uk/media/1619/issue14.pdf.
24. BS EN 14662-4:2005, Ambient air quality--Standard method for the
measurement of benzene concentrations--Part 4: Diffusive sampling
followed by thermal desorption and gas chromatography.
25. ISO 16017-2:2003(E): Indoor, ambient and workplace air--Sampling
and analysis of volatile organic compounds by sorbent tube/thermal
desorption/capillary gas chromatography--Part 2: Diffusive sampling.

17.0 Tables, Diagrams, Flowcharts and Validation Data

Table 17.1--Summary of GC/MS Analysis Quality Control Procedures
----------------------------------------------------------------------------------------------------------------
Parameter Frequency Acceptance criteria Corrective action
----------------------------------------------------------------------------------------------------------------
Bromofluorobenzene Instrument Tune Daily\a\ prior to Evaluation criteria (1) Retune and or
Performance Check. sample analysis. presented in Section (2) Perform
9.5 and Table 9.2. Maintenance.
Five point calibration bracketing the Following any major (1) Percent Deviation (1) Repeat calibration
expected sample concentration. change, repair or (%DEV) of response sample analysis.
maintenance or if factors 30%. check.
meet method (2) Relative Retention (3) Prepare new
requirements. Times (RRTs) for calibration standards
Recalibration not to target peaks 0.06 units from repeat analysis.
mean RRT.
Calibration Verification (CCV Second Following the The response factor (1) Repeat calibration
source calibration verification calibration curve. 30% DEV check.
check). from calibration curve (2) Repeat calibration
average response curve.
factor.
Laboratory Blank Analysis............ Daily \a\ following (1) <=0.2 ppbv per (1) Repeat analysis
bromofluoro- benzene analyte or <=3 times with new blank tube.
and calibration check; the LOD, whichever is (2) Check system for
prior to sample greater. leaks, contamination.
analysis. (2) Internal Standard 3) Analyze additional
(IS) area response blank.
40% and IS
Retention Time (RT)
0.33 min.
of most recent
calibration check.
Blank Sorbent Tube Certification..... One tube analyzed for <0.2 ppbv per VOC Reclean all tubes in
each batch of tubes targeted compound or 3 batch and reanalyze.
cleaned or 10 percent times the LOD,
of tubes whichever is whichever is greater.
greater.
Samples--Internal Standards.......... All samples............ IS area response 40% and IS RT invalidation.
0.33 min.
of most recent
calibration validation.
----------------------------------------------------------------------------------------------------------------
\a\ Every 24 hours.

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ADDENDUM A to Method 325B--Method 325 Performance Evaluation

A.1 Scope and Application

A.1.1 To be measured by Methods 325A and 325B, each new target
volatile organic compound (VOC) or sorbent that is not listed in
Table 12.1 must be evaluated by exposing the selected sorbent tube
to a known concentration of the target compound(s) in an exposure
chamber following the procedure in this Addendum or by following the
procedures in the national/international standard methods: ISO
16017-2:2003(E),

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ASTM D6196-03 (Reapproved 2009), or BS EN 14662-4:2005 (all
incorporated by reference--see Sec. 63.14), or reported in peer-
reviewed open literature.
A.1.2 You must determine the uptake rate and the relative
standard deviation compared to the theoretical concentration of
volatile material in the exposure chamber for each of the tests
required in this method. If data that meet the requirement of this
Addendum are available in the peer reviewed open literature for VOCs
of interest collected on your passive sorbent tube configuration,
then such data may be submitted in lieu of the testing required in
this Addendum.
A.1.3 You must expose sorbent tubes in a test chamber to parts
per trillion by volume (pptv) and low parts per billion by volume
(ppbv) concentrations of VOCs in humid atmospheres to determine the
sorbent tube uptake rate and to confirm compound capture and
recovery.

A.2 Summary of Method

Note: The technique described here is one approach for
determining uptake rates for new sorbent/sorbate pairs. It is
equally valid to follow the techniques described in any one of the
following national/international standards methods: ISO 16017-
2:2003(E), ASTM D6196-03 (Reapproved 2009), or BS EN 14662-4:2005
(all incorporated by reference--see Sec. 63.14).

A.2.1 Known concentrations of VOC are metered into an exposure
chamber containing sorbent tubes filled with media selected to
capture the volatile organic compounds of interest (see Figure A.1
and A.2 for an example of the exposure chamber and sorbent tube
retaining rack). VOC are diluted with humid air and the chamber is
allowed to equilibrate for 6 hours. Clean passive sampling devices
are placed into the chamber and exposed for a measured period of
time. The passive uptake rate of the passive sampling devices is
determined using the standard and dilution gas flow rates. Chamber
concentrations are confirmed with whole gas sample collection and
analysis or direct interface volatile organic compound measurement
methods.
A.2.2 An exposure chamber and known gas concentrations must be
used to challenge and evaluate the collection and recovery of target
compounds from the sorbent and tube selected to perform passive
measurements of VOC in atmospheres.

A.3 Definitions

A.3.1 cc is cubic centimeter.
A.3.2 ECD is electron capture detector.
A.3.3 FID is flame ionization detector.
A.3.4 LED is light-emitting diode.
A.3.5 MFC is mass flow controller.
A.3.6 MFM is mass flow meter.
A.3.7 min is minute.
A.3.8 ppbv is parts per billion by volume.
A.3.9 ppmv is parts per million by volume.
A.3.10 PSD is passive sampling device.
A.3.11 psig is pounds per square inch gauge.
A.3.12 RH is relative humidity.
A.3.13 VOC is volatile organic compound.

A.4 Interferences

A.4.1 VOC contaminants in water can contribute interference or
bias results high. Use only distilled, organic-free water for
dilution gas humidification.
A.4.2 Solvents and other VOC-containing liquids can contaminate
the exposure chamber. Store and use solvents and other VOC-
containing liquids in the exhaust hood when exposure experiments are
in progress to prevent the possibility of contamination of VOCs into
the chamber through the chamber's exhaust vent.

Note: Whenever possible, passive sorbent evaluation should be
performed in a VOC free laboratory.

A.4.3 PSDs should be handled by personnel wearing only clean,
white cotton or powder free nitrile gloves to prevent contamination
of the PSDs with oils from the hands.
A.4.4 This performance evaluation procedure is applicable to
only volatile materials that can be measured accurately with direct
interface gas chromatography or whole gas sample collection,
concentration and analysis. Alternative methods to confirm the
concentration of volatile materials in exposure chambers are subject
to Administrator approval.

A.5 Safety

A.5.1 This procedure does not address all of the safety concerns
associated with its use. It is the responsibility of the user of
this standard to establish appropriate field and laboratory safety
and health practices and determine the applicability of regulatory
limitations prior to use.
A.5.2 Laboratory analysts must exercise appropriate care in
working with high-pressure gas cylinders.

A.6 Equipment and Supplies

A.6.1 You must use an exposure chamber of sufficient size to
simultaneously expose a minimum of eight sorbent tubes.
A.6.2 Your exposure chamber must not contain VOC that interfere
with the compound under evaluation. Chambers made of glass and/or
stainless steel have been used successfully for measurement of known
concentration of selected VOC compounds.
A.6.3 The following equipment and supplies are needed:
Clean, white cotton or nitrile gloves;
Conditioned passive sampling device tubes and diffusion
caps; and
NIST traceable high resolution digital gas mass flow
meters (MFMs) or flow controllers (MFCs).

A.7 Reagents and Standards

A.7.1 You must generate an exposure gas that contains between 35
and 75 percent relative humidity and a concentration of target
compound(s) within 2 to 5 times the concentration to be measured in
the field.
A.7.2 Target gas concentrations must be generated with certified
gas standards and diluted with humid clean air. Dilution to reach
the desired concentration must be done with zero grade air or
better.
A.7.3 The following reagents and standards are needed:
Distilled water for the humidification;
VOC standards mixtures in high-pressure cylinder
certified by the supplier (Note: The accuracy of the certified
standards has a direct bearing on the accuracy of the measurement
results. Typical vendor accuracy is 5 percent accuracy
but some VOC may only be available at lower accuracy (e.g., acrolein
at 10 percent)); and
Purified dilution air containing less than 0.2 ppbv of
the target VOC.

A.8 Sample Collection, Preservation and Storage

A.8.1 You must use certified gas standards diluted with humid
air. Generate humidified air by adding distilled organic free water
to purified or zero grade air. Humidification may be accomplished by
quantitative addition of water to the air dilution gas stream in a
heated chamber or by passing purified air through a humidifying
bubbler. You must control the relative humidity in the test gas
throughout the period of passive sampler exposure.

Note: The RH in the exposure chamber is directly proportional
to the fraction of the purified air that passes through the water in
the bubbler before entering the exposure chamber. Achieving uniform
humidification in the proper range is a trial-and-error process with
a humidifying bubbler. You may need to heat the bubbler to achieve
sufficient humidity. An equilibration period of approximately 15
minutes is required following each adjustment of the air flow
through the humidifier. Several adjustments or equilibration cycles
may be required to achieve the desired RH level.

Note: You will need to determine both the dilution rate and the
humidification rate for your design of the exposure chamber by trial
and error before performing method evaluation tests.

A.8.2 Prepare and condition sorbent tubes following the
procedures in Method 325B Section 7.0.
A.8.3 You must verify that the exposure chamber does not leak.
A.8.4 You must complete two evaluation tests using a minimum of
eight passive sampling tubes in each test with less than 5-percent
depletion of test analyte by the samplers.
A.8.4.1 Perform at least one evaluation at two to five times the
estimated analytical detection limit or less.
A.8.4.2 Perform second evaluation at a concentration equivalent
to the middle of the analysis calibration range.
A.8.5 You must evaluate the samplers in the test chamber
operating between 35 percent and 75 percent RH, and at 25 5 [deg]C. Allow the exposure chamber to equilibrate for 6
hours before starting an evaluation.
A.8.6 The flow rate through the chamber must be <=0.5 meter per
second face velocity across the sampler face.
A.8.7 Place clean, ready to use sorbent tubes into the exposure
chamber for predetermined amounts of time to evaluate collection and
recovery from the tubes. The exposure time depends on the
concentration of volatile test material in the chamber and the
detection limit required for the sorbent tube sampling application.
Exposure time

[[Page 75350]]

should match sample collection time. The sorbent tube exposure
chamber time may not be less than 24 hours and should not be longer
than 2 weeks.
A.8.7.1 To start the exposure, place the clean PSDs equipped
with diffusion caps on the tube inlet into a retaining rack.
A.8.7.2 Place the entire retaining rack inside the exposure
chamber with the diffusive sampling end of the tubes facing into the
chamber flow. Seal the chamber and record the exposure start time,
chamber RH, chamber temperature, PSD types and numbers, orientation
of PSDs, and volatile material mixture composition (see Figure A.2).
A.8.7.3 Diluted, humidified target gas must be continuously fed
into the exposure chamber during cartridge exposure. Measure the
flow rate of target compound standard gas and dilution air to an
accuracy of 5 percent.
A.8.7.4 Record the time, temperature, and RH at the beginning,
middle, and end of the exposure time.
A.8.7.5 At the end of the exposure time, remove the PSDs from
the exposure chamber. Record the exposure end time, chamber RH, and
temperature.
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A.9 Quality Control

A.9.1 Monitor and record the exposure chamber temperature and RH
during PSD exposures.
A.9.2 Measure the flow rates of standards and purified humified
air immediately following PSD exposures.

A.10 Calibration and Standardization

A.10.1 Follow the procedures described in Method 325B Section
10.0 for calibration.
A.10.2 Verify chamber concentration by direct injection into a
gas chromatograph calibrated for the target compound(s) or by
collection of an integrated SUMMA canister followed by analysis
using a preconcentration gas chromatographic method such as EPA
Compendium Method TO-15, Determination of VOCs in Air Collected in
Specially-Prepared Canisters and Analyzed By GC/MS.
A.10.2.1 To use direct injection gas chromatography to verify
the exposure chamber concentration, follow the procedures in Method
18 of 40 CFR part 60, Appendix A-6. The method ASTM D6420-99
(Reapproved 2010) (incorporated by reference--see Sec. 63.14) is an
acceptable alternative to EPA Method 18 of 40 CFR part 60).

Note: Direct injection gas chromatography may not be
sufficiently sensitive for all compounds. Therefore, the whole gas
preconcentration sample and analysis method may be required to
measure at low concentrations.

A.10.2.2 To verify exposure chamber concentrations using SUMMA
canisters,

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prepare clean canister(s) and measure the concentration of VOC
collected in an integrated SUMMA canister over the period used for
the evaluation (minimum 24 hours). Analyze the TO-15 canister sample
following EPA Compendium Method TO-15.
A.10.2.3 Compare the theoretical concentration of volatile
material added to the test chamber to the measured concentration to
confirm the chamber operation. Theoretical concentration must agree
with the measured concentration within 30 percent.

A.11 Analysis Procedure

Analyze the sorbent tubes following the procedures described in
Section 11.0 of Method 325B.

A.12 Recordkeeping Procedures for Sorbent Tube Evaluation

Keep records for the sorbent tube evaluation to include at a
minimum the following information:
A.12.1 Sorbent tube description and specifications.
A.12.2 Sorbent material description and specifications.
A.12.3 Volatile analytes used in the sampler test.
A.12.4 Chamber conditions including flow rate, temperature, and
relative humidity.
A.12.5 Relative standard deviation of the sampler results at the
conditions tested.
A.12.6 95 percent confidence limit on the sampler overall
accuracy.
A.12.7 The relative accuracy of the sorbent tube results
compared to the direct chamber measurement by direct gas
chromatography or SUMMA canister analysis.

A.13 Method Performance

A.13.1 Sorbent tube performance is acceptable if the relative
accuracy of the passive sorbent sampler agrees with the active
measurement method by 10 percent at the 95 percent
confidence limit and the uptake ratio is equal to greater than 0.5
mL/min (1 ng/ppm-min).

Note: For example, there is a maximum deviation comparing
Perkin-Elmer passive type sorbent tubes packed with Carbopack\TM\ X
of 1.3 to 10 percent compared to active sampling using the following
uptake rates.

----------------------------------------------------------------------------------------------------------------
1,3-butadiene Estimated Estimated
uptake rate mL/ detection limit Benzene uptake detection limit (2
min (2 week) rates mL/min week)
----------------------------------------------------------------------------------------------------------------
Carbopack\TM\ X (2 week)........ 0.61 0.1 ppbv 0.67 \a\ 0.05 ppbv
0.11 \a\
----------------------------------------------------------------------------------------------------------------
\a\ McClenny, W.A., K.D. Oliver, H.H. Jacumin, Jr., E.H. Daughtrey, Jr., D.A. Whitaker. 2005. 24 h diffusive
sampling of toxic VOCs in air onto Carbopack\TM\ X solid adsorbent followed by thermal desorption/GC/MS
analysis--laboratory studies. J. Environ. Monit. 7:248-256.

A13.2 Data Analysis and Calculations for Method Evaluation
A.13.2.1 Calculate the theoretical concentration of VOC
standards using Equation A.1.
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Where:

Cf = The final concentration of standard in the exposure
chamber (ppbv).
FRi = The flow rate of the target compound I (mL/min).
FRt = The flow rate of all target compounds from separate
if multiple cylinders are used (mL/min).
FRa = The flow rate of dilution air plus moisture (mL/
min).
Cs = The concentration of target compound in the standard
cylinder (parts per million by volume).

A.13.2.3 Determine the uptake rate of the target gas being
evaluated using Equation A.2.
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Where:

Mx = The mass of analyte measured on the sampling tube
([eta]g).
Ce = The theoretical exposure chamber concentration
([eta]g/mL).
Tt = The exposure time (minutes).

A.13.2.4 Estimate the variance (relative standard deviation
(RSD)) of the inter-sampler results at each condition tested using
Equation A.3. RSD for the sampler is estimated by pooling the
variance estimates from each test run.
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Where:

Xi = The measured mass of analyte found on sorbent tube
i.
Xi = The mean value of all Xi.
n = The number of measurements of the analyte.

A.13.2.4 Determine the percent relative standard deviation of
the inter-sampler results using Equation A.4.

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A.13.2.5 Determine the 95 percent confidence interval for the
sampler results using Equation A.5. The confidence interval is
determined based on the number of test runs performed to evaluate
the sorbent tube and sorbent combination. For the minimum test
requirement of eight samplers tested at two concentrations, the
number of tests is 16 and the degrees of freedom are 15.
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Where:

[Delta]95% = 95 percent confidence interval.
%RSD = percent relative standard deviation.
t0.95 = The Students t statistic for f degrees of freedom
at 95 percent confidence.
f = The number of degrees of freedom.
n = Number of samples.

A.13.2.6 Determine the relative accuracy of the sorbent tube
combination compared to the active sampling results using Equation
A.6.
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Where:
RA = Relative accuracy.
Xi = The mean value of all Xi.
Xi = The average concentration of analyte measured by the
active measurement method.
[Delta]95% = 95 percent confidence interval.

A.14 Pollution Prevention

This method involves the use of ambient concentrations of
gaseous compounds that post little or no pollution to the
environment.

A.15 Waste Management

Expired calibration solutions should be disposed of as hazardous
materials.

A.16 References

1. ISO TC 146/SC 02 N 361 Workplace atmospheres--Protocol for
evaluating the performance of diffusive samplers.

[FR Doc. 2015-26486 Filed 11-30-15; 8:45 am]
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