Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards, 36879-37075 [2014-12167]

Download as PDF Vol. 79 Monday, No. 125 June 30, 2014 Part II Environmental Protection Agency emcdonald on DSK67QTVN1PROD with PROPOSALS2 40 CFR Parts 60 and 63 Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards; Proposed Rule VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00001 Fmt 4717 Sfmt 4717 E:\FR\FM\30JNP2.SGM 30JNP2 36880 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 60 and 63 [EPA–HQ–OAR–2010–0682; FRL–9720–4] RIN 2060–AQ75 Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards Environmental Protection Agency. ACTION: Proposed rule. AGENCY: This action proposes amendments to the national emission standards for hazardous air pollutants for petroleum refineries to address the risk remaining after application of the standards promulgated in 1995 and 2002. This action also proposes amendments to the national emission standards for hazardous air pollutants for petroleum refineries based on the results of the Environmental Protection Agency (EPA) review of developments in practices, processes and control technologies and includes new monitoring, recordkeeping and reporting requirements. The EPA is also proposing new requirements related to emissions during periods of startup, shutdown and malfunction to ensure that the standards are consistent with court opinions issued since promulgation of the standards. This action also proposes technical corrections and clarifications for new source performance standards for petroleum refineries to improve consistency and clarity and address issues raised after the 2008 rule promulgation. Implementation of this proposed rule will result in projected reductions of 1,760 tons per year (tpy) of hazardous air pollutants (HAP), which will reduce cancer risk and chronic health effects. DATES: Comments. Comments must be received on or before August 29, 2014. A copy of comments on the information collection provisions should be submitted to the Office of Management and Budget (OMB) on or before July 30, 2014. Public Hearing. The EPA will hold public hearings on this proposed rule on July 16, 2014, at Banning’s Landing Community Center, 100 E. Water Street, Wilmington, California 90744, and on August 5, 2014, at the Alvin D. Baggett Recreation Building 1302 Keene Street in Galena Park, Texas, 77547. ADDRESSES: Comments. Submit your comments, identified by Docket ID Number EPA– emcdonald on DSK67QTVN1PROD with PROPOSALS2 SUMMARY: VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 HQ–OAR–2010–0682, by one of the following methods: • https://www.regulations.gov: Follow the on-line instructions for submitting comments. • Email: a-and-r-docket@epa.gov. Attention Docket ID Number EPA–HQ– OAR–2010–0682. • Fax: (202) 566–9744. Attention Docket ID Number EPA–HQ–OAR– 2010–0682. • Mail: U.S. Postal Service, send comments to: EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Attention Docket ID Number EPA–HQ–OAR–2010–0682, U.S. Environmental Protection Agency, Mailcode: 28221T, 1200 Pennsylvania Ave. NW., Washington, DC 20460. Please include a total of two copies. In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), Attn: Desk Officer for EPA, 725 17th Street NW., Washington, DC 20503. • Hand Delivery: U.S. Environmental Protection Agency, WJC West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC 20004. Attention Docket ID Number EPA–HQ–OAR–2010–0682. Such deliveries are only accepted during the Docket’s normal hours of operation, and special arrangements should be made for deliveries of boxed information. Instructions. Direct your comments to Docket ID Number EPA–HQ–OAR– 2010–0682. The EPA’s policy is that all comments received will be included in the public docket without change and may be made available online at https://www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be confidential business information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through https:// www.regulations.gov or email. The https://www.regulations.gov Web site is an ‘‘anonymous access’’ system, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through https:// www.regulations.gov, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in PO 00000 Frm 00002 Fmt 4701 Sfmt 4702 the body of your comment and with any disk or CD–ROM you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption and be free of any defects or viruses. For additional information about the EPA’s public docket, visit the EPA Docket Center homepage at: https://www.epa.gov/dockets. Docket. The EPA has established a docket for this rulemaking under Docket ID Number EPA–HQ–OAR–2010–0682. All documents in the docket are listed in the regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy. Publicly available docket materials are available either electronically in regulations.gov or in hard copy at the EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution Ave. NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566–1744, and the telephone number for the EPA Docket Center is (202) 566–1742. Public Hearing. The public hearing will be held in Wilmington, California on July 16, 2014 at Banning’s Landing Community Center, 100 E. Water Street, Wilmington, California 90744. The hearing will convene at 9 a.m. and end at 8 p.m. A lunch break will be held from 1 p.m. until 2 p.m. A dinner break will be held from 5 p.m. until 6 p.m. The public hearing in Galena Park, Texas will be held on August 5, 2014, at the Alvin D. Baggett Recreation Building 1302 Keene Street Galena Park, Texas 77547. The hearing will convene at 9 a.m. and will end at 8 p.m. A lunch break will be held from noon until 1 p.m. A dinner break will be held from 5 p.m. until 6 p.m. Please contact Ms. Virginia Hunt at (919) 541–0832 or at hunt.virginia@epa.gov to register to speak at the hearing. The last day to preregister in advance to speak at the hearing is July 11, 2014, for the Wilmington, California hearing and August 1, 2014, for the Galena Park, Texas hearing. Additionally, requests to speak will be taken the day of the hearing at the hearing registration desk, although preferences on speaking times may not be able to be fulfilled. If you require the service of a translator or E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules special accommodations such as audio description, please let us know at the time of registration. FOR FURTHER INFORMATION CONTACT: For questions about this proposed action, contact Ms. Brenda Shine, Sector Policies and Programs Division (E143– 01), Office of Air Quality Planning and Standards (OAQPS), 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 (OAQPS), 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 National Emissions Standards for Hazardous Air Pollutants (NESHAP) or the New Source Performance Standards (NSPS) to a particular entity, contact Maria Malave, Office of Enforcement and Compliance Assurance (OECA), telephone number: (202) 564–7027; fax number: (202) 564– 0050; and email address: malave.maria@epa.gov. SUPPLEMENTARY INFORMATION: Preamble Acronyms and Abbreviations emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 ACGIH American Conference of Governmental Industrial Hygienists ADAF age-dependent adjustment factors AEGL acute exposure guideline levels AERMOD air dispersion model used by the HEM–3 model APCD air pollution control devices API American Petroleum Institute BDT best demonstrated technology BLD bag leak detectors BSER best system of emission reduction Btu/ft2 British thermal units per square foot Btu/scf British thermal units per standard cubic foot CAA Clean Air Act CalEPA California EPA CBI confidential business information CCU catalytic cracking units Ccz combustion zone combustibles concentration CDDF chlorinated dibenzodioxins and furans CDX Central Data Exchange VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 CEDRI Compliance and Emissions Data Reporting Interface CEMS continuous emissions 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 CRU catalytic reforming units CS2 carbon disulfide DCU delayed coking units DIAL differential absorption light detection and ranging EBU enhanced biological unit EPA Environmental Protection Agency ERPG emergency response planning guidelines ERT Electronic Reporting Tool ESP electrostatic precipitator FCCU fluid catalytic cracking units FGCD fuel gas combustion devices FR Federal Register FTIR Fourier transform infrared spectroscopy g PM/kg grams particulate matter per kilogram GC gas chromatograph GHG greenhouse gases GPS global positioning system H2S hydrogen sulfide HAP hazardous air pollutants HCl hydrogen chloride HCN hydrogen cyanide HEM–3 Human Exposure Model, Version 1.1.0 HF hydrogen fluoride HFC highest fenceline concentration HI hazard index HQ hazard quotient ICR Information Collection Request IRIS Integrated Risk Information System km kilometers lb/day pounds per day LDAR leak detection and repair LFL lower flammability limit LFLcz combustion zone lower flammability limit LMC lowest measured concentration LOAEL lowest-observed-adverse-effect level LTD long tons per day MACT maximum achievable control technology mg/kg-day milligrams per kilogram per day mg/L milligrams per liter mg/m3 milligrams per cubic meter Mg/yr megagrams per year MFC measured fenceline concentration MFR momentum flux ratio MIR maximum individual risk mph miles per hour NAAQS National Ambient Air Quality Standards NAICS North American Industry Classification System NAS National Academy of Sciences NATA National Air Toxics Assessment NEI National Emissions Inventory NESHAP National Emissions Standards for Hazardous Air Pollutants NFS near-field interfering source NHVcz combustion zone net heating value PO 00000 Frm 00003 Fmt 4701 Sfmt 4702 36881 Ni nickel NIOSH National Institutes for Occupational Safety and Health NOAEL no-observed-adverse-effect level NOX nitrogen oxides NRC National Research Council 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 OMB Office of Management and Budget OSC off-site source contribution OTM other test method PAH polycyclic aromatic hydrocarbons PB–HAP hazardous air pollutants known to be persistent and bio-accumulative in the environment PBT persistent, bioaccumulative, and toxic PCB polychlorinated biphenyls PEL probable effect level PM particulate matter PM2.5 particulate matter 2.5 micrometers in diameter and smaller POM polycyclic organic matter ppm parts per million ppmv parts per million by volume ppmw parts per million by weight 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 RfC reference concentration RfD reference dose RTR residual risk and technology review SAB Science Advisory Board SBA Small Business Administration SBAR Small Business Advocacy Review SCR selective catalytic reduction SISNOSE significant economic impact on a substantial number of small entities S/L/Ts state, local and tribal air pollution control agencies SO2 sulfur dioxide SRU sulfur recovery unit SSM startup, shutdown and malfunction STEL short-term exposure limit TEQ toxicity equivalent TLV threshold limit value TOC total organic carbon TOSHI target organ-specific hazard index tpy tons per year TRIM.FaTE Total Risk Integrated Methodology.Fate, Transport, and Ecological Exposure model UB uniform background UF uncertainty factor UMRA Unfunded Mandates Reform Act URE unit risk estimate UV–DOAS ultraviolet differential optical absorption spectroscopy VCS voluntary consensus standards VOC volatile organic compounds WJC William Jefferson Clinton °F degrees Fahrenheit DC the concentration difference between the highest measured concentration and the lowest measured concentration mg/m3 micrograms per cubic meter The EPA also defines the following abbreviations for regulations cited within this preamble: E:\FR\FM\30JNP2.SGM 30JNP2 36882 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules AWP Alternative Work Practice To Detect Leaks From Equipment (40 CFR 63.11(c), (d) and (e)) Benzene NESHAP National Emission Standards for Hazardous Air Pollutants: Benzene Emissions from Maleic Anhydride Plants, Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene Equipment Leaks, and Coke By-Product Recovery Plants (40 CFR part 61, subpart L as of publication in the Federal Register at 54 FR 38044, September 14, 1989) BWON National Emission Standard for Benzene Waste Operations (40 CFR part 61, subpart FF) Generic MACT National Emission Standards for Storage Vessels (40 CFR part 63, subpart WW) HON National Emission Standards for Organic Hazardous Air Pollutants (40 CFR part 63, subparts F, G and H) Marine Vessel MACT National Emission Standards for Marine Tank Vessel Loading Operations (40 CFR part 63, subpart Y) Refinery MACT 1 National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries (40 CFR part 63, subpart CC) Refinery MACT 2 National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units (40 CFR part 63, subpart UUU) Refinery NSPS J Standards of Performance for Petroleum Refineries (40 CFR part 60, subpart J) Refinery NSPS Ja Standards of Performance for Petroleum Refineries for which Construction, Reconstruction, or Modification Commenced After May 14, 2007 (40 CFR part 60, subpart Ja) Organization of This Document. The information in 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. What should I consider as I prepare my comments for the EPA? D. Public Hearing II. Background A. What is the statutory authority for this action? B. What are the source categories and how do the NESHAP and NSPS regulate emissions? C. What data collection activities were conducted to support this action? D. What other relevant background information and data are available? III. Analytical Procedures A. How did we estimate post-MACT risks posed by the source categories? B. How did we consider the risk results in making decisions for this proposal? C. How did we perform the technology review? IV. Analytical Results and Proposed Decisions A. What actions are we taking pursuant to CAA sections 112(d)(2) and 112(d)(3)? B. What are the results and proposed decisions based on our technology review? C. What are the results of the risk assessment and analyses? D. What are our proposed decisions regarding risk acceptability, ample margin of safety and adverse environmental effects? E. What other actions are we proposing? F. What compliance dates are we proposing? V. Summary of Cost, Environmental and Economic Impacts A. What are the affected sources, the air quality impacts and cost impacts? B. What are the economic impacts? C. What are the benefits? VI. Request for Comments VII. Submitting Data Corrections VIII. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act 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 J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations A redline version of the regulatory language that incorporates the proposed changes in this action is available in the docket for this action (Docket ID No. EPA–HQ–OAR–2010–0682). I. General Information A. Does this action apply to me? Table 1 of this preamble lists the industries that are the subject of this proposal. Table 1 is not intended to be exhaustive but rather to provide a guide for readers regarding the entities that this proposed action is likely to affect. These proposed standards, once promulgated, will be directly applicable to the affected sources. Thus, federal, state, local and tribal government entities would not be affected by this proposed action. As defined in the ‘‘Initial List of Categories of Sources Under Section 112(c)(1) of the Clean Air Act Amendments of 1990’’ (see 57 FR 31576, July 16, 1992), the ‘‘Petroleum Refineries—Catalytic Cracking (Fluid and other) Units, Catalytic Reforming Units, and Sulfur Plant Units’’ source category and the ‘‘Petroleum Refineries—Other Sources Not Distinctly Listed’’ both consist of any facility engaged in producing gasoline, naphthas, kerosene, jet fuels, distillate fuel oils, residual fuel oils, lubricants, or other products from crude oil or unfinished petroleum derivatives. The first of these source categories includes process vents associated with the following refinery process units: Catalytic cracking (fluid and other) units, catalytic reforming units and sulfur plant units. The second source category includes all emission sources associated with refinery process units except the process vents listed in the Petroleum Refineries—Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant Units Source Category. The emission sources included in this source category include, but are not limited to, miscellaneous process vents (vents other than those listed in Petroleum Refineries—Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant Units Source Category), equipment leaks, storage vessels, wastewater, gasoline loading, marine vessel loading, and heat exchange systems. emcdonald on DSK67QTVN1PROD with PROPOSALS2 TABLE 1—INDUSTRIES AFFECTED BY THIS PROPOSED ACTION NAICSa Code Industry Petroleum Refining Industry ...................... a North 324110 Examples of regulated entities Petroleum refinery sources that are subject to 40 CFR part 60, subpart J and Ja and 40 CFR part 63, subparts CC and UUU. American Industry Classification System. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00004 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules B. Where can I get a copy of this document and other related information? Following signature by the EPA Administrator, the EPA will post a copy of this proposed action at: https:// www.epa.gov/ttn/atw/petref.html. Following publication in the Federal Register, the EPA will post the Federal Register version of the proposal and key technical documents at the Web site. Information on the overall residual risk and technology review (RTR) program is available at the following Web site: https://www.epa.gov/ttn/atw/rrisk/ rtrpg.html. C. What should I consider as I prepare my comments for the EPA? Submitting CBI. Do not submit information containing CBI to the EPA through https://www.regulations.gov or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on a disk or CD– ROM that you mail to the EPA, mark the outside of the disk or CD–ROM as CBI and then identify electronically within the disk or CD–ROM the specific information that is claimed as CBI. In addition to one complete version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not contain the information claimed as CBI for inclusion in the public docket. If you submit a CD–ROM or disk that does not contain CBI, mark the outside of the disk or CD–ROM clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and the EPA’s electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 Code of Federal Regulations (CFR) part 2. Send or deliver information identified as CBI only to the following address: Roberto Morales, OAQPS Document Control Officer (C404–02), OAQPS, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention Docket ID Number EPA–HQ–OAR–2010–0682. emcdonald on DSK67QTVN1PROD with PROPOSALS2 D. Public Hearing The hearing will provide interested parties the opportunity to present data, views or arguments concerning the proposed action. The EPA will make every effort to accommodate all speakers who arrive and register. The EPA may ask clarifying questions during the oral presentations but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 will be considered with the same weight as oral comments and supporting information presented at the public hearing. Written comments on the proposed rule must be postmarked by August 29, 2014. Commenters should notify Ms. Virginia Hunt if they will need specific equipment, or if there are other special needs related to providing comments at the hearing. Oral testimony will be limited to 5 minutes for each commenter. The EPA encourages commenters to provide the EPA with a copy of their oral testimony electronically (via email or CD) or in hard copy form. Verbatim transcripts of the hearings and written statements will be included in the docket for the rulemaking. The EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearing to run either ahead of schedule or behind schedule. Information regarding the hearing will be available at: https:// www.epa.gov/ttnatw01/petrefine/ petrefpg.html. II. Background A. What is the statutory authority for this action? 1. NESHAP Section 112 of the Clean Air Act (CAA) establishes a two-stage regulatory process to address emissions of HAP from stationary sources. In the first stage, after the EPA has identified categories of sources emitting one or more of the HAP listed in CAA section 112(b), CAA section 112(d) requires us to promulgate technology-based national emissions standards for hazardous air pollutants (NESHAP) for those sources. ‘‘Major sources’’ are those that emit or have the potential to emit 10 tpy or more of a single HAP or 25 tpy or more of any combination of HAP. For major sources, the technology-based NESHAP must reflect the maximum degree of emissions reductions of HAP achievable (after considering cost, energy requirements and non-air quality health and environmental impacts) and are commonly referred to as maximum achievable control technology (MACT) standards. MACT standards must reflect the maximum degree of emissions reduction achievable through the application of measures, processes, methods, systems or techniques, including, but not limited to, measures that (1) reduce the volume of or eliminate pollutants through process changes, substitution of materials or other modifications; (2) enclose systems or processes to eliminate emissions; (3) capture or treat pollutants when released from a PO 00000 Frm 00005 Fmt 4701 Sfmt 4702 36883 process, stack, storage or fugitive emissions point; (4) are design, equipment, work practice or operational standards (including requirements for operator training or certification); or (5) are a combination of the above. CAA section 112(d)(2)(A)–(E). The MACT standards may take the form of design, equipment, work practice or operational standards where the EPA first determines either that (1) a pollutant cannot be emitted through a conveyance designed and constructed to emit or capture the pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with law; or (2) the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations. CAA section 112(h)(1)–(2). The MACT ‘‘floor’’ is the minimum control level allowed for MACT standards promulgated under CAA section 112(d)(3) and may not be based on cost considerations. For new sources, the MACT floor cannot be less stringent than the emissions control that is achieved in practice by the bestcontrolled similar source. The MACT floor for existing sources can be less stringent than floors for new sources but not less stringent than the average emissions limitation achieved by the best-performing 12 percent of existing sources in the category or subcategory (or the best-performing five sources for categories or subcategories with fewer than 30 sources). In developing MACT standards, the EPA must also consider control options that are more stringent than the floor. We may establish standards more stringent than the floor based on considerations of the cost of achieving the emission reductions, any non-air quality health and environmental impacts and energy requirements. The EPA is then required to review these 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. CAA section 112(d)(6). In conducting this review, the EPA is not required to recalculate the MACT floor. Natural Resources Defense Council (NRDC) v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008). Association of Battery Recyclers, Inc. v. EPA, 716 F.3d 667 (D.C. Cir. 2013). The second stage in standard-setting focuses on reducing any remaining (i.e., ‘‘residual’’) risk according to CAA section 112(f). Section 112(f)(1) required that the EPA by November 1996 prepare a report to Congress discussing (among E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36884 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules other things) methods of calculating the risks posed (or potentially posed) by sources after implementation of the MACT standards, the public health significance of those risks and the EPA’s recommendations as to legislation regarding such remaining risk. The EPA prepared and submitted the Residual Risk Report to Congress, EPA–453/R– 99–001 (Risk Report) in March 1999. CAA section 112(f)(2) then provides that if Congress does not act on any recommendation in the Risk Report, the EPA must analyze and address residual risk for each category or subcategory of sources 8 years after promulgation of such standards pursuant to CAA section 112(d). Section 112(f)(2) of the CAA requires the EPA to determine for source categories subject to MACT standards whether the emission standards provide an ample margin of safety to protect public health. Section 112(f)(2)(B) of the CAA expressly preserves the EPA’s use of the two-step process for developing standards to address any residual risk and the agency’s interpretation of ‘‘ample margin of safety’’ developed in the National Emissions Standards for Hazardous Air Pollutants: Benzene Emissions from Maleic Anhydride Plants, Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene Equipment Leaks, and Coke By-Product Recovery Plants (Benzene NESHAP) (54 FR 38044, September 14, 1989). The EPA notified Congress in the Risk Report that the agency intended to use the Benzene NESHAP approach in making CAA section 112(f) residual risk determinations (EPA–453/R–99–001, p. ES–11). The EPA subsequently adopted this approach in its residual risk determinations and in a challenge to the risk review for the Synthetic Organic Chemical Manufacturing source category, the United States Court of Appeals for the District of Columbia Circuit upheld as reasonable the EPA’s interpretation that subsection 112(f)(2) incorporates the standards established in the Benzene NESHAP. See NRDC v. EPA, 529 F.3d 1077, 1083 (D.C. Cir. 2008) (‘‘[S]ubsection 112(f)(2)(B) expressly incorporates the EPA’s interpretation of the Clean Air Act from the Benzene standard, complete with a citation to the Federal Register.’’); see also A Legislative History of the Clean Air Act Amendments of 1990, vol. 1, p. 877 (Senate debate on Conference Report). The first step in the process of evaluating residual risk is the determination of acceptable risk. If risks are unacceptable, the EPA cannot consider cost in identifying the emissions standards necessary to bring VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 risks to an acceptable level. The second step is the determination of whether standards must be further revised in order to provide an ample margin of safety to protect public health. The ample margin of safety is the level at which the standards must be set, unless an even more stringent standard is necessary to prevent, taking into consideration costs, energy, safety and other relevant factors, an adverse environmental effect. a. Step 1—Determining Acceptability The agency in the Benzene NESHAP concluded ‘‘that the acceptability of risk under section 112 is best judged on the basis of a broad set of health risk measures and information’’ and that the ‘‘judgment on acceptability cannot be reduced to any single factor.’’ Id. at 38046. The determination of what represents an ‘‘acceptable’’ risk is based on a judgment of ‘‘what risks are acceptable in the world in which we live’’ (Risk Report at 178, quoting NRDC v. EPA, 824 F. 2d 1146, 1165 (D.C. Cir. 1987) (en banc) (‘‘Vinyl Chloride’’), recognizing that our world is not riskfree. In the Benzene NESHAP, we stated that ‘‘EPA will generally presume that if the risk to [the maximum exposed] individual is no higher than approximately one in 10 thousand, that risk level is considered acceptable.’’ 54 FR at 38045, September 14, 1989. We discussed the maximum individual lifetime cancer risk (or maximum individual risk (MIR)) as being ‘‘the estimated risk that a person living near a plant would have if he or she were exposed to the maximum pollutant concentrations for 70 years.’’ Id. We explained that this measure of risk ‘‘is an estimate of the upper bound of risk based on conservative assumptions, such as continuous exposure for 24 hours per day for 70 years.’’ Id. We acknowledged that maximum individual lifetime cancer risk ‘‘does not necessarily reflect the true risk, but displays a conservative risk level which is an upper-bound that is unlikely to be exceeded.’’ Id. Understanding that there are both benefits and limitations to using the MIR as a metric for determining acceptability, we acknowledged in the Benzene NESHAP that ‘‘consideration of maximum individual risk * * * must take into account the strengths and weaknesses of this measure of risk.’’ Id. Consequently, the presumptive risk level of 100-in-1 million (1-in-10 thousand) provides a benchmark for judging the acceptability of maximum individual lifetime cancer risk, but does not constitute a rigid line for making PO 00000 Frm 00006 Fmt 4701 Sfmt 4702 that determination. Further, in the Benzene NESHAP, we noted that: [p]articular attention will also be accorded to the weight of evidence presented in the risk assessment of potential carcinogenicity or other health effects of a pollutant. While the same numerical risk may be estimated for an exposure to a pollutant judged to be a known human carcinogen, and to a pollutant considered a possible human carcinogen based on limited animal test data, the same weight cannot be accorded to both estimates. In considering the potential public health effects of the two pollutants, the Agency’s judgment on acceptability, including the MIR, will be influenced by the greater weight of evidence for the known human carcinogen. Id. at 38046. The agency also explained in the Benzene NESHAP that: [i]n establishing a presumption for MIR, rather than a rigid line for acceptability, the Agency intends to weigh it with a series of other health measures and factors. These include the overall incidence of cancer or other serious health effects within the exposed population, the numbers of persons exposed within each individual lifetime risk range and associated incidence within, typically, a 50 km exposure radius around facilities, the science policy assumptions and estimation uncertainties associated with the risk measures, weight of the scientific evidence for human health effects, other quantified or unquantified health effects, effects due to co-location of facilities, and coemission of pollutants. Id. at 38045. In some cases, these health measures and factors taken together may provide a more realistic description of the magnitude of risk in the exposed population than that provided by maximum individual lifetime cancer risk alone. As noted earlier, in NRDC v. EPA, the court held that section 112(f)(2) ‘‘incorporates the EPA’s interpretation of the Clean Air Act from the Benzene Standard.’’ The court further held that Congress’ incorporation of the Benzene standard applies equally to carcinogens and non-carcinogens. 529 F.3d at 1081– 82. Accordingly, we also consider noncancer risk metrics in our determination of risk acceptability and ample margin of safety. b. Step 2—Determination of Ample Margin of Safety CAA section 112(f)(2) requires the EPA to determine, for source categories subject to MACT standards, whether those standards provide an ample margin of safety to protect public health. As explained in the Benzene NESHAP, ‘‘the second step of the inquiry, determining an ‘ample margin of safety,’ again includes consideration of all of the health factors, and whether to reduce the risks even further. . . . E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 Beyond that information, additional factors relating to the appropriate level of control will also be considered, including costs and economic impacts of controls, technological feasibility, uncertainties and any other relevant factors. Considering all of these factors, the agency will establish the standard at a level that provides an ample margin of safety to protect the public health, as required by section 112.’’ 54 FR at 38046, September 14, 1989. According to CAA section 112(f)(2)(A), if the MACT standards for HAP ‘‘classified as a known, probable, or possible human carcinogen do not reduce lifetime excess cancer risks to the individual most exposed to emissions from a source in the category or subcategory to less than one in one million,’’ the EPA must promulgate residual risk standards for the source category (or subcategory), as necessary to provide an ample margin of safety to protect public health. In doing so, the EPA may adopt standards equal to existing MACT standards if the EPA determines that the existing standards (i.e., the MACT standards) are sufficiently protective. 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.’’) The EPA must also adopt more stringent standards, if necessary, to prevent an adverse environmental effect,1 but must consider cost, energy, safety and other relevant factors in doing so. The CAA does not specifically define the terms ‘‘individual most exposed,’’ ‘‘acceptable level’’ and ‘‘ample margin of safety.’’ In the Benzene NESHAP, 54 FR at 38044–38045, September 14, 1989, we stated as an overall objective: In protecting public health with an ample margin of safety under section 112, EPA strives to provide maximum feasible protection against risks to health from hazardous air pollutants by (1) protecting the greatest number of persons possible to an individual lifetime risk level no higher than approximately 1-in-1 million and (2) limiting to no higher than approximately 1-in-10 thousand [i.e., 100-in-1 million] the estimated risk that a person living near a plant would have if he or she were exposed to the maximum pollutant concentrations for 70 years. 1 ‘‘Adverse environmental effect’’ is defined as any significant and widespread adverse effect, which may be reasonably anticipated to wildlife, aquatic life or natural resources, including adverse impacts on populations of endangered or threatened species or significant degradation of environmental qualities over broad areas. CAA section 112(a)(7). VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 The agency further stated that ‘‘[t]he EPA also considers incidence (the number of persons estimated to suffer cancer or other serious health effects as a result of exposure to a pollutant) to be an important measure of the health risk to the exposed population. Incidence measures the extent of health risks to the exposed population as a whole, by providing an estimate of the occurrence of cancer or other serious health effects in the exposed population.’’ Id. at 38045. In the ample margin of safety decision process, the agency again considers all of the health risks and other health information considered in the first step, including the incremental risk reduction associated with standards more stringent than the MACT standard or a more stringent standard that EPA has determined is necessary to ensure risk is acceptable. In the ample margin of safety analysis, the agency considers additional factors, including costs and economic impacts of controls, technological feasibility, uncertainties and any other relevant factors. Considering all of these factors, the agency will establish the standard ‘‘at a level that provides an ample margin of safety to protect the public health,’’ as required by CAA section 112(f). 54 FR 38046, September 14, 1989. 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 new source performance standards (NSPS) which 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 PO 00000 Frm 00007 Fmt 4701 Sfmt 4702 36885 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 to sources that are constructed, modified or reconstructed after the EPA proposes the NSPS for the relevant source category.2 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. 2 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. E:\FR\FM\30JNP2.SGM 30JNP2 36886 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 B. What are the source categories and how do the NESHAP and NSPS regulate emissions? The source categories include petroleum refineries engaged 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. Petroleum refinery activities start with the receipt of crude oil for storage at the refinery, include all 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 refinery-specific process units include fluid catalytic cracking units (FCCU) and catalytic reforming units (CRU), as well as units and processes found at many types of manufacturing facilities (including petroleum refineries), such as 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). Criteria pollutants and other non-hazardous air pollutants that are also emitted include nitrogen oxides (NOX), particulate matter (PM), sulfur dioxide (SO2), volatile organic compounds (VOC), carbon monoxide (CO), greenhouse gases (GHG), and total reduced sulfur. The federal emission standards that are the primary subject of this proposed rulemaking are: • National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries (40 CFR part 63, subpart CC) (Refinery MACT 1); • National Emission Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units (40 CFR part 63, subpart UUU) (Refinery MACT 2); • Standards of Performance for Petroleum Refineries (40 CFR part 60, subpart J) (Refinery NSPS J); and • Standards of Performance for Petroleum Refineries for which Construction, Reconstruction, or Modification Commenced After May 14, VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 2007 (40 CFR part 60, subpart Ja) (Refinery NSPS Ja). 1. Refinery MACT Standards The EPA promulgated MACT standards pursuant to CAA section 112(d)(2) and (3) for refineries located at major sources in three 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 emission sources from petroleum refinery process units, except those listed separately under the section 112(c) source category list expected to be regulated by other MACT standards. Some of the emission sources regulated in Refinery MACT 1 include miscellaneous process vents, storage vessels, wastewater, equipment leaks, gasoline loading racks, marine tank vessel loading and heat exchange systems. 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 were subsequently regulated under a second MACT standard specific to these petroleum refinery process vents, codified as 40 CFR part 63, subpart UUU, which we promulgated on April 11, 2002 (67 FR 17762). This standard, which is referred to as ‘‘Refinery MACT 2,’’ covers process vents on catalytic cracking units (CCU) (including FCCU), CRU and sulfur recovery units (SRU). Finally, on October 28, 2009, we promulgated 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 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 has reached an agreement to settle that litigation. In a consent decree filed January 13, 2014 in the U.S. District Court for the District of Columbia, the EPA commits to perform the risk and technology review for Refinery MACT 1 and 2 and by May 15, 2014, either propose any regulations or propose that additional regulations are not necessary. Under the Consent Decree, the EPA commits to take final PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 action by April 17, 2015, establishing regulations pursuant to the risk and technology review or to issue a final determination that revision to the existing rules is not necessary. 2. Refinery NSPS Refinery NSPS subparts J and Ja regulate criteria pollutant emissions, including PM, SO2, NOX and CO from FCCU catalyst regenerators, fuel gas combustion devices (FGCD) and sulfur recovery plants. Refinery NSPS Ja also regulates criteria pollutant emissions from fluid coking units and delayed coking units (DCU). The NSPS for petroleum refineries (40 CFR part 60, subpart J; Refinery NSPS 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 Refinery NSPS J, the EPA developed separate standards of performance for new process units (40 CFR part 60, subpart Ja; Refinery NSPS Ja). However, the EPA received petitions for reconsideration and granted reconsideration on issues related to those standards. On December 22, 2008, the EPA addressed petition issues related to process heaters and flares by proposing amendments to certain provisions. Final amendments to Refinery NSPS Ja were promulgated on September 12, 2012 (77 FR 56422). In this action, we are proposing amendments to address technical corrections and clarifications raised in a 2008 industry petition for reconsideration applicable to Refinery NSPS Ja. We are addressing these issues in this proposal because they also affect sources included within these proposed amendments to Refinery MACT 1 and 2. C. What data collection activities were conducted to support this action? In 2010, the EPA began a significant effort to gather additional information and perform analyses to determine how to address statutory obligations for the Refinery MACT standards and the NSPS. This effort focused on gathering comprehensive information through an industry-wide Information Collection Request (ICR) on petroleum refineries, conducted under CAA section 114 authority. The information not claimed as CBI by respondents is available in the docket (see Docket Item Nos. EPA–HQ– OAR–2010–0682–0064 through 0069). The EPA issued a single ICR (OMB Control Number 2060–0657) for sources covered under Refinery MACT 1 and 2 and Refinery NSPS J and Ja. On April 1, 2011, the ICR was sent out to the petroleum refining industry. In a comprehensive manner, the ICR E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules collected information on processing characteristics, crude slate characteristics, emissions inventories and source testing to fill known data gaps. The ICR had four components: (1) A questionnaire on processes and controls to be completed by all petroleum refineries (Component 1); (2) an emissions inventory to be developed by all petroleum refineries using the emissions estimation protocol developed for this effort (Component 2); (3) distillation feed sampling and analysis to be conducted by all petroleum refineries (Component 3); and (4) emissions source testing to be completed in accordance with an EPAapproved protocol for specific sources at specific petroleum refineries (Component 4). We received responses from 149 refineries. We have since learned that seven refineries are synthetic minor sources, bringing the total number of major source refineries operating in 2010 to 142. Information collected through the ICR was used to establish the baseline emissions and control levels for purposes of the regulatory reviews, to identify the most effective control measures, and to estimate the environmental and cost impacts associated with the regulatory options considered. As part of the information collection process, we provided a protocol for survey respondents to follow in developing the emissions inventories under Component 2 (Emission Estimation Protocol for Petroleum Refineries, available as Docket Item Number EPA–HQ–OAR– 2010–0682–0060). The protocol contained detailed guidance for estimating emissions from typical refinery emission sources and was intended to provide a measure of consistency and replicability for emission estimates across the refining industry. Prior to issuance of the ICR, the protocol was publicly disseminated and underwent several revisions after public comments were received. Draft and final versions of the emission estimation protocol are provided in the docket to this rule (Docket ID Number EPA–HQ–OAR–2010–0682). The protocol provided a hierarchy of methodologies available for estimating emissions that corresponded to the level of information available at refineries. For each emission source, the various emission measurement or estimation methods specific to that source were ranked in order of preference, with ‘‘Methodology Rank 1’’ being the preferred method, followed by ‘‘Methodology Rank 2,’’ and so on. Refinery owners and operators were VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 requested through the ICR to use the highest ranked method (with Methodology Rank 1 being the highest) for which data were available. Methodology Ranks 1 or 2 generally relied on continuous emission measurements. When continuous measurement data were not available, engineering calculations or site-specific emission factors (Methodology Ranks 3 and 4) were specified in the protocol by EPA; these methods generally needed periodic, site-specific measurements. When site-specific measurement or test data were not available, default emission factors (Methodology Rank 5) were provided in the protocol by EPA. As we reviewed the ICR-submitted emissions inventories, we determined that, in some cases, refiners either did not follow the protocol methodology or made an error in their calculations. This was evident because pollutants that we expected to be reported from certain emission sources were either not reported or were reported in amounts that were not consistent with the protocol methodology. In these cases, we contacted the refineries and, based on their replies, made corrections to emission estimates. The original Component 2 submittals, documentation of the changes as a result of our review, and the final emissions inventories we relied on for our analyses are available in the technical memorandum entitled Emissions Data Quality Memorandum and Development of the Risk Model Input File, in Docket ID Number EPA–HQ–OAR–2010–0682. Collected emissions test data (test reports, continuous emissions monitoring system (CEMS) data and other continuous monitoring system data) were used to assess the effectiveness of existing control measures, to fill data gaps and to examine variability in emissions. The ICR requested source testing for a total of 90 specific process units at 75 particular refineries across the industry. We received a total of 72 source tests; in some cases, refinery sources claimed that units we requested to be tested were no longer in operation, did not exist or did not have an emission point to the atmosphere (this was the case for hydrocrackers). In other cases, refiners claimed they were not able to conduct testing because of process characteristics. For example, source testing of DCU proved to be difficult because the moisture content of the steam vent required a significant amount of gas to be sampled to account for dilution. Venting periods of less than 20 minutes did not accommodate this strategy and, therefore, if refiners vented for less than 20 minutes, they did not PO 00000 Frm 00009 Fmt 4701 Sfmt 4702 36887 sample their steam vent. As a result, only two DCU tests out of eight requested were received as part of Component 4. Results of the stack test data are compiled and available in Docket ID Number EPA–HQ–OAR– 2010–0682. D. What other relevant background information and data are available? Over the past several years, the EPA has worked with the Texas Commission on Environmental Quality and industry representatives to better characterize proper flare performance. Flares are used to control emissions from various vents at refineries as well as at other types of facilities not in the petroleum refinery source categories, such as chemical and petrochemical manufacturing facilities. In April 2012, we released a technical report for peer review that discussed our observations regarding the operation and performance of flares. The report was a result of the analysis of several flare efficiency studies and flare performance test reports. To provide an objective evaluation of our analysis, we asked a third party to facilitate an ad hoc peer review process of the technical report. This third party established a balanced peer review panel of reviewers from outside the EPA. These reviewers consisted of individuals that could be considered ‘‘technical combustion experts’’ within four interest groups: the refinery industry, industrial flare consultants, academia, and environmental stakeholders. The EPA developed a charge statement with ten charge questions for the review panel. The peer reviewers were asked to perform a thorough review of the technical report and answer the charge questions to the extent possible, based on their technical expertise. The details of the peer review process and the charge questions, as well as comments received from the peer review process, were posted online to the Consolidated Petroleum Refinery Rulemaking Repository at the EPA’s Technology Transfer Network Air Toxics Web site (see https:// www.epa.gov/ttn/atw/petref.html). These items are also provided in a memorandum entitled Peer Review of ‘‘Parameters for Properly Designed and Operated Flares’’ (see Docket ID Number EPA–HQ–OAR–2010–0682). After considering the comments received from the peer review process, we developed a final technical memorandum (see technical memorandum, Flare Performance Data: Summary of Peer Review Comments and Additional Data Analysis for Steam- E:\FR\FM\30JNP2.SGM 30JNP2 36888 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Assisted Flares, in Docket ID Number EPA–HQ–OAR–2010–0682). III. Analytical Procedures In this section, we describe the analyses performed to support the proposed decisions for the RTR and other issues addressed in this proposal. emcdonald on DSK67QTVN1PROD with PROPOSALS2 A. How did we estimate post-MACT risks posed by the source categories? The EPA conducted a risk assessment that provided estimates of the MIR posed by the HAP emissions from each source in the source categories, the hazard index (HI) for chronic exposures to HAP with the potential to cause noncancer health effects, and the hazard quotient (HQ) for acute exposures to HAP with the potential to cause noncancer health effects. The assessment also provided estimates of the distribution of cancer risks within the exposed populations, cancer incidence and an evaluation of the potential for adverse environmental effects for each source category. The eight sections that follow this paragraph describe how we estimated emissions and conducted the risk assessment. The docket for this rulemaking (Docket ID Number EPA– HQ–OAR–2010–0682) contains the following document which provides more information on the risk assessment inputs and models: Draft Residual Risk Assessment for the Petroleum Refining Source Sector. The methods used to assess risks (as described in the eight primary steps below) are consistent with those peer-reviewed by a panel of the EPA’s Science Advisory Board (SAB) in 2009 and described in their peer review report issued in 2010 3; they are also consistent with the key recommendations contained in that report. 1. How did we estimate actual emissions and identify the emissions release characteristics? We compiled data sets using the ICR emission inventory submittals as a starting point. The data sets were refined following an extensive quality assurance check of source locations, emission release characteristics, annual emission estimates and FCCU release parameters. They were then updated based on additional information received from refineries. In addition, we supplemented these data with results from stack testing, which were required later than the inventories under the ICR. As the stack test information was 3 U.S. EPA SAB. Risk and Technology Review (RTR) Risk Assessment Methodologies: For Review by the EPA’s Science Advisory board with Case Studies—MACT I Petroleum Refining Sources and Portland Cement Manufacturing, May 2010. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 received, we compared these data against the refined emission inventories and the default emission factors provided in the Emission Estimation Protocol for Petroleum Refineries (Docket Item Number EPA–HQ–OAR– 2010–0682–0060). Based on the stack test data for FCCU, we calculated that, on average, HCN emissions were a factor of 10 greater than the average emission factor of 770 pounds per barrel FCCU feed provided in the protocol. Therefore, we revised the HCN emissions for FCCU in the emissions inventory used for the risk modeling runs (the results are presented in this preamble). For the 10 facilities that performed a stack test to determine HCN emissions from their FCCU, we used the actual emissions measured during the stack tests in place of the inventories originally supplied in response to the ICR. For those facilities that did not perform a stack test, but reported HCN emissions in the emissions inventory portion of the ICR, we increased the emissions of HCN by a factor of 10, assuming the original emission inventory estimates for FCCU HCN emissions were based on the default emission factor in the protocol. The emissions inventory from the ICR and documentation of the changes made to the file as a result of our review are contained in the technical memorandum entitled Emissions Data Quality Memorandum and Development of the Risk Model Input File, in Docket ID Number EPA–HQ–OAR–2010–0682 and available on our Web site.4 2. How did we estimate MACTallowable emissions? The available emissions data in the RTR dataset (i.e., the emissions inventory) include estimates of the mass of HAP emitted during the specified annual time period. In some cases, these ‘‘actual’’ emission levels are lower than the emission levels required to comply with the MACT standards. The emissions level allowed to be emitted by the MACT standards is referred to as the ‘‘MACT-allowable’’ emissions level. We discussed the use of both MACTallowable and actual emissions in the final Coke Oven Batteries residual risk rule (70 FR 19998–19999, April 15, 2005) and in the proposed and final Hazardous Organic NESHAP residual risk rules (71 FR 34428, June 14, 2006, and 71 FR 76609, December 21, 2006, respectively). In those previous actions, we noted that assessing the risks at the MACT-allowable level is inherently 4 The emissions inventory and the revised emissions modeling file can also be found at https:// www.epa.gov/ttn/atw/petref.htm. PO 00000 Frm 00010 Fmt 4701 Sfmt 4702 reasonable since these risks reflect the maximum level facilities could emit and still comply with national emission standards. We also explained that it is reasonable to consider actual emissions, where such data are available, in both steps of the risk analysis, in accordance with the Benzene NESHAP approach. (54 FR 38044, September 14, 1989.) We requested allowable emissions data in the ICR. However, unlike for actual emissions, where the ICR specified the use of the Emission Estimation Protocol for Petroleum Refineries (available as Docket Item Number EPA–HQ–OAR–2010–0682– 0060), we did not specify a method to calculate allowable emissions. As a result, in our review of these data and when comparing estimates between facilities, we found that facilities did not estimate allowable emissions consistently across the industry. In addition, facilities failed to report allowable emissions for many emission points, likely because they did not know how to translate a work practice or performance standard into an allowable emission estimate and they did not know how to speciate individual HAP where the MACT standard is based on a surrogate, such as PM or VOC. Therefore, the ICR-submitted information for allowable emissions did not include emission estimates for all HAP and sources of interest. Consequently, we used our Refinery Emissions Model (REM Model) to estimate allowable emissions. The REM model 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. The risks associated with the allowable emissions were evaluated using the same dispersion modeling practices, exposure assumptions and health benchmarks as the actual risks. However, because each refinery’s allowable emissions were calculated by using model plants, selected based on each refinery’s actual capacities and throughputs, emission estimates for point sources are not specific to a particular latitude/longitude location. Therefore, for risk modeling purposes, all allowable emissions were assumed to be released from the centroid of the facility. (Note: for fugitive (area) sources, the surface area was selected by the size of the model plant and the release point was shifted to the southwest so the center of the fugitive area was near the centroid of the facility). The emission and risk estimates for the actual emission inventory were compared to the E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 allowable emissions and risk estimates. For most work practices, where allowable emission estimates are difficult to predict, the actual risk estimates were higher than those projected using the REM Model estimates. Consequently, we postprocessed the two risk files, taking the higher risk estimates from the actual emissions inventory for sources subject to work practice standards, such as process equipment leaks, and sources that were not covered in the REM Model, combining them with the risk estimates from sources with more readily determined allowable emissions. The combined post-processed allowable risk estimates provide a high estimate of the risk allowed under Refinery MACT 1 and 2. The REM Model assumptions and emission estimates, along with the post-processing of risk estimate results that produced the final risk estimates for the allowable emissions, are provided in the docket (see Refinery Emissions and Risk Estimates for Modeled ‘‘Allowable’’ Emissions in Docket ID Number EPA– HQ–OAR–2010–0682). 3. How did we conduct dispersion modeling, determine inhalation exposures and estimate individual and population inhalation risks? Both long-term and short-term inhalation exposure concentrations and health risks from the source categories addressed in this proposal were estimated using the Human Exposure Model (Community and Sector HEM–3 version 1.1.0). The HEM–3 performs three primary risk assessment activities: (1) Conducting dispersion modeling to estimate the concentrations of HAP in ambient air, (2) estimating long-term and short-term inhalation exposures to individuals residing within 50 kilometers (km) of the modeled sources 5, and (3) estimating individual and population-level inhalation risks using the exposure estimates and quantitative dose-response information. The air dispersion model used by the HEM–3 model (AERMOD) is one of the EPA’s preferred models for assessing pollutant concentrations from industrial facilities.6 To perform the dispersion modeling and to develop the preliminary risk estimates, HEM–3 draws on three data libraries. The first is a library of meteorological data, which is used for dispersion calculations. This library includes 1 5 This metric comes from the Benzene NESHAP. See 54 FR 38046, September 14, 1989. 6 U.S. EPA. Revision to the Guideline on Air Quality Models: Adoption of a Preferred General Purpose (Flat and Complex Terrain) Dispersion Model and Other Revisions (70 FR 68218, November 9, 2005). VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 year (2011) of hourly surface and upper air observations for 824 meteorological stations, selected to provide coverage of the United States and Puerto Rico. A second library of United States Census Bureau census block 7 internal point locations and populations provides the basis of human exposure calculations (U.S. Census, 2010). In addition, for each census block, the census library includes the elevation and controlling hill height, which are also used in dispersion calculations. A third library of pollutant unit risk factors and other health benchmarks is used to estimate health risks. These risk factors and health benchmarks are the latest values recommended by the EPA for HAP and other toxic air pollutants. These values are available at: https://www.epa.gov/ttn/ atw/toxsource/summary.html and are discussed in more detail later in this section. In developing the risk assessment for chronic exposures, we used the estimated annual average ambient air concentrations of each HAP emitted by each source for which we have emissions data in the source category. The air concentrations at each nearby census block centroid were used as a surrogate for the chronic inhalation exposure concentration for all the people who reside in that census block. We calculated the MIR for each facility as the cancer risk associated with a continuous lifetime (24 hours per day, 7 days per week, and 52 weeks per year for a 70-year period) exposure to the maximum concentration at the centroid of inhabited census blocks. Individual cancer risks were calculated by multiplying the estimated lifetime exposure to the ambient concentration of each of the HAP (in micrograms per cubic meter (mg/m3)) by its unit risk estimate (URE). The URE is an upper bound estimate of an individual’s probability of contracting cancer over a lifetime of exposure to a concentration of 1 microgram of the pollutant per cubic meter of air. For residual risk assessments, we generally use URE values from the EPA’s Integrated Risk Information System (IRIS). For carcinogenic pollutants without EPA IRIS values, we look to other reputable sources of cancer dose-response values, often using California EPA (CalEPA) URE values, where available. In cases where new, scientifically credible doseresponse values have been developed in a manner consistent with the EPA guidelines and have undergone a peer review process similar to that used by the EPA, we may use such dose7 A census block is the smallest geographic area for which census statistics are tabulated. PO 00000 Frm 00011 Fmt 4701 Sfmt 4702 36889 response values in place of, or in addition to, other values, if appropriate. We note here that several carcinogens emitted by facilities in these source categories have a mutagenic mode of action. For these compounds, we applied the age-dependent adjustment factors (ADAF) described in the EPA’s Supplemental Guidance for Assessing Susceptibility from Early-Life Exposure to Carcinogens.8 This adjustment has the effect of increasing the estimated lifetime risks for these pollutants by a factor of 1.6. Although only a small fraction of the total polycyclic organic matter (POM) emissions were reported as individual compounds, the EPA expresses carcinogenic potency of POM relative to the carcinogenic potency of benzo[a]pyrene, based on evidence that carcinogenic POM have the same mutagenic mode of action as does benzo[a]pyrene. The EPA’s Science Policy Council recommends applying the ADAF to all carcinogenic polycyclic aromatic hydrocarbons (PAH) for which risk estimates are based on potency relative to benzo[a]pyrene. Accordingly, we have applied the ADAF to the benzo[a]pyrene-equivalent mass portion of all POM mixtures. The EPA estimated incremental individual lifetime cancer risks associated with emissions from the facilities in the source categories as the sum of the risks for each of the carcinogenic HAP (including those classified as carcinogenic to humans, likely to be carcinogenic to humans, and suggestive evidence of carcinogenic potential 9) emitted by the modeled sources. Cancer incidence and the distribution of individual cancer risks for the population within 50 km of the sources were also estimated for the source categories as part of this assessment by summing individual risks. A distance of 50 km is consistent with both the analysis supporting the 8 Supplemental Guidance for Assessing Susceptibility from Early-Life Exposure to Carcinogens. Risk Assessment Forum, U.S. Environmental Protection Agency, Washington, DC. EPA/630/R–03/003F. March 2005. Available at https://www.epa.gov/ttn/atw/childrens_supplement_ final.pdf. 9 These classifications also coincide with the terms ‘‘known carcinogen, probable carcinogen, and possible carcinogen,’’ respectively, which are the terms advocated in the EPA’s previous Guidelines for Carcinogen Risk Assessment, published in 1986 (51 FR 33992, September 24, 1986). Summing the risks of these individual compounds to obtain the cumulative cancer risks is an approach that was recommended by the EPA’s SAB in their 2002 peer review of EPA’s National Air Toxics Assessment (NATA) entitled, NATA—Evaluating the Nationalscale Air Toxics Assessment 1996 Data—an SAB Advisory, available at: https://yosemite.epa.gov/sab/ sabproduct.nsf/ 214C6E915BB04E14852570CA007A682C/$File/ ecadv02001.pdf. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36890 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 1989 Benzene NESHAP (54 FR 38044, September 14, 1989) and the limitations of Gaussian dispersion models, including AERMOD. To assess the risk of non-cancer health effects from chronic exposures, we summed the HQ for each of the HAP that affects a common target organ system to obtain the HI for that target organ system (or target organ-specific HI, TOSHI). The HQ is the estimated exposure divided by the chronic reference level, which is a value selected from one of several sources. First, the chronic reference level can be the EPA Reference Concentration (RfC) (https://www.epa.gov/riskassessment/ glossary.htm), defined as ‘‘an estimate (with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation exposure to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime.’’ Alternatively, in cases where an RfC from the EPA’s IRIS database is not available or where the EPA determines that using a value other than the RfC is appropriate, the chronic reference level can be a value from the following prioritized sources: (1) The Agency for Toxic Substances and Disease Registry Minimum Risk Level (https://www.atsdr.cdc.gov/mrls/ index.asp), which is defined as ‘‘an estimate of daily human exposure to a hazardous substance that is likely to be without an appreciable risk of adverse non-cancer health effects (other than cancer) over a specified duration of exposure’’; (2) the CalEPA Chronic Reference Exposure Level (REL) (https:// www.oehha.ca.gov/air/hot_spots/pdf/ HRAguidefinal.pdf), which is defined as ‘‘the concentration level (that is expressed in units of mg/m3 for inhalation exposure and in a dose expressed in units of milligram per kilogram per day (mg/kg-day) for oral exposures), at or below which no adverse health effects are anticipated for a specified exposure duration’’; or (3), as noted above, a scientifically credible dose-response value that has been developed in a manner consistent with the EPA guidelines and has undergone a peer review process similar to that used by the EPA, in place of or in concert with other values. The EPA also evaluated screening estimates of acute exposures and risks for each of the HAP at the point of highest off-site exposure for each facility (i.e., not just the census block centroids), assuming that a person is located at this spot at a time when both the peak (hourly) emissions rate and worst-case dispersion conditions occur. The acute HQ is the estimated acute VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 exposure divided by the acute doseresponse value. In each case, the EPA calculated acute HQ values using best available, short-term dose-response values. These acute dose-response values, which are described below, include the acute REL, acute exposure guideline levels (AEGL) and emergency response planning guidelines (ERPG) for 1-hour exposure durations. As discussed below, we used realistic assumptions based on knowledge of the emission point release characteristics for emission rates, and conservative assumptions for meteorology and exposure location for our acute analysis. As described in the CalEPA’s Air Toxics Hot Spots Program Risk Assessment Guidelines, Part I, The Determination of Acute Reference Exposure Levels for Airborne Toxicants, an acute REL value (https:// www.oehha.ca.gov/air/pdf/acuterel.pdf) is defined as ‘‘the concentration level at or below which no adverse health effects are anticipated for a specified exposure duration.’’ Id. at page 2. Acute REL values are based on the most sensitive, relevant, adverse health effect reported in the peer-reviewed medical and toxicological literature. Acute REL values are designed to protect the most sensitive individuals in the population through the inclusion of margins of safety. Because margins of safety are incorporated to address data gaps and uncertainties, exceeding the REL value does not automatically indicate an adverse health impact. AEGL values were derived in response to recommendations from the National Research Council (NRC). As described in Standing Operating Procedures (SOP) of the National Advisory Committee on Acute Exposure Guideline Levels for Hazardous Substances (https://www.epa.gov/oppt/ aegl/pubs/sop.pdf),10 ‘‘the NRC’s previous name for acute exposure levels—community emergency exposure levels—was replaced by the term AEGL to reflect the broad application of these values to planning, response, and prevention in the community, the workplace, transportation, the military, and the remediation of Superfund sites.’’ Id. at 2. This document also states that AEGL values ‘‘represent threshold exposure limits for the general public and are applicable to emergency exposures ranging from 10 minutes to eight hours.’’ Id. at 2. The document lays out the purpose and objectives of AEGL by 10 National Academy of Sciences (NAS), 2001. Standing Operating Procedures for Developing Acute Exposure Levels for Hazardous Chemicals, page 2. PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 stating that ‘‘the primary purpose of the AEGL program and the National Advisory Committee for Acute Exposure Guideline Levels for Hazardous Substances is to develop guideline levels for once-in-a-lifetime, short-term exposures to airborne concentrations of acutely toxic, high-priority chemicals.’’ Id. at 21. In detailing the intended application of AEGL values, the document states that ‘‘[i]t is anticipated that the AEGL values will be used for regulatory and nonregulatory purposes by U.S. Federal and state agencies and possibly the international community in conjunction with chemical emergency response, planning and prevention programs. More specifically, the AEGL values will be used for conducting various risk assessments to aid in the development of emergency preparedness and prevention plans, as well as real-time emergency response actions, for accidental chemical releases at fixed facilities and from transport carriers.’’ Id. at 31. The AEGL–1 value is then specifically defined as ‘‘the airborne concentration (expressed as ppm (parts per million) or mg/m 3 (milligrams per cubic meter)) of a substance above which it is predicted that the general population, including susceptible individuals, could experience notable discomfort, irritation, or certain asymptomatic nonsensory effects. However, the effects are not disabling and are transient and reversible upon cessation of exposure.’’ Id. at 3. The document also notes that, ‘‘Airborne concentrations below AEGL– 1 represent exposure levels that can produce mild and progressively increasing but transient and nondisabling odor, taste, and sensory irritation or certain asymptomatic, nonsensory effects.’’ Id. Similarly, the document defines AEGL–2 values as ‘‘the airborne concentration (expressed as parts per million or milligrams per cubic meter) of a substance above which it is predicted that the general population, including susceptible individuals, could experience irreversible or other serious, long-lasting adverse health effects or an impaired ability to escape.’’ Id. ERPG values are derived for use in emergency response, as described in the American Industrial Hygiene Association’s ERP Committee document entitled, ERPGS Procedures and Responsibilities, which states that, ‘‘Emergency Response Planning Guidelines were developed for emergency planning and are intended as health-based guideline concentrations for single exposures to E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules chemicals.’’ 11 Id. at 1. The ERPG–1 value is defined as ‘‘the maximum airborne concentration below which it is believed that nearly all individuals could be exposed for up to 1 hour without experiencing other than mild transient adverse health effects or without perceiving a clearly defined, objectionable odor.’’ Id. at 2. Similarly, the ERPG–2 value is defined as ‘‘the maximum airborne concentration below which it is believed that nearly all individuals could be exposed for up to one hour without experiencing or developing irreversible or other serious health effects or symptoms which could impair an individual’s ability to take protective action.’’ Id. at 1. As can be seen from the definitions above, the AEGL and ERPG values include the similarly-defined severity levels 1 and 2. For many chemicals, a severity level 1 value AEGL or ERPG has not been developed because the types of effects for these chemicals are not consistent with the AEGL–1/ERPG–1 definitions; in these instances, we compare higher severity level AEGL–2 or ERPG–2 values to our modeled exposure levels to screen for potential acute concerns. When AEGL–1/ERPG–1 values are available, they are used in our acute risk assessments. Acute REL values for 1-hour exposure durations are typically lower than their corresponding AEGL–1 and ERPG–1 values. Even though their definitions are slightly different, AEGL–1 values are often the same as the corresponding ERPG–1 values, and AEGL–2 values are often equal to ERPG–2 values. Maximum HQ values from our acute screening risk assessments typically result when basing them on the acute REL value for a particular pollutant. In cases where our maximum acute HQ value exceeds 1, we also report the HQ value based on the next highest acute dose-response value (usually the AEGL– 1 and/or the ERPG–1 value). To develop screening estimates of acute exposures in the absence of hourly emissions data, generally we first develop estimates of maximum hourly emissions rates by multiplying the average actual annual hourly emissions rates by a default factor to cover routinely variable emissions. However, for the petroleum refineries category, we incorporated additional information and process knowledge in order to better characterize acute emissions, as described below. The ICR included 11 ERP Committee Procedures and Responsibilities. November 1, 2006. American Industrial Hygiene Association. Available at https://www.aiha.org/get-involved/AIHAGuideline Foundation/EmergencyResponsePlanning Guidelines/Documents/ERP-SOPs2006.pdf. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 input fields for both annual emissions and maximum hourly emissions. The maximum hourly emission values were often left blank or appeared to be reported in units other than those required for this emissions field (pounds per hour). Consequently, instead of relying on the inadequate data provided in response to the ICR, we elected to estimate the hourly emissions based on the reported annual emissions (converted to average hourly emissions in terms of pounds per hour) and then to apply an escalation factor, considering the different types of emission sources and their inherent variability, in order to calculate maximum hourly rates. For sources with relatively continuous operations and steady state emissions, such as FCCU, sulfur recovery plants, and continuous catalytic reformers, a factor of 2 was used to estimate the maximum hourly rates from the average hourly emission rates. For sources with relatively continuous emissions, but with more variability, like storage tanks and wastewater systems, a factor of 4 was used to estimate the maximum hourly rates from the average hourly emission rates. For non-continuous emission sources with more variability, such as DCU, cyclic CRU, semi-regenerative CRU, and transfer and loading operations, the number of hours in the venting cycle and the variability of emissions expected in that cycle were used to determine the escalation factor for each emissions source. The escalation factors for these processes range from 10 to 60. For more detail regarding escalation factors and the rationale for their selection, see Derivation of Hourly Emission Rates for Petroleum Refinery Emission Sources Used in the Acute Risk Analysis, available in the docket for this rulemaking (Docket ID Number EPA– HQ–OAR–2010–0682). As part of our acute risk assessment process, for cases where acute HQ values from the screening step were less than or equal to 1 (even under the conservative assumptions of the screening analysis), acute impacts were deemed negligible and no further analysis was performed. In cases where an acute HQ from the screening step was greater than 1, additional sitespecific data were considered to develop a more refined estimate of the potential for acute impacts of concern. For these source categories, the data refinements employed consisted of using the site-specific facility layout to distinguish facility property from an area where the public could be exposed. These refinements are discussed more PO 00000 Frm 00013 Fmt 4701 Sfmt 4702 36891 fully in the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, which is available in the docket for this rulemaking (Docket ID Number EPA–HQ–OAR–2010–0682). Ideally, we would prefer to have continuous measurements over time to see how the emissions vary by each hour over an entire year. Having a frequency distribution of hourly emissions rates over a year would allow us to perform a probabilistic analysis to estimate potential threshold exceedances and their frequency of occurrence. Such an evaluation could include a more complete statistical treatment of the key parameters and elements adopted in this screening analysis. Recognizing that this level of data is rarely available, we instead rely on the multiplier approach. To better characterize the potential health risks associated with estimated acute exposures to HAP, and in response to a key recommendation from the SAB’s peer review of the EPA’s RTR risk assessment methodologies,12 we generally examine a wider range of available acute health metrics (e.g., REL, AEGL) than we do for our chronic risk assessments. This is in response to the SAB’s acknowledgement that there are generally more data gaps and inconsistencies in acute reference values than there are in chronic reference values. In some cases, e.g., when Reference Value Arrays 13 for HAP have been developed, we consider additional acute values (i.e., occupational and international values) to provide a more complete risk characterization. 4. How did we conduct the multipathway exposure and risk screening? The EPA conducted a screening analysis examining the potential for significant human health risks due to exposures via routes other than inhalation (i.e., ingestion). We first determined whether any sources in the source categories emitted any hazardous air pollutants known to be persistent and bio-accumulative in the environment (PB–HAP). The PB–HAP compounds or compound classes are 12 The SAB peer review of RTR Risk Assessment Methodologies is available at: https:// yosemite.epa.gov/sab/sabproduct.nsf/ 4AB3966E263D943A8525771F00668381/$File/EPASAB-10-007-unsigned.pdf. 13 U.S. EPA. (2009) Chapter 2.9 Chemical Specific Reference Values for Formaldehyde in Graphical Arrays of Chemical-Specific Health Effect Reference Values for Inhalation Exposures (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R–09/061, and available on-line at https://cfpub.epa.gov/ncea/cfm/ recordisplay.cfm?deid=211003. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36892 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules identified for the screening from the EPA’s Air Toxics Risk Assessment Library (available at https:// www.epa.gov/ttn/fera/risk_atra_ vol1.html). For the petroleum refinery source categories, we identified emissions of cadmium compounds, chlorinated dibenzodioxins and furans (CDDF), lead compounds, mercury compounds, polychlorinated biphenyls (PCB), and polycylic organic matter (POM). Because PB–HAP are emitted by at least one facility, we proceeded to the second step of the evaluation. In this step, we determined whether the facility-specific emission rates of each of the emitted PB–HAP were large enough to create the potential for significant non-inhalation human health risks under reasonable worst-case conditions. To facilitate this step, we developed emissions rate screening levels for each PB–HAP using a hypothetical upper-end screening exposure scenario developed for use in conjunction with the EPA’s ‘‘Total Risk Integrated Methodology. Fate, Transport, and Ecological Exposure’’ (TRIM.FaTE) model. We conducted a sensitivity analysis on the screening scenario to ensure that its key design parameters would represent the upper end of the range of possible values, such that it would represent a conservative but not impossible scenario. The facility-specific emissions rates of each of the PB–HAP were compared to their corresponding emission rate screening values to assess the potential for significant human health risks via noninhalation pathways. We call this application of the TRIM.FaTE model the Tier I TRIM- Screen or Tier I screen. For the purpose of developing emissions rates for our Tier I TRIMScreen, we derived emission levels for each PB–HAP (other than lead) at which the maximum excess lifetime cancer risk would be 1-in-1 million or, for HAP that cause non-cancer health effects, the maximum HQ would be 1. If the emissions rate of any PB–HAP exceeds the Tier I screening emissions rate for any facility, we conduct a second screen, which we call the Tier II TRIMscreen or Tier II screen. In the Tier II screen, the location of each facility that exceeded the Tier I emission rate is used to refine the assumptions associated with the environmental scenario while maintaining the exposure scenario assumptions. We then adjust the riskbased Tier I screening level for each PB– HAP for each facility based on an understanding of how exposure concentrations estimated for the screening scenario change with meteorology and environmental assumptions. PB–HAP emissions that do VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 not exceed these new Tier II screening levels are considered to pose no unacceptable risks. When facilities exceed the Tier II screening levels, it does not mean that multi-pathway impacts are significant, only that we cannot rule out that possibility based on the results of the screen. These facilities may be further evaluated for multipathway risks using the TRIM.FaTE model. In evaluating the potential for multipathway risk from emissions of lead compounds, rather than developing a screening emissions rate for them, we compared modeled maximum estimated chronic inhalation exposures with the level of the current National Ambient Air Quality Standards (NAAQS) for lead.14 Values below the level of the primary (health-based) lead NAAQS were considered to have a low potential for multi-pathway risk. For further information on the multipathway analysis approach, see the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, which is available in the docket for this action (Docket ID Number EPA–HQ– OAR–2010–0682). emissions based on the operating characteristics and controls reported for each unit. For example, HAP emissions from each storage vessel were estimated based on the size, contents, and controls reported for that storage vessel. If additional controls would be necessary to comply with proposed requirements for storage vessels, the HAP emissions were again estimated based on the upgraded controls. The pre- and postcontrol emissions were summed across all storage vessels at the facility to determine a facility-specific emission reduction factor. The facility-specific emission reduction factor was then used to adjust the emissions for each of the pollutants reported for storage vessels at that facility to account for the postcontrol emissions. In this manner, the expected emission reductions were applied to the specific HAP and emission points in the source category dataset to develop corresponding estimates of risk and incremental risk reductions. The resulting emission file used for post-control risk analysis is available in the docket for this action (Docket ID Number EPA–HQ–OAR– 2010–0682). 5. How did we assess risks considering emissions control options? In addition to assessing baseline inhalation risks and screening for potential multipathway risks, we also estimated risks considering the potential emission reductions that would be achieved by the control options under consideration. We used the same emissions inventory that we used for the risk modeling and applied emission reduction estimates for the control options we are proposing to calculate the post-control risk. We note that for storage vessels, in response to the ICR some facilities reported emissions for their tank farm or a group of storage vessels rather than for each individual storage vessel. In order to calculate emissions for each storage vessel, we used unit-specific data from the ICR to estimate the pre- and post-control 6. How did we conduct the environmental risk screening assessment? 14 In doing so, EPA notes that the legal standard for a primary NAAQS—that a standard is requisite to protect public health and provide an adequate margin of safety (CAA Section 109(b))—differs from the Section 112(f) standard (requiring among other things that the standard provide an ‘‘ample margin of safety’’). However, the lead NAAQS is a reasonable measure of determining risk acceptability (i.e., the first step of the Benzene NESHAP analysis) since it is designed to protect the most susceptible group in the human population— children, including children living near major lead emitting sources. 73 FR 67002/3; 73 FR 67000/3; 73 FR 67005/1, November 12, 2008. In addition, applying the level of the primary lead NAAQS at the risk acceptability step is conservative, since that primary lead NAAQS reflects an adequate margin of safety. PO 00000 Frm 00014 Fmt 4701 Sfmt 4702 a. Adverse Environmental Effect The EPA has developed a screening approach to examine the potential for adverse environmental effects as required under section 112(f)(2)(A) of the CAA. Section 112(a)(7) of the CAA defines ‘‘adverse environmental effect’’ as ‘‘any significant and widespread adverse effect, which may reasonably be anticipated, to wildlife, aquatic life, or other natural resources, including adverse impacts on populations of endangered or threatened species or significant degradation of environmental quality over broad areas.’’ b. Environmental HAP The EPA focuses on seven HAP, which we refer to as ‘‘environmental HAP,’’ in its screening analysis: five PB– HAP and two acid gases. The five PB– HAP are cadmium, dioxins/furans, POM, mercury (both inorganic mercury and methyl mercury) and lead compounds. The two acid gases are HCl and HF. The rationale for including these seven HAP in the environmental risk screening analysis is presented below. HAP that persist and bioaccumulate are of particular environmental concern because they accumulate in the soil, sediment and water. The PB–HAP are E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules taken up, through sediment, soil, water, and/or ingestion of other organisms, by plants or animals (e.g., small fish) at the bottom of the food chain. As larger and larger predators consume these organisms, concentrations of the PB– HAP in the animal tissues increases as does the potential for adverse effects. The five PB–HAP we evaluate as part of our screening analysis account for 99.8 percent of all PB–HAP emissions nationally from stationary sources (on a mass basis from the 2005 National Emissions Inventory (NEI)). In addition to accounting for almost all of the mass of PB–HAP emitted, we note that the TRIM.Fate model that we use to evaluate multipathway risk allows us to estimate concentrations of cadmium compounds, dioxins/furans, POM and mercury in soil, sediment and water. For lead compounds, we currently do not have the ability to calculate these concentrations using the TRIM.Fate model. Therefore, to evaluate the potential for adverse environmental effects from lead, we compare the estimated HEM-modeled exposures from the source category emissions of lead with the level of the secondary NAAQS for lead.15 We consider values below the level of the secondary lead NAAQS to be unlikely to cause adverse environmental effects. Due to their well-documented potential to cause direct damage to terrestrial plants, we include two acid gases, HCl and HF, in the environmental screening analysis. According to the 2005 NEI, HCl and HF account for about 99 percent (on a mass basis) of the total acid gas HAP emitted by stationary sources in the U.S. In addition to the potential to cause direct damage to plants, high concentrations of HF in the air have been linked to fluorosis in livestock. Air concentrations of these HAP are already calculated as part of the human multipathway exposure and risk screening analysis using the HEM3– AERMOD air dispersion model, and we are able to use the air dispersion modeling results to estimate the potential for an adverse environmental effect. The EPA acknowledges that other HAP beyond the seven HAP discussed above may have the potential to cause adverse environmental effects. Therefore, the EPA may include other 15 The secondary lead NAAQS is a reasonable measure of determining whether there is an adverse environmental effect since it was established considering ‘‘effects on soils, water, crops, vegetation, man-made materials, animals, wildlife, weather, visibility and climate, damage to and deterioration of property, and hazards to transportation, as well as effects on economic values and on personal comfort and well-being.’’ VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 relevant HAP in its environmental risk screening in the future, as modeling science and resources allow. The EPA invites comment on the extent to which other HAP emitted by the source categories may cause adverse environmental effects. Such information should include references to peerreviewed ecological effects benchmarks that are of sufficient quality for making regulatory decisions, as well as information on the presence of organisms located near facilities within the source categories that such benchmarks indicate could be adversely affected. c. Ecological Assessment Endpoints and Benchmarks for PB–HAP An important consideration in the development of the EPA’s screening methodology is the selection of ecological assessment endpoints and benchmarks. Ecological assessment endpoints are defined by the ecological entity (e.g., aquatic communities including fish and plankton) and its attributes (e.g., frequency of mortality). Ecological assessment endpoints can be established for organisms, populations, communities or assemblages, and ecosystems. For PB–HAP, we evaluated the following community-level ecological assessment endpoints to screen for organisms directly exposed to HAP in soils, sediment and water: • Local terrestrial communities (i.e., soil invertebrates, plants) and populations of small birds and mammals that consume soil invertebrates exposed to PB–HAP in the surface soil. • Local benthic (i.e., bottom sediment dwelling insects, amphipods, isopods and crayfish) communities exposed to PB–HAP in sediment in nearby water bodies. • Local aquatic (water-column) communities (including fish and plankton) exposed to PB–HAP in nearby surface waters. For PB–HAP, we also evaluated the following population-level ecological assessment endpoint to screen for indirect HAP exposures of top consumers via the bioaccumulation of HAP in food chains. • Piscivorous (i.e., fish-eating) wildlife consuming PB–HAPcontaminated fish from nearby water bodies. For cadmium compounds, dioxins/ furans, POM and mercury, we identified the available ecological benchmarks for each assessment endpoint. An ecological benchmark represents a concentration of HAP (e.g., 0.77 micrograms of HAP per liter of water) PO 00000 Frm 00015 Fmt 4701 Sfmt 4702 36893 that has been linked to a particular environmental effect level (e.g., a noobserved-adverse-effect level (NOAEL)) through scientific study. For PB–HAP we identified, where possible, ecological benchmarks at the following effect levels: • Probable effect level (PEL): Level above which adverse effects are expected to occur frequently. • Lowest-observed-adverse-effect level (LOAEL): The lowest exposure level tested at which there are biologically significant increases in frequency or severity of adverse effects. • No-observed-adverse-effect level (NOAEL): The highest exposure level tested at which there are no biologically significant increases in the frequency or severity of adverse effect. We established a hierarchy of preferred benchmark sources to allow selection of benchmarks for each environmental HAP at each ecological assessment endpoint. In general, the EPA sources that are used at a programmatic level (e.g., Office of Water, Superfund Program) were used, if available. If not, the EPA benchmarks used in regional programs (e.g., Superfund) were used. If benchmarks were not available at a programmatic or regional level, we used benchmarks developed by other federal agencies (e.g., NOAA) or state agencies. Benchmarks for all effect levels are not available for all PB–HAP and assessment endpoints. In cases where multiple effect levels were available for a particular PB–HAP and assessment endpoint, we use all of the available effect levels to help us to determine whether ecological risks exist and, if so, whether the risks could be considered significant and widespread. d. Ecological Assessment Endpoints and Benchmarks for Acid Gases The environmental screening analysis also evaluated potential damage and reduced productivity of plants due to direct exposure to acid gases in the air. For acid gases, we evaluated the following ecological assessment endpoint: • Local terrestrial plant communities with foliage exposed to acidic gaseous HAP in the air. The selection of ecological benchmarks for the effects of acid gases on plants followed the same approach as for PB–HAP (i.e., we examine all of the available chronic benchmarks). For HCl, the EPA identified chronic benchmark concentrations. We note that the benchmark for chronic HCl exposure to plants is greater than the reference concentration for chronic inhalation exposure for human health. This means E:\FR\FM\30JNP2.SGM 30JNP2 36894 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules that where EPA includes regulatory requirements to prevent an exceedance of the reference concentration for human health, additional analyses for adverse environmental effects of HCl would not be necessary. For HF, EPA identified chronic benchmark concentrations for plants and evaluated chronic exposures to plants in the screening analysis. High concentrations of HF in the air have also been linked to fluorosis in livestock. However, the HF concentrations at which fluorosis in livestock occur are higher than those at which plant damage begins. Therefore, the benchmarks for plants are protective of both plants and livestock. emcdonald on DSK67QTVN1PROD with PROPOSALS2 e. Screening Methodology For the environmental risk screening analysis, the EPA first determined whether any petroleum refineries emitted any of the seven environmental HAP. For the petroleum refinery source categories, we identified emissions of cadmium, dioxins/furans, POM, mercury (both inorganic mercury and methyl mercury), lead, HCl and HF. Because one or more of the seven environmental HAP evaluated are emitted by at least one petroleum refinery, we proceeded to the second step of the evaluation. f. PB–HAP Methodology For cadmium, mercury, POM and dioxins/furans, the environmental screening analysis consists of two tiers, while lead is analyzed differently as discussed earlier. In the first tier, we determined whether the maximum facility-specific emission rates of each of the emitted environmental HAP were large enough to create the potential for adverse environmental effects under reasonable worst-case environmental conditions. These are the same environmental conditions used in the human multipathway exposure and risk screening analysis. To facilitate this step, TRIM.FaTE was run for each PB–HAP under hypothetical environmental conditions designed to provide conservatively high HAP concentrations. The model was set to maximize runoff from terrestrial parcels into the modeled lake, which in turn, maximized the chemical concentrations in the water, the sediments, and the fish. The resulting media concentrations were then used to back-calculate a screening threshold emission rate that corresponded to the relevant exposure benchmark concentration value for each assessment endpoint. To assess emissions from a facility, the reported emission rate for each PB–HAP was compared to the VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 screening threshold emission rate for that PB–HAP for each assessment endpoint. If emissions from a facility do not exceed the Tier I threshold, the facility ‘‘passes’’ the screen, and therefore, is not evaluated further under the screening approach. If emissions from a facility exceed the Tier I threshold, we evaluate the facility further in Tier II. In Tier II of the environmental screening analysis, the screening emission thresholds are adjusted to account for local meteorology and the actual location of lakes in the vicinity of facilities that did not pass the Tier I screen. The modeling domain for each facility in the Tier II analysis consists of eight octants. Each octant contains five modeled soil concentrations at various distances from the facility (5 soil concentrations × 8 octants = total of 40 soil concentrations per facility) and one lake with modeled concentrations for water, sediment and fish tissue. In the Tier II environmental risk screening analysis, the 40 soil concentration points are averaged to obtain an average soil concentration for each facility for each PB–HAP. For the water, sediment and fish tissue concentrations, the highest value for each facility for each pollutant is used. If emission concentrations from a facility do not exceed the Tier II threshold, the facility passes the screen, and is typically not evaluated further. If emissions from a facility exceed the Tier II threshold, the facility does not pass the screen and, therefore, may have the potential to cause adverse environmental effects. Such facilities are evaluated further to investigate factors such as the magnitude and characteristics of the area of exceedance. g. Acid Gas Methodology The environmental screening analysis evaluates the potential phytotoxicity and reduced productivity of plants due to chronic exposure to acid gases. The environmental risk screening methodology for acid gases is a singletier screen that compares the average off-site ambient air concentration over the modeling domain to ecological benchmarks for each of the acid gases. Because air concentrations are compared directly to the ecological benchmarks, emission-based thresholds are not calculated for acid gases as they are in the ecological risk screening methodology for PB–HAP. For purposes of ecological risk screening, EPA identifies a potential for adverse environmental effects to plant communities from exposure to acid gases when the average concentration of the HAP around a facility exceeds the PO 00000 Frm 00016 Fmt 4701 Sfmt 4702 LOAEL ecological benchmark. In such cases, we further investigate factors such as the magnitude and characteristics of the area of exceedance (e.g., land use of exceedance area, size of exceedance area) to determine if there is an adverse environmental effect. For further information on the environmental screening analysis approach, see section IV.C.5 of this preamble and the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, which is available in the docket for this action (Docket ID Number EPA–HQ–OAR–2010–0682). 7. How did we conduct facility-wide assessments? To put the source category risks in context, following the assessment approach outlined in the SAB (2010) review, we examine the risks from the entire ‘‘facility,’’ where the facility includes all HAP-emitting operations within a contiguous area and under common control. In other words, we examine the HAP emissions not only from the source category emission points of interest, but also emissions of HAP from all other emission sources at the facility for which we have data. The emissions inventories provided in response to the ICR included emissions information for all emission sources at the facilities that are part of the refineries source categories. Generally, only a few emission sources located at refineries are not subject to either Refinery MACT 1 or 2; the most notable are boilers, process heaters and internal combustion engines, which are addressed by other MACT standards. We analyzed risks due to the inhalation of HAP that are emitted ‘‘facility-wide’’ for the populations residing within 50 km of each facility, consistent with the methods used for the source category analysis described above. For these facility-wide risk analyses, the modeled source category risks were compared to the facility-wide risks to determine the portion of facilitywide risks that could be attributed to each of the source categories addressed in this proposal. We specifically examined the facility that was associated with the highest estimates of risk and determined the percentage of that risk attributable to the source category of interest. The Draft Residual Risk Assessment for the Petroleum Refining Source Sector available through the docket for this action (Docket ID Number EPA–HQ–OAR– 2010–0682) provides the methodology and results of the facility-wide analyses, including all facility-wide risks and the percentage of source category contribution to facility-wide risks. E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 8. How did we consider uncertainties in risk assessment? In the Benzene NESHAP we concluded that risk estimation uncertainty should be considered in our decision-making under the ample margin of safety framework. Uncertainty and the potential for bias are inherent in all risk assessments, including those performed for this proposal. Although uncertainty exists, we believe that our approach, which used conservative tools and assumptions, ensures that our decisions are health protective and environmentally protective. A brief discussion of the uncertainties in the emissions datasets, dispersion modeling, inhalation exposure estimates and dose-response relationships follows below. A more thorough discussion of these uncertainties is included in the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, which is available in the docket for this action (Docket ID Number EPA–HQ– OAR–2010–0682). emcdonald on DSK67QTVN1PROD with PROPOSALS2 a. Uncertainties in the Emission Datasets Although the development of the RTR datasets involved quality assurance/ quality control processes, the accuracy of emissions values will vary depending on the source of the data, the degree to which data are incomplete or missing, the degree to which assumptions made to complete the datasets are accurate, errors in emission estimates and other factors. The emission estimates considered in this analysis are annual totals for 2010, and they do not reflect short-term fluctuations during the course of a year or variations from year to year. The estimates of peak hourly emissions rates for the acute effects screening assessment were based on emission adjustment factors applied to the average annual hourly emission rates, which are intended to account for emission fluctuations due to normal facility operations. As discussed previously, we attempted to provide a consistent framework for reporting of emissions information by developing the refinery emissions estimation protocol and requesting that refineries follow the protocol when reporting emissions inventory data in response to the ICR. This protocol, called Emission Estimation Protocol for Petroleum Refineries, is available in the docket for this rulemaking (Docket Item Number EPA–HQ–OAR–2010–0682–0060). Additionally, we developed our own estimates of emissions that are based on the factors provided in the protocol and the REM Model. We developed emission VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 estimates based on refinery unit capacities, which also provided an estimate of allowable emissions. We then conducted risk modeling using REM Model estimates and by locating emissions at the centroid of each refinery in an attempt to understand the risk associated with emissions from each refinery. Therefore, even if there were errors in the emission inventories reported in the ICR, as was the case in many instances, emissions for those facilities were also modeled using the protocol emission factors. The risk modeling of allowable emissions based on emission factors and unit capacities did not result in significantly different risk results than the actual emissions modeling runs. Results of the allowable emissions risk estimates are provided in the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, which is available in Docket ID Number EPA–HQ–OAR–2010–0682. b. Uncertainties in Dispersion Modeling We recognize there is uncertainty in ambient concentration estimates associated with any model, including the EPA’s recommended regulatory dispersion model, AERMOD. In using a model to estimate ambient pollutant concentrations, the user chooses certain options to apply. For RTR assessments, we select some model options that have the potential to overestimate ambient air concentrations (e.g., not including plume depletion or pollutant transformation). We select other model options that have the potential to underestimate ambient impacts (e.g., not including building downwash). Other options that we select have the potential to either under- or overestimate ambient levels (e.g., meteorology and receptor locations). On balance, considering the directional nature of the uncertainties commonly present in ambient concentrations estimated by dispersion models, the approach we apply in the RTR assessments should yield unbiased estimates of ambient HAP concentrations. c. Uncertainties in Inhalation Exposure The EPA did not include the effects of human mobility on exposures in the assessment. Specifically, short-term mobility and long-term mobility between census blocks in the modeling domain were not considered.16 The approach of not considering short- or long-term population mobility does not bias the estimate of the theoretical MIR 16 Short-term mobility is movement from one micro-environment to another over the course of hours or days. Long-term mobility is movement from one residence to another over the course of a lifetime. PO 00000 Frm 00017 Fmt 4701 Sfmt 4702 36895 (by definition), nor does it affect the estimate of cancer incidence because the total population number remains the same. It does, however, affect the shape of the distribution of individual risks across the affected population, shifting it toward higher estimated individual risks at the upper end and reducing the number of people estimated to be at lower risks, thereby increasing the estimated number of people at specific high-risk levels (e.g., 1-in-10 thousand or 1-in-1 million). In addition, the assessment predicted the chronic exposures at the centroid of each populated census block as surrogates for the exposure concentrations for all people living in that block. Using the census block centroid to predict chronic exposures tends to over-predict exposures for people in the census block who live further from the facility and underpredict exposures for people in the census block who live closer to the facility. Thus, using the census block centroid to predict chronic exposures may lead to a potential understatement or overstatement of the true maximum impact, but is an unbiased estimate of average risk and incidence. We reduce this uncertainty by analyzing large census blocks near facilities using aerial imagery and adjusting the location of the block centroid to better represent the population in the block, as well as adding additional receptor locations where the block population is not well represented by a single location. The assessment evaluates the cancer inhalation risks associated with pollutant exposures over a 70-year period, which is the assumed lifetime of an individual. In reality, both the length of time that modeled emission sources at facilities actually operate (i.e., more or less than 70 years) and the domestic growth or decline of the modeled industry (i.e., the increase or decrease in the number or size of domestic facilities) will influence the future risks posed by a given source or source category. Depending on the characteristics of the industry, these factors will, in most cases, result in an overestimate both in individual risk levels and in the total estimated number of cancer cases. However, in the unlikely scenario where a facility maintains, or even increases, its emissions levels over a period of more than 70 years, residents live beyond 70 years at the same location, and the residents spend most of their days at that location, then the cancer inhalation risks could potentially be underestimated. However, annual cancer incidence estimates from exposures to emissions from these E:\FR\FM\30JNP2.SGM 30JNP2 36896 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 sources would not be affected by the length of time an emissions source operates. The exposure estimates used in these analyses assume chronic exposures to ambient (outdoor) levels of pollutants. Because most people spend the majority of their time indoors, actual exposures may not be as high, depending on the characteristics of the pollutants modeled. For many of the HAP, indoor levels are roughly equivalent to ambient levels, but for very reactive pollutants or larger particles, indoor levels are typically lower. This factor has the potential to result in an overestimate of 25 to 30 percent of exposures.17 In addition to the uncertainties highlighted above, there are several factors specific to the acute exposure assessment that should be highlighted. The accuracy of an acute inhalation exposure assessment depends on the simultaneous occurrence of independent factors that may vary greatly, such as hourly emissions rates, meteorology and human activity patterns. In this assessment, we assume that individuals remain for 1 hour at the point of maximum ambient concentration as determined by the cooccurrence of peak emissions and worstcase meteorological conditions. These assumptions would tend to be worstcase actual exposures as it is unlikely that a person would be located at the point of maximum exposure during the time when peak emissions and worstcase meteorological conditions occur simultaneously. d. Uncertainties in Dose-Response Relationships There are uncertainties inherent in the development of the dose-response values used in our risk assessments for cancer effects from chronic exposures and non-cancer effects from both chronic and acute exposures. Some uncertainties may be considered quantitatively, and others generally are expressed in qualitative terms. We note as a preface to this discussion a point on dose-response uncertainty that is brought out in the EPA’s 2005 Cancer Guidelines; namely, that ‘‘the primary goal of EPA actions is protection of human health; accordingly, as an Agency policy, risk assessment procedures, including default options that are used in the absence of scientific data to the contrary, should be health protective’’ (EPA 2005 Cancer Guidelines, pages 1–7). This is the approach followed here as summarized 17 U.S. EPA. National-Scale Air Toxics Assessment for 1996. (EPA 453/R–01–003; January 2001; page 85.) VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 in the next several paragraphs. A complete detailed discussion of uncertainties and variability in doseresponse relationships is given in the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, which is available in the docket for this action (Docket ID Number EPA–HQ– OAR–2010–0682). Cancer URE values used in our risk assessments are those that have been developed to generally provide an upper bound estimate of risk. That is, they represent a ‘‘plausible upper limit to the true value of a quantity’’ (although this is usually not a true statistical confidence limit).18 In some circumstances, the true risk could be as low as zero; however, in other circumstances, the risk could also be greater.19 When developing an upperbound estimate of risk and to provide risk values that do not underestimate risk, health-protective default approaches are generally used. To err on the side of ensuring adequate healthprotection, the EPA typically uses the upper bound estimates rather than lower bound or central tendency estimates in our risk assessments, an approach that may have limitations for other uses (e.g., priority-setting or expected benefits analysis). Chronic non-cancer RfC and reference dose (RfD) values represent chronic exposure levels that are intended to be health-protective levels. Specifically, these values provide an estimate (with uncertainty spanning perhaps an order of magnitude) of a continuous inhalation exposure (RfC) or a daily oral exposure (RfD) to the human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime. To derive values that are intended to be ‘‘without appreciable risk,’’ the methodology relies upon an uncertainty factor (UF) approach (U.S. EPA, 1993, 1994) which considers uncertainty, variability and gaps in the available data. The UF are applied to derive reference values that are intended to protect against appreciable risk of deleterious effects. The UF are commonly default values,20 e.g., factors 18 IRIS glossary (https://ofmpub.epa.gov/sor_ internet/registry/termreg/searchandretrieve/ glossariesandkeywordlists/search.do?details=& glossaryName=IRIS%20Glossary). 19 An exception to this is the URE for benzene, which is considered to cover a range of values, each end of which is considered to be equally plausible, and which is based on maximum likelihood estimates. 20 According to the NRC report, Science and Judgment in Risk Assessment (NRC, 1994) ‘‘[Default] options are generic approaches, based on general scientific knowledge and policy judgment, that are applied to various elements of the risk PO 00000 Frm 00018 Fmt 4701 Sfmt 4702 of 10 or 3, used in the absence of compound-specific data; where data are available, UF may also be developed using compound-specific information. When data are limited, more assumptions are needed and more UF are used. Thus, there may be a greater tendency to overestimate risk in the sense that further study might support development of reference values that are higher (i.e., less potent) because fewer default assumptions are needed. However, for some pollutants, it is possible that risks may be underestimated. While collectively termed ‘‘UF,’’ these factors account for a number of different quantitative considerations when using observed animal (usually rodent) or human toxicity data in the development of the RfC. The UF are intended to account for: (1) Variation in susceptibility among the members of the human population (i.e., inter-individual variability); (2) uncertainty in extrapolating from experimental animal data to humans (i.e., interspecies differences); (3) uncertainty in extrapolating from data obtained in a study with less-than-lifetime exposure (i.e., extrapolating from sub-chronic to chronic exposure); (4) uncertainty in extrapolating the observed data to obtain an estimate of the exposure associated with no adverse effects; and (5) uncertainty when the database is incomplete or there are problems with the applicability of available studies. Many of the UF used to account for variability and uncertainty in the development of acute reference values are quite similar to those developed for chronic durations, but they more often use individual UF values that may be less than 10. The UF are applied based on chemical-specific or health effectspecific information (e.g., simple irritation effects do not vary appreciably between human individuals, hence a value of 3 is typically used), or based on the purpose for the reference value (see the following paragraph). The UF assessment process when the correct scientific model is unknown or uncertain.’’ The 1983 NRC report, Risk Assessment in the Federal Government: Managing the Process, defined default option as ‘‘the option chosen on the basis of risk assessment policy that appears to be the best choice in the absence of data to the contrary’’ (NRC, 1983a, p. 63). Therefore, default options are not rules that bind the Agency; rather, the Agency may depart from them in evaluating the risks posed by a specific substance when it believes this to be appropriate. In keeping with EPA’s goal of protecting public health and the environment, default assumptions are used to ensure that risk to chemicals is not underestimated (although defaults are not intended to overtly overestimate risk). See EPA, 2004, An Examination of EPA Risk Assessment Principles and Practices, EPA/100/B–04/001 available at: https://www.epa.gov/osa/pdfs/ratf-final.pdf. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules applied in acute reference value derivation include: (1) Heterogeneity among humans; (2) uncertainty in extrapolating from animals to humans; (3) uncertainty in lowest observable adverse effect (exposure) level to no observed adverse effect (exposure) level adjustments; and (4) uncertainty in accounting for an incomplete database on toxic effects of potential concern. Additional adjustments are often applied to account for uncertainty in extrapolation from observations at one exposure duration (e.g., 4 hours) to derive an acute reference value at another exposure duration (e.g., 1 hour). Not all acute reference values are developed for the same purpose and care must be taken when interpreting the results of an acute assessment of human health effects relative to the reference value or values being exceeded. Where relevant to the estimated exposures, the lack of shortterm dose-response values at different levels of severity should be factored into the risk characterization as potential uncertainties. Although every effort is made to identify appropriate human health effect dose-response assessment values for all pollutants emitted by the sources in this risk assessment, some HAP emitted by these source categories are lacking doseresponse assessments. Accordingly, these pollutants cannot be included in the quantitative risk assessment, which could result in quantitative estimates understating HAP risk. To help to alleviate this potential underestimate, where we conclude similarity with a HAP for which a dose-response assessment value is available, we use that value as a surrogate for the assessment of the HAP for which no value is available. To the extent use of surrogates indicates appreciable risk, we may identify a need to increase priority for new IRIS assessment of that substance. We additionally note that, generally speaking, HAP of greatest concern due to environmental exposures and hazard are those for which dose-response assessments have been performed, reducing the likelihood of understating risk. Further, HAP not included in the quantitative assessment are assessed qualitatively and considered in the risk characterization that informs the risk management decisions, including with regard to consideration of HAP reductions achieved by various control options. For a group of compounds that are unspeciated (e.g., glycol ethers), we conservatively use the most protective reference value of an individual compound in that group to estimate risk. Similarly, for an individual VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 compound in a group (e.g., ethylene glycol diethyl ether) that does not have a specified reference value, we also apply the most protective reference value from the other compounds in the group to estimate risk. e. Uncertainties in the Multipathway Assessment For each source category, we generally rely on site-specific levels of PB-HAP emissions to determine whether a refined assessment of the impacts from multipathway exposures is necessary. This determination is based on the results of a two-tiered screening analysis that relies on the outputs from models that estimate environmental pollutant concentrations and human exposures for four PB-HAP. Two important types of uncertainty associated with the use of these models in RTR risk assessments and inherent to any assessment that relies on environmental modeling are model uncertainty and input uncertainty.21 Model uncertainty concerns whether the selected models are appropriate for the assessment being conducted and whether they adequately represent the actual processes that might occur for that situation. An example of model uncertainty is the question of whether the model adequately describes the movement of a pollutant through the soil. This type of uncertainty is difficult to quantify. However, based on feedback received from previous EPA SAB reviews and other reviews, we are confident that the models used in the screen are appropriate and state-of-theart for the multipathway risk assessments conducted in support of RTR. Input uncertainty is concerned with how accurately the models have been configured and parameterized for the assessment at hand. For Tier I of the multipathway screen, we configured the models to avoid underestimating exposure and risk. This was accomplished by selecting upper-end values from nationally-representative data sets for the more influential parameters in the environmental model, including selection and spatial configuration of the area of interest, lake location and size, meteorology, surface water and soil characteristics and structure of the aquatic food web. We also assume an ingestion exposure scenario and values for human exposure 21 In the context of this discussion, the term ‘‘uncertainty’’ as it pertains to exposure and risk encompasses both variability in the range of expected inputs and screening results due to existing spatial, temporal, and other factors, as well as uncertainty in being able to accurately estimate the true result. PO 00000 Frm 00019 Fmt 4701 Sfmt 4702 36897 factors that represent reasonable maximum exposures. In Tier II of the multipathway assessment, we refine the model inputs to account for meteorological patterns in the vicinity of the facility versus using upper-end national values and we identify the actual location of lakes near the facility rather than the default lake location that we apply in Tier I. By refining the screening approach in Tier II to account for local geographical and meteorological data, we decrease the likelihood that concentrations in environmental media are overestimated, thereby increasing the usefulness of the screen. The assumptions and the associated uncertainties regarding the selected ingestion exposure scenario are the same for Tier I and Tier II. For both Tiers I and II of the multipathway assessment, our approach to addressing model input uncertainty is generally cautious. We choose model inputs from the upper end of the range of possible values for the influential parameters used in the models, and we assume that the exposed individual exhibits ingestion behavior that would lead to a high total exposure. This approach reduces the likelihood of not identifying high risks for adverse impacts. Despite the uncertainties, when individual pollutants or facilities do screen out, we are confident that the potential for adverse multipathway impacts on human health is very low. On the other hand, when individual pollutants or facilities do not screen out, it does not mean that multipathway impacts are significant, only that we cannot rule out that possibility and that a refined multipathway analysis for the site might be necessary to obtain a more accurate risk characterization for the source categories. For further information on uncertainties and the Tier I and II screening methods, refer to the risk document Appendix 4, Technical Support Document for TRIM-Based Multipathway Tiered Screening Methodology for RTR. f. Uncertainties in the Environmental Risk Screening Assessment For each source category, we generally rely on site-specific levels of environmental HAP emissions to perform an environmental screening assessment. The environmental screening assessment is based on the outputs from models that estimate environmental HAP concentrations. The same models, specifically the TRIM.FaTE multipathway model and the AERMOD air dispersion model, are used to estimate environmental HAP E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36898 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules concentrations for both the human multipathway screening analysis and for the environmental screening analysis. Therefore, both screening assessments have similar modeling uncertainties. Two important types of uncertainty associated with the use of these models in RTR environmental screening assessments—and inherent to any assessment that relies on environmental modeling—are model uncertainty and input uncertainty.22 Model uncertainty concerns whether the selected models are appropriate for the assessment being conducted and whether they adequately represent the movement and accumulation of environmental HAP emissions in the environment. For example, does the model adequately describe the movement of a pollutant through the soil? This type of uncertainty is difficult to quantify. However, based on feedback received from previous EPA SAB reviews and other reviews, we are confident that the models used in the screen are appropriate and state-of-theart for the environmental risk assessments conducted in support of our RTR analyses. Input uncertainty is concerned with how accurately the models have been configured and parameterized for the assessment at hand. For Tier I of the environmental screen for PB–HAP, we configured the models to avoid underestimating exposure and risk to reduce the likelihood that the results indicate the risks are lower than they actually are. This was accomplished by selecting upper-end values from nationally-representative data sets for the more influential parameters in the environmental model, including selection and spatial configuration of the area of interest, the location and size of any bodies of water, meteorology, surface water and soil characteristics and structure of the aquatic food web. In Tier I, we used the maximum facilityspecific emissions for cadmium compounds, dioxins/furans, POM, and mercury and each of the media when comparing to ecological benchmarks. This is consistent with the conservative design of Tier I of the screen. In Tier II of the environmental screening analysis for PB–HAP, we refine the model inputs to account for meteorological patterns in the vicinity of the facility versus using upper-end national values, and we identify the locations of water bodies 22 In the context of this discussion, the term ‘‘uncertainty,’’ as it pertains to exposure and risk assessment, encompasses both variability in the range of expected inputs and screening results due to existing spatial, temporal, and other factors, as well as uncertainty in being able to accurately estimate the true result. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 near the facility location. By refining the screening approach in Tier II to account for local geographical and meteorological data, we decrease the likelihood that concentrations in environmental media are overestimated, thereby increasing the usefulness of the screen. To better represent widespread impacts, the modeled soil concentrations are averaged in Tier II to obtain one average soil concentration value for each facility and for each PB– HAP. For PB–HAP concentrations in water, sediment and fish tissue, the highest value for each facility for each pollutant is used. For the environmental screening assessment for acid gases, we employ a single-tiered approach. We use the modeled air concentrations and compare those with ecological benchmarks. For both Tiers I and II of the environmental screening assessment, our approach to addressing model input uncertainty is generally cautious. We choose model inputs from the upper end of the range of possible values for the influential parameters used in the models, and we assume that the exposed organism (e.g., invertebrate, fish) exhibits ingestion behavior that would lead to a high total exposure. This approach reduces the likelihood of not identifying potential risks for adverse environmental impacts. Uncertainty also exists in the ecological benchmarks for the environmental risk screening analysis. We established a hierarchy of preferred benchmark sources to allow selection of benchmarks for each environmental HAP at each ecological assessment endpoint. In general, EPA benchmarks used at a programmatic level (e.g., Office of Water, Superfund Program) were used if available. If not, we used EPA benchmarks used in regional programs (e.g., Superfund). If benchmarks were not available at a programmatic or regional level, we used benchmarks developed by other agencies (e.g., NOAA) or by state agencies. In all cases (except for lead, which was evaluated through a comparison to the NAAQS), we searched for benchmarks at the following three effect levels, as described in section III.A.6 of this preamble: 1. A no-effect level (i.e., NOAEL). 2. Threshold-effect level (i.e., LOAEL). 3. Probable effect level (i.e., PEL). For some ecological assessment endpoint/environmental HAP combinations, we could identify benchmarks for all three effect levels, but for most, we could not. In one case, PO 00000 Frm 00020 Fmt 4701 Sfmt 4702 where different agencies derived significantly different numbers to represent a threshold for effect, we included both. In several cases, only a single benchmark was available. In cases where multiple effect levels were available for a particular PB–HAP and assessment endpoint, we used all of the available effect levels to help us to determine whether risk exists and if the risks could be considered significant and widespread. The EPA evaluated the following seven HAP in the environmental risk screening assessment: Cadmium, dioxins/furans, POM, mercury (both inorganic mercury and methyl mercury), lead compounds, HCl and HF. These seven HAP represent pollutants that can cause adverse impacts for plants and animals either through direct exposure to HAP in the air or through exposure to HAP that is deposited from the air onto soils and surface waters. These seven HAP also represent those HAP for which we can conduct a meaningful environmental risk screening assessment. For other HAP not included in our screening assessment, the model has not been parameterized such that it can be used for that purpose. In some cases, depending on the HAP, we may not have appropriate multipathway models that allow us to predict the concentration of that pollutant. The EPA acknowledges that other HAP beyond the seven HAP that we are evaluating may have the potential to cause adverse environmental effects and, therefore, the EPA may evaluate other relevant HAP in the future, as modeling science and resources allow. Further information on uncertainties and the Tier I and II environmental screening methods is provided in Appendix 5 of the document Technical Support Document for TRIM-Based Multipathway Tiered Screening Methodology for RTR: Summary of Approach and Evaluation. Also, see the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, available in the docket for this action (Docket ID Number EPA–HQ–OAR– 2010–0682). B. How did we consider the risk results in making decisions for this proposal? As discussed in section II.A.1 of this preamble, in evaluating and developing standards under CAA section 112(f)(2), we apply a two-step process to address residual risk. In the first step, the EPA determines whether risks are acceptable. This determination ‘‘considers all health information, including risk estimation uncertainty, and includes a presumptive limit on maximum individual lifetime E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules [cancer] risk (MIR) 23 of approximately [1-in-10 thousand] [i.e., 100-in-1 million].’’ 54 FR 38045, September 14, 1989. If risks are unacceptable, the EPA must determine the emissions standards necessary to bring risks to an acceptable level without considering costs. In the second step of the process, the EPA considers whether the emissions standards provide an ample margin of safety ‘‘in consideration of all health information, including the number of persons at risk levels higher than approximately 1-in-1 million, as well as other relevant factors, including costs and economic impacts, technological feasibility, and other factors relevant to each particular decision.’’ Id. The EPA must promulgate tighter emission standards if necessary to provide an ample margin of safety. In past residual risk actions, the EPA considered a number of human health risk metrics associated with emissions from the categories under review, including the MIR, the number of persons in various risk ranges, cancer incidence, the maximum non-cancer HI and the maximum acute non-cancer hazard. See, e.g., 72 FR 25138, May 3, 2007; 71 FR 42724, July 27, 2006. The EPA considered this health information for both actual and allowable emissions. See, e.g., 75 FR 65068, October 21, 2010, and 75 FR 80220, December 21, 2010). The EPA also discussed risk estimation uncertainties and considered the uncertainties in the determination of acceptable risk and ample margin of safety in these past actions. The EPA considered this same type of information in support of this action. The agency is considering these various measures of health information to inform our determinations of risk acceptability and ample margin of safety under CAA section 112(f). As explained in the Benzene NESHAP, ‘‘the first step of judgment on acceptability cannot be reduced to any single factor,’’ and thus ‘‘[t]he Administrator believes that the acceptability of risk under [previous] section 112 is best judged on the basis of a broad set of health risk measures and information.’’ 54 FR 38046, September 14, 1989. Similarly, with regard to making the ample margin of safety determination, ‘‘the Agency again considers all of the health risk and other health information considered in the first step. Beyond that information, additional factors relating to the appropriate level of control will also be considered, including cost and 23 Although defined as ‘‘maximum individual risk,’’ MIR refers only to cancer risk. MIR, one metric for assessing cancer risk, is the estimated risk were an individual exposed to the maximum level of a pollutant for a lifetime. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 economic impacts of controls, technological feasibility, uncertainties, and any other relevant factors.’’ Id. The Benzene NESHAP approach provides flexibility regarding factors the EPA may consider in making determinations and how the EPA may weigh those factors for each source category. In responding to comment on our policy under the Benzene NESHAP, the EPA explained that: [t]he policy chosen by the Administrator permits consideration of multiple measures of health risk. Not only can the MIR figure be considered, but also incidence, the presence of non-cancer health effects, and the uncertainties of the risk estimates. In this way, the effect on the most exposed individuals can be reviewed as well as the impact on the general public. These factors can then be weighed in each individual case. This approach complies with the Vinyl Chloride mandate that the Administrator ascertain an acceptable level of risk to the public by employing [her] expertise to assess available data. It also complies with the Congressional intent behind the CAA, which did not exclude the use of any particular measure of public health risk from the EPA’s consideration with respect to CAA section 112 regulations, and thereby implicitly permits consideration of any and all measures of health risk which the Administrator, in [her] judgment, believes are appropriate to determining what will ‘protect the public health.’ See 54 FR at 38057, September 14, 1989. Thus, the level of the MIR is only one factor to be weighed in determining acceptability of risks. The Benzene NESHAP explained that ‘‘an MIR of approximately one in 10 thousand should ordinarily be the upper end of the range of acceptability. As risks increase above this benchmark, they become presumptively less acceptable under CAA section 112, and would be weighed with the other health risk measures and information in making an overall judgment on acceptability. Or, the Agency may find, in a particular case, that a risk that includes MIR less than the presumptively acceptable level is unacceptable in the light of other health risk factors.’’ Id. at 38045. Similarly, with regard to the ample margin of safety analysis, the EPA stated in the Benzene NESHAP that: ‘‘EPA believes the relative weight of the many factors that can be considered in selecting an ample margin of safety can only be determined for each specific source category. This occurs mainly because technological and economic factors (along with the health-related factors) vary from source category to source category.’’ Id. at 38061. We also consider the uncertainties associated with the various risk analyses, as discussed earlier in this preamble, in PO 00000 Frm 00021 Fmt 4701 Sfmt 4702 36899 our determinations of acceptability and ample margin of safety. The EPA notes that it has not considered certain health information to date in making residual risk determinations. At this time, we do not attempt to quantify those HAP risks that may be associated with emissions from other facilities that do not include the source categories in question, mobile source emissions, natural source emissions, persistent environmental pollution or atmospheric transformation in the vicinity of the sources in these categories. The agency understands the potential importance of considering an individual’s total exposure to HAP in addition to considering exposure to HAP emissions from the source category and facility. We recognize that such consideration may be particularly important when assessing non-cancer risks, where pollutant-specific health reference levels (e.g., RfCs) are based on the assumption that thresholds exist for adverse health effects. For example, the agency recognizes that, although exposures attributable to emissions from a source category or facility alone may not indicate the potential for increased risk of adverse non-cancer health effects in a population, the exposures resulting from emissions from the facility in combination with emissions from all of the other sources (e.g., other facilities) to which an individual is exposed may be sufficient to result in increased risk of adverse non-cancer health effects. In May 2010, the SAB advised the EPA ‘‘that RTR assessments will be most useful to decision makers and communities if results are presented in the broader context of aggregate and cumulative risks, including background concentrations and contributions from other sources in the area.’’ 24 In response to the SAB recommendations, the EPA is incorporating cumulative risk analyses into its RTR risk assessments, including those reflected in this proposal. The agency is: (1) Conducting facility-wide assessments, which include source category emission points as well as other emission points within the facilities; (2) considering sources in the same category whose emissions result in exposures to the same individuals; and (3) for some persistent and 24 EPA’s responses to this and all other key recommendations of the SAB’s advisory on RTR risk assessment methodologies (which is available at: https://yosemite.epa.gov/sab/sabproduct.nsf/ 4AB3966E263D943A8525771F00668381/$File/EPASAB-10-007-unsigned.pdf) are outlined in a memo to this rulemaking docket from David Guinnup entitled, EPA’s Actions in Response to the Key Recommendations of the SAB Review of RTR Risk Assessment Methodologies. E:\FR\FM\30JNP2.SGM 30JNP2 36900 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 bioaccumulative pollutants, analyzing the ingestion route of exposure. In addition, the RTR risk assessments have always considered aggregate cancer risk from all carcinogens and aggregate noncancer hazard indices from all noncarcinogens affecting the same target organ system. Although we are interested in placing source category and facility-wide HAP risks in the context of total HAP risks from all sources combined in the vicinity of each source, we are concerned about the uncertainties of doing so. Because we have not conducted in-depth studies of risks due to emissions from sources other those at refineries subject to this RTR review, such estimates of total HAP risks would have significantly greater associated uncertainties than the source category or facility-wide estimates. Such aggregate or cumulative assessments would compound those uncertainties, making the assessments too unreliable. C. How did we perform the technology review? Our technology review focused on the identification and evaluation of developments in practices, processes and control technologies that have occurred since the MACT standards were promulgated. Where we identified such developments, in order to inform our decision of whether it is ‘‘necessary’’ to revise the emissions standards, we analyzed the technical feasibility of applying these developments, and the estimated costs, energy implications, non-air environmental impacts, as well as considering the emission reductions. We also considered the appropriateness of applying controls to new sources versus retrofitting existing sources. Based on our analyses of the available data and information, we identified potential developments in practices, processes and control technologies. For this 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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). We reviewed a variety of data sources in our investigation of potential practices, processes or controls to consider. Among the sources we reviewed were the NESHAP for various industries that were promulgated since the MACT standards being reviewed in this action. We reviewed the regulatory requirements and/or technical analyses associated with these regulatory actions to identify any practices, processes and control technologies considered in these efforts that could be applied to emission sources subject to Refinery MACT 1 or 2, as well as the costs, non-air impacts and energy implications associated with the use of these technologies. Additionally, we requested information from facilities as described in section II.C of this preamble. Finally, we reviewed information from other sources, such as state and/or local permitting agency databases and industry-supported databases. IV. Analytical Results and Proposed Decisions A. What actions are we taking pursuant to CAA sections 112(d)(2) and 112(d)(3)? In this action, we are proposing the following revisions to the Refinery MACT 1 and 2 standards pursuant to CAA section 112(d)(2) and (3) 25: (1) Adding MACT standards for DCU decoking operations; (2) revising the CRU purge vent pressure exemption; (3) adding operational requirements for flares used as air pollution control devices (APCD) in Refinery MACT 1 and 2; and (4) adding requirements and clarifications for vent control bypasses in Refinery MACT 1. The results and proposed decisions based on the analyses performed pursuant to CAA section 112(d)(2) and (3) are presented below. 25 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). PO 00000 Frm 00022 Fmt 4701 Sfmt 4702 1. Delayed Coking Units a. Description of Delayed Coker Process Operations and Emissions We are proposing to establish MACT standards specific to the DCU pursuant to CAA section 112(d)(2) and (3). The DCU uses thermal cracking to upgrade heavy feedstocks and to produce petroleum coke. Unlike most other refinery operations that are continuous, the DCU operates in a semi-batch system. Most DCU consist of a large process heater, two or more coking drums, and a single product distillation column. The DCU feed is actually fed to the unit’s distillation column. Bottoms from the distillation column are heated to near cracking temperatures and the resulting heavy oil is fed to one of the coking drums. As the cracking reactions occur, coke is produced in the drum and begins to fill the drum with sponge-like solid coke material. During this process, the DCU is a closed system, with the produced gas streams piped to the unit’s distillation column for product recovery. When the first coke drum becomes filled with coke, the feed is diverted to the second coke drum and processing continues via the second coke drum. The full coke drum, which is no longer receiving oil feed, is taken through a number of steps, collectively referred to as decoking operations, to remove the coke from the drum and prepare the drum for subsequent oil feed processing. The decoking steps include: purging, cooling/quenching, venting, draining, deheading, and coke cutting. A description of these steps and the potential emissions from these activities are provided in the next several paragraphs. Once the coke is removed, the vessel is re-sealed (i.e., the drain valve is closed and the ‘‘head’’ is reattached), pressure tested (typically using steam), purged to remove oxygen, then slowly heated to processing temperatures so it can go back on-line. When the second coke drum becomes filled with coke, feed is diverted back to the first coke drum and the second drum is then decoked. In this manner, the DCU allows for continuous processing of oil even though the individual coke drums operate in cyclical batch fashion. The first step in decoking operations is to purge the coke drum with steam. This serves to cool the coke bed and to flush oil or reaction products from the coke bed. The steam purge is initially sent to the product distillation column and then diverted to the unit’s blowdown system. The blowdown system serves to condense the steam and other liquids entrained in the E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules steam. Nearly all DCU operate a ’’closed blowdown’’ system, such that uncondensed gases from the blowdown system are sent to the product distillation column or the facility’s light gas plant, recovered as fuel gas, or combusted in a flare. In an open blowdown system, these uncondensed gases would be vented directly to atmosphere. The DCU vent discharge to the blowdown system is specifically defined in Refinery MACT 1 as the ‘‘delayed coker vent.’’ The next step in the decoking process is cooling/quenching the coke drum and its contents via the addition of water, commonly referred to as quench water, at the bottom of the coke drum. The water added to the vessel quickly turns to steam due to the high temperature of the coke bed. The water/steam helps to further cool the coke bed and ‘‘quench’’ any residual coking reactions that may still occur within the hot coke bed. As with the steam purge, steam off-gas from the cooling/quenching cycle is recovered in the unit’s blowdown system and this vent discharge is specifically defined in Refinery MACT 1 as the ‘‘delayed coker vent.’’ After several hours, the coke drum is sufficiently cooled so that the water level in the drum can be raised to entirely cover the coke bed. Although water covers the coke bed, the upper portion of the coke bed may still be well above 212 degrees Fahrenheit (°F) and will continue to generate steam. In fact, since the coke drum vessel pressure is greater than atmospheric pressure, the equilibrium boiling point of water in the vessel is greater than 212 °F. Therefore, the water at the top of the coke drum is typically well above 212 °F (superheated water). As the coke drum and its contents continue to cool from the evaporative cooling effect of the steam generation, the steam generation rate and the pressure within the vessel will decrease. Owners or operators of DCU may use different indicators or set points to determine when the system has cooled sufficiently to move to the venting step; however, one of the most common indicators monitored is the pressure of the coke drum vessel (or steam vent line just above the coke drum, where steam exits the coke drum en route to the blowdown system). When the vessel has cooled sufficiently (e.g., when the coke drum vessel pressure reaches the desired set point), valves are opened to allow the steam generated in the coke drum to vent directly to the atmosphere rather than the closed blowdown system. This vent is commonly referred to as the ‘‘coker steam vent’’ and is typically the first direct atmospheric VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 emission release during the decoking operations when an enclosed blowdown system is used. While this vent gas contains predominately steam, methane and ethane, a variety of HAP are also emitted with this steam. These HAP include light aromatics (e.g., benzene, toluene, and xylene) and light POM (predominately naphthalene and 2methyl naphthalene). The level of HAP emitted from the DCU has been found to be a function of the quantity of steam generated (see the technical memorandum entitled Impacts Estimates for Delayed Coking Units in Docket ID Number EPA–HQ–OAR– 2010–0682). In general, the next step in the decoking process is draining the water from the coke drum by opening a large valve at the bottom of the coke drum. The drain water typically falls from the coke drum onto a slanted concrete pad that directs the water to the coke pit area (where water and coke are collected and separated). Some DCU owners or operators initiate draining at the same time they initiate venting; other owners or operators may allow the vessel to vent for 20 or more minutes prior to initiating draining. While draining immediately may reduce the amount of steam exiting the unit via the stack, as explained below, it is not expected to alter the overall emissions from the unit. During the venting and draining process, the pressure of the system falls to atmospheric. Steam will be generated until the evaporative cooling effect of that steam generation cools the coker quench water to 212 °F. If draining is initiated immediately, some of the superheated water may drain from the DCU before being cooled. A portion of that drained water will then convert to steam during the draining process as that superheated water contacts the open atmosphere. Therefore, draining quickly is not expected to alter the total amount of steam generated from the unit nor alter the overall emissions from the unit. It will, however, alter the relative proportion of the emissions that are released via the vent versus the quench water drain area. The next step in the decoking process is ‘‘deheading’’ the coke drum. At the top of the coke drum is a large 3- to 5foot diameter opening, which is sealed with a gasketed lid during normal operations. When the steam generation rate from the coke drum has sufficiently subsided, this gasketed lid is removed to allow access for a water drill that will be used to remove coke from the drum. The process of removing this lid is referred to as ‘‘deheading’’ the coke drum. Different DCU owners or operators may use different criteria for PO 00000 Frm 00023 Fmt 4701 Sfmt 4702 36901 when to dehead the coke drum. If the coke drum is deheaded soon after venting is initiated, some steam and associated HAP emissions may be released from this opening. As with draining, it is anticipated that the total volume of steam generated will be a function of the temperature/pressure of the coke drum. Deheading the coke drum prior to the coke drum contents reaching 212 °F will generally mean that some of the steam will be released from the coke drum head opening. However, this will not alter the total amount of steam generated; it merely alters the location of the release (coke drum head opening versus steam vent). The HAP emissions from the deheading process are expected to be proportional to the amount of steam released in the same manner as the emissions from the steam vent. The final step of the decoking process is coke cutting. A high-pressure water jet is used to drill or cut the coke out of the vessel. The drilling water and coke slurry exits the coke drum via the drain opening and collects in the coke pit. Generally, the coke drum and its contents are sufficiently cooled so that this process is not expected to yield significant HAP emissions. However, if the other decoking steps are performed too quickly, hot spots may exist within the coke bed and HAP emissions may occur as water contacts these hot spots and additional steam and emissions are released. Once the coke is cut out of the drum, the drum is closed and prepared to go back on-line. This process includes pressurizing with steam to ensure there are no leaks (i.e., that the head is properly attached and sealed and the drain valve is fully closed). The vessel is then purged to remove any oxygen and heated by diverting the produced gas from the processing coke drum through the empty drum prior to sending it to the unit’s distillation column. A coke drum cycle is typically 28 to 36 hours from start of feed to start of the next feed. b. How Delayed Coker Vents Are Addressed in Refinery MACT 1 Delayed coker vents are specifically mentioned as an example within the first paragraph of the definition of ‘‘miscellaneous process vent’’ in 40 CFR 63.641 of Refinery MACT 1. However, the definition of ‘‘miscellaneous process vent’’ also excludes coking unit vents associated with coke drum depressuring (at or below a coke drum outlet pressure of 15 pounds per square inch gauge [psig]), deheading, draining, or decoking (coke cutting) or pressure testing after decoking. Refinery MACT 1 also E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36902 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules includes a definition of ‘‘delayed coker vent’’ in 40 CFR 63.641. This vent is typically intermittent in nature, and usually occurs only during the initiation of the depressuring cycle of the decoking operation when vapor from the coke drums cannot be sent to the fractionator column for product recovery, but instead is routed to the atmosphere through a closed blowdown system or directly to the atmosphere in an open blowdown system. The emissions from the decoking phases of DCU operations, which include coke drum deheading, draining, or decoking (coke cutting), are not considered to be delayed coker vents. The first paragraph of the definition of ‘‘miscellaneous process vent’’ also includes blowdown condensers/ accumulators as an example of a miscellaneous process vent. Therefore, the DCU blowdown system is a miscellaneous process vent regardless of whether or not the blowdown system is associated with a DCU or another process unit. Further, the inclusion of the ‘‘delayed coker vent’’ as an example of a miscellaneous process vent makes it clear that the DCU’s blowdown system vent (if an open blowdown system is used) is considered a miscellaneous process vent. It is less clear from the regulatory text whether the direct venting of the coke drum to the atmosphere via the steam vent during the final depressurization is considered to be a ‘‘delayed coker vent’’ (i.e., whether direct venting to the atmosphere is equivalent to venting ‘‘directly to the atmosphere in an open blowdown system’’). The regulatory text is clear that this steam vent is exempt from the definition of ‘‘miscellaneous process vent’’ when the pressure of the vessel is less than 15 psig. It is also clear that the subsequent release points from the decoking operations (i.e., deheading, draining, and coke cutting) are excluded from both the definition of ‘‘delayed coker vent’’ and the definition of ‘‘miscellaneous process vent.’’ Further, based on the statements in the background information document for the August 1995 final Refinery MACT 1 rule,26 the 15 psig pressure limit for the direct venting of the DCU to the atmosphere was not established as a MACT floor control level; it was established to accommodate all DCU at whatever pressure they typically switched from venting to the closed blowdown system to venting directly to 26 National Emission Standards for Hazardous Air Pollutants Petroleum Refineries—Background Information for Final Standards; EPA–453/R–95– 015b. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 the atmosphere. Based on this information, as well as the data from the 2011 Refinery ICR, refinery enforcement settlements and other information available, which indicate that all refineries depressurize the coke drum below 15 psig, we have determined that the direct atmospheric releases from the DCU decoking operations are currently unregulated emissions. These unregulated releases include emissions during atmospheric depressuring (i.e., the steam vent), deheading, draining, and coke cutting. c. Evaluation of MACT Emission Limitations for Delayed Coking Units We evaluated emissions and controls during DCU decoking operations in order to identify appropriate MACT emission limitations pursuant to CAA section 112(d)(2) and (3). Establishing a lower pressure set point at which a DCU owner or operator can switch from venting to an enclosed blowdown system to venting to the atmosphere is the control technique identified for reducing emissions from delayed coking operations. Essentially, there is a fixed quantity of steam that will be generated as the coke drum and its contents cool. The lower pressure set point will require the DCU to vent to the closed blowdown system longer, where the organic HAP can be recovered or controlled. This will result in fewer emissions released during the venting, draining and deheading process. We consider this control technique, which is a work practice standard, appropriate for the DCU for the reasons discussed below for each of the four possible emission points at the DCU: draining, deheading, coke cutting and the steam vent. For the first three steps, the emissions cannot be emitted through a conveyance designed and constructed to emit or capture such pollutant. For example, during draining, the drain water typically falls from the coke drum onto a slanted concrete pad that directs the water to an open coke pit area (where water and coke are collected and separated). When the coke drum is deheaded, the coke drum head must be removed to provide an accessible opening in the drum so the coke cutting equipment can be lowered into the drum. This opening cannot be sealed during coke cutting because the drilling shaft will occupy the opening and the shaft must be free to be lowered or raised during the coke cutting process. While the emissions from the fourth point, the DCU steam vent, are released via a conveyance designed and constructed to emit or capture such pollutant, as provided in CAA section 112(h)(2)(B), it is not feasible to PO 00000 Frm 00024 Fmt 4701 Sfmt 4702 prescribe or enforce an emission standard for the DCU steam vent because the application of a measurement methodology for this source is not practicable due to technological and economic limitations. First, it is not practicable to use a measurement methodology for the DCU steam vent. The emissions from the vent typically contain 99 percent water, which interferes with common sample collection and analysis techniques. Also, the flow rate from this vent is not constant; rather, it decreases during the venting process as the pressure in the DCU coke drum approaches atmospheric pressure. Additionally, the venting time can be very short. As part of the ICR, we requested stack testing of eight DCU. After discussions with stack testing experts within the agency and with outside contractors used by industry to perform the tests, we concluded that sources with venting times less than 20 minutes would not be able to perform an emissions test that would yield valid results. Therefore, only two of the eight facilities actually performed the tests. We anticipate all units complying with the proposed standards for DCU steam vents would vent for less than 20 minutes. Second, it is not feasible to enforce an emission standard only on the steam vent because the timing of drainage and deheading can alter the portion of the decoking emissions that are released from the actual steam vent. If draining and deheading are initiated quickly after venting, this will reduce the emissions discharged from the vent (although as explained above, it does not reduce the emissions from the collective set of decoking operations release points). Consequently, due to the unique nature of DCU emissions, the difficulties associated with monitoring the DCU steam vent, and the inability to construct a conveyance to capture emissions from all decoking release points, we are proposing that it is appropriate to develop work practice standards in place of emission limits for the DCU. To establish the MACT floor, we then reviewed regulations, permits and consent decrees that require coke controls. Refinery NSPS Ja establishes a pressure limit of 5 psig prior to allowing the coke drum to be vented to the atmosphere. Based on a review of permit limits and consent decrees, we found that coke drum vessel pressure limits have been established (and achieved) as low as 2 psig. There are 75 operating DCU according to the Refinery ICR responses, so the sixth percentile is represented by the fifth-best performing DCU. We identified eight DCU with E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules permit requirements or consent decrees specifying a coke drum venting pressure limit of 2 psig; we did not identify any permit or consent decree requirements more stringent than 2 psig. Refinery owners and operators were asked to provide the ‘‘typical coke drum pressure just prior to venting’’ for each DCU in their responses to the Refinery ICR, and the responses indicate that four DCU operate such that the typical venting pressure is 1 psig or less. However, this ‘‘typical coke drum pressure’’ does not represent a not-to-be-exceeded pressure limit; it is expected that these units are operated this way to meet a pressure limit of 2 psig. We do not have information to indicate whether these facilities are always depressurized at 1 psig or less. Moreover, there were only four units for which a typical venting pressure of 1 psig was identified and the MACT floor for existing sources is represented by the fifth-best operating DCU, not the best-performing unit. Therefore, we are proposing that the MACT floor for DCU decoking operations is to depressure at 2 psig or less prior to venting to the atmosphere for existing sources. We are also proposing that the MACT floor for new sources is 2 psig, since the bestperforming source is permitted to depressure at 2 psig or less. For additional details on the MACT floor analysis, see memorandum entitled MACT Analysis for Delayed Coking Unit Decoking Operations in Docket ID Number EPA–HQ–OAR–2010–0682. We then considered control options beyond the floor level of 2 psig to determine if additional emission reductions could be cost-effectively achieved. We considered establishing a venting pressure limit of 1 psig or less, since four facilities reported in the ICR that the typical coke drum pressure prior to depressurizing was 1 psig. There are several technical difficulties associated with establishing a pressure limit at this lower level. First, the lowest pressure at any point in a closed blowdown system is generally designed to be no lower than 0.5 psig. Consequently, the DCU compressor system would operate with an inlet pressure of no less than 0.5 psig. Second, there are several valves and significant piping (for cooling and condensing steam) between the DCU drum and the recovery compressor. There is an inherent pressure drop when a fluid flows through a pipe or valve. Two valves are used for all DCU lines to make sure that the unit is either blocked off from the processing fluids or blocked in so there are no product losses out the steam line during VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 processing. Considering the need for two valves and piping needed in the cooling system, DCU designed for a minimal pressure loss will generally still have a 0.5 to 1 psig pressure drop between the DCU drum and the recovery compressor inlet, even for a new DCU designed to minimize this pressure drop. Finally, in order to meet a 1 psig pressure limit at all times, the DCU closed vent system would need to be designed to achieve a vessel pressure of approximately 0.5 psig. Given the above considerations, it is not technically feasible for new or existing DCU to routinely achieve a vessel pressure of 0.5 psig in order to comply with a never-to-be-exceeded drum vessel pressure of 1 psig. As noted previously, facilities that ‘‘typically’’ achieve vessel pressures of about 1 psig or less are expected to do so in order to meet a never-to-be-exceeded drum vessel pressure limit of 2 psig and they are not expected to be able to comply with a never-to-be-exceeded drum vessel pressure limit of 1 psig. We considered setting additional work practice standards regarding draining, deheading, and coke cutting. The decoking emissions can be released from a variety of locations, and the 2psig-or-less limit for depressurizing the coke drum will effectively reduce the emissions from all of these emission points, provided that atmospheric venting via the DCU steam vent is the first step in the decoking process. However, it is possible to start draining water prior to opening the steam vent. We are concerned that owners or operators may adopt this practice as a means to reduce pressure in the coke drum prior to venting the drum to the atmosphere. Initiating water draining prior to reaching 2 psig would result in draining water that is hotter than it would be had the drum been sufficiently cooled (i.e., the pressure limit achieved) prior to draining the vessel, effectively diverting HAP emissions to the water drain area rather than capturing these HAP in the enclosed blowdown system, where they can be either recovered or controlled. Therefore, we are proposing that the coke drum must reach 2 psig or less prior to any decoking operations, which includes atmospheric venting, draining, deheading, and coke cutting. We could not identify any other emission reduction options that could lower the emissions from the DCU decoking operations. Since we could not identify a technically feasible control option beyond the MACT floor, we determined that the MACT floor pressure limit of 2 psig is MACT for existing sources. We also determined PO 00000 Frm 00025 Fmt 4701 Sfmt 4702 36903 that the same technical limitations of going beyond the 2 psig pressure limit for existing sources exist for new sources; therefore we determined that the MACT floor pressure limit of 2 psig is MACT for new sources. We request comment on whether depressurizing to 2 psig prior to venting to the atmosphere is the appropriate MACT floor and whether it is appropriate to include restrictions for the other three decoking operations draining, deheading and coke cutting, in the MACT requirements. We request comments on whether we have adequately interpreted the information that indicates that there is currently no applicable MACT floor for delayed coking. If Refinery MACT 1 currently provided standards for DCU based on the MACT floor, we would evaluate whether it is necessary to revise such delayed coking standards under the risk and technology review requirements of the Act (i.e., CAA section 112(f) and 112(d)(6)) as discussed later in this preamble. Finally, we request comment and supporting information on any other practices that may be used to limit emissions during the decoking operations. d. Evaluation of Cost and Environmental Impacts of MACT Emission Limitations for Delayed Coking Units DCU that cannot currently meet the 2 psig pressure limit would be expected to install a device (compressor or steam ejector system) to lower the DCU vessel pressure. In the Refinery NSPS Ja impact analysis, facilities not able to meet the pressure threshold were assumed to purchase and install a larger compressor to lower the blowdown system pressure. Other approaches to lowering blowdown system (and coke drum) pressure exist. Specifically, steam ejectors have been identified as a method to help existing units depressurize more fully in order to achieve a set vessel pressure or drum bed temperature. Upgrading the closed vent system to reduce pressure losses or to increase steam condensing capacity may also allow the DCU to depressurize more quickly while the emissions are still vented to the closed blowdown system. This is important because delays in the decoking operations may impact process feed rates. That is, if the decoking and drum preparation steps take too long, the feed rate to the other coke unit must be reduced to prevent overfilling one coke drum prior to being able to switch to the other coke drum. This issue is less critical for DCU that operate with 3 or 4 drums per distillation column, but a consistent increase in the decoking times across all E:\FR\FM\30JNP2.SGM 30JNP2 36904 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules drums may still limit the capacity of the DCU at some petroleum refineries. For existing sources, we assumed all DCU that reported a ‘‘typical drum pressure prior to venting’’ of more than 2 psig would install and operate a steam ejector system to reduce the coke drum pressure to 2 psig prior to venting to atmosphere or draining. The operating costs of the steam ejector system are offset, to some extent, by the additional recovered vapors. Vapors from the additional gases routed to the blowdown system contain high levels of methane (approximately 70 percent by volume on a dry basis) based on DCU steam vent test data. If these vapors are directed to the closed blowdown system rather than to the atmosphere, generally the dry gas can be recovered in the refinery fuel gas system or light-ends gas plant. This recovered methane is expected to off-set natural gas purchases for the fuel gas system. For new sources, it is anticipated that the DCU’s closed vent system could be designed to achieve a 2 psig vessel pressure with no significant increase in capital or operating costs. Designing the system to vent at a lower pressure would also result in additional vapor recovery, which is expected to off-set any additional capital costs associated with the low pressure design closed vent system. The costs of complying with the 2 psig coke drum threshold prior to venting or draining are summarized in Table 2 of this preamble. The costs are approximately $1,000 per ton of VOC reduced and approximately $5,000 per ton of organic HAP reduced when considering VOC and methane recovery credits. In addition to VOC and HAP reductions, the proposed control option will result in a reduction in methane emissions of 18,000 tpy or 343,000 metric tonnes per year of carbon dioxide equivalents (CO2e), assuming a global warming potential of 21 for methane. TABLE 2—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF CONTROL OPTION FOR DELAYED COKING UNITS AT PETROLEUM REFINERIES Capital cost (million $) Control option Annualized costs without recovery credits (million $/yr) 52 10.2 2 psig ......................................................................................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 2. CRU Vents A CRU is designed to reform (i.e., change the chemical structure of) naphtha into higher-octane aromatics. Over time, coke deposits form on the reforming catalyst, which reduces the catalyst activity. When catalyst activity is reduced to a certain point, the catalyst is regenerated by burning the coke off of the catalyst. Prior to this coke burn-off process, the catalyst (or reactor vessel containing the catalyst) must be removed from active service and organics remaining on the catalyst (or in the reactor) must be purged from the system. This is generally accomplished by depressurizing the vessel to a certain vessel pressure, then re-pressurizing the vessel with nitrogen and depressurizing the vessel again. The re-pressurization and depressurization process is repeated several times until all organics have been purged from the system. The organic HAP emissions from this depressurization/purge cycle vent are typically controlled by directing the purge gas directly to the CRU process heater or venting the gas to a flare. Refinery MACT 2 requires a 98percent reduction of organic HAP measured as total organic carbon (TOC) or non-methane TOC or an outlet concentration of 20 ppmv or less (dry basis, as hexane, corrected to 3-percent oxygen), whichever is less stringent, for this CRU depressurization/purge cycle vent (purging prior to coke-burn-off). The emission limits for organic HAP for the CRU do not apply to emissions from VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 Emissions reduction, VOC (tpy) 4,250 process vents during depressuring and purging operations when the reactor vent pressure is 5 psig or less. The Refinery MACT 2 requirements were based on the typical operation of CRU utilizing sequential pressurization and passive depressurization. The 5 psig pressure limit exclusion was provided based on state permit conditions, which recognized that depressurization to an APCD (without other active motive of flow) is limited by the back pressure of the control system, which is often a flare or process heater. Source testing information collected from the 2011 Refinery ICR indicates that facilities have interpreted the rule to allow the 5 psig pressure limit exclusion to be used by units using active purging techniques (such as continuous nitrogen purge or vacuum pump on the CRU reactor at low pressures) to discharge to the atmosphere without emission controls. The information collected indicates that HAP emissions from a continuous, active purging technique could result in emissions of HAP from CRU depressurization vents much higher than expected to be allowed under the Refinery MACT 2 requirements, which presumed sequential re-pressurization and purging cycles. The testing information received indicated that at one facility, the active purge vent had non-methane TOC concentrations of 700 to 10,000 ppmv (dry basis, as hexane, corrected to 3-percent oxygen) compared to less than 10 ppmv for the typical passive purge vent tested. The PO 00000 Frm 00026 Fmt 4701 Sfmt 4702 Cost effectiveness ($/ton HAP) Emissions reduction, HAP (tpy) Total annualized costs with VOC recovery credit (million $/yr) Overall cost effectiveness with VOC recovery credit ($/ton HAP) 12,000 3.98 4,700 850 annual HAP emissions for the CRU with the active purge vent were estimated to exceed 10 tpy, while a comparable unit using the cyclic re-pressurization and passive depressurization purge technique is projected to have HAP emissions of less than 0.1 tpy. Therefore, we are proposing to amend the exclusion in 40 CFR 63.1566(a)(4) to clarify the application of the 5 psig exclusion, consistent with the MACT floor under CAA section 112(d)(2) and (3). Specifically, we are limiting the vessel pressure limit exclusion to apply only to passive vessel depressurization. Units utilizing active purging techniques have a motive of flow that can be used to direct the purge gas to a control system, regardless of the CRU vessel pressure. If a CRU owner or operator uses active purging techniques (e.g., a continual nitrogen purge) or active vessel depressurization (e.g., vacuum pump), then the 98-percent reduction or 20 ppmv TOC emission limits would apply to these discharges regardless of the vessel pressure. 3. Refinery Flares The EPA is proposing under CAA section 112(d)(2) and (3) to amend the operating and monitoring requirements for petroleum refinery flares. We have determined that the current requirements for flares are not adequate to ensure compliance with the Refinery MACT standards. In the development of Refinery MACT 1, the EPA determined that the average emission limitation achieved by the best-performing 12 E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules percent of existing sources was established as the use of combustion controls for miscellaneous process vents. Further, the EPA stated that ‘‘data analyses conducted in developing previous NSPS and the [National Emission Standards for Organic Hazardous Air Pollutants (40 CFR part 63, subparts F, G, and H)] HON determined that combustion controls can achieve 98-percent organic HAP reduction or an outlet organic HAP concentration of 20 ppmv for all vent streams’’ (59 FR 36139, July 15, 1994). The requirements applicable to flares at refineries are set forth in the General Provisions to 40 CFR part 63 and are cross-referenced in Refinery MACT 1 and 2. In general, flares used as APCD were expected to achieve 98-percent HAP destruction efficiencies when designed and operated according to the requirements in the General Provisions. Recent studies on flare performance, however, indicate that these General Provisions requirements are inadequate to ensure proper performance of refinery flares, particularly when assist steam or assist air is used. Over the last decade, flare minimization efforts at petroleum refineries have led to an increasing number of flares operating at well below their design capacity, and while this effort has resulted in reduced flaring of gases at refineries, situations of overassisting with steam or air have become exacerbated, leading to the degradation of flare combustion efficiency. Therefore, these amendments are necessary to ensure that refineries that use flares as APCD meet the MACT standards at all times when controlling HAP emissions. Refinery MACT 1 and 2 require flares used as an APCD to meet the operational requirements set forth in the General Provisions at 40 CFR 63.11(b). These General Provisions requirements specify that flares shall be: (1) Steamassisted, air-assisted, or non-assisted; (2) operated at all times when emissions may be vented to them; (3) designed for and operated with no visible emissions (except for periods not to exceed a total of 5 minutes during any 2 consecutive hours); and (4) operated with the presence of a pilot flame at all times. The General Provisions also specify requirements for both the minimum heat content of gas combusted in the flare and maximum exit velocity at the flare tip. The General Provisions only specify monitoring requirements for the presence of the pilot flame and the operation of a flare with no visible emissions. For all other operating limits, Refinery MACT 1 and 2 require an initial performance evaluation to VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 demonstrate compliance but there are no specific monitoring requirements to ensure continuous compliance. As noted previously, flare performance tests conducted over the past few years suggest that the current regulatory requirements are insufficient to ensure that refinery flares are operating consistently with the 98-percent HAP destruction efficiencies that we determined were the MACT floor. In 2012, the EPA compiled information and test data collected on flares and summarized its preliminary findings on operating parameters that affect flare combustion efficiency (see technical report, Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA–HQ–OAR– 2010–0682). The EPA submitted the report, along with a charge statement and a set of charge questions to an external peer review panel.27 The panel concurred with the EPA’s assessment that three primary factors affect flare performance: (1) The flow of the vent gas to the flare; (2) the amount of assist media (e.g., steam or air) added to the flare; and (3) the combustibility of the vent gas/assist media mixture in the combustion zone (i.e., the net heating value, lower flammability, and/or combustibles concentration) at the flare tip. Following is a discussion of requirements we are proposing for refinery flares, along with impacts and costs associated with these new requirements. Specifically, this action proposes that refinery flares operate pilot flame systems continuously and with automatic re-ignition systems and that refinery flares operate with no visible emissions. In addition, this action also consolidates requirements related to flare tip velocity and proposes new operational and monitoring requirements related to the combustion zone gas. Prior to these proposed amendments, Refinery MACT 1 and 2 cross-reference the General Provisions requirements at 40 CFR 63.11(b) for the operational requirements for flares used as APCD. Rather than revising the General Provisions requirements for flares, which would impact dozens of different source categories, this proposal will specify all refinery flare operational and monitoring requirements specifically in Refinery MACT 1 and cross-reference these same requirements in Refinery MACT 2. All of the requirements for flares operating at petroleum refineries in this proposed rulemaking are intended to ensure compliance with the Refinery MACT 1 27 These documents can also be found at https:// www.epa.gov/ttn/atw/petref.html. PO 00000 Frm 00027 Fmt 4701 Sfmt 4702 36905 and 2 standards when using a flare as an APCD. a. Pilot Flames Refinery MACT 1 and 2 reference the flare requirements in the General Provisions, which require a flare used as an APCD device to operate with a pilot flame present at all times. Pilot flames are proven to improve flare flame stability; even short durations of an extinguished pilot could cause a significant reduction in flare destruction efficiency. In this action, we are proposing to remove the cross-reference to the General Provisions and instead include the requirement that flares operate with a pilot flame at all times and be continuously monitored for using a thermocouple or any other equivalent device in Refinery MACT 1 and 2. We are also proposing to amend Refinery MACT 1 and 2 to add a new operational requirement to use automatic relight systems for all flare pilot flames. An automatic relight system provides a quicker response time to relighting a snuffed-out flare compared to manual methods and thereby results in improved flare flame stability. In comparison, manual relighting is much more likely to result in a longer period where the pilot remains unlit. Because of safety issues with manual relighting, we anticipate that nearly all refinery flares are already equipped with an automated device to relight the pilot flame in the event it is extinguished. Also, due to the possibility that a delay in relighting the pilot could result in a flare not meeting the 98-percent destruction efficiency for the period when the pilot flame is out, we are proposing to amend Refinery MACT 1 and 2 to add this requirement to ensure that the pilot operates at all times. b. Visible Emissions Refinery MACT 1 and 2 reference the flare requirements in the General Provisions, which require a flare used as an APCD to operate with visible emissions for no more than 5 minutes in a 2-hour period. Owners or operators of these flares are required to conduct an initial performance demonstration for visible emissions using EPA Method 22 of 40 CFR part 60, Appendix A–7. We are proposing to remove the crossreference to the General Provisions and include the limitation on visible emissions in Refinery MACT 1 and 2. In addition, we are proposing to amend Refinery MACT 1 and 2 to add a requirement that a visible emissions test be conducted each day and whenever visible emissions are observed from the flare. We are proposing that owners or E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36906 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules operators of flares monitor visible emissions at a minimum of once per day using an observation period of 5 minutes and EPA Method 22 of 40 CFR part 60, Appendix A–7. Additionally, any time there are visual emissions from the flare, we are proposing that another 5-minute visible emissions observation period be performed using EPA Method 22 of 40 CFR part 60, Appendix A–7, even if the minimum required daily visible emission monitoring has already been performed. For example, if an employee observes visual emissions or receives notification of such by the community, the owner or operator of the flare would be required to perform a 5minute EPA Method 22 observation in order to check for compliance upon initial observation or notification of such event. We are also proposing that if visible emissions are observed for greater than one continuous minute during any of the required 5-minute observation periods, the monitoring period shall be extended to 2 hours. Industry representatives have suggested to the EPA that flare combustion efficiency is highest at the incipient smoke point (the point at which black smoke begins to form within the flame). They stated that the existing limit for visible emissions could be increased from 5 minutes to 10 minutes in a 2-hour period to encourage operation near the incipient smoke point (see memorandum, Meeting Minutes for February 19, 2013, Meeting Between the U.S. EPA and Representatives from the Petroleum Refining Industry, in Docket ID Number EPA–HQ–OAR–2010–0682). While we agree that operating near the incipient smoke point results in good combustion at the flare tip, we disagree that the allowable period for visible emissions be increased from 5 to 10 minutes for a 2-hour period. Smoking flares can contribute significantly to emissions of particulate matter 2.5 micrometers in diameter and smaller (PM2.5) emissions, and we are concerned that increasing the allowable period of visible emissions from 5 minutes to 10 minutes for every 2-hour period could result in an increase in the PM2.5 emissions from flares. As discussed later in this section, we are proposing additional operational and monitoring requirements for refinery flares which we expect will result in refineries installing equipment that can be used to fine-tune and control the amount of assist steam or air introduced at the flare tip such that combustion efficiency of the flare will be maximized. These monitoring and control systems will assist refinery flare owners or operators operating near the VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 incipient smoke point without exceeding the visible emissions limit. While combustion efficiency may be highest at the incipient smoke point, it is not significantly higher than the combustion efficiency achieved by these proposed operating limits, discussed in section IV.A.3.d of this preamble. As seen in the performance curves for flares (see technical memorandum, Petroleum Refinery Sector Rule: Operating Limits for Flares, in Docket ID Number EPA– HQ–OAR–2010–0682), there is very limited improvement in flare performance beyond the performance achieved at these proposed operating limits. We solicit comments and data on appropriate periods of visible emissions that would encourage operation at the incipient smoke point while not significantly increasing PM2.5 emissions. c. Flare Tip Velocity The General Provisions at 40 CFR 63.11(b) specify maximum flare tip velocities based on flare type (nonassisted, steam-assisted, or air-assisted) and the net heating value of the flare vent gas. These maximum flare tip velocities are required to ensure that the flame does not ‘‘lift off’’ the flare, which could cause flame instability and/or potentially result in a portion of the flare gas being released without proper combustion. We are proposing to remove the cross-reference to the General Provisions and consolidate the requirements for maximum flare tip velocity into Refinery MACT 1 and 2 as a single equation, irrespective of flare type (i.e., steam-assisted, air-assisted or non-assisted). Based on our analysis of the various studies for air-assisted flares, we identified air-assisted test runs with high flare tip velocities that had high combustion efficiencies (see technical memorandum, Petroleum Refinery Sector Rule: Evaluation of Flare Tip Velocity Requirements, in Docket ID Number EPA–HQ–OAR– 2010–0682). These test runs exceeded the maximum flare tip velocity limits for air-assisted flares using the linear equation in 40 CFR 63.11(b)(8). When these test runs were compared with the test runs for non-assisted and steamassisted flares, the air-assisted flares appeared to have the same operating envelope as the non-assisted and steamassisted flares. Therefore, we are proposing that air-assisted flares at refineries use the same equation that non-assisted and steam-assisted flares currently use to establish the flare tip velocity operating limit. In developing these proposed flare tip velocity requirements, we considered whether any adjustments to these velocity equations were necessary. The PO 00000 Frm 00028 Fmt 4701 Sfmt 4702 flare tip velocity equations require the input of the net heating value of the vent gas going to the flare, as opposed to the net heating value of the gas mixture at the flare tip (i.e., the combustion zone gas). As discussed later in this section, we found that the performance of the flare was much more dependent on the net heating value of the gas mixture in the combustion zone than on the net heating value of only the vent gas going into the flare (excluding all assist media). We considered replacing the term in the velocity equation for the net heating value of the vent gas going into the flare with the net heating value of the gas mixture in the combustion zone. However, the steam addition rates were not reported for the tests conducted to evaluate flame stability as a function of flare tip velocity, so direct calculation of all the terms needed for calculating the net heating value in the combustion zone could not be made. At higher flare tip velocities, we expect that the steam assist rates would be small in comparison to the total vent gas flow rate, so there would not be a significant difference between the net heating value of the vent gas going into the flare and the combustion zone gas net heating value for the higher velocity flame stability tests. We request comment on the need and/or scientific reasons to use the flare vent gas net heating value versus the combustion zone net heating value when determining the maximum allowable flare tip velocity. In the 2012 flare peer review, we also discussed the effect of flame lift off and velocity on flare flame stability (see technical report, Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA–HQ–OAR– 2010–0682). In looking at ways of trying to prohibit flame instability, we examined the use of the Shore equation as a means to limit flare tip velocity. However, after receiving many comments on use of this equation from the peer reviewers, the uncertainty with how well the Shore equation models the large range of flare operation, and the limited dataset with which recent testing used high velocities (all recent test runs were performed at 10 feet per second or less), we determined that use of the existing velocity equation discussed above was still warranted. We are also proposing for Refinery MACT 1 and 2 to not include the special flare tip velocity equation in the General Provisions at 40 CFR 63.11(b)(6)(i)(A) for non-assisted flares with hydrogen content greater than 8 percent. This equation, which was developed based on limited data from a chemicals manufacturer, has very limited E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 applicability for petroleum refinery flares in that it only provides an alternative for non-assisted flares with large quantities of hydrogen. Approximately 90 percent of all refinery flares are either steam- or air-assisted. Furthermore, we are proposing compliance alternatives in this section that we believe provide a better way for flares at petroleum refineries with high hydrogen content to comply with the rule while ensuring proper destruction performance of the flare (see section IV.A.3.d of this preamble for additional details). Therefore, we are proposing to not include this special flare tip velocity equation as a compliance alternative for refinery flares. We request comment on the need to include this equation. If a commenter supports inclusion of this equation, we request that the commenter submit supporting documentation regarding the vent gas composition and flows and, if available, combustion efficiency determinations that indicate that this additional equation is needed and is appropriate for refinery flares. We also request documentation that the maximum allowable flare tip velocity predicted by this equation adequately ensures proper combustion efficiency. The General Provisions require an initial demonstration that a flare used as an APCD meets the applicable flare tip velocity requirement in 40 CFR 63.11(b). However, most refinery flares can have highly variable vent gas flows and a single initial demonstration is insufficient to demonstrate continuous compliance with the flare tip velocity requirement. Consequently, we are proposing to amend Refinery MACT 1 and 2 to require continuous monitoring to determine flare tip velocity, calculated by monitoring the flare vent gas volumetric flow rate and dividing by the cross-sectional area of the flare tip. As an alternative to installing continuous volumetric flow rate monitors, we are proposing that the owner or operator may elect to install a pressure- and temperature-monitoring system and use engineering calculations to determine the flare tip velocity. d. Refinery Flare Operating and Monitoring Requirements The current requirements for flares in the General Provisions specify that the flare vent gas must meet a minimum net heating value of 200 British thermal units per standard cubic foot (Btu/scf) for non-assisted flares and 300 Btu/scf for air- and steam-assisted flares. Refinery MACT 1 and 2 reference these requirements, but neither the General Provisions nor Refinery MACT 1 and 2 include specific monitoring VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 requirements to monitor the net heating value of the vent gas. Moreover, recent flare testing results indicate that this parameter alone does not adequately address instances when the flare may be over-assisted since it only considers the gas being combusted in the flare and nothing else (e.g., no assist media). However, many industrial flares use steam or air as an assist medium to protect the design of the flare tip, promote turbulence for the mixing, induce air into the flame and operate with no visible emissions. Using excessive steam or air results in dilution and cooling of flared gases and can lead to operating a flare outside its stable flame envelope, reducing the destruction efficiency of the flare. In extreme cases, over-steaming or excess aeration can actually snuff out a flame and allow regulated material to be released into the atmosphere completely uncombusted. Since approximately 90 percent of all flares at refineries are either steam- or air-assisted, it is critical that we ensure the assist media be accounted for in some form or fashion. Recent flare test data have shown that the best way to account for situations of over-assisting is to consider the properties of the mixture of all gases at the flare tip in the combustion zone when evaluating the ability to combust efficiently. As discussed in the introduction to this section, the external peer review panel concurred with our assessment that the combustion zone properties at the flare tip are critical parameters to know in determining whether a flare will achieve good combustion. The General Provisions, however, solely rely on the net heating value of the flare vent gas. We are proposing to add definitions of two key terms relevant to refinery flare performance. First, we are proposing to define ‘‘flare vent gas’’ to include all waste gas, sweep gas, purge gas and supplemental gas, but not include pilot gas or assist media. We are proposing this definition because information about ‘‘flare vent gas’’ (e.g., flow rate and composition) is one of the necessary inputs needed to evaluate the make-up of the combustion zone gas. To that end, we are also proposing to define the ‘‘combustion zone gas’’ as flare vent gas plus the total steam-assist media and premix assist air that is supplied to the flare. Based on our review of the recent flare test data, we have determined that the following combustion zone operational limits can be used to determine good combustion: Net heating value (Btu/scf), lower flammability limit (LFL) or a total combustibles fraction (e.g., a simple carbon count). In this PO 00000 Frm 00029 Fmt 4701 Sfmt 4702 36907 action, we are proposing these new operational limits, along with methods for determining these limits in the combustion zone at the flare tip for steam-assisted, air-assisted and nonassisted flares to ensure that there is enough combustible material readily available to achieve good combustion. For air-assisted flares, use of too much perimeter assist air can lead to poor flare performance. Based on our analysis, we found that including the flow rate of perimeter assist air in the calculation of combustion zone operational limits in itself does not identify all instances of excess aeration. The data suggest that the diameter of the flare tip, in concert with the amount of perimeter assist air, provides the inputs necessary to calculate whether or not this type of flare is over-assisted. Therefore, we are proposing that in addition to complying with combustion zone operational limits to ensure that there is enough combustible material available to adequately combust the gas and pass through the flammability region, air-assisted flares would also comply with an additional dilution parameter that factors in the flow rate of the flare vent gas, flow rates of all assist media (including perimeter assist air), and diameter of flare tip to ensure that degradation of flare performance from excess aeration does not occur. This dilution parameter is consistent with the combustion theory that the more ‘‘time’’ the gas spends in the flammability region above the flare tip, the better it will combust. Also, since both the volume of the combustion zone (represented by the diameter here) and how quickly this gas is diluted to a point below the flammability region (represented by perimeter assist air flow rate) characterize this ‘‘time,’’ it makes sense that we propose such a term (see technical memorandum, Petroleum Refinery Sector Rule: Operating Limits for Flares, in Docket ID Number EPA– HQ–OAR–2010–0682). It should be noted that in the 2012 flare peer review report, we considered a limit for perimeter assist air via the stoichiometric air ratio. This stoichiometric air ratio is the ratio of the actual mass flow rate of assist air to the theoretical stoichiometric mass flow rate of air (based on complete chemical combustion of fuel to carbon dioxide (CO2) and water) needed to combust the flare vent gas. However, we are not proposing to include this term as part of the calculation methodology, as we have determined that the dilution parameter discussed in this section better assures that air-assisted flare performance is not degraded due to excess aeration. E:\FR\FM\30JNP2.SGM 30JNP2 36908 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules The proposed rule allows the owner or operator flexibility to select the form of the combustion zone operational limit (i.e., net heating value, LFL, or total combustibles fraction) with which to comply in order to provide facilities the option of using monitors they may already have in place. The monitoring methods we are proposing take into account the combustible properties of all gas going to the flare (i.e., flare vent gas, assist gas, and premix air) that affects combustion efficiency, and they can be used to determine whether a flare has enough combustible material to achieve the desired level of control (and whether it is being over-assisted). These methods require the owner or operator to input the flow of the vent gas to the flare, the characteristics of the vent gas going to the flare (i.e., either a heat content (Btu/scf), LFL, or total combustible fuel content, depending on how the operational limit is expressed), and the flow of assist media added to the flare. To estimate the LFL, we are proposing to use a calculation method based on the Le Chatelier equation. The Le Chatelier calculation uses the reciprocal of the volume-weighted average over the LFL of the individual compounds in the gas mixture to estimate the LFL of the gas mixture. Although Le Chatelier’s equation was originally limited to binary mixtures of combustible gases, we are proposing a method that was developed by Karim, et al. (1985) and assumes a LFL of infinity for inert gases. We are also aware of other methods and/or adjustments that can be made to the Le Chatelier equation in order to calculate a more accurate estimate of the LFL of a gas mixture (see technical memorandum, Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA–HQ–OAR– 2010–0682). We are soliciting comment on the use of this proposed method. Recent data indicate that one set of operational limits may not be sufficient for all refinery flares. Flares that receive vent gas containing significant levels of both hydrogen and olefins often exhibit lower combustion efficiencies than flares that receive vent gas with only one (or none) of these compounds. Therefore, we are proposing more stringent operational limits for flares that simultaneously receive vent gas containing significant levels of both hydrogen and olefins (see technical memorandum, Petroleum Refinery Sector Rule: Operating Limits for Flares, in Docket ID Number EPA–HQ–OAR– 2010–0682). Although the minimum net heating value in the combustion zone (i.e., Btu/scf) is a good indicator of combustion efficiency, as noted in the flare peer review report, the LFL and combustibles concentration (or total combustibles) in the combustion zone are also good indicators of flare combustion efficiency. For some gas mixtures, such as gases with high hydrogen content, the LFL or combustibles concentration in the combustion zone may be better indicators of performance than net heating value. Consequently, we are proposing operational limits expressed all three ways, along with associated monitoring requirements discussed later in this section. The three operating limits were established in such a way that each limit is protective on its own. As such, the owner or operator may elect to comply with any of the three alternative operating limits at any time, provided they use a monitoring system capable of determining compliance with each of the proposed alternative operating limits on which they rely (see technical memorandum, Petroleum Refinery Sector Rule: Operating Limits for Flares, in Docket ID Number EPA–HQ–OAR– 2010–0682). For example, the owner or operator may elect to install monitoring for only one of the three alternative operating limits, in which case the owner or operator must comply with that selected operating limit at all times. If the owner or operator installs a system capable of monitoring for all three of the alternative operating limits, the owner or operator can choose which of the three operating limits the source will rely on to demonstrate compliance. A summary of the operating limits specified in this proposed rule is provided in Table 3 of this preamble. We are proposing that owners or operators of flares used as APCD would conduct an initial performance test to determine the values of the parameters to be monitored (e.g., the flow rate and heat content of the incoming flare vent gas, the assist media flow rate, and premix air flow rate, if applicable) in order to demonstrate continuous compliance with the operational limits in Table 3. We are proposing to require owners or operators to record and calculate 15minute block average values for these parameters. Our rationale for selecting a 15-minute block averaging period is provided in section IV.A.3.e of this preamble. TABLE 3—OPERATING LIMITS FOR FLARES IN THIS PROPOSED ACTION Operating limits: Flares without hydrogen-olefin interaction b Operating parameter a Operating limits: Flares with hydrogen-olefin interaction b Combustion zone parameters for all flares NHVcz ................................... LFLcz .................................... Ccz ........................................ ≥270 Btu/scf .................................................................... ≤0.15 volume fraction ...................................................... ≥0.18 volume fraction ...................................................... NHVdil ................................... LFLdil .................................... Cdil ........................................ ≥22 ....................................................................... ≤2.2 volume fraction/ft ..................................................... ≥0.012 volume fraction-ft ................................................ ≥380 Btu/scf. ≤0.11 volume fraction. ≥0.23 volume fraction. emcdonald on DSK67QTVN1PROD with PROPOSALS2 Dilution parameters for flares using perimeter assist air Btu/ft2 ≥32 Btu/ft2. ≤1.6 volume fraction/ft. ≥0.015 volume fraction-ft. a The operating parameters are: NHVcz = combustion zone net heating value. LFLcz = combustion zone lower flammability limit. Ccz = combustion zone combustibles concentration. NHVdil = net heating value dilution parameter. LFLdil = lower flammability limit dilution parameter. Cdil = combustibles concentration dilution parameter. b Hydrogen-Olefin interactions are assumed to be present when the concentration of hydrogen and olefins in the combustion zone exceed all three of the following criteria: (1) The concentration of hydrogen in the combustion zone is greater than 1.2 percent by volume. (2) The cumulative concentration of olefins in the combustion zone is greater than 2.5 percent by volume. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00030 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36909 emcdonald on DSK67QTVN1PROD with PROPOSALS2 (3) The cumulative concentration of olefins in the combustion zone plus the concentration of hydrogen in the combustion zone is greater than 7.4 percent by volume. Btu/ft2 = British thermal units per square foot. We are soliciting comment on the appropriateness of the operating limits and dilution parameters in Table 3 of this preamble and whether they ensure that refinery flares operate in a manner that that will ensure compliance with the MACT requirements for vents to achieve a 98-percent organic HAP reduction. Combustion zone gas monitoring alternatives. As discussed previously in this section, we are proposing to define the combustion zone gas as the mixture of gas at the flare tip consisting of the flare vent gas, the total steam-assist media and premix assist air. In order to demonstrate compliance with the three combustion zone parameter operating limits of net heating value, LFL and total combustibles fraction, the owner or operator would need to monitor four things: (1) Flow rate of the flare vent gas; (2) flow rate of total steam assist media; (3) flow rate of premix assist air and (4) specific characteristics associated with the flare vent gas (e.g., heat content, composition). In order to monitor the flow rates of the flare vent gas, total steam assist media, and premix assist air, we are proposing that refinery owners or operators use a continuous volumetric flow rate monitoring system or a pressure- and temperature-monitoring system with use of engineering calculations. We are also proposing use of either of these monitoring methods for purposes of determining the flow rate of perimeter assist air (for compliance with the dilution parameter). However, the one component that will determine how many combustion zone parameter operating limits an owner or operator can comply with is the specific type of monitor used to characterize the flare vent gas. Monitoring the individual component concentrations of the flare vent gas using an on-line gas chromatograph (GC) along with monitoring vent gas and assist gas flow rates will allow the owner or operator to determine compliance with any of the three proposed combustion zone operating limits and any of the three proposed dilution operating limits (if using airassisted flares). We considered requiring all refinery owners or operators of flares to only use a GC to monitor the flare vent gas composition but since facilities may have other non-GC monitors already in place (e.g., calorimeters), we are not proposing such a requirement at this time. However, use of a GC can VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 improve refinery flare operation and management of resources. For example, use of a GC to characterize the flare vent gas can lead to product/cost savings for refiners because they could more readily identify and correct instances of product being unintentionally sent to a flare, either through a leaking pressure relief valve or other conveyance that is ultimately routed to the flare header system. In addition, an owner or operator that chooses to use a GC (in lieu of one of the other proposed monitoring alternatives) will be more likely to benefit from the ability to continuously fine-tune their operations (by reducing assist gas addition and/or supplemental gas to the flare) in order to meet any one of the three operating limits. Furthermore, some facilities are already required to use a GC to demonstrate compliance with state flare requirements. We are soliciting comment on the additional benefits that using a GC offers and whether it would be reasonable to require a GC on all refinery flares. As an alternative to a continuous compositional monitoring system, we are proposing to allow the use of grab samples along with engineering calculations to determine the individual component concentration. Like the online GC, the grab sampling option relies on compound speciation and is therefore flexible to use with any form of the operational limits we are proposing. The disadvantage of this option is that if a grab sample indicates non-compliance with the operational limits, the permitting authority could presume non-compliance from the time of the previous grab sample indicating compliance, which would include all 15-minute periods in that time period. However, there are a number of situations where the refinery owner or operator may find this option advantageous. For example, some flares receive flows only from a specific process with a consistent composition and high heat content. In this case, the owner or operator may elect to actively adjust the assist gas flow rates using the expected vent gas composition and rely on the analysis of the grab sample to confirm the expected vent gas composition. This alternative may also be preferred for flares that are used infrequently (non-routine flow flares) or that have flare gas recovery systems designed and operated to recover 100 percent of the flare gas under typical conditions. For these flares, flaring PO 00000 Frm 00031 Fmt 4701 Sfmt 4702 events may be so seldom that the refinery owner or operator may prefer the uncertainty in proactive control to the higher cost of continuous monitors that would seldom be used. As an alternative to performing a compositional analysis with use of a GC (through either on-line monitoring or analysis of the grab sample), we are proposing that owners or operators of flares may elect to install a device that directly monitors vent gas net heating value (i.e., a calorimeter). If the owner or operator elects this monitoring method, we are proposing that they must comply with the operating limits that are based on the net heating value operating limit. Similarly, we are also proposing that owners or operators of flares may elect to install a device that directly monitors the total hydrocarbon content of the flare vent gas (as a measure of the combustibles concentration). If the owner or operator elects this monitoring method, they must comply with the operating limits that are based on the combustibles concentration. e. Data Averaging Periods for Flare Gas Operating Limits We are proposing to use a 15-minute block averaging period for each proposed flare operating parameter (including flare tip velocity) to ensure that the flare is operated within the appropriate operating conditions. As flare vent gas flow rates and composition can change significantly over short periods of time, a short averaging time was considered to be the most appropriate for assessing proper flare performance. Furthermore, since flare destruction efficiencies can fall precipitously fast below the proposed operating limits, short time periods where the operating limits are not met could seriously impact the overall performance of the flare. With longer averaging times, there may be too much opportunity to mask these short periods of poor performance (i.e., to achieve the longer-term average operating limit while not achieving a high destruction efficiency over that time period because of short periods of poor performance). Moreover, a 15-minute averaging period is in line with the test data and the analysis used to establish the operating limits in this proposed rule. Ninety-three percent of the flare test runs used as a basis for establishing the proposed operating limits ranged in duration from 5 to 30 minutes, and 77 E:\FR\FM\30JNP2.SGM 30JNP2 36910 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 percent of the runs ranged in duration from 5 to 20 minutes. The failure analysis (discussed in section IV.A.3.f of this preamble) considered minute-byminute test run data, but as there are limitations on how quickly compositional analyses can be conducted, many of the compositional data still reflect set values over 10- to 15-minute time intervals. Because the GC compositional analyses generally require 10 to 15 minutes to conduct, shorter averaging times are not practical. To be consistent with the available test data and to ensure there are no short periods of significantly poor performance, we are proposing 15minute block averaging times. Given the short averaging times for the operating limits, we are proposing special calculation methodologies to enable refinery owners or operators to use ‘‘feed forward’’ calculations to ensure compliance with the operating limits on a 15-minute block average. Specifically, the results of the compositional analysis determined just prior to a 15-minute block period are to be used for the next 15-minute block average. Owners or operators of flares will then know the vent gas properties for the upcoming 15-minute block period and can adjust assist gas flow rates relative to vent gas flow rates to comply with the proposed operating limits. Owners or operators of flares that elect to use grab sampling and engineering calculations to determine compliance must still assess compliance on a 15-minute block average. The composition of each grab sample is to be used for the duration of the episode or until the next grab sample is taken. We are soliciting comment on whether this approach is appropriate, and whether grab samples are needed on a more frequent basis to ensure compliance with the operating limits. f. Other Peer Review Considerations In an effort to better inform the proposed new requirements for refinery flares, in the spring of 2012 the EPA summarized its preliminary findings on operating parameters that affect flare combustion efficiency in a technical report and put this report out for a letter review. Based on the feedback received, the EPA considered many of the concerns peer reviewers expressed in their comments in the development of this proposal for refinery flares (see memorandum, Peer Review of ‘‘Parameters for Properly Designed and Operated Flares’’, in Docket ID Number EPA–HQ–OAR–2010–0682). While the more substantive issues have been previously discussed in sections VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 IV.A.3.a through e of this preamble, the following discussion addresses other peer review considerations that the EPA either discussed in the peer review technical document or considered from comments received by the peer review panel that played a role in the development of this proposal. Test data quality and analysis. For steam-assisted flares, we asked peer reviewers to comment on our criteria for excluding available flare test data from our analyses. In general, peer reviewers considered the EPA’s reasons for removing certain test data (prior to performing any final analysis) to be appropriate; however, one reviewer suggested the EPA complete an analysis of quality on the data before applying any criteria, and several reviewers commented on the level of scrutiny of the 10 data points specifically discussed in the technical report for not meeting the combustion zone LFL trend. These reviewers stated it appeared the EPA had scrutinized test data more if it were inconsistent with the LFL threshold conclusions made in the report. Although we felt it was appropriate to discuss specific test data not fitting the trend, we do agree with the reviewers that a more general and standard set of criteria should be applied to all test data prior to making any conclusion. In addition, other peer reviewers saw no reason why the EPA should exclude 0percent combustion efficiency data points, or data points where smoking occurs, or single test runs when there was also a comparable average test run. Therefore, in response to these peer review comments, the EPA performed a validation and usability analysis on all available test data. This resulted in a change to the population of test data used in our final analysis (see technical memorandum, Flare Performance Data: Summary of Peer Review Comments and Additional Data Analysis for SteamAssisted Flares, in Docket ID Number EPA–HQ–OAR–2010–0682 for a more detailed discussion of the data quality and analysis). To help determine appropriate operating limits, several peer reviewers suggested the EPA perform a falsepositive-to-false-negative comparison (or failure type) analysis between the potential parameters discussed in the technical report as indicators of flare performance. The reviewers suggested that the EPA attempt to minimize the standard error of all false positives (i.e., poor observed combustion efficiency when the correlation would predict good combustion) and false negatives (i.e., good observed combustion efficiency when the correlation would predict poor combustion). In response to PO 00000 Frm 00032 Fmt 4701 Sfmt 4702 these comments, the EPA has conducted a failure analyses of these parameters which helped form the basis for the operating limits we are proposing for flares (see technical memorandum, Petroleum Refinery Sector Rule: Operating Limits for Flares, in Docket ID Number EPA–HQ–OAR–2010–0682). Some peer reviewers contended that it is appropriate for the EPA to round each established operating limit to the nearest whole number, because using a decimal implies far more accuracy and reliability than can be determined from the test data. Based on these comments, we have given more consideration to the number of significant figures used in the operating limits, and we are proposing to use two significant figures for the flare operating limits in these proposed amendments. Multiple peer reviewers performed additional analyses to try and determine the appropriateness of the limits raised in the technical report. Some peer reviewers tried to fit the data to a curve, others performed various failure analyses, while others looked at different metrics not discussed in the technical report (see memorandum, Peer Review of ‘‘Parameters for Properly Designed and Operated Flares’’, in Docket ID Number EPA–HQ–OAR– 2010–0682). Based on the conclusions drawn from these various analyses, a range of combustion zone net heating value targets from 200 Btu/scf to 450 Btu/scf were identified as metrics that would provide a high level of certainty regarding good combustion in flares (Note: 450 Btu/scf was the assumed to be approximately equivalent to a combustion zone LFL of 10 percent). We solicit comment on this range and the appropriateness for which the operating limits selected in this proposal will ensure compliance with the MACT requirements for vents at petroleum refineries. Effect of supplemental gas use. Most flares normally operate at a high turndown ratio, which means the actual flare gas flow rate is much lower than what the flare is designed to handle. In addition, steam-assisted flares have a manufacturers’ minimum steam requirement in order to protect the flare tip. A combination of high turndown ratio and minimum steam requirement will likely require some owners or operators to add supplemental gas to achieve one of the combustion zone gas operating limits we are proposing here (e.g., combustion zone combustibles concentration (Ccz) ≥ 18 volume percent; combustion zone lower flammability limit (LFLcz) ≤ 15 volume percent; or combustion zone net heating value (NHVcz) ≥ 270 Btu/scf). However, fine- E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules tuning the actual steam flow to the flare should significantly reduce the need for supplemental gas. We considered proposing a steam-to-vent gas ratio limitation on steam-assisted flares. However, a steam-to-vent gas ratio alone cannot fully address over-steaming because it would not account for the variability of chemical properties within the flare gas. We request that commenters on this issue provide supporting documentation on their potential to reduce steam as well as their use of supplemental gas to achieve the proposed operating limit(s), and how it could affect cost and potential emissions. We emphasize that the amount and cost of supplemental gas should be reflective of conditions after any excess steam use has been rectified. It would not be valuable to consider situations where large amounts of supplemental gas are added, while steam is simultaneously added far in excess of the amount recommended by the flare manufacturer or other guidance documents. In assessing the combustion zone gas and looking at all the gas at the flare tip, another potential source of added heat content comes from the gas being used as fuel to maintain a continuously lit pilot flame. However, since pilot gas is being used as fuel for a continuous ignition source and is burned to create a flame prior to (or at the periphery of) the combustion zone, this gas does not directly contribute to the heat content or flammability of the gas being sent to the flare to be controlled under Refinery MACT 1 or 2. In addition, in looking at available test data, the pilot gas flow rate is generally so small that it does not significantly impact the combustion zone properties at all. Furthermore, by leaving pilot gas out of the combustion zone operating limit calculations, the equations become simplified and a requirement to continuously monitor pilot gas flow rate can be avoided. Therefore, we are proposing that the owner or operator not factor in the pilot gas combustible component (or net heating value) contribution when determining any of the three proposed combustion zone gas operating limits (Ccz, LFLcz, or NHVcz). Effects of wind on flame performance. Several published studies have investigated the significance of wind on the fluid mechanics of a flare flame (see technical memorandum, Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA–HQ–OAR– 2010–0682). These studies were conducted in wind tunnels at crosswind velocities up to about 60 miles per hour (mph) and have illustrated that increased crosswind velocity can have a VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 strong effect on flare flame dimensions and shape, causing the flame to become segmented or discontinuous, and wakedominated (i.e., where the flame is bent over on the downwind side of a flare pipe and is imbedded in the wake of the flare tip), which may lead to poor flare performance due to fuel stripping. However, the majority of this research is confined to laboratory studies on flares with effective diameters less than 3 inches, which have been shown not to be representative of industrial-sized flares. Research that does include performance tests conducted on flares scalable to refinery flares (i.e., 3-inch, 4inch, and 6-inch pipe flares) was conducted with flare tip velocities as low as 0.49 feet per second and crosswind velocities of about 26 mph and less; all tests resulted in good flare performance. Furthermore, there is no indication that crosswind velocities negatively impact flare performance in the recent flare performance tests. These tests were conducted on various sizes of industrial flares (i.e., effective diameters ranging between 12 and 54 inches) in winds of about 22 mph and less, and at relatively low flare tip velocities (i.e., 10 feet per second or less). (See Parameters for Properly Designed and Operated Flares, in Docket ID Number EPA–HQ– OAR–2010–0682.) We are aware of flare operating parameters that consider crosswind velocity; however, using the available flare performance test data, we were unable to determine a clear correlation that would be appropriate for all refinery flares. For example, the momentum flux ratio (MFR) is a measure of momentum strength of the flare exit gas relative to the crosswind (i.e., the product of flare exit gas density and velocity squared divided by the product of air density and crosswind velocity squared). The plume buoyancy factor is the ratio of crosswind velocity to the flare exit gas velocity, and considers the area of the flare pipe. The power factor is the ratio of the power of the crosswind to the power of combustion of the flare gas. Because the available flare performance test data have relatively low flare tip velocities, and crosswind velocities were relatively constant during each test run, we are unable to examine these parameters to the fullest extent. In light of the data available from performance tests (Gogolek et al., 2010), we asked peer reviewers whether the MFR could be used in crosswind velocities greater than 22 mph at the flare tip to indicate wake-dominated flame situations. We also asked for comment on observations that in the absence of crosswind greater than 22 PO 00000 Frm 00033 Fmt 4701 Sfmt 4702 36911 mph, a low MFR does not necessarily indicate poor flare performance. Peer reviewers suggested that there are no data available from real industrial flares in winds greater than 22 mph to support that MFR could be used to identify wake-dominated flame situations. In addition, we received no further peer review comments that have caused us to reconsider the observation we made in the April 2012 technical report that in the absence of crosswind greater than 22 mph, a low MFR does not necessarily indicate poor flare performance. We request comment with supporting data and rationale on any of these, or other parameters, as a measure of wind effects on flare combustion efficiency. We considered including observation requirements for detecting segmented or discontinuous wake-dominated flames, especially for winds greater than 22 mph (where limited test data is available). However, owners or operators of flares cannot control the wind speed, and it would be detrimental to increase the quantity of flared gases in high crosswind conditions in efforts to improve the MFR and reduce wake-dominated flow conditions. Furthermore, there is no indication that crosswind velocities negatively impact flare performance in the recent flare performance tests. For these reasons, we are not proposing any flare operating parameter(s) to minimize wind effects on flare combustion efficiency. g. Impacts of the Flare Operating and Monitoring Requirements The EPA expects that the newly proposed requirements for refinery flares discussed in this section will affect all flares at petroleum refineries. Based on data received as a result of the Refinery ICR, we estimate that there are 510 flares operating at petroleum refineries and that 285 of these receive flare vent gas flow on a regular basis (i.e., other than during periods of startup, shutdown, and malfunction). Costs were estimated for each flare for a given refinery, considering operational type (e.g., receive flare vent gas flow on a regular basis, use flare gas recovery systems to recover 100 percent of routine flare flow, handle events during startup, shutdown, or malfunction only, etc.) and current monitoring systems already installed on each individual flare. Costs for any additional monitoring systems needed were estimated based on installed costs received from petroleum refineries and, if installed costs were unavailable, costs were estimated based on vendorpurchased equipment. The baseline emission estimate and the emission E:\FR\FM\30JNP2.SGM 30JNP2 36912 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules reductions achieved by the proposed rule were estimated based on current vent gas and steam flow data submitted by industry representatives. The results of the impact estimates are summarized in Table 4 of this preamble. We note that the requirements for refinery flares we are proposing in this action will ensure compliance with the Refinery MACT standards when flares are used as an APCD. As such, these proposed operational and monitoring requirements for flares at refineries have the potential to reduce excess emissions from flares by approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 327,000 metric tonnes per year of CO2e. The VOC compounds are non-methane, nonethane total hydrocarbons. According to the Component 2 database from the Refinery ICR, there are approximately 50 individual HAP compounds included in the emission inventory for flares, but many of these are emitted in trace quantities. A little more than half of the HAP emissions from flares are attributable to hexane, followed next by benzene, toluene, xylenes, and 1,3butadiene. For more detail on the impact estimates, see the technical memorandum Petroleum Refinery Sector Rule: Flare Impact Estimates in Docket ID Number EPA–HQ–OAR– 2010–0682. TABLE 4—NATIONWIDE COST IMPACTS OF PROPOSED AMENDMENTS TO ENSURE PROPER FLARE PERFORMANCE Affected source Total capital investment (million $) Total annualized costs (million $/yr) Flare Monitoring ....................................................................................................................................................... 147 36.3 emcdonald on DSK67QTVN1PROD with PROPOSALS2 4. Vent Control Bypasses a. Relief Valve Discharges Refinery MACT 1 recognized relief valve discharges to be the result of malfunctions. Relief valves are designed to remain closed during normal operation and only release as the result of unplanned and/or unpredictable events. A release from a relief valve usually occurs during an over pressurization of the system. However, emissions vented directly to the atmosphere by relief valves in organic HAP service contain HAP that are otherwise regulated under Refinery MACT 1. Refinery MACT 1 regulated relief valves through equipment leak provisions that applied only after the pressure relief occurred. In addition the rule followed the EPA’s then-practice of exempting startup, shutdown and malfunction (SSM) events from otherwise applicable emission standards. Consequently, with relief valve releases defined as unplanned and nonroutine and the result of malfunctions, Refinery MACT 1 did not restrict relief valve releases to the atmosphere but instead treated them the same as all malfunctions through the SSM exemption provision. In Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court determined that the SSM exemption violates the CAA. See section IV.E of this preamble for additional discussion. To ensure this standard is consistent with that decision, these proposed amendments remove the malfunction exemption in Refinery MACT 1 and 2 and provide that emissions of HAP may not be discharged to the atmosphere from relief valves in organic HAP service. To ensure compliance with this amendment, we are also proposing to VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 require that sources monitor relief valves 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. Pressure release events from relief valves to the atmosphere have the potential to emit large quantities of HAP. Where a pressure release occurs, it is important to identify and mitigate it as quickly as possible. For purposes of estimating the costs of this requirement, we assumed that operators would install electronic monitors on each relief valve that vents to the atmosphere to identify and record the time and duration of each pressure release. However, we are proposing to allow owners and operators to use a range of methods to satisfy these requirements, including the use of a parameter monitoring system (that may already be in place) on the process operating pressure that is sufficient to indicate that a pressure release has occurred as well as record the time and duration of that pressure release. Based on our cost assumptions, the nationwide capital cost of installing these electronic monitors is $9.54 million and the annualized capital cost is $1.36 million per year. As defined in the Refinery MACT standards, relief valves are valves used only to release unplanned, nonroutine discharges. A relief valve discharge results from an operator error, a malfunction such as a power failure or equipment failure, or other unexpected cause that requires immediate venting of gas from process equipment in order to avoid safety hazards or equipment damage. Even so, to the extent that there are atmospheric HAP emissions from relief valves, we are required to follow the Sierra Club ruling to address those PO 00000 Frm 00034 Fmt 4701 Sfmt 4702 emissions in our rule, and we can no longer exempt them as permitted malfunction emissions as we did under Refinery MACT 1. Our information indicates that there are approximately 12,000 pressure relief valves that vent to the atmosphere (based on the ICR responses) and that the majority of relief valves in the refining industry are not atmospheric, but instead are routed to flares (see letter from API, Docket Item Number EPA–HQ–OAR–2010–0682– 0012). We request comment on our approach and on alternatives to our approach to regulating releases from pressure relief valves and also request commenters to provide information supporting any such comments. b. Bypass Lines For a closed vent system containing bypass lines that can divert the stream away from the APCD to the atmosphere, Refinery MACT 1 requires the owner or operator to either: (1) Install, maintain and operate a continuous parametric monitoring system (CPMS) for flow on the bypass line that is capable of detecting whether a vent stream flow is present at least once every hour, or (2) secure the bypass line valve in the nondiverting position with a car-seal or a lock-and-key type configuration. Under option 2, the owner or operator is also required to inspect the seal or closure mechanism at least once per month to verify the valve is maintained in the non-diverting position (see 40 CFR 63.644(c) for more details). We are proposing under CAA section 112(d)(2) and (3) that the use of a bypass at any time to divert a Group 1 miscellaneous process vent is a violation of the emission standard, and to specify that if option 1 is chosen, the owner or operator would be required to install, E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 maintain and operate a CPMS for flow that is capable of recording the volume of gas that bypasses the APCD. The CMPS must be equipped with an automatic alarm system that will alert an operator immediately when flow is detected in the bypass line. We are proposing this revision because, as noted above, APCD are not to be bypassed because doing so could result in a release of regulated organic HAP to the atmosphere. In Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court determined that standards under CAA section 112(d) must provide for compliance at all times and a release of uncontrolled HAP to the atmosphere is inconsistent with that requirement. c. In Situ Sampling Systems (Onstream Analyzers) The current Refinery MACT 1 definition of ‘‘miscellaneous process vent’’ states that ‘‘in situ sampling systems (onstream analyzers)’’ are not miscellaneous process vents. 40 CFR 63.641. For several reasons, we are proposing to remove ‘‘in situ sampling systems (onstream analyzers)’’ from the list of vents not considered miscellaneous process vents. First, the language used in this exclusion is inconsistent. We generally consider ‘‘in situ sampling systems’’ to be nonextractive samplers or in-line samplers. There are certain in situ sampling systems where the measurement is determined directly via a probe placed in the process stream line. Such sampling systems do not have an atmospheric vent, so excluding these from the definition of ‘‘miscellaneous process vent’’ is not meaningful. The parenthetical term ‘‘onstream analyzers’’ generally refers to sampling systems that feed directly to an analyzer located at the process unit, and has been interpreted to exclude the ‘‘onstream’’ analyzer’s vent from the definition of miscellaneous process vents. As these two terms do not consistently refer to the same type of analyzer, the provision is not clear. Second, we find that there is no technical reason to include analyzer vents in a list of vents not considered miscellaneous process vents. For extractive sampling systems and systems with purges, the equipment leak standards in Refinery MACT 1 require that the material be returned to the process or controlled. Thus, the only potential emissions from any sampling system compliant with the Refinery MACT 1 equipment leak provisions would be from the analyzer’s ‘‘exhaust gas’’ vent. The parenthetical term ‘‘onstream analyzers’’ indicates that the focus of the exemption is primarily on VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 the analyzer (or analyzer vent) rather than the sampling system. This phrase has been interpreted to exclude the ‘‘onstream’’ analyzer’s vent from the definition of miscellaneous process vents. Analyzer venting is expected to be routine (continuous or daily intermittent venting). We are proposing to delete this exclusion from the definition of ‘‘miscellaneous process vent’’ and to require these vents to meet the standards applicable to miscellaneous process vents at all times. We expect most analyzer vents to be Group 2 miscellaneous process vents because analyzer vents are not expected to exceed the 72 pounds per day (lb/day) emissions threshold for Group 1 miscellaneous process vents. However, if there are larger analyzer vents that exceed the 72 lb/day emissions threshold for Group 1 miscellaneous process vents, these emission sources would need to be controlled as a Group 1 miscellaneous process vent under this proposal. We solicit comment on the existence of any onstream analyzers that have VOC emissions greater than 72 lb/ day and why such vents are not amenable to control. d. Refinery Flares and Fuel Gas Systems The current definition of ‘‘miscellaneous process vent’’ in Refinery MACT 1 states that ‘‘gaseous streams routed to a fuel gas system’’ are not miscellaneous process vents. Furthermore, the affected source subject to Refinery MACT 1 does not specifically include ‘‘emission points routed to a fuel gas system, as defined in § 63.641 of this subpart.’’ The EPA allowed these exemptions for streams routed to fuel gas systems because according to the 1994 preamble for Refinery MACT 1, ‘‘these vents are already controlled to the most stringent levels achievable’’ (59 FR 36141, July 15, 1994). Since gaseous streams routed to a fuel gas system are eventually burned as fuel, typically in a boiler or process heater, these combustion controls burning the gaseous streams as fuel effectively achieve this most stringent level of control (i.e., 98percent organic HAP reduction or an outlet organic HAP concentration of 20 ppmv for all vent streams). However, there can be instances when gaseous streams from the fuel gas system that would otherwise be combusted in a boiler or process heater are instead routed to a flare (e.g., overpressure in the fuel gas system, used as flare sweep gas, used as flare purge gas). In cases where an emission source is required to be controlled in Refinery MACT 1 and 2 but is routed to a fuel gas system, we PO 00000 Frm 00035 Fmt 4701 Sfmt 4702 36913 are proposing that any flare receiving gases from that fuel gas system must comply with the flare operating and monitoring requirements discussed in section IV.A.3 of this preamble. B. What are the results and proposed decisions based on our technology review? 1. Refinery MACT 1—40 CFR Part 63, Subpart CC Refinery MACT 1 sources include miscellaneous process vents, storage vessels, equipment leaks, gasoline loading racks, marine vessel loading operations, cooling towers/heat exchange systems, and wastewater. a. Miscellaneous Process Vents Many unit operations at petroleum refineries generate gaseous streams containing HAP. These streams may be routed to other unit operations for additional processing (e.g., a gas stream from a reactor that is routed to a distillation unit for separation) or they may be sent to a blowdown system or vented to the atmosphere. Miscellaneous process vents emit gases to the atmosphere, either directly or after passing through recovery and/or APCD. Under 40 CFR 63.643, the owner or operator must reduce organic HAP emissions from miscellaneous process vents using a flare that meets the equipment specifications in 40 CFR 63.11 of the General Provisions (subpart A) or use APCD (e.g., thermal oxidizers, carbon adsorbers) to reduce organic HAP emissions by 98 weight-percent or to a concentration of 20 parts per million by volume (ppmv) dry basis, corrected to 3-percent oxygen. In the technology review, we did not identify any practices, processes or control technologies beyond those already required by Refinery MACT 1. Therefore, we are proposing that it is not necessary to revise Refinery MACT 1 requirements for miscellaneous process vents pursuant to CAA section 112(d)(6). b. Storage Vessels Storage vessels (also known as storage tanks) are used to store liquid and gaseous feedstocks for use in a process, as well as liquid and gaseous products coming from a process. Most storage vessels are designed for operation at atmospheric or near atmospheric pressures; high-pressure vessels are used to store compressed gases and liquefied gases. Atmospheric storage vessels are typically cylindrical with a vertical orientation, and they are constructed with either a fixed roof or a floating roof. Some, generally small, E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36914 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules atmospheric storage vessels are oriented horizontally. High pressure vessels are either spherical or horizontal cylinders. Section 63.646(a) requires certain existing and new storage vessels to comply with 40 CFR 63.119 through 40 CFR 63.121 of the HON. Under 40 CFR 63.119 through 63.121, storage vessels must be equipped with an internal floating roof with proper seals, an external floating roof with proper seals, an external floating roof converted to an internal floating roof with proper seals or a closed vent system routed to an APCD that reduces HAP emissions by 95 percent. Storage vessels at existing sources that use floating roofs are not required under Refinery MACT 1 to install certain fitting controls included in 40 CFR 63.1119 of the HON (e.g., gaskets for automatic bleeder vents, slit fabric covers for sample wells, flexible fabric seals or gasketed sliding covers for guidepoles and gasketed covers for other roof openings). See 40 CFR 63.646(c). In 2012, we conducted a general analysis to identify the latest developments in practices, processes and control technologies for storage vessels at chemical manufacturing facilities and petroleum refineries, and we estimated the impacts of applying those practices, processes and technologies to model storage vessels. (See Survey of Control Technology for Storage Vessels and Analysis of Impacts for Storage Vessel Control Options, January 20, 2012, Docket Item Number EPA–HQ–OAR–2010–0871–0027.) We used this analysis as a starting point for conducting the technology review for storage vessels at refineries. In this analysis, we identified fitting controls, particularly controls for floating roof guidepoles, and monitoring equipment (liquid level monitors and leak monitors) as developments in practices, processes and control technologies for storage vessels. In our refinery-specific review, we also noted that the Group 1 storage vessel size and vapor pressure thresholds in Refinery MACT 1 were higher than those for storage vessels in MACT standards for other similar industries. Therefore, we also evaluated revising the Group 1 storage vessel thresholds as a development in practices for storage vessels in the refining industry. We used data from our 2011 ICR to evaluate the impacts of requiring the additional controls identified in the technology review for the petroleum refinery source category. The emission reduction options identified during the technology review are: (1) Requiring guidepole controls and other fitting controls for existing external or internal VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 floating roof tanks as required in the Generic MACT for storage vessels (40 CFR part 63, subpart WW) in 40 CFR 63.1063; (2) option 1 plus revising the definition of Group 1 storage vessel to include smaller capacity storage vessels and/or storage vessels containing materials with lower vapor pressures and (3) option 2 plus requiring additional monitoring to prevent roof landings, liquid level overfills and to identify leaking vents and fittings from tanks. We identified options 1 and 2 as developments in practices, processes and control technologies because these options are required for similar tanks in some chemical manufacturing MACT standards and we believe they are technologically feasible for storage vessels at refineries (e.g., Generic MACT, the HON). Option 3 is also an improvement in practices because these monitoring methods have been required for refineries by other regulatory agencies. Under option 1, we considered the impacts of requiring improved deck fittings and controls for guidepoles as is required for other chemical manufacturing sources in the Generic MACT. Specifically, we considered these controls for storage vessels with existing internal or external floating roof tanks. This option also includes the inspection, recordkeeping, and reporting requirements set forth in the Generic MACT to account for the additional requirements for fitting controls. We are aware of recent waiver requests to EPA to allow in-service, topside inspections instead of the out-ofservice inspections required on a 10year basis for internal floating roof tanks for facilities that are currently subject to 40 CFR part 60, subpart Kb and Refinery MACT 1. The requirements of Generic MACT allow for this option if there is visual access to all the deck components. Under option 1, we considered the Generic MACT provisions for in-service, top-side inspection. We are requesting comment on whether or not these in-service inspections are adequate for identifying conditions that are indicative of deck, fitting, and rim seal failures; we are also requesting comment on methods to effectively accomplish top-side inspections. For option 2, we evaluated revising the definition of Group 1 storage vessels to include smaller capacity storage vessels and/or storage vessels with lower vapor pressure, such that these additional storage vessels would be subject to the Group 1 control requirements. For storage vessels at existing sources, Refinery MACT 1 currently defines Group 1 storage PO 00000 Frm 00036 Fmt 4701 Sfmt 4702 vessels to be those with a capacity of 177 cubic meters (46,760 gallons) or greater, and a true vapor pressure of 10.4 kilopascals (1.5 pounds per square inch absolute (psia)) or greater. Under option 2, we evaluated the impacts of changing the definition of Group 1 storage vessels to include storage vessels with a capacity of 151 cubic meters (40,000 gallons) or greater and a true vapor pressure of 5.2 kilopascals (0.75 psia) or greater, and also evaluated including storage vessels with a capacity of 76 cubic meters (20,000 gallons) or greater (but less than 151 cubic meters), provided the true vapor pressure of the stored liquid is 13.1 kilopascals (1.9 psia) or greater. These thresholds are consistent with storage vessel standards already required for the chemical industry (e.g., the HON). We believe the predominant effect of changing these thresholds will be fixed roof tanks at existing petroleum refineries shifting from Group 2 storage vessels to Group 1 storage vessels. These fixed roof tanks would thus need to be retrofitted with floating roofs or vented to an APCD in order to comply with the provisions for Group 1 storage vessels. We estimated the impacts of option 2 by assuming all uncontrolled fixed roof storage vessels that meet or exceed the proposed new applicability requirements for Group 1 storage vessels (based on the information collected in the Refinery ICR) would install an internal floating roof with a single rim seal and deck fittings to the existing fixed roof tank. The costs of these fixed roof retrofits were added to the costs determined for option 1 to determine the cost of option 2. Under option 3, we considered the impacts of including additional monitoring requirements for Group 1 storage vessels (in addition to fitting controls and fixed roof retrofits considered under options 1 and 2). The monitoring requirements evaluated include monitoring of internal or external floating roof tanks with EPA Method 21 (of 40 CFR part 60, Appendix A–7) or optical gas imaging for fittings, and requiring the use of liquid level overfill warning monitors and roof landing warning monitors. These costs were estimated based on the total number of Group 1 storage vessels considering the change in the applicability thresholds included in option 2. For further details on the assumptions and methodologies used in this analysis, see the technical memorandum titled Impacts for Control Options for Storage Vessels at Petroleum Refineries, in Docket ID Number EPA–HQ–OAR–2010–0682. E:\FR\FM\30JNP2.SGM 30JNP2 36915 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Table 5 of this preamble presents the impacts for the three options considered. Although the options were considered cumulatively, the calculation of the incremental cost effectiveness allows us to assess the impacts of the incremental change between the options. As seen by the incremental cost effectiveness column in Table 5, both options 1 and 2 result in a net cost savings considering the VOC recovery credit for product not lost to the atmosphere from the storage vessel.28 We seek comment on the appropriateness of the VOC recovery credit we used. The incremental cost effectiveness for option 3 exceeds $60,000 per ton of HAP removed. We consider option 3 not to be cost effective and are not proposing to require this additional monitoring. Based on this analysis, we consider option 2 to be cost effective. We are, therefore, proposing to revise Refinery MACT 1 to cross-reference the corresponding storage vessel requirements in the Generic MACT (including requirements for guidepole controls and other fittings as well as inspection requirements), and to revise 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 1.9 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. TABLE 5—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF CONTROL OPTIONS FOR STORAGE VESSELS AT PETROLEUM REFINERIES Capital cost (million $) Control option Annualized costs without recovery credits (million $/yr) 11.9 18.5 36.4 1.8 3.1 9.6 emcdonald on DSK67QTVN1PROD with PROPOSALS2 1 .................................................................................................................... 2 .................................................................................................................... 3 .................................................................................................................... Emissions reduction, VOC (tpy) Emissions reduction, HAP (tpy) 11,800 14,600 16,000 Cost effectiveness ($/ton HAP) Total annualized costs with VOC recovery credit (million $/yr) Overall cost effectiveness with VOC Rrcovery credit ($/ton HAP) Incremental cost effectiveness with VOC recovery credit ($/ton HAP) 2,470 3,430 9,580 (4.8) (5.0) 0.56 (6,690) (5,530) 560 (1,140) 61,500 720 910 1,000 c. Equipment Leaks Equipment leaks are releases of process fluid or vapor from processing equipment, including pump and compressor seals, process valves, relief devices, open-ended valves and lines, flanges and other connectors, agitators and instrumentation systems. These releases occur primarily at the interface between connected components of equipment or in sealing mechanisms. Refinery MACT 1 requires the owner or operator of an existing source to comply with the equipment leak provisions in 40 CFR part 60, subpart VV (Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry) for all equipment in organic HAP service. The term ‘‘in organic HAP service’’ means that a piece of equipment either contains or contacts a fluid (liquid or gas) that is at least 5 percent by weight of total organic HAP. Refinery MACT 1 specifies that the owner or operator of a new source must comply with the HON, as modified by Refinery MACT 1. The provisions for both new and existing sources require inspection (either through instrument monitoring using EPA Method 21 of 40 CFR part 60, Appendix A–7, or other method such as visible inspection) and repair of leaking equipment. For existing sources, the leak definition under 40 CFR part 60, subpart VV triggers repair at an instrument reading of 10,000 parts per million (ppm) for all equipment monitored using EPA Method 21 of 40 CFR part 60, Appendix A–7 (i.e., pumps and valves; instrument monitoring of equipment in heavy liquid service and connectors is optional). For new sources, the Refinery MACT 1-modified version of the HON triggers repair of leaks for pumps at 2,000 ppm and for valves at 1,000 ppm. Refinery MACT 1 requires new and existing sources to install a cap, plug or blind flange, as appropriate, on open-ended valves or lines. Refinery MACT 1 does not require instrument monitoring of connectors for either new or existing sources. We conducted a general analysis to identify the latest developments in practices, processes and control technologies applicable to equipment leaks at chemical manufacturing facilities and petroleum refineries, and we estimated the impacts of applying the identified practices, processes and technologies to several model plants. (See Analysis of Emissions Reduction Techniques for Equipment Leaks, December 21, 2011, Docket Item Number EPA–HQ–OAR–2010–0869– 0029.) We used this general analysis as a starting point for conducting the technology review for equipment leaks at refineries, but did not identify any developments beyond those in the general analysis. We estimated the impacts of applying the practices, processes and technologies identified in the general analysis to equipment leaks in petroleum refinery processes using the information we collected through the 2011 Refinery ICR. In general, leak detection and repair (LDAR) programs have been used by many industries for years to control emissions from equipment leaks. Over the years, repair methods have improved and owners and operators have become more proficient at implementing these programs. The specific developments identified include: (1) Requiring repair of leaks at a concentration of 500 ppm for valves and 2,000 ppm for pumps for new and existing sources (rather than 10,000 ppm for valves and pumps at existing sources and 1,000 for valves at new sources); (2) requiring monitoring of connectors using EPA Method 21 (of 40 CFR part 60, Appendix A–7) and repair of leaks for valves and pumps at a concentration of 500 ppm; and (3) allowing the use of optical gas imaging devices as an alternative method of monitoring. The first option we evaluated was to require repair based on a leak definition of 500 ppm for valves and a leak definition of 2,000 ppm for pumps at both new and existing sources. The nationwide costs and emission reduction impacts of applying those lower leak definitions to equipment leaks at petroleum refineries are shown in Table 6 of this preamble. For further details on the assumptions and methodologies used in this analysis, see the technical memorandum titled Impacts for Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA–HQ–OAR–2010–0682. 28 The VOC recovery credit is $560 per ton, based on $1.75/gal price for generic refinery product (gasoline/diesel fuel). (See the technical memorandum titled Impacts for Control Options for Storage Vessels at Petroleum Refineries, in Docket ID Number EPA–HQ–OAR–2010–0682 for more details.) VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00037 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 36916 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules The emissions reduction results in product not being lost by a leak; this additional product can be sold to generate revenue, referred to as a VOC recovery credit. Table 6 shows costs and cost effectiveness both with and without the VOC recovery credit. Based on the estimated organic HAP emission reductions of 24 tpy and the cost effectiveness of $14,100 per ton of organic HAP (including VOC recovery credit), we consider lowering the leak definition not to be a cost-effective option for reducing HAP emissions. We are, therefore, proposing that it is not necessary to revise Refinery MACT 1 pursuant to CAA section 112(d)(6) to require repair of leaking valves at 500 ppm or greater and repair of leaking pumps at 2,000 ppm or greater. TABLE 6—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF MONITORING AND REPAIR REQUIREMENTS AT LOWER LEAK DEFINITIONS [500 ppm for valves; 2,000 ppm for pumps] Capital cost (million $) Annualized costs without recovery credits (million $/yr) Emissions reduction, VOC (tpy) Emissions reduction, HAP (tpy) Cost effectiveness ($/ton VOC) Cost effectiveness ($/ton HAP) Total annualized costs with VOC recovery credit (million $/yr) Overall cost effectiveness with VOC recovery credit ($/ton VOC) Overall cost effectiveness with VOC recovery credit ($/ton HAP) 1.22 ............................................... 0.53 342 24 1,550 22,100 0.34 987 14,100 We note that we are aware that some owners and operators are required to repair leaking valves as low as 100 ppm and pumps as low as 500 ppm. However, we consider requiring repair of leaking valves at 500 ppm or greater and repair of leaking pumps at 2,000 ppm or greater not to be cost effective. As documented in Analysis of Emissions Reduction Techniques for Equipment Leaks (December 21, 2011, in Docket ID Number EPA–HQ–OAR– 2010–0869), the cost effectiveness for this option would be even higher than the values shown in Table 6 of this preamble. The second option we considered was connector monitoring and repair. Several standards applying to chemical manufacturing facilities, including the HON, include requirements for connector monitoring using EPA Method 21 (of 40 CFR part 60, Appendix A–7) and requirements for repair of any connector leaks above 500 ppm VOC. Neither the Refinery MACT 1 nor the NSPS for equipment leaks from refineries (40 CFR part 60, subpart GGG and 40 CFR part 60, subpart GGGa) currently require connector monitoring and repair (provisions are provided for connector monitoring in Refinery MACT 1, but they are optional). We evaluated the costs and emissions reduction of requiring connector monitoring and repair requirements for equipment leaks at refineries. The nationwide costs and emission reduction impacts, both with and without VOC recovery credit, are shown in Table 7 of this preamble. For further details on the assumptions and methodologies used in this analysis, see the technical memorandum titled Impacts for Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA–HQ–OAR–2010–0682. Based on the high annualized cost ($13.9 million per year) and high cost effectiveness ($153,000 per ton of HAP) of connector monitoring and repair for equipment leaks at refineries, we are proposing that it is not necessary to revise Refinery MACT 1 pursuant to CAA section 112(d)(6) to require connector monitoring using EPA Method 21 (of 40 CFR part 60, Appendix A–7) and repair. TABLE 7—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF APPLYING MONITORING AND REPAIR REQUIREMENTS TO CONNECTORS AT PETROLEUM REFINERIES [500 ppm] Annualized costs without recovery credits (million $/yr) Emissions reduction, VOC (tpy) Emissions reduction, HAP (tpy) Cost effectiveness ($/ton VOC) Cost effectiveness ($/ton HAP) Total annualized costs with VOC recovery credit (million $/yr) Overall cost effectiveness with VOC recovery credit ($/ton VOC) Overall cost effectiveness with VOC recovery credit ($/ton HAP) 52.1 ............................................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 Capital cost (million $) 13.9 1,230 86 11,300 161,000 13.2 10,700 153,000 Another development identified was to provide optical gas imaging provisions (including the required instrument specifications, monitoring frequency, and repair threshold) as an alternative monitoring option where instrument monitoring using EPA Method 21 of 40 CFR part 60, Appendix A–7, is required in Refinery MACT 1. Since Refinery MACT 1 was issued, there have been developments in LDAR work practices using remote sensing technology for detecting leaking equipment. In this method of detecting leaks, an operator scans equipment using a device or system specially designed to use one of several types of remote sensing techniques, including optical gas imaging of infrared wavelengths, differential absorption VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 light detection and ranging (DIAL), and solar occultation flux. The most common remote sensing instrument is a passive system that creates an image based on the absorption of infrared wavelengths (also referred to as a ‘‘camera’’). A gas cloud containing certain hydrocarbons (i.e., leaks) will show up as black or white plumes (depending on the instrument settings and characteristics of the leak) on the optical gas imaging instrument screen. This type of instrument is the device on which our evaluation of optical gas imaging instruments is based, and the instrument to which we are referring when we use the term ‘‘optical gas imaging instrument.’’ These optical gas imaging instruments can be used to identify specific pieces of PO 00000 Frm 00038 Fmt 4701 Sfmt 4702 equipment that are leaking. Other optical methods, such as DIAL and solar occultation flux, are used primarily to assess emissions downwind of a source. These methods cannot be used to identify specific leaking equipment; they would only measure the aggregate emissions from all equipment and any other source up-wind of the measurement location. While we did review these technologies as discussed further (see the discussion under fenceline monitoring, section IV.B.1.h of this preamble), we do not consider DIAL and solar occultation flux methods to be suitable alternatives to EPA Method 21 for monitoring equipment leaks and are not considering them further in our technology review for equipment leaks. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules We expect that all refinery streams ‘‘in organic HAP service’’ will include at least one of the compounds visible with an optical gas imaging instrument, such as benzene, methane, propane or butane. Therefore, it is technically feasible to use an optical gas imaging instrument to detect leaks at petroleum refineries. The optical gas imaging device can monitor many more pieces of equipment than can be monitored using instrument monitoring over the same period of time, and we expect that specific requirements for using an optical gas imaging device to detect leaks without accompanying instrument monitoring could be an appropriate alternative to traditional leak detection methods (EPA Method 21, as specified in 40 CFR part 60, Appendix A–7). Owners and operators currently have the option to use the Alternative Work Practice To Detect Leaks From Equipment (AWP) at 40 CFR 63.11(c), (d) and (e). This AWP includes provisions for using optical gas imaging in combination with annual monitoring using EPA Method 21 of 40 CFR part 60, Appendix A–7. In this proposal, we are considering the use of optical gas imaging without an accompanying requirement to conduct annual monitoring using EPA Method 21, and developing a protocol for using optical gas imaging techniques. We anticipate proposing the protocol as Appendix K to 40 CFR part 60. Rather than specifying the exact instrument that must be used, this protocol would outline equipment specifications, calibration techniques, required performance criteria, procedures for conducting surveys and training requirements for optical gas imaging instrument operators. This protocol would also contain techniques to verify that the instrument selected can image the most prevalent chemical in the monitored process unit. Because field conditions greatly impact detection of the regulated material using optical gas imaging, the protocol would describe the impact these field conditions may have on readings, how to address them and instances when monitoring with this technique is inappropriate. Finally, the protocol would also address difficulties with identifying equipment and leaks in dense industrial areas. Pursuant to CAA section 112(d)(6), we are proposing to allow refineries to meet the LDAR requirements in Refinery MACT 1 by monitoring for leaks via optical gas imaging in place of EPA Method 21 (of 40 CFR part 60, Appendix A–7), using the monitoring requirements to be specified in Appendix K to 40 CFR part 60. When Appendix K is proposed, we will VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 request comments on that appendix and how those requirements would apply for purposes of this proposed action. We will not take final action adopting use of Appendix K to 40 CFR part 60 for optical gas imaging for refineries subject to Refinery MACT 1 until such time as we have considered any comments on that protocol as it would apply to refineries. We do not yet know the exact requirements of Appendix K to 40 CFR part 60, and this cannot provide a reliable estimate of potential costs at this time. However, we have calculated an initial estimate of the potential costs and emission reduction impacts, assuming that Appendix K to 40 CFR part 60 is similar to the AWP without the annual monitoring using EPA Method 21 of 40 CFR part 60, Appendix A–7. For more information on these potential impacts, see the technical memorandum titled Impacts for Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA– HQ–OAR–2010–0682. d. Gasoline Loading Racks Loading racks are the equipment used to fill gasoline cargo tanks, including loading arms, pumps, meters, shutoff valves, relief valves and other piping and valves. Emissions from loading racks may be released when gasoline loaded into cargo tanks displaces vapors inside these containers. Refinery MACT 1 specifies that Group 1 gasoline loading racks at refineries must comply with the requirements of the National Emission Standards for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations) in 40 CFR part 63, subpart R. The standard specified in 40 CFR part 63, subpart R is an emission limit of 10 milligrams of total organic compounds per liter of gasoline loaded (mg/L). Additionally, 40 CFR part 63, subpart R requires all tank trucks and railcars that are loaded with gasoline to undergo annual vapor tightness testing in accordance with EPA Method 27 of 40 CFR part 60, Appendix A–8. For our technology review of Group 1 gasoline loading racks subject to Refinery MACT 1, we relied on two separate analyses. First, we previously conducted a technology review for gasoline distribution facilities (71 FR 17353, April 6, 2006), in which no new control systems were identified. Second, more recently, we conducted a general analysis to identify any developments in practices, processes and control technologies for transfer operations at chemical manufacturing facilities and petroleum refineries. (See Survey of Control Technology for Transfer Operations and Analysis of Impacts for PO 00000 Frm 00039 Fmt 4701 Sfmt 4702 36917 Transfer Operation Control Options, January 20, 2012, Docket Item Number EPA–HQ–OAR–2010–0871–0021.) We identified several developments as part of this analysis and evaluated the impacts of applying the developments to gasoline loading racks subject to Refinery MACT 1. We have not identified any developments beyond those in the second analysis. The identified developments include controlling loading racks above specific throughput thresholds by submerged loading and by venting displaced emissions from the transport vehicles through a closed vent system to an APCD that reduces organic regulated material emissions by at least 95 percent. We evaluated the emissions projected using this control technique for a range of different gasoline vapor pressures (to consider the different seasonal formulations of gasoline). We determined that submerged loading in combination with 95-percent control of displaced vapors would allow emissions of 12 to 42 mg/L of gasoline loaded, depending on the vapor pressure of the gasoline (see Evaluation of the Stringency of Potential Standards for Gasoline Loading Racks at Petroleum Refineries in Docket ID Number EPA– HQ–OAR–2010–0682.) The current Refinery MACT 1 emission limit for gasoline loading is 10 mg/L of gasoline loaded. We did not identify any developments in practices, process and control technologies for gasoline loading racks that would reduce emissions beyond the levels already in Refinery MACT 1. Therefore, we are proposing that it is not necessary to revise Refinery MACT 1 requirements for gasoline loading racks pursuant to CAA section 112(d)(6). e. Marine Vessel Loading Operations Marine vessel loading operations load and unload liquid commodities in bulk, such as crude oil, gasoline and other fuels, and naphtha. The cargo is pumped from the terminal’s large, above-ground storage tanks through a network of pipes and into a storage compartment (tank) on the vessel. The HAP emissions are the vapors that are displaced during the filling operation. Refinery MACT 1 specifies that marine tank vessel loading operations at refineries must comply with the requirements in 40 CFR part 63, subpart Y (National Emission Standards for Marine Tank Vessel Loading Operations, ‘‘Marine Vessel MACT’’). We previously completed a technology review of the Marine Vessel MACT (40 CFR part 63, subpart Y) and issued amendments to subpart Y in E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36918 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 2011 (76 FR 22595, Apr. 21, 2011). The analysis conducted for the marine vessel loading source category specifically considered loading of petroleum products such as conventional and reformulated gasoline. As such, the conclusions drawn from this analysis are directly applicable to marine vessel loading operations at petroleum refineries. We have not identified any developments beyond those addressed in that analysis. The Marine Vessel MACT required add-on APCD for loading operations with HAP emissions equal to or greater than 10 tpy of a single pollutant or 25 tpy of cumulative pollutants (referred to as ‘‘10/25 tpy’’). In our technology review of the Marine Vessel MACT standards, we considered the use of add-on APCD for marine vessel loading operations with HAP emissions less than 10/25 tpy. We also evaluated the costs for lean oil absorption systems as add-on APCD under the Marine Vessel MACT technology review. Depending on the throughput of the vessel, costs ranged from $77,000 per ton HAP removed for barges to $510,000 per ton HAP removed for ships ($3,900 per ton VOC removed to $25,000 per ton VOC removed) (see Cost Effectiveness and Impacts of Lean Oil Absorption for Control of Hazardous Air Pollutants from Gasoline Loading—Promulgation in Docket Item Number EPA–HQ–OAR– 2010–0600–0401). We consider requiring add-on APCD for these smaller marine vessel loading operations not to be cost effective. As part of the technology review of 40 CFR part 63, subpart Y, we also considered requiring marine vessel loading operations with emissions less than 10/25 tpy and offshore operations to use submerged loading (also referred to as submerged filling). We did include this requirement in the Marine Vessel MACT. However, when we amended the Marine Vessel MACT, we specifically excluded marine vessel loading operations at petroleum refineries from these provisions, deferring the decisions to include this requirement until we performed the technology review for Refinery MACT 1. The submerged filling requirement in 40 CFR part 63, subpart Y cites the cargo filling line requirements developed by the Coast Guard in 46 CFR 153.282. We project that applying the submerged filling requirements to marine vessel loading operations at petroleum refineries will have no costs or actual emission reductions because marine vessels carrying bulk liquids, liquefied gases or compressed gas hazardous materials are already required by 46 CFR 153.282 to have compliant ‘‘submerged fill’’ cargo VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 lines that also meet the requirements of the Marine Vessel MACT. While we do not anticipate that this requirement will affect actual emissions, it will lower the allowable emissions for these sources under Refinery MACT 1. Therefore, we are proposing, pursuant to CAA section 112(d)(6), to amend 40 CFR part 63, subpart Y to delete the exclusion for marine vessel loading operations at petroleum refineries, which would 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. f. Cooling Towers/Heat Exchange Systems Heat exchange systems include equipment necessary to cool heated non-contact cooling water prior to returning the cooling water to a heat exchanger or discharging the water to another process unit, waste management unit or to a receiving water body. Heat exchange systems are designed as closed-loop recirculation systems with cooling towers or once-through systems that do not recirculate the cooling water through a cooling tower. Heat exchangers in heat exchange systems are constructed with tubes designed to prevent contact between hot process fluids and cooling water. Heat exchangers occasionally develop leaks that allow process fluids to enter the cooling water. The volatile HAP and other volatile compounds in these process fluids are then emitted to the atmosphere due to stripping in a cooling tower or volatilization from a cooling water pond or receiving water body. We established MACT standards for heat exchange systems at refineries in 2009 (see 74 FR 55686, October 28, 2009, as amended at 75 FR 37731, June 30, 2010). The EPA received a petition for reconsideration from the American Petroleum Institute (API) and granted reconsideration on certain issues. On June 20, 2013, we issued a final rule addressing the petition, clarifying rule provisions, and revising the monitoring provisions to provide additional flexibility (78 FR 37133). We are not aware of any developments in processes, practices or control technologies beyond those we recently considered in our analysis of emission reduction techniques for heat exchange systems, which can be found in the docket (Docket Item Number EPA–HQ– OAR–2003–0146–0229). Therefore, we are proposing that it is not necessary to revise Refinery MACT 1 requirements PO 00000 Frm 00040 Fmt 4701 Sfmt 4702 for heat exchange systems pursuant to CAA section 112(d)(6). g. Wastewater Treatment Wastewater collection includes components such as drains, manholes, trenches, junction boxes, sumps, lift stations and sewer lines. Wastewater treatment systems are divided into three categories: primary treatment operations, which include oil-water separators and equalization basins; secondary treatment systems, such as biological treatment units or steam strippers; and tertiary treatment systems, which further treat or filter wastewater prior to discharge to a receiving body of water or reuse in a process. Refinery MACT 1 requires wastewater streams at a new or existing refinery to comply with 40 CFR 61.340 through 61.355 of the NESHAP for Benzene Waste Operations (BWON) in 40 CFR part 61, subpart FF. The BWON requires control of wastewater collection and treatment units for facilities with a total annual benzene quantity of greater than or equal to 10 megagrams per year (Mg/ yr). Individual waste streams at refineries with a total annual benzene quantity greater than or equal to 10 Mg/ yr are not required to adopt controls if the flow-weighted annual average benzene concentration is less than 10 parts per million by weight (ppmw) or the flow rate is less than 0.02 liters per minute at the point of generation. The BWON requires affected waste streams to comply with one of several options for controlling benzene emissions from waste management units and for treating the wastes containing benzene (55 FR 8346, March 7, 1990; 58 FR 3095, January 7, 1993). Although the BWON specifically regulates benzene only, benzene is considered a surrogate for organic HAP from wastewater treatment systems at petroleum refineries. Benzene is present in nearly all refinery process streams. It is an excellent surrogate for wastewater pollutants because its unique chemical properties cause it to partition into the wastewater more readily than most other organic chemicals present at petroleum refineries. We stated our rationale regarding the use of benzene as a surrogate for refinery HAP emissions from wastewater in the original preamble to Refinery MACT 1 (59 FR 36133, July 15, 1994). We performed a technology review for wastewater treatment systems to identify different control technologies for reducing emissions from wastewater treatment systems. We also reviewed the current standards for wastewater treatment systems in different rules E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules including the HON, the proposed NSPS for wastewater systems at petroleum refineries, and the BWON (See Technology Review for Industrial Wastewater Collection and Treatment Operations at Petroleum Refineries, in Docket ID Number EPA–HQ–OAR– 2010–0682.) We identified several developments in processes, practices and control technologies for wastewater treatment, and evaluated the cost and cost effectiveness of each of those developments: (1) requiring wastewater drain and tank controls at refineries with a total annual benzene (TAB) quantity of less than 10 Mg/yr; (2) requiring specific performance parameters for an enhanced biological unit (EBU) beyond those required in the BWON; and (3) requiring wastewater streams with a VOC content of 750 ppmv or higher to be treated by steamstripping prior to any other treatment process for facilities with high organic loading rates (i.e., facilities with total annualized benzene quantity of 10 Mg/ yr or more). These options are, for the most part, independent of each other, so the costs and cost effectiveness of each option are considered separately. Option 1 was evaluated because refineries with a total annual benzene quantity of less than 10 Mg/yr are not required to install additional controls on their wastewater treatment system. Thus, these refineries are limiting the amount of benzene produced in wastewater streams to less than 10 Mg/ yr, which effectively limits their benzene emissions from wastewater to less than 10 Mg/yr. Option 2 is intended to improve the performance of wastewater treatment systems that use an EBU, and thereby achieve additional emission reductions. The BWON, as it applies under Refinery MACT 1, has limited operational requirements for an EBU. Available data suggest that these systems are generally effective for degrading benzene and other organic HAP; however, without specific performance or operational requirements, the effectiveness of the EBU to reduce emissions can be highly variable. Under option 2, more stringent operating requirements are considered for the EBU at refineries. Option 3 considers segregated treatment of wastewater streams with a volatile organic content of greater than 36919 750 ppmw, or high-strength wastewater streams, directly in a steam stripper (i.e., not allowing these streams to be mixed and treated in the EBU). Preliminary investigations revealed direct treatment of wastewater by steam-stripping is only cost effective for high-strength wastewater streams of sufficient quantities. For more detail regarding the impact analysis for these control options, see Technology Review for Industrial Wastewater Collection and Treatment Operations at Petroleum Refineries, in Docket ID Number EPA– HQ–OAR–2010–0682. Table 8 provides the nationwide impacts for the control options. Based on the costs and emission reductions for each of the options, we consider none of the options identified to be cost effective for reducing emissions from petroleum refinery wastewater treatment systems. We are proposing that it is not necessary to revise Refinery MACT 1 to require additional controls for wastewater treatment systems pursuant to CAA section 112(d)(6). TABLE 8—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF CONTROL OPTIONS CONSIDERED FOR WASTEWATER TREATMENT SYSTEMS AT PETROLEUM REFINERIES Control option Capital cost (million $) emcdonald on DSK67QTVN1PROD with PROPOSALS2 1 ....................................... 2 ....................................... 3 ....................................... 19:35 Jun 27, 2014 Emissions reduction, VOC (tpy) 4.2 28.6 50.7 592 2,060 3,480 19.7 223 142 h. Fugitive Emissions The EPA recognizes that, in many cases, it is impractical to directly measure emissions from fugitive emission sources at refineries. Direct measurement of fugitive emissions from sources such as wastewater collection and treatment operations, equipment leaks and storage vessels can be costly and difficult, especially if required to be deployed on all sources of fugitives within a refinery and certainly on a national scale. This is a major reason why fugitive emissions associated with refinery processes are generally estimated using factors and correlations rather than by direct measurement. For example, equipment leak emissions are estimated using factors and correlations between leak rates and concentrations from EPA Method 21 instrument monitoring. Fugitive emissions from wastewater collection and treatment are estimated based on process data, material balances and empirical correlations. Relying on these kinds of VerDate Mar<15>2010 Annualized costs (million $/yr) Jkt 232001 Emissions reduction, HAP (tpy) approaches introduces uncertainty into the emissions inventory for fugitive emission sources. For each of the individual fugitive emission points, we evaluated developments in processes, practices and control technologies for measuring and controlling fugitive emissions from these sources. For storage vessels, as discussed in section IV.B.1.b of this preamble, we are proposing to lower the size and vapor pressure threshold and to require additional fittings on tanks, similar to requirements for tanks in the chemical industry because we project a cost savings due to recovered product. However, we considered but are not proposing to require EPA Method 21 of 40 CFR part 60, Appendix A–7 or optical gas imaging monitoring to identify fugitive emissions from each individual storage vessel. For equipment leaks, as discussed in section IV.B.1.c of this preamble, we considered lowering the leak definition for equipment at petroleum refineries from PO 00000 Frm 00041 Fmt 4701 Sfmt 4702 Cost effectiveness ($/ton VOC) 158 549 929 7,100 13,900 14,500 Cost effectiveness ($/ton HAP) 26,600 52,100 54,500 the current Refinery MACT 1 level of 10,000 ppm for pumps and valves down to the 500 ppm definition that is used in all the other MACT standards applying to the chemical industry, as well as adding a requirement for connectors to be included in the LDAR program because we consider these more stringent LDAR requirements to be technically feasible for the petroleum refining industry. Nevertheless, we rejected these options under the technology review as not being cost effective, based on costs projected by using the industry-reported emissions inventories. We are, however, proposing to adopt the use of optical gas imaging devices following 40 CFR part 60, Appendix K as an alternative to using EPA Method 21, which will be an alternative available to petroleum refiners that could offer cost savings, once the monitoring protocol set forth in Appendix K is promulgated. For wastewater treatment systems, as discussed in section IV.B.1.g of this E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36920 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules preamble, we considered both lowering the threshold for refinery wastewater streams requiring control, as well as requiring refineries to comply with enhanced monitoring and operating limits for EBU, such as the requirements contained in most of the chemical sector MACT standards, because we consider these requirements to be technically feasible for the refining industry. However, like equipment leaks, we are rejecting further controls for wastewater because using the industry-reported emissions inventory, we determined that further wastewater requirements are not cost effective. Although we are not proposing to require a number of additional control options for fugitive emission sources because we determined them not cost effective, we remain concerned regarding the potential for high emissions from these fugitive sources due to the difficulties in monitoring actual emission levels. For example, the regulations require infrequent monitoring of storage tank floating roof seals (visual inspections are required annually and direct inspections of primary seals are required only when the vessel is emptied and degassed, or no less frequently than once every 5 years for internal floating roofs or 10 years for external floating roofs with secondary seals). Given these inspection frequencies, tears or failures in floating roof seals may exist for years prior to being noticed, resulting in much higher emissions than expected or estimated for these sources in the emissions inventory. Similarly, water seals, which are commonly used to control emissions from wastewater collection drain systems, may be difficult to monitor (e.g., some are underground so visible emissions tests cannot be performed) and are subject only to infrequent inspections. During hot, dry months, these water seals may dry out, leaving an open pathway of vapors to escape from the collection system to the atmosphere. Significant emission releases may occur from these ‘‘dry’’ drains, which could persist for long periods of time prior to the next required inspection. Because the requirements and decisions that we are proposing in this action are based upon the emissions inventory reported by facilities in response to the 2011 Refinery ICR, and considering the uncertainty with estimating emissions from fugitive emission sources, we believe that it is appropriate under CAA section 112(d)(6) to require refiners to monitor, and if necessary, take corrective action to minimize fugitive emissions, to ensure that facilities appropriately VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 manage emissions of HAP from fugitive sources. In other words, in this action, we are proposing a HAP concentration to be monitored in the ambient air around a refinery, that if exceeded, would trigger corrective action to minimize fugitive emissions. The fenceline concentration action level would be set at a level such that no facility in the category would need to undertake additional corrective measures if the facility’s estimate of emissions from fugitive emissions is consistent with the level of fugitive emissions actually emitted. On the other hand, if a facility’s estimate of fugitive HAP emissions was not accurate, the owner or operator may need to take some corrective action to minimize fugitive emissions. This approach would provide the owner or operator with the flexibility to determine how best to reduce HAP emissions to ensure levels remain below the fenceline concentration action level. The details of this proposed approach are set forth in more detail in the following discussions in this preamble section. In light of the impracticality of directly monitoring many of these fugitive emission sources on a regular basis, which would help ensure these fugitive sources are properly functioning to the extent practical, we evaluated a fenceline monitoring program under CAA section 112(d)(6). In this section, we evaluate the developments in processes, practices and control technologies for measuring and controlling fugitive emissions from the petroleum refinery as a whole through fenceline monitoring techniques. Fenceline monitoring will identify a significant increase in emissions in a timely manner (e.g., a large equipment leak or a significant tear in a storage vessel seal), which would allow corrective action measures to occur more rapidly than it would if a source relied solely on the traditional infrequent monitoring and inspection methods. Small increases in emissions are not likely to impact the fenceline concentration, so a fenceline monitoring approach will generally target larger emission sources that have the most impact on the ambient pollutant concentration near the refinery. Historically, improved information through measurement data has often led to emission reductions. However, without a specific emission limitation, there may be no incentive for owners or operators to act on the additional information. Therefore, as part of the fenceline monitoring approach, we seek to develop a not-to-be exceeded annual fenceline concentration, above which refinery owners or operators would be PO 00000 Frm 00042 Fmt 4701 Sfmt 4702 required to implement corrective action to reduce their fenceline concentration. We sought to develop a maximum fenceline concentration action level that is consistent with the emissions projected from fugitive sources compliant with the provisions of the refinery MACT standards as modified by the additional controls proposed in this action (e.g., additional fittings on storage vessels). This section details our technology review to identify developments in processes, practices and technologies for measuring air toxics at the fenceline of a facility. Upon selection of a specific fenceline monitoring method, we provide our rationale for the specific details regarding the fenceline monitoring approach, including requirements for siting the monitors, procedures for adjusting for background interferences, selection of the fenceline action level, and requirements for corrective action. Developments in monitoring technology and practices. The EPA reviewed the available literature and identified several different methods for measuring fugitive emissions around a petroleum refinery. These methods include: (1) Passive diffusive tube monitoring networks; (2) active monitoring station networks; (3) ultraviolet differential optical absorption spectroscopy (UV–DOAS) fenceline monitoring; (4) open-path Fourier transform infrared spectroscopy (FTIR); (5) DIAL monitoring; and (6) solar occultation flux monitoring. We considered these monitoring methods as developments in practices under CAA section 112(d)(6) for purposes of all fugitive emission sources at petroleum refineries. Each of these methods has its own strengths and weaknesses, which are discussed in the following paragraphs. Fenceline passive diffusive tube monitoring networks employ a series of diffusive tube samplers at set intervals along the fenceline to measure a timeintegrated ambient air concentration at each sampling location. A diffusive tube sampler consists of a small tube filled with an adsorbent, selected based on the pollutant(s) of interest, and capped with a specially designed cover with small holes that allow ambient air to diffuse into the tube at a small, fixed rate. Diffusive tube samplers have been demonstrated to be a cost-effective, accurate technique for measuring ambient concentrations of pollutants resulting from fugitive emissions in a number of studies.29 30 In addition, 29 McKay, J., M. Molyneux, G. Pizzella, V. Radojcic. Environmental Levels of Benzene at the E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 diffusive samplers are used in the European Union to monitor and maintain air quality, as described in European Union directives 2008/50/EC and Measurement Standard EN 14662– 4:2005 for benzene. The International Organization for Standardization developed a standard method for diffusive sampling (ISO/FDIS 16017–2). In 2009, the EPA conducted a yearlong fenceline monitoring pilot project at Flint Hills West Refinery in Corpus Christi, Texas, to evaluate the viability and performance of passive diffusive sampling technology. Overall, we found the technology to be capable of providing cost effective, high spatialdensity long-term monitoring. This approach was found to be relatively robust and implementable by modestly trained personnel and provided useful information on overall concentration levels and source identification using simple upwind and downwind comparisons.31 Combined with on-site meteorological measurements, 2-week time-integrated passive monitoring has been shown to provide useful facility emission diagnostics. There are several drawbacks of timeintegrated sampling, including the lack of immediate feedback on the acquired data and the loss of short-term temporal information. Additionally, timeintegrated monitoring usually requires the collected sample to be transported to another location for analysis, leading to possible sample integrity problems (e.g., sample deterioration, loss of analytes, and contamination from the surrounding environment). However, time-integrated monitoring systems are generally lower-cost and require less labor than time-resolved monitoring systems. Furthermore, while passive diffusive tube monitoring employs timeintegrated sampling, these timeintegrated samples still represent much shorter time intervals (2 weeks) than many of the current source-specific monitoring and inspection requirements (annually or less frequently). Consequently, passive diffusive tube monitoring still allows earlier detection of significant fugitive emissions than conventional source-specific monitoring. Active monitoring station networks are similar to passive diffusive tube Boundaries of Three European Refineries, prepared by the CONCAWE Air Quality Management Group’s Special Task Force on Benzene Monitoring at Refinery Fenceline (AQ/STF–45), Brussels, June 1999. 30 Thoma, E.D., M.C. Miller, K.C. Chung, N.L. Parsons, B.C. Shine. 2011. Facility Fenceline Monitoring using Passive Sampling, J. Air & Waste Manage Assoc. 61: 834–842. 31 Thoma, et al., 2011. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 monitoring networks in that a series of discrete sampling sites are established; however, each sampling location uses a pump to actively draw ambient air at a known rate through an adsorption tube. Because of the higher sampling rate, adsorption tubes can be analyzed on a daily basis, providing additional time resolution compared to diffusive tube sampling systems. Alternatively, the active sampling system can directly feed an analyzer for even more time resolution. However, this direct analysis of ambient air generally has higher detection limits than when the organic vapors are collected and concentrated on an adsorption matrix prior to analysis. Active monitoring stations have been used for a variety of pollutants in a variety of settings and the methods are well-established. However, compared to the passive diffusive tube monitoring stations, the sampling system is more expensive, more labor-intensive, and generally requires highly-trained staff to operate. UV–DOAS fenceline monitoring is an ‘‘open-path’’ technology. An electromagnetic energy source is used to emit a beam of electromagnetic energy (ultraviolet radiation) into the air towards a detection system some distance from the energy source (typically 100 to 500 meters). The electromagnetic energy beam interacts with components in the air in the open path between the energy source and the detector. The detector measures the disruptions in the energy beam to determine an average pollutant concentration across the open path length. Because the UV–DOAS system can monitor integrated concentrations over a fairly long path-length, fewer monitoring ‘‘stations’’ (energy source/ detector systems) would be needed to measure the ambient concentration around an entire refinery. However, each UV–DOAS monitoring system is more expensive than an active or passive monitoring station and generally requires significant instrumentation shelter to protect the energy source and analyzer when used for long-term (ongoing) measurements. Advantages of UV–DOAS systems include providing real-time measurement data with detection limits in the low parts per billion range for certain compounds. Fog or other visibility issues (e.g., dust storm, high pollen, wildfire smoke) will interfere with the measurements. UV– DOAS systems have been used for fenceline monitoring at several U.S. petroleum refineries and petrochemical plants. UV–DOAS monitoring systems are specifically included as one of the measurement techniques suitable under PO 00000 Frm 00043 Fmt 4701 Sfmt 4702 36921 EPA’s Other Test Method 10 (OTM– 10).32 Open-path FTIR is similar to UV– DOAS monitoring except that an infrared light source and detector system are used. Like the UV–DOAS monitoring approach, the open-path FTIR monitoring system will measure the average pollutant concentration across the open path length between the infrared source and detector. Path lengths and equipment costs for an open-path FTIR system are similar to those for a UV–DOAS system, and the open-path FTIR system provides realtime measurement data. The open-path FTIR system has spectral interferences with water vapor, CO and CO2, which can impact the lower detection limit for organic vapors. Open-path FTIR fenceline monitoring has also been used to measure ambient air concentrations around several petroleum refineries and petrochemical plants. Open-path FTIR is specifically included as a measurement technique in EPA’s OTM– 10. Although open-path FTIR can be used to measure a larger number of compounds than UV–DOAS, the detection limit of open-path FTIR for benzene is higher than for UV–DOAS, as noted in OTM–10. In other words, openpath FTIR is not as sensitive to benzene levels as is UV–DOAS. As benzene is an important pollutant from fugitive sources at petroleum refineries and can often be used as a surrogate for other organic HAP emissions, this high detection limit for benzene is a significant disadvantage. Thus, for the purposes of measuring organic HAP from fugitive sources at the fenceline of a petroleum refinery, a UV–DOAS monitoring system is expected to be more sensitive than an open-path FTIR system. As the cost and operation of open-path FTIR and UV–DOAS systems are very comparable, the benzene detection limit issue is a significant differentiator between these two methods when considering fenceline monitoring to measure fugitives around a petroleum refinery. DIAL monitoring systems employ a pulsed laser beam across the measurement path. Small portions of the light are backscattered due to particles and aerosols in the measurement path. This backscattered light is collected through a telescope system adjacent to the laser and measured via a sensitive light detector. The timing of the received light provides a measure of the distance of 32 ‘‘Optical Remote Sensing for Emission Characterization from Non-Point Sources.’’ Final ORS Protocol, June 14, 2006. Available at: https:// www.epa.gov/ttn/emc/prelim/otm10.pdf. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36922 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules the emission plume. Two different wavelengths of light are pulsed in quick succession: one wavelength that is absorbed strongly by the pollutant of interest and one that is not absorbed. The difference in the returned signal strength between these two light pulses provides a measure of the concentration of the pollutant. Thus, a unique advantage of the DIAL monitoring system is that it can provide spatially resolved pollutant concentrations in two dimensions. Measurements can be made in a relatively short period of time, so the method also provides good time resolution. The DIAL monitoring system has been used in a variety of studies to measure emissions from petroleum refinery and petrochemical sources. It is typically used for specific, shorter-term studies (one to several weeks in duration). The equipment is expensive, has limited availability in the U.S., and requires highly trained professionals to operate. Although DIAL monitoring is included as an appropriate method for EPA’s OTM–10, there are no known long-term applications of this technology for the purpose of fenceline monitoring. Given the limited availability of the equipment and qualified personnel to operate the equipment, we do not consider DIAL monitoring to be technically feasible for the purposes of ongoing, long-term fenceline monitoring. The last fenceline monitoring method evaluated was solar occultation flux. Solar occultation flux uses the sun as the light source and uses an FTIR or UV detector to measure the average pollutant concentration across the measurement path. In this case, the measurement path is vertical. In order to measure the concentrations around an industrial source, the measurement device is installed in a specially equipped van, which is slowly driven along the perimeter of the facility. Measurement signal strength and a global positioning system (GPS) enables determination of pollutant concentrations along the perimeter of the site. This method provides more spatial resolution of the emissions than the UV–DOAS or open-path FTIR methods and is less expensive than a DIAL system. It has the advantage that only one monitoring system is needed per facility, assuming a mobile device is used. Disadvantages of this method include the need of full-time personnel VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 to drive the equipment around the perimeter of the facility (or the need to buy a detector for each measurement location around the perimeter of the facility, if set locations are used), potential accessibility issues for some fenceline locations (e.g., no road near the fenceline), and the measurement method cannot be used at night or during cloudy periods. It would be possible to purchase numerous detection devices and establish fixed monitoring stations similar to the passive or active monitoring approaches described earlier, but this would be very expensive. Furthermore, any application of solar occultation flux is dependent on the sun, so this approach would mean significant periods each calendar day when the monitoring system would not be able to provide data. Based on our evaluation of this technology, we determined that this method is not a reasonable approach for monitoring fenceline concentrations of pollutants around a petroleum refinery on a longterm, ongoing basis. We are soliciting comment on the application of alternative monitoring techniques previously discussed for purposes of fenceline monitoring at refineries. Costs associated with fenceline monitoring alternatives. Based on our review of available monitoring methods, we determined that the following monitoring methods were technically feasible and appropriate for monitoring organic HAP from fugitive emission sources at the fenceline of a petroleum refinery on a long-term basis: (1) Passive diffusive tube monitoring networks; (2) active monitoring station networks; (3) UV–DOAS fenceline monitoring; and (4) open-path FTIR. While DIAL monitoring and solar occultation flux monitoring can be used for short-term studies, we determined that these methods were not appropriate for continuous monitoring at petroleum refineries. This section evaluates the costs of these technically feasible monitoring methods. As noted previously, the cost identified for the open-path monitoring methods (UV– DOAS and FTIR) are very similar. Therefore, we developed costs for only the UV–DOAS system because this method provides lower detection limits for pollutants of interest (specifically, benzene). Costs for the fenceline monitoring methods are dependent on the sampling frequency (for passive and active PO 00000 Frm 00044 Fmt 4701 Sfmt 4702 monitoring locations) and the number of monitoring locations needed based on the size and geometry of the facility. For the open-path methods, we estimated that four monitoring systems (along the east, west, north and south fencelines) would be needed, regardless of the size of the refinery. Some fencelines at larger refineries may be too long for a single open path length, but we did not vary the number of detectors needed for the open-path systems based on refinery size in order to provide a reasonable lower-cost estimate for the open-path monitoring option. For small petroleum refineries (less than 750 acres), we estimated 12 passive or active monitoring stations would be sufficient. For medium-sized refineries (750 to 1,500 acres), we estimated 18 monitoring stations would be required; for large refineries (greater than 1,500 acres), we estimated that 24 monitoring stations would be needed. For the passive diffusive tube monitoring we assumed a 2-week sampling interval; for active monitoring stations, we assumed a daily sampling frequency. We estimated the first year installation and equipment costs for the passive tube monitoring system could cost up to $100,000 for larger refineries (i.e., 24 sampling locations). Annualized costs for ongoing monitoring are projected to be approximately $40,000 per year, assuming the ongoing sample analyses are performed in-house. Capital costs for active sampling systems were estimated to be approximately twice that of the passive system for the larger refinery. Ongoing costs were more than 10 times higher, however, due to the daily sampling frequency. Equipment costs for a single UV–DOAS system were estimated to be about $100,000, so a complete fenceline monitoring system (four systems plus shelters) was estimated to cost more than $500,000. A refinery using this technology for two fenceline locations estimated the annualized cost of calibrating and maintaining these systems approaches $1-million per year. (See Fenceline Monitoring Technical Support Document, in Docket ID Number EPA–HQ–OAR–2010–0682). Table 9 provides the nationwide costs of the monitoring approaches as applied to all U.S. petroleum refineries. E:\FR\FM\30JNP2.SGM 30JNP2 36923 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 9—NATIONWIDE COST IMPACTS OF FENCELINE MONITORING OPTIONS AT PETROLEUM REFINERIES 1 ............................... 2 ............................... 3 ............................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 Monitoring option description Passive diffusive tube monitoring network ................................ Active sampling monitoring network .......................................... Open-path monitoring (UV–DOAS, FTIR) ................................. The primary goal of a fenceline monitoring network is to ensure that owners and operators properly monitor and manage fugitive HAP emissions. As explained further in this preamble section, we are proposing a concentration action level that was derived by modeling fenceline benzene concentrations (as a surrogate for HAP) at each facility after full compliance with the refinery MACT standards, as amended by this proposed action. As such, we are proposing a fenceline benzene concentration that all facilities in the category can meet, according to the emissions inventories reported in response to the 2011 Refinery ICR. Therefore, we do not project a HAP emission reduction that the fenceline monitoring network will achieve. However, if an owner or operator has underestimated the fugitive emissions from one or more sources, or if a leak develops or a tank seal or fitting fails, a fenceline monitoring system would provide for identification of such leaks much earlier than current monitoring requirements and, where emissions are beyond those projected from implementation of the MACT standards, would help ensure that such emissions are quickly addressed. We note that any costs for a fugitive monitoring system would be offset, to some extent, by product recovery since addressing these leaks more quickly than would otherwise occur based on the more infrequent monitoring required would reduce product losses. Based on the low cost and relative benefits of passive monitoring, which include the ability to generate timeintegrated concentration measurements at low detection limits, coupled with relative ease of deployment and analysis, the EPA is proposing to require refineries to deploy passive timeintegrated samplers at the fenceline. These samplers would monitor the level of fugitive emissions that reach the fenceline from all fugitive emission sources at the facility. The EPA is proposing to require fugitive emission reductions if fenceline concentrations exceed a specified concentration action level, as described further below. These proposed fenceline monitoring requirements complement the EPA’s VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 proposal to allow the use of the optical gas imaging camera as described in Appendix K of 40 CFR part 60 as an alternative work practice for measuring emissions from equipment leaks, in lieu of monitoring with EPA Method 21 of 40 CFR part 60, Appendix A–7 (see section IV.B.1.c of this preamble for further discussion). Both approaches utilize low-cost methods to help ensure that total fugitives from a facility are adequately controlled. Because there is no current EPA test method for passive diffusive tube monitoring, as part of this action we are proposing specific monitor citing and sample collection requirements as EPA Method 325A of 40 CFR part 63, Appendix A, and specific methods for analyzing the sorbent tube samples as EPA Method 325B of 40 CFR part 63, Appendix A. We are proposing to establish an ambient concentration of benzene at the fenceline that would trigger required corrective action. A brief summary of the proposed fenceline sampling requirements and our rationale for selecting the corrective action concentration levels are provided below. Siting, design and sampling requirements for fenceline monitors. The EPA is proposing that passive fenceline monitors collecting 2-week time-integrated samples be deployed to measure fenceline concentrations at refineries. We are proposing that refineries deploy passive samplers at 12 to 24 points circling the refinery perimeter. A primary requirement for a fenceline monitoring system is that it provides adequate spatial coverage for determination of representative pollutant concentrations at the boundary of the facility or operation. In an ideal scenario, fenceline monitors would be placed so that any fugitive plume originating within the facility would have a high probability of intersecting one or more monitors, regardless of wind direction. This proposed monitoring program would require that monitors be placed at 15 to 30 degree intervals along the perimeter of the refinery, depending on the size of the facility. For small refineries (less than 750 acres), monitors should be placed at 30 degree intervals, for a total PO 00000 Frm 00045 Fmt 4701 Annual operating costs (million $/yr) Capital cost (million $) Monitoring option Sfmt 4702 Total annualized costs (million $/yr) 3.83 30.2 35.5 5.58 33.1 45.6 12.2 20.6 71.0 of 12 locations; for facilities that are larger than 750 acres and less than 1,500 acres, monitors should be placed at 20 degree intervals, at 18 locations; and for facilities greater than 1,500 acres, monitors should be placed at 15 degree intervals, accounting for 24 locations. We have also established an alternative siting procedure where monitors can be placed every 2,000 feet along the fenceline of the refinery, which may be easier to implement, especially for irregularly-shaped facilities. In proposing these requirements for the number and location of required monitors, the EPA assumes that all portions of the facility are contiguous such that it is possible to define a single facility boundary or perimeter, although this perimeter may be irregular in shape. We request comment on how these monitoring requirements should be adapted for instances where one or more portions of the facility are not contiguous, and on the number and location of facilities for which special fenceline monitoring requirements to accommodate non-contiguous operations might apply. We are proposing that the highest concentration of benzene, as an annual rolling average measured at any individual monitor and adjusted for background (see below), would be compared against the concentration action level in order to determine if there are significant excess emissions of fugitive emissions that need to be addressed. Existing sources would be required to deploy samplers no later than 3 years after the effective date of the final rule; new sources would be required to deploy samplers by the effective date of the final rule or startup, whichever is later. Because the proposed concentration action level is composed of 1 year’s worth of data, we are proposing that refinery owners and operators would be required to demonstrate compliance with the concentration action level for the first time 1 year following the compliance date, and thereafter on a 1-year rolling annual average basis (i.e., considering results from the most recent 26 consecutive 2-week sampling intervals and recalculating the average every 2 weeks). E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36924 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Benzene as an appropriate target analyte. Passive diffusive tube monitors can be used to determine the ambient concentration of a large number of compounds. However, different sorbent materials are typically needed to collect compounds with significantly different properties. Rather than require multiple tubes per monitoring location and require a full analytical array of compounds to be determined, which would significantly increase the cost of the proposed fenceline monitoring program, we are proposing that the fenceline monitors be analyzed specifically for benzene. Refinery owners or operators may elect to do more detailed speciation of the emissions, which could help identify the process unit that may be contributing to a high fenceline concentration, but we are only establishing monitoring requirements and action level requirements for benzene. We consider benzene to be an excellent surrogate for organic HAP from fugitive sources for multiple reasons. First, benzene is ubiquitous at refineries, and is present in nearly all refinery process streams such that leaking components generally will leak benzene at some level (in addition to other compounds). Benzene is also present in crude oil and gasoline, so most storage tank emissions include benzene. As described previously in our discussion of wastewater treatment systems, benzene is also a very good surrogate for organic HAP emissions from wastewater and is already considered a surrogate for organic HAP emissions in the wastewater treatment system control requirements in Refinery MACT 1. Second, the primary releases of benzene occur at ground level as fugitive emissions from process equipment, storage vessels and wastewater collection and treatment systems, and the highest ambient benzene concentrations outside the facility will likely occur near the property boundary near ground level, so fugitive releases of benzene will be effectively detected at the ground-level monitoring sites. According to the emissions inventory we have relied on for this proposed action, 85 percent of benzene emissions from refineries result from ground-level fugitive emissions from equipment and wastewater collection and treatment (see the Component 2 database contained in Docket ID Number EPA–HQ–OAR– 2010–0682). Finally, benzene is present in nearly all process streams. Therefore, the presence of benzene at the fenceline is also an indicator of other air toxics VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 emitted from fugitive sources at refineries. For the reasons discussed above, we believe that benzene is the most appropriate pollutant to monitor. We believe that other compounds, such as PAH or naphthalene, would be less suitable indicators of total fugitive HAP for a couple of reasons. First, they are prevalent in stack emissions as well as fugitive emissions, so there is more potential for fenceline monitors to pick up contributions from non-fugitive sources. In contrast, almost all benzene comes from fugitive sources, so monitoring for benzene increases our confidence that the concentration detected at the fenceline is from fugitives. Second, as compared to benzene, these other compounds are expected to be present at lower concentrations and, therefore, would be more difficult to measure accurately using fenceline monitoring. We request comments on the suitability of selecting benzene or other HAP, including PAH or naphthalene, as the indicator to be monitored by fenceline samplers. We also request comment on whether it would be appropriate to require multiple HAP to be monitored at the fenceline considering the capital and annual cost for additional monitors, and if so, which pollutants should be monitored. Adjusting for background benzene concentrations. Under this proposed approach, absolute measurements along a facility fenceline cannot completely characterize which emissions are associated with the refinery and which are associated with other background sources. The EPA recognizes that sources outside the refinery boundaries may influence benzene levels monitored at the fenceline. Furthermore, background levels driven by local upwind sources are spatially variable. Both of these factors could result in inaccurate estimates of the actual contribution of fugitive emissions from the facility itself to the concentration measured at the fenceline. Many refineries and petrochemical industries are found side-by-side along waterways or transport corridors. With this spatial positioning, there is a possibility that the local upwind neighbors of a facility could cause different background levels on different sides of the facility. To account for background concentrations (i.e., to remove the influence of benzene emissions from sources outside the refinery on monitored fenceline values), we are proposing to adjust monitored fenceline values to account for background concentrations as described below. We solicit comments on PO 00000 Frm 00046 Fmt 4701 Sfmt 4702 alternative approaches for making these adjustments for background benzene. Fenceline-deployed passive samplers measure concentrations that originate from both the observed facility and from off-site sources. The relative contribution of the facility versus offsite source(s) to the measured concentration depends on the emission levels of the observed facility and offsite sources (including both near-field and remote sources), transporting wind direction and atmospheric dispersion. The ability to identify facility and offsite source contributions is reliant on the measurement scheme selected. The most basic (and lowest cost) approach involves different calculations using 2week deployed samplers located only at the facility fenceline. Greater discrimination capability is found by adding passive samplers to specific areas of the facility, reducing the time duration of the passive samplers, and coupling measured meteorology information to the passive sampler analysis. Selective use of time-resolved monitoring or wind sector sampling approaches provides the highest source and background discrimination capability. The approach we are proposing seeks to remove off-site source contributions to the measured fenceline concentrations to the greatest extent possible using the most costeffective measurement solutions. The highest fenceline concentration (HFC) for each 2-week sampling period can be expressed as: HFC = Maximum × (MFC¥OSCi) Where: HFC = highest fenceline concentration, corrected for background. MFCi = measured fenceline concentration for the sampling period at monitoring location i. OSCi = estimated off-site source contribution for the sampling period at monitoring location i. The off-site source contribution (OSC) consists of two primary components: (1) A slowly varying, spatially uniform background (UB) concentration and, in some cases, (2) potential near-field interfering sources. OSCi = UB + NFSi Where: UB = uniform background concentration. NFSi = near-field interfering source concentration contribution at monitoring location i. In some deployment scenarios (such as spatially isolated facilities), the major off-site source component can be identified as background concentrations that are uniform across the facility fenceline and neighboring area. In this E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules scenario, a UB concentration level can be determined and subtracted from the measured fenceline concentrations for each sampling period. This can be accomplished through use of facilitymeasured or otherwise available, quality assured time-resolved (or wind sectorresolved) background monitoring data, or from placement of additional passive samplers at upwind locations away from the facility fenceline and other sources. In other scenarios, such as where other industrial sources or a highway are located nearby, background concentrations are likely not uniform. These outside sources would influence some, but not perhaps not all, fenceline monitors and, therefore, the true ‘‘background’’ concentration would vary, depending where on the fenceline the measurement was taken. In this case, background is not uniform, and monitoring location-specific near-field interfering source (NFS) values would need to be determined. Due to the difficulties associated with determining location-specific NFS values, we are proposing to approximate OSC by using the lowest measured concentration (LMC) at the facility fenceline for that period. In this case, the HFC for the monitoring period, corrected for background, would be calculated as: HFC ≈ DC = HMC¥LMC emcdonald on DSK67QTVN1PROD with PROPOSALS2 Where: DC = concentration difference between the highest and lowest measured concentrations for the sampling period. HMC = highest measured fenceline concentration for the sampling period. LMC = lowest measured fenceline concentration for the sampling period. This alternative is directly applicable for all refinery locations and requires no additional, off-site, upwind monitors, the placement of which is impossible to prescribe a priori. Use of LMC provides a reasonable proxy for OSC in most cases, but can over- or underestimate OSC in some cases. In locations where there are few upwind source contributions and where wind direction is relatively consistent, upwind passive samples on the fenceline can provide a realistic approximation of the actual offsite background levels. As the meteorology becomes more complicated (e.g., mixed wind directions, higher percentage of calm winds), the LMC will reflect a progressively larger amount of emissions from the facility itself, so differential calculations may underestimate the true HFC for some monitoring periods (by inadvertently allowing some facility emissions to be subtracted as part of ‘‘background’’). On the other hand, if a near-field source VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 impacts the highest measured concentration monitoring location significantly, but contributes little to the monitoring location with the LMC, the LMC differential calculation (i.e., DC) could lead to an artificially elevated assessment of the highest fenceline concentration, corrected for background. Based on our examination of previous fenceline monitoring results, we expect that the use of the LMC differential will provide an accurate method by which to determine HFC. Therefore, we are not proposing to limit the use of the LMC differential calculation in cases where there are no near-field sources and where mixed wind direction (or calm wind) is common. In these special cases, use of the UB concentration alone (no NFS term) may be more accurate than using LMC. We are seeking comment on how to identify conditions under which the LMC differential may underestimate the highest fenceline concentration, corrected for background, and the need to require facilities to determine and use UB rather than LMC in these cases. We also recognize that under different site-specific conditions, the NFS contribution may affect certain fenceline monitoring stations more than others, causing the LMC differential calculation to overestimate the facility’s contribution to the highest fenceline concentration. Therefore, we are also proposing to allow owners or operators of petroleum refineries to develop sitespecific monitoring plans to determine UB and NFSi. If standard 2-week passive fenceline data and site analysis indicate potential near-field off-site source interferences at a section of the refinery, the proposal allows the owner or operator to conduct additional sampling strategies to determine a local background (OSC term) for use in the HFC calculation. The owner or operator would be required to report the basis for this correction, including analyses used to identify the sources and contribution of benzene concentration to the passive sampler concentration, within 45 days of the date the owner or operator first measures an exceedance of the concentration action level. We envision that facilities would implement these additional strategies to refine fenceline concentration estimates only if appropriate given site-specific characteristics and only if HFC determined by the LMC approach is likely to exceed the concentration action level (see discussion below regarding this action level). Facilities with HFC below the concentration action level based on the simple LMC differential calculation would not be required to make any further demonstration of the PO 00000 Frm 00047 Fmt 4701 Sfmt 4702 36925 influence of background sources on concentrations measured at the fenceline. For facilities where additional background adjustment is appropriate, optional strategies could include deployment of additional passive samplers at distances from the fenceline (toward and away from suspected NFS) and reducing the time intervals of passive deployments to increase time resolution and wind directioncomparison capability. In complex cases, such as two refineries sharing a common fenceline, wind-sector sampling or various forms of timeresolved monitoring may be required to ascertain the fenceline concentrations. We are proposing that owners or operators of petroleum refineries electing to determine monitoring location-specific NFS concentrations must prepare and submit a site-specific monitoring plan. The monitoring plan is required to identify specific near-field sources, identify the location and type of monitors used to determine UB and NFS concentrations, identify the monitoring location(s) for which the NFS concentrations would apply, and delineate the calculations to be used to determine monitoring location specific NFS concentrations (for those monitoring locations impacted by the near-field source). We are proposing that the site-specific monitoring plan must be submitted to the Administrator for approval and receive approval prior to its use for determining HFC values. The EPA requests comment on the most appropriate approach(es) for adjusting measured fenceline concentrations for background contributions, including (in complex cases) where meteorology is highly variable or where one or more near-field off-site sources affect the measured fenceline concentration (MFC) at a refinery. We are also seeking comment on the adequacy of the proposed requirements for developing and approving site-specific monitoring plans. Concentration action level. As mentioned above, the EPA is proposing to require refineries to take corrective action to reduce fugitive emissions if monitored fenceline concentrations exceed a specific concentration action level on a rolling annual average basis (recalculated every two weeks). We selected this proposed fenceline action level by modeling fenceline benzene concentrations using the emissions inventories reported in response to the 2011 Refinery ICR, assuming that those reported emissions represented full compliance with all refinery MACT requirements, adjusted for additional control requirements we are proposing E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36926 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules in today’s action. Thus, if the reported inventories are accurate, all facilities should be able to meet the fenceline concentration action level. We estimated the long-term ambient postcontrol benzene concentrations at each petroleum refinery using the postcontrol emission inventory and EPA’s American Meteorological Society/EPA Regulatory Model dispersion modeling system (AERMOD). Concentrations were estimated by the model at a set of polar grid receptors centered on each facility, as well as surrounding census block centroid receptors extending from the facility outward to 50 km. For purposes of this modeling analysis, we assumed that the nearest off-site polar grid receptor was the best representation of each facility’s fenceline concentration in the post-control case, unless there was a census block centroid nearer to the fenceline than the nearest off-site polar grid receptor or an actual receptor was identified from review of the site map. In those instances, we estimated the fenceline concentration as the concentration at the census block centroid. Only receptors (either the polar or census block) that were estimated to be outside the facility fenceline were considered in determining the maximum benzene level for each facility. We note that this analysis does not correlate to any particular metric related to risk. The maximum post-control benzene concentration modeled at the fenceline for any facility is 9 micrograms per cubic meter (mg/m3) (annual average). (For further details of the analysis, see memo entitled Fenceline Ambient Benzene Concentrations Surrounding Petroleum Refineries in Docket ID Number EPA–HQ–OAR–2010–0682.) The facility inventories generally project emissions with the required fugitive controls working as designed (e.g., no tears in seals for storage vessel floating roofs and water in all water drain seals). If facility inventories are correct, annual average benzene concentrations would not exceed 9 mg/ m3 at the fenceline of any facility. Because the modeling approach considers only the emissions from the refinery, with no contribution from background or near-field sources, this concentration is comparable to the highest modeled fenceline concentration after correcting for background concentrations, as described previously. The EPA is proposing to set the standard at this concentration action level. We also note that this modeling effort evaluated the annual average benzene concentration at the fenceline, so that this action level applies to the VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 annual average fenceline concentration measured at the facility. The EPA recognizes that, because it is difficult to directly measure emissions from fugitive sources, there is significant uncertainty in current emissions inventories for fugitives. Thus, there is the potential for benzene concentrations monitored at the fenceline to exceed modeled concentrations. However, given the absence of fenceline monitors at most facilities, there is very limited information available at present about fenceline concentrations and the extent to which they may exceed concentrations modeled from inventories. In the absence of additional data regarding the concentration of fugitive emissions of benzene at the fenceline, the EPA believes it is reasonable to rely on the maximum modeled fenceline value as the concentration action level. We are soliciting comment on alternative concentration action levels and other approaches for establishing the concentration action level. Due to differences in short-term meteorological conditions, short-term (i.e., two-week average) concentrations at the fenceline can vary greatly. Given the high variability in short-term fenceline concentrations and the difficulties and uncertainties associated with estimating a maximum 2-week fenceline concentration given a limited number of years of meteorological data used in the modeling exercise, we determined that it would be inappropriate and ineffective to propose a short-term concentration action level that would trigger corrective action based on a single 2-week sampling event. One objective for this monitoring program is to identify fugitive emission releases more quickly, so that corrective action can be implemented in a more timely fashion than might otherwise occur without the fenceline monitoring requirement. We believe the proposed fenceline monitoring approach and a rolling annual average concentration action limit (i.e., using results from the most recent 26 consecutive 2-week samples and recalculating the average every 2 weeks) will achieve this objective. The proposed fenceline monitoring will provide the refinery owner or operator with fenceline concentration information once every 2 weeks. Therefore, the refinery owner or operator will be able to timely identify emissions leading to elevated fenceline concentrations. We anticipate that the refinery owners or operators will elect to identify and correct these sources early, in efforts to avoid exceeding the PO 00000 Frm 00048 Fmt 4701 Sfmt 4702 annual benzene concentration action level. An ‘‘exceedance’’ of the benzene concentration action level would occur when the rolling annual average highest fenceline concentration, corrected for background (determined as described previously), exceeds 9 mg/m3. Upon exceeding the concentration action level, we propose that refinery owners or operators would be required to conduct analyses to identify sources contributing to fenceline concentrations and take corrective action to reduce fugitive emissions to ensure fenceline benzene concentrations remain at or below 9 mg/m3 (rolling annual average). Corrective action requirements. As described previously, the EPA is proposing that the owner or operator analyze the samples and compare the rolling annual average fenceline concentration, corrected for background, to the concentration action level. This section summarizes the corrective action requirements in this proposed rule. First, we are proposing that the calculation of the rolling annual average fenceline concentration must be completed within 30 days after the completion of each sampling episode. If the rolling annual average fenceline benzene concentration, corrected for background, exceeds the proposed concentration action level (i.e., 9 mg/ m3), the facility must, within 5 days of comparing the rolling annual average concentration to the concentration action level, initiate a root cause analysis to determine the primary cause, and any other contributing cause(s), of the exceedance. The facility must complete the root cause analysis and implement corrective action within 45 days of initiating the root cause analysis. We are not proposing specific controls or corrections that would be required when the concentration action level is exceeded because the cause of an exceedance could vary greatly from facility to facility and episode to episode, since many different sources emit fugitive emissions. Rather, we are proposing to allow facilities to determine, based on their own analysis of their operations, the action that must be taken to reduce air concentrations at the fenceline to levels at or below the concentration action level, representing full compliance with all refinery MACT requirements, adjusted for additional control requirements we are proposing in today’s action. If, upon completion of the corrective action described above, the owner or operator exceeds the action level for the next two-week sampling episode following the completion of a first set of corrective actions, the owner or operator E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules would be required to develop and submit to EPA a corrective action plan that would describe the corrective actions completed to date. This plan would include a schedule for implementation of emission reduction measures that the owner or operator can demonstrate is as soon as practical. This plan would be submitted to the Administrator for approval within 30 days of an exceedance occurring during the next two-week sampling episode following the completion of the initial round of corrective action. The EPA would evaluate this plan based on the ambient concentrations measured, the sources identified as contributing to the high fenceline concentration, the potential emission reduction measures identified, and the emission reduction measures proposed to be implemented in light of the costs of the options considered and the reductions needed to reduce the ambient concentration below the action level threshold. To minimize burden on the state implementing agencies and provide additional resources for identifying potential emission sources, we are proposing not to delegate approval of this plan. The refinery owner or operator is not deemed out of compliance with the proposed concentration action level, provided that the appropriate corrective action measures are taken according to the time-frame detailed in an approved corrective action plan. The EPA requests comment on whether it is appropriate to establish a standard time frame for compliance with actions listed in a corrective action plan. We also request comment on whether the approval of the corrective action plan should be delegated to state, local and tribal governments. The EPA’s post-control dispersion modeling (described in section III.A of this preamble), which relies on reported emissions inventories from the 2011 Refinery ICR, adjusted to reflect compliance with the existing refinery MACT standards as modified by the additional controls proposed in this rulemaking, indicates that fugitive emissions at all refineries are low enough to ensure that fenceline concentrations of benzene do not exceed the proposed concentration action level. Assuming the reported inventories and associated modeling are accurate, we expect that few, if any, facilities will need to engage in required corrective action. We do, however, expect that facilities may identify ‘‘poorperforming’’ sources (e.g., unusual leaks) from the fenceline monitoring data and, based on this additional information, will take action to reduce VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 HAP emissions before they would have otherwise been aware of the issue through existing inspection and enforcement measures. By selecting a fenceline monitoring approach and by selecting benzene as the surrogate for organic HAP emissions, we believe that the proposed monitoring approach will effectively target refinery MACT-regulated fugitive emission sources. However, there may be instances where the fenceline concentration is impacted by a low-level miscellaneous process vent, heat exchange system or other similar source. As these sources are regulated under Refinery MACT 1 and the emissions from these sources were included in our post-control modeling file (from which the 9 mg/m3 fenceline concentration action level was developed), sources would not be able to avoid taking corrective action by claiming the exceedance of the fenceline concentration was from one of these emission points rather than from fugitive emission sources. There may be instances in which the high fenceline concentration is impacted by a non-refinery emission source. The most likely instance of this would be leaks from HON equipment or HON storage vessels co-located at the refinery. However, we consider the fenceline monitoring requirement to be specific to refinery emission sources. Therefore, we are proposing to allow refinery owners or operators to develop site-specific monitoring plans to determine the impact of these nonRefinery emission sources on the ambient benzene concentration measured at the fenceline. This monitoring plan would be identical to those used by refinery owners or operators that elect to determine monitoring location-specific NFS values for nearby off-site sources. In this case, however, the NFS is actually within the refinery fenceline. Upon approval and implementation of the monitoring plan, the refinery owner or operator would determine the highest fenceline concentration corrected for background; the background correction in this case includes a correction for the co-located non-Refinery emission source(s). The EPA requests comment on whether the corrective action requirements should be limited to exceedances of the fenceline concentration solely from refinery emission sources and whether a refinery owner or operator should be allowed to exceed the annual average fenceline concentration action level if they can demonstrate the exceedance of the action level is due to a non-refinery emissions source. We also request PO 00000 Frm 00049 Fmt 4701 Sfmt 4702 36927 comment on the requirements proposed for refinery owners or operators to demonstrate that the exceedance is caused by a non-refinery emissions source. Specifically, we request comment on whether the ‘‘near-field source’’ correction is appropriate for onsite sources and whether there are other methods by which refinery owners or operators with co-located, non-refinery emission sources can demonstrate that their benzene concentrations do not exceed the proposed fenceline concentration action level. Additional requirements of the fenceline monitoring program. We are proposing that fenceline data at each monitor location be reported electronically for each semiannual period’s worth of sampling periods (i.e., 13 to 14 2-week sampling periods per semiannual period). These data would be reported within 45 days of the end of each semiannual period, and will be made available to the public through the EPA’s electronic reporting and data retrieval portal, in keeping with the EPA’s efforts to streamline and reduce reporting burden and to move away from hard copy submittals of data where feasible. We are proposing to require the reporting of raw fenceline monitoring data, and not just the HFC, on a semiannual basis; considering the fact that the fenceline monitoring standard is a new approach for fugitive emissions control, and it involves the use of new methods, both analytical and siting methods, this information is necessary for the EPA to evaluate whether this standard has been implemented correctly. Further, the information provided by the raw data, such as the need for additional or less monitoring sites, the range of measured concentrations, the influence of background sources, and the ability to collect and compare data from all refineries, will inform us of further improvements we can make to the fenceline standard, monitoring and analytical methods, approaches for estimating refinery fugitive emissions, and guidance that may be helpful to improve implementation of the fenceline monitoring approach. We seek comment on suggestions for other ways we can monitor and improve the fenceline monitoring requirement. We are proposing that facilities be required to conduct fenceline monitoring on a continuous basis, in accordance with the specific methods described above, even if benzene concentrations, as measured at the fenceline, routinely are substantially lower than the concentration action level. In light of the low annual E:\FR\FM\30JNP2.SGM 30JNP2 36928 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 monitoring and reporting costs associated with the fenceline monitors (as described in the next section), and the importance of the fenceline monitors as a means of ensuring the control of fugitives achieves the expected emission levels, we believe it is appropriate to require collection of fenceline monitoring data on a continuous basis. However, the EPA recognizes that fugitive benzene emissions from some facilities may be so low as to make it improbable that exceedances of the concentration action level would ever occur. In the interest of reducing the cost burden on facilities to comply with this rule, the EPA solicits comment on approaches for reducing or eliminating fenceline monitoring requirements for facilities that consistently measure fenceline concentrations below the concentration action level, and the measurement level that should be used to provide such relief. Such an approach would be consistent with graduated requirements for valve leak monitoring in Refinery MACT 1 and other equipment leak standards, where the frequency of required monitoring varies depending on the percent of leaking valves identified during the previous monitoring period (see, for example, 40 CFR 63.648(c) and 40 CFR 63.168(d)). The EPA requests comment on the minimum time period facilities should be required to conduct fenceline monitoring; the level of performance, in terms of monitored fenceline concentrations, that would enable a facility to discontinue use of fenceline monitors or reduce the frequency of data collection and reporting; and any adjustments to the optical gas imaging camera requirements that would be necessary in conjunction with such changes to the fenceline monitoring requirements. i. Delayed Coking Units As noted in section IV.A of this preamble, we are soliciting comments on the need to establish MACT standards for DCU under CAA section 112(d)(2) and (3). Even if we were to assume that there is already an applicable MACT standard for DCU, a technology review of this emission source, as prescribed under CAA section 112(d)(6), would lead us to propose a depressurization limit of 2 psig because of technology advancements since the MACT standards were originally issued and because it is cost effective. Industry representatives have pointed out that Refinery NSPS Ja requires DCU at new and modified sources to depressure to 5 psig, and they have indicated that EPA should not require a lower VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 depressurization limit under a CAA section 112(d)(6) technology review. Further, industry representatives also provided summary-level information (available in Docket ID Number EPA– HQ–OAR–2010–0682 as correspondence from API entitled Coker Vent Potential Release Limit Preliminary Emission, Cost and Cost Effectiveness Estimates) on costs to depressure to 5 psig versus 2 psig. While the cost information does not show large differences for any particular facility to depressure at 5 psig versus 2 psig, the information does show a large range in potential costs between refineries. At this time, we do not have the detailed, refinery-specific cost breakdowns to compare against our cost assumptions, which were derived from data obtained for a facility that did install the necessary equipment to meet a 2 psig limit. We also do not have detailed information on the design and operation of the DCU in industry’s cost study to evaluate whether there are any differences that would warrant subcategories. We solicit information on designs, operational factors, detailed costs and emissions data for DCU, and we specifically solicit comments on what should be the appropriate DCU depressurization limit if we were to adopt such a requirement pursuant to CAA section 112(d)(6) rather than pursuant to CAA section 112(d)(2) and (3). 2. Refinery MACT 2—40 CFR Part 63, Subpart UUU The Refinery MACT 2 source category regulates HAP emissions from FCCU, CRU and SRU process vents. Criteria pollutant emissions from FCCU and SRU are regulated under 40 CFR part 60, subparts J and Ja (Refinery NSPS J and Refinery NSPS Ja, respectively). We conducted a technology review of Refinery NSPS J emission limits from 2005 to 2008 and promulgated new standards for FCCU and SRU (among other sources) in Refinery NSPS Ja on June 24, 2008 (73 FR 35838). Our current technology review of Refinery MACT 2 relies upon, but is not limited to, consideration of this recent technology review of Refinery NSPS J for FCCU and SRU. a. FCCU Process Vent The FCCU has one large atmospheric vent, the coke burn-off exhaust stream for the unit’s catalyst regenerator. HAP emissions from this FCCU process vent include metal HAP associated with entrained catalyst particles and organic HAP, mostly by-products of incomplete combustion from the coke burn-off process. As the control technologies associated with each of these classes of PO 00000 Frm 00050 Fmt 4701 Sfmt 4702 pollutants are very different, the controls associated with each of these classes of pollutants are considered separately. Metal HAP emission controls. The current Refinery MACT 2 includes several different compliance options, some based on PM as a surrogate for total metal HAP and some based on nickel (Ni) as a surrogate for total metal HAP. Refinery NSPS J was the basis of the PM emission limits and the metal HAP MACT floor in Refinery MACT 2. Refinery NSPS J limits PM from FCCU catalyst regeneration vents to 1.0 gram particulate matter per kilogram (g PM/ kg) of coke burn-off, with an additional incremental PM allowance for liquid or solid fuel burned in an incinerator, waste heat boiler, or similar device. Refinery MACT 2 states that FCCU subject to Refinery NSPS J PM emission limits are required to demonstrate compliance with Refinery NSPS J PM emission limits as specified in Refinery NSPS J. As provided in Refinery NSPS J, ongoing compliance with the PM emission limits is determined by compliance with a 30-percent opacity limit, except for one 6-minute average per hour not to exceed 60-percent opacity. FCCU not subject to Refinery NSPS J may elect to comply with the FCCU PM provisions in Refinery NSPS J. Alternatively, they may comply with a 1.0 g PM/kg of coke burn-off emission limit in Refinery MACT 2 (with no provision for an additional incremental PM allowance for liquid or solid fuel burned in an incinerator, waste heat boiler, or similar device). Compliance with this limit in Refinery MACT 2 is demonstrated by either a 1-hour average site-specific opacity limit using a continuous opacity monitoring system (COMS) or APCD-specific daily average operating limits using CPMS. Refinery MACT 2 also includes two emission limit alternatives that use Ni, rather than PM, as the surrogate for metal HAP. The first of these Ni alternatives is a mass emission limit of 13 grams Ni per hour; the second nickel alternative is an emission limit of 1.0 milligrams Ni per kilogram of coke burn-off. Compliance with the Ni emission limits in Refinery MACT 2 is demonstrated by either a daily average site-specific Ni operating limit (using a COMS and weekly determination of Ni concentration on equilibrium FCCU catalyst), or APCD-specific daily average operating limits using CPMS and monthly average Ni concentration operating limit for the equilibrium FCCU catalyst. Under Refinery MACT 2, an initial performance demonstration (source test) is required to show that FCCU is E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules compliant with the emission limits selected by the refinery owner or operator. No additional performance test is required for facilities already complying with Refinery NSPS J. The performance test is a one-time requirement; additional performance tests are only required if the owner or operator elects to establish new operating limits, or to modify the FCCU or control system in such a manner that could affect the control system’s performance. Under the review for Refinery NSPS J, we conducted a literature review as well as a review of the EPA’s refinery settlements and state and local regulations affecting refineries to identify developments in practices, processes and control technologies to reduce PM emissions from refinery sources (see Summary of Data Gathering Efforts: Emission Control and Emission Reduction Activities, August 19, 2005, and Review of PM Emission Sources at Refineries, December 20, 2005, Docket Item Number EPA–HQ–OAR–2007– 0011–0042). At that time, we identified regulations for PM from FCCU that were more stringent than the Refinery NSPS J requirements for PM, and we promulgated more stringent PM limits in Refinery NSPS Ja. Refinery NSPS Ja limits PM from FCCU catalyst regeneration vents to 1.0 g PM/kg of coke burn-off for modified or reconstructed FCCU, with no incremental allowance for PMassociated liquid or solid fuels burned in a post-combustion device. Furthermore, an emission limit of 0.5 g PM/kg of coke burn-off was established for FCCU constructed after May 14, 2007. In addition, the Refinery NSPS J review identified improvements in APCD monitoring practices, which were included in the Refinery NSPS Ja standards. Refinery NSPS J includes a 30-percent opacity limit as the only ongoing monitoring requirements for PM from the FCCU. This 30-percent opacity limit has shown to be lenient and high in comparison to recent federal rules that have included more stringent opacity limits (e.g., 40 CFR part 60, subpart Db with 20-percent opacity), and recent state and local agency rules that omit opacity limits altogether in favor of operating limits for the emission control systems. Based on the Refinery NSPS J review, Refinery NSPS Ja does not include an opacity limit, but includes updated and more appropriate monitoring approaches, such as requiring bag leak detectors (BLD) for fabric filter control systems, and requiring CPMS for electrostatic precipitators (ESP) and wet scrubbers. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 Additionally, Refinery NSPS Ja includes an option to measure PM emissions directly using a PM CEMS. For this monitoring alternative, a direct PM concentration limit (equivalent to the conventional FCCU PM emission limit in terms of g PM/kg of coke burn-off) is included in the rule. Finally, in our review for Refinery NSPS J, we noted that, even with improved monitoring methods, periodic source testing is needed to verify the performance of the control system as it ages. In Refinery NSPS Ja, annual performance demonstrations are required for affected FCCU. The Refinery NSPS Ja standards for PM from FCCU reflect the latest developments in practices, processes and control technologies. In our current review of Refinery MACT 2, we did not identify any other developments in practices, processes or control technologies since we promulgated Refinery NSPS Ja in 2008. The conclusions of the technology review conducted for the Refinery NSPS J PM emission limits are directly applicable to Refinery MACT 2; the initial Refinery MACT 2 rule recognized this by providing that compliance with Refinery NSPS J would also be compliance with Refinery MACT 2. We considered the impacts of proposing to revise Refinery MACT 2 to incorporate the developments in monitoring practices and control technologies reflected in the Refinery NSPS Ja limits and monitoring provisions. As noted above, Refinery NSPS Ja includes a limit of 0.5 g PM/kg of coke burn-off for newly constructed sources. There would be no costs associated with requiring the lower emission limit of 0.5 g PM/kg of coke burn-off for Refinery MACT 2 new sources under CAA section 112(d)(6) because these sources would already be required to comply with that limit under Refinery NSPS Ja. Therefore, we are proposing that it is necessary pursuant to CAA section 112(d)(6) to revise Refinery MACT 2 to incorporate the Refinery NSPS Ja PM limit for new sources. We are also proposing to establish emission limits and monitoring requirements in Refinery MACT 2 that are consistent with those in Refinery NSPS Ja. This option would not impose any additional cost on sources already subject to Refinery NSPS Ja. We note that for facilities subject to Refinery NSPS J, this would not lead to duplicative or conflicting monitoring requirements because Refinery NSPS J already includes a provision that allows affected facilities subject to Refinery NSPS J to instead comply with the provisions in Refinery NSPS Ja (see 40 CFR 60.100(e)). PO 00000 Frm 00051 Fmt 4701 Sfmt 4702 36929 In addition, in conjunction with our proposal to revise Refinery MACT 2 to include the more stringent requirements in Refinery NSPS Ja, we are proposing to remove the less stringent compliance option of meeting the requirements of Refinery NSPS J. As described previously, Refinery NSPS J includes an incremental PM emissions allowance for post-combustion devices and relies on a 30-percent opacity limit that is outdated and has been demonstrated to be ineffective at identifying exceedances of the 1.0 g PM/kg coke burn-off emissions limit. We also reviewed the compliance monitoring requirements for the Refinery MACT 2 PM and Ni-based emission limits. As described previously, Refinery MACT 2 includes operating limits based on APCD operating parameters or site-specific opacity limits. There are differences between the monitoring approaches in Refinery MACT 2 for these limits and Refinery NSPS Ja monitoring approaches for the NSPS PM limit, so we evaluated whether it is necessary, pursuant to CAA section 112(d)(6), to revise the monitoring provisions in Refinery MACT 2 consistent with the requirements in Refinery NSPS Ja. The first significant difference is in the averaging times used for the different operating limits. Refinery NSPS Ja requires a 3-hour rolling average for the operating limits for parametric monitoring systems; Refinery MACT 2 includes daily averaging of the operating limits. Typically, the averaging time for operating limits is based on the duration of the performance test used to establish those operating limits. As the performance test duration is 3 hours (three 1-hour test runs) and compliance with the PM (or Ni) emission limit is based on the average emissions during this 3-hour period, the most appropriate averaging period for these operating limits is 3 hours. Using a daily average could allow poor performance (i.e., control equipment for shorter periods (e.g., 3hour averages that are higher than the PM emissions limit in Refinery NSPS Ja). For example, assume an operating limit developed from a performance test has a value of 1 and that values exceeding this level would suggest that the control system is not operating as well as during the performance test (i.e., potentially exceeding the PM emission limit). If the control system is run for 18 hours operating at a level of 0.9 and 6 hours at a level of 1.2, the unit would be in compliance with the daily operating limit even though the unit may have 6 consecutive hours during which the operating limit was exceeded. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36930 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Reducing the averaging time does not impact the types of monitors required; it merely requires the owner or operator of the unit to pay more careful attention to the APCD operating parameters. We are proposing that it is necessary, pursuant to CAA section 112(d)(6), to incorporate the use of 3-hour averages rather than daily averages for parameter operating limits in Refinery MACT 2 for both the PM and Ni limits, because this is a cost-effective development in monitoring practice. The site-specific opacity operating limit for PM in Refinery MACT 2 (for units not electing to comply with Refinery NSPS J) has a 1-hour averaging period, but the Ni operating limits (which use opacity monitoring) have a 24-hour averaging period. These averaging periods are inconsistent with the duration of the performance test, which is over a 3-hour period. We are proposing, pursuant to CAA section 112(d)(6), to incorporate the use of 3hour averages for the site-specific opacity operating limit and the Ni operating limits rather than daily averages because this is a cost-effective development in monitoring practice. We also compared the APCD-specific operating parameters used in Refinery MACT 2 to those that we promulgated for Refinery NSPS Ja. The Refinery NSPS Ja rule includes monitoring approaches that are not included in Refinery MACT 2. These include the option of using PM CEMS and requiring BLD for fabric filter control systems. Adding a PM CEMS as an option for demonstrating compliance with the Refinery MACT 2 PM limit (similar to what is provided in Refinery NSPS Ja) would not impact the costs of complying with Refinery MACT 2 because sources can choose whether or not to adopt this monitoring method. With respect to BLD, there is only one refinery that currently uses a baghouse (fabric filter) to control emissions from its FCCU (although one additional unit has indicated that it has plans to install a fabric filter control within the next few years). Under the existing requirements in Refinery MACT 2 (assuming that the FCCU currently operating with a fabric filter has not elected to comply with the Refinery NSPS J PM emission limit option), it is required to comply with a site-specific opacity operating limit. For new, reconstructed, or modified FCCU, Refinery NSPS Ja requires use of BLD. While we generally consider the BLD to be superior to opacity monitors for ensuring fabric filter control systems are operating efficiently, it is difficult to determine what, if any, increment in assurance that the unit is properly VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 controlled would be achieved by requiring the one facility currently operating a fabric filter control system and complying with a site-specific opacity operating limit to switch from a COMS to BLD. Therefore, we are proposing that it is not necessary to require the one existing FCCU with a fabric filter control system to switch from COMS to a BLD system because this would require additional monitoring equipment (with additional costs) and little to no associated increase in assurance that the unit is properly controlled. Although we are not proposing to require existing sources using a fabric filter to use BLD, we are proposing to include BLD as an option to COMS; owners or operators of FCCU using fabric filter-type control systems at existing sources can elect (but are not required) to use BLD in lieu of COMS and the site-specific opacity operating limit. The Refinery NSPS Ja monitoring requirements for ESP include CPMS for monitoring and recording the total power and the secondary current to the entire system. The current MACT requires monitoring voltage and secondary current or monitoring only the total power to the APCD. While these monitoring requirements are similar, we consider that the Refinery NSPS Ja requirements will provide improved operation of the ESP. As the monitors required to measure these parameters are a routine part of ESP installations, we project no additional costs for monitoring equipment. We expect that a new performance test would be needed to ensure that both total power and secondary current are recorded during the source test. As discussed later in this section, we are proposing to require ongoing performance tests regardless of the monitoring option, so we are not projecting any additional costs specific to revising the monitoring requirements for ESP. Because the Refinery NSPS Ja monitoring and operating requirements for ESP are expected to provide improved performance of the APCD with no incremental costs, we propose that it is necessary, pursuant to CAA section 112(d)(6), to incorporate the total power and the secondary current operating limits into Refinery MACT 2. Refinery NSPS Ja provides a specific monitoring alternative to pressure drop for jet ejector-type wet scrubbers or any other type of wet scrubbers equipped with atomizing spray nozzles. Owners or operators of FCCU controlled by these types of wet scrubbers can elect to perform daily checks of the air or water pressure to the spray nozzle rather than monitor pressure. Refinery MACT 2 PO 00000 Frm 00052 Fmt 4701 Sfmt 4702 currently excludes these types of control systems from monitoring pressure drop but includes no specific monitoring to ensure the jet ejectors or atomizing spray nozzle systems are properly operating. Since proper functioning of the jet ejectors or atomizing spray nozzles is critical to ensuring these control systems operate at the level contemplated by the MACT, some monitoring/inspection requirement of these components is necessary to ensure compliance with the FCCU PM or Ni emission limit. The owner or operator of a jet ejector-type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles should be performing routine checks of these systems, such as the daily checks of the air or water pressure to the spray nozzles, as required in Refinery NSPS Ja. These daily checks are consistent with good operational practices for wet scrubbers and should not add significant burden to the FCCU wet scrubber owner or operator. For these reasons, we propose it is necessary to require owners or operators of a jet ejector-type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles to perform daily checks of the air or water pressure to the spray nozzles pursuant to CAA section 112(d)(6). Finally, in our action promulgating Refinery NSPS Ja, we noted that, even with improved monitoring methods, periodic source testing is needed to verify the performance of the control system as it ages. In Refinery NSPS Ja, annual performance demonstrations are required for new sources. FCCU subject to Refinery MACT 2 as new sources would also be subject to Refinery NSPS Ja and would have to comply with the annual testing requirements in Refinery NSPS Ja. However, Refinery MACT 2 does not include periodic performance tests for any FCCU. We considered adding an annual testing requirement for FCCU subject to Refinery MACT 2. The annual nationwide cost burden exceeds $1 million per year and we project only modest improvement in control performance resulting from the performance demonstrations. We considered requiring FCCU performance tests once every 5 years (i.e., once per title V permit period). The nationwide annual cost of this additional testing requirement for FCCU is projected to be, on average, $213,000 per year. We consider this to be a reasonable minimum frequency for which affected sources should demonstrate direct compliance with the FCCU emission limits and that this cost is reasonable. Therefore, we propose that it is E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules necessary, pursuant to CAA section 112(d)(6), to require a performance test once every 5 years for all FCCU under to Refinery MACT 2. Organic HAP. Refinery MACT 2 uses CO as a surrogate for organic HAP and establishes an emission limit of 500 ppmv CO (dry basis). Some FCCU, referred to as complete-combustion FCCU, employ excess oxygen in the FCCU regenerator and are able to meet this emission limit without the need for a post-combustion device. Other FCCU, referred to as partial-combustion FCCU, do not supply enough air/oxygen for complete combustion of the coke to CO2 and, therefore, produce a significant quantity of CO in the regenerator exhaust. Partial-combustion FCCU are typically followed by a post-combustion unit, commonly referred to as a CO boiler, to burn the CO in the regenerator exhaust in order to meet the 500 ppmv CO limit (and to recover useful heat from the exhaust stream). In our review of Refinery NSPS J, we conducted a review of state and local regulations affecting refineries to identify control strategies to reduce CO emissions or VOC emissions from refinery sources (see Review of VOC Emission Sources at Refineries, December 14, 2005, Docket Item Number EPA–HQ–OAR–2007–0011– 0043). We also conducted a review of federal, state and local regulations affecting refineries to identify control strategies to reduce CO emissions from refinery sources (see Review of CO Emission Sources at Refineries, December 22, 2005, Docket Item Number EPA–HQ–OAR–2007–0011– 0044). We did not identify any developments in practices, processes and control technologies to reduce CO or VOC emissions from FCCU as part of the review of Refinery NSPS J, and we have not identified any developments in practices, processes and control technologies for FCCU that would reduce organic HAP since promulgation of Refinery MACT 2. We are proposing that it is not necessary to revise the regulatory provisions for organic HAP in the current MACT standards for FCCU, pursuant to CAA section 112(d)(6). Inorganic HAP. As mentioned previously, Refinery MACT 2 includes a CO emission limit of 500 ppmv. Although this limit is expressly provided as a limit addressing organic HAP emissions, this emission limit is also expected to limit the emissions of oxidizable inorganic HAP, such as HCN. That is, the CO concentration limit was developed as an indicator of complete combustion for all oxidizable pollutants typically found in exhaust gas from the FCCU regenerator operated in partial VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 burn mode. We note that HCN concentrations in FCCU regenerator exhaust with high CO levels also have high HCN concentrations and that HCN concentrations in the regenerator exhaust from complete-combustion FCCU (those meeting the 500 ppmv CO limit without the need for a postcombustion device) are much lower than those from partial burn FCCU prior to a post-combustion device. Thus, we consider that the CO emission limit also acts as a surrogate for the control of oxidizable inorganic HAP, such as HCN. The source test data from the ICR effort revealed that HCN emissions from FCCU are greater than previous tests indicated, particularly for completecombustion FCCU. The increase in HCN emissions was observed at units meeting lower NOX emission limits, which have recently been required by consent decrees, state and local requirements and Refinery NSPS Ja. The higher HCN emissions from complete-combustion FCCU appear to be directly related to operational changes made in efforts to meet these lower NOX emission limits (e.g., reduced excess oxygen levels in the regenerator and reduced regenerator bed temperatures). These higher HCN emissions were only observed in complete-combustion FCCU; FCCU that operated in partial burn mode followed by a CO boiler or similar postcombustion device had significantly lower HCN emissions subsequent to the post-combustion device. Based on our review of the available ICR data and the technologies used in practice, we considered establishing specific emission limits for HCN. In order to comply with emission limits for HCN, owners or operators of completecombustion FCCU would either have to operate their FCCU regenerator at slightly higher temperatures and excess oxygen concentrations (to limit the formation of HCN in the regenerator) or employ a post-combustion device or thermal oxidizer to destroy HCN exhausted from the FCCU regenerator. However, each of these options comes with significant secondary energy and environmental impacts. First, both of these control strategies would yield a significant increase in NOX emissions. We anticipate that most FCCU owners or operators would have to install a selective catalytic reduction (SCR) system to meet their NOX emission limits, if applicable. Operation of the SCR would have energy impacts and may have additional secondary PM2.5 impacts (associated with ammonia slip from the SCR). We expect that modifying the regenerator operating characteristics is the most cost-effective option, although installing and using a PO 00000 Frm 00053 Fmt 4701 Sfmt 4702 36931 thermal oxidizer may be necessary, depending on the operational characteristics of the regenerator and the HCN control requirement. Using a thermal oxidizer to treat FCCU regenerator exhaust, a gas stream that has limited heating value (due to the already low CO concentrations) would be much more expensive and would have additional energy and secondary impacts associated with the auxiliary fuel needed for the device, as compared to modifying regenerator operating conditions. We first performed a screening analysis of the impacts of making only operational changes to the FCCU with the highest HCN concentrations. If this control option is not cost effective for these FCCU, it would not be cost effective for units that have lower HCN concentrations and lower HCN emissions. Similarly, if operating changes in the FCCU regenerator alone are not cost effective, then we can assume that installing a thermal oxidizer to achieve this same level of HCN emission reductions would also not be cost effective. We calculated the cost of changing the regenerator parameters and adding an SCR for the FCCU with the highest HCN emissions rate reported in the ICR, which is an annual emissions rate of 460 tpy. This is also the largest FCCU in operation in the United States and its territories. Based on the size of this unit, we project that an SCR would be expected to cost approximately $13-million and have annualized costs of approximately $4.0million/yr. Thus, if the HCN emissions can be reduced by 95 percent, the cost effectiveness would be approximately $9,000 per ton of HCN. A smaller FCCU had similar HCN concentrations and annual HCN emissions of 141 tpy. Based on the size of this unit, we project an SCR would be expected to cost approximately $7-million and have annualized costs of approximately $1.5million/yr. Assuming a 95-percent reduction in HCN emissions, the cost effectiveness would be approximately $11,000 per ton of HCN. The secondhighest emitting FCCU was larger than this unit, but had lower HCN concentrations. This third unit had emissions of 184 tpy. Based on the size of this unit, we expect that an SCR would cost approximately $9-million and have annualized costs of approximately $2.2-million/yr. Assuming a 95-percent reduction in HCN emissions, the cost effectiveness would be approximately $12,600 per ton of HCN. These costs are for the FCCU with the largest HCN emissions and the lowest control cost (assuming operational E:\FR\FM\30JNP2.SGM 30JNP2 36932 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 changes alone are insufficient to significantly reduce HCN emissions), and the average cost effectiveness for these units exceeds $10,000 per ton HCN emissions reduced. Based on the economies of scale and considering lower HCN concentrations for all other units, the costs per ton of HCN removed for a nationwide standard would be higher. If a post-combustion device is needed to achieve a specific HCN emissions limit, the costs would be even higher. Based on the cost, secondary energy and secondary environmental impacts of an HCN emission limit beyond that achieved by the CO emission limit as a surrogate for HCN, we are proposing, at this time, that it is not necessary, pursuant to CAA section 112(d)(6), to revise the MACT standard to establish a separate HCN standard. As our understanding of the mechanisms of HCN and NOX formation improves and as catalyst additives evolve, it may be possible to achieve both low NOX and low HCN emissions without the use of an SCR and/or post-combustion controls. However, at this time our test data indicate an inverse correlation between these two pollutants. The three facilities with the highest HCN concentrations were the facilities with the lowest NOX concentrations, all of which were below 20 ppmv (dry basis, 0-percent excess air) during the performance tests. While a 20 ppmv NOX limit may be achievable, we anticipate that further reducing the NOX new source performance limits for FCCU would either increase PM2.5 secondary emissions (via the use of an SCR and its associated ammonia slip) or further increase HCN emissions (if combustion controls are used). b. CRU Process Vents A CRU is designed to reform (i.e., change the chemical structure of) naphtha into higher-octane aromatics. The reforming process uses a platinum or bimetal (e.g., platinum and rhenium) catalyst material. Small amounts of coke deposit on the catalyst during the catalytic reaction and this coke is burned off the catalyst to regenerate catalyst activity. There are three types of CRU classified by differences in how the units are designed and operated to effect reforming catalyst regeneration. Semiregenerative reforming is characterized by shutting down the reforming unit at specified intervals, or at the operator’s convenience, for in situ catalyst regeneration. Semi-regenerative CRU typically regenerate catalyst once every 8 to 18 months, with the regeneration cycle lasting approximately 2 weeks. Cyclic-regeneration reforming is VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 characterized by continuous or continual reforming operation with periodic (but frequent) regeneration of catalyst in situ by isolating one of the reactors in the series, regenerating the catalyst, then returning the reactor to the reforming operation. The regeneration of the catalyst in a single reactor may occur numerous times per year (e.g., once a month), and the regeneration of each reactor may take 3 to 5 days to complete. Continuousregeneration reforming units use moving catalyst bed reactors situated vertically (which is why they are often referred to as platforming units). Catalyst flows down the series of reactors. At the bottom of the last reactor, catalyst is continually isolated and sent to a special regenerator. After regeneration, the regenerated catalyst is continually fed to the first (top) reactor. Thus, continuous-regeneration reforming units are characterized by continuousreforming operation along with continuous-regeneration operation. The catalytic reforming reaction is performed in a closed reactor system; there are no emissions associated with the processing portion of the CRU. There is a series of emission points associated with the CRU catalyst regenerator. Regardless of the type of CRU used, there is a series of steps conducted to effect catalyst regeneration. These steps are: (1) Initial depressurization/purge; (2) coke burnoff; (3) catalyst rejuvenation; and (4) reduction/final purge. The primary emissions during the depressurization/ purge cycle are organic HAP. Inorganic HAP, predominately HCl and chlorine, are emitted during the coke burn-off and rejuvenation cycles. The reduction purge is mostly inert materials (nitrogen and/or hydrogen). Refinery MACT 2 contains organic HAP emission limits for the depressurization/purge cycle (purging prior to coke-burn-off) and inorganic HAP emission limits for the coke burn-off and catalyst rejuvenation cycles. Our technology review, summarized below, considers each of these emission limits separately. For additional details on the technology review for CRU, see Technology Review Memorandum for Catalytic Reforming Units at Petroleum Refineries in Docket ID Number EPA–HQ–OAR–2010–0682. Organic HAP. Refinery MACT 2 requires the owner or operator to comply with either a 98-percent reduction of TOC or non-methane TOC, or an outlet concentration of 20 ppmv or less (dry basis, as hexane, corrected to 3-percent oxygen). The emission limits for organic HAP for the CRU do not apply to emissions from process vents during depressuring and purging PO 00000 Frm 00054 Fmt 4701 Sfmt 4702 operations when the reactor vent pressure is 5 psig or less. Control technologies used include directing the purge gas directly to the CRU process heater to be burned, recovering the gas to the facility’s fuel gas system, or venting to a flare or other APCD. The pressure limit exclusion was provided to allow atmospheric venting of the emissions when the pressure of the vessel fell below that needed to passively direct the purge gas to the APCD (most commonly the CRU process heater or flare). We did not identify any developments in practices, processes and control technologies for reducing organic HAP emissions from CRU. However, as noted in section IV.A.2 of this preamble, we are proposing to amend the pressure limit exclusion pursuant to CAA sections 112(d)(2) and (3) to clarify that this limit only applies during passive vessel depressuring. Also, as described in section IV.A.3 of this preamble, we are proposing revisions to Refinery MACT 1 and 2, pursuant to CAA sections 112(d)(2) and (3), to ensure flares used as APCD meet the required destruction efficiency, which includes flares used to control the organic HAP emissions from the CRU depressurization/purge vent streams. Inorganic HAP. Refinery MACT 2 uses HCl as a surrogate for inorganic HAP during the coke burn-off and rejuvenation cycles. Refinery MACT 2 requires owners or operators of existing semi-regenerative CRU to reduce uncontrolled emissions of HCl by 92percent by weight or to a concentration of 30 ppmv (dry basis, corrected to 3percent oxygen) during the coke burnoff and rejuvenation cycles. Owners or operators of new semi-regenerative CRU, new or existing cyclic CRU, or new or existing continuous CRU are required to reduce uncontrolled emissions of HCl by 97-percent by weight or to a concentration of 10 ppmv (dry basis, corrected to 3-percent oxygen) during the coke burn-off and rejuvenation cycles. Technologies used to achieve these limits include caustic spray injection, wet scrubbers, and solid adsorption systems. We conducted a technology review for CRU by reviewing the ICR responses and scientific literature. We did not identify any developments in practices, processes and control technologies for reducing inorganic HAP emissions from CRU. We are proposing that it is not necessary to revise the current inorganic HAP MACT standards for CRU, pursuant to CAA section 112(d)(6). E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 c. SRU Process Vents Most sulfur recovery plants at petroleum refineries use the Claus reaction to produce elemental sulfur. In the Claus reaction, two moles of hydrogen sulfide (H2S) react with one mole of SO2 in a catalytic reactor to form elemental sulfur and water vapor. Prior to the Claus reactors, one-third of the H2S in the sour gas feed to the sulfur plant must be oxidized to SO2 to have the correct proportion of H2S and SO2 for the Claus reaction. This oxidation step is performed in the ‘‘Claus burner.’’ The remaining gas stream, after the elemental sulfur is condensed, is referred to as ‘‘tail gas.’’ HAP emissions in tail gas from sulfur recovery plants are predominately COS and CS2, which are primarily formed as side reactions of the Claus process. Refinery MACT 2 contains HAP standards for SRU that were based on the Refinery NSPS J SO2 and reduced sulfur compounds emission limits. Refinery NSPS J includes an emission limit of 300 ppmv reduced sulfur compounds for a reduction control system not followed by an incinerator, and an emission limit of 250 ppmv SO2 (dry basis, 0-percent excess air) for oxidative control systems or reductive control systems followed by incineration. These Refinery NSPS J limits apply only to Claus sulfur recovery plants with a sulfur recovery capacity greater than 20 long tons per day (LTD). These emission limits effectively required sulfur recovery plants to achieve 99.9-percent sulfur recovery. Refinery MACT 2 defines SRU as a process unit that recovers elemental sulfur from gases that contain reduced sulfur compounds and other pollutants, usually by a vapor-phase catalytic reaction of sulfur dioxide and hydrogen sulfide (see 40 CFR 63.1579). This definition specifically excludes sulfur recovery processes that do not recover elemental sulfur, such as the LO–CAT II process, but does not necessarily limit applicability to Claus SRU. Refinery MACT 2 requires owners or operators of an SRU that is subject to Refinery NSPS J to meet the Refinery NSPS J limits. Owners or operators of an SRU that is not subject to Refinery NSPS J can elect to meet the emission limits in Refinery NSPS J or meet a reduced sulfur compound limit of 300 ppmv (dry basis, 0-percent excess air) regardless of the type of control system or the presence of an incinerator. Unlike Refinery NSPS J, Refinery MACT 2 does not have a capacity applicability limit, so this 300 ppmv reduced sulfur compound limit is VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 applicable to all SRU (as that term is defined), regardless of size. Upon completion of our technology review for Refinery NSPS J, we promulgated Refinery NSPS Ja, which includes new provisions for the sulfur recovery plant. First, Refinery NSPS Ja limits are now applicable to all sulfur recovery plants, not just Claus sulfur recovery plants. Second, emission limits were added for sulfur recovery plants with a capacity of 20 LTD or less, to require new, small sulfur recovery plants to achieve a target sulfur recovery efficiency of 99-percent. These limits are a factor of 10 higher than the emission limits for larger sulfur recovery plants (i.e., 3,000 ppmv reduced sulfur compounds for a reduction control system not followed by an incinerator and 2,500 ppmv SO2 for oxidative control systems or reductive control systems followed by incineration). Refinery NSPS J did not include emission limits for these smaller sulfur recovery plants. Third, new correlations were introduced to provide equivalent emission limits for systems that use oxygen-enriched air in their Claus burner. The technology review conducted for Refinery NSPS J focused on SO2 emissions. Under our current technology review for Refinery MACT 2, we considered the developments in practices, processes or control technologies identified in the Refinery NSPS J technology review as they pertain to HAP emissions and the existing Refinery MACT 2 requirements. We considered the new Refinery NSPS Ja limits for small sulfur recovery plants. While Refinery NSPS Ja establishes criteria pollutant emission limits for these smaller sulfur recovery plants that were previously unregulated for such emissions, these sources are already covered under Refinery MACT 2. Refinery MACT 2 requires these SRU to meet a 300 ppmv reduced sulfur compound limit, which is more stringent than the 3,000 ppmv limit established in Refinery NSPS Ja. We also considered the new correlations in Refinery NSPS Ja for SRU that use oxygen-enriched air in their Claus burner. In the technology review under Refinery NSPS J, we identified a change in practice in the operation of certain Claus SRU. At the time we promulgated Refinery MACT 2, we assumed that all units were using ambient air in the Claus burner, and we established the same emission limits as in Refinery NSPS J. Now, however, we understand that some facilities are using oxygen-enriched air. This practice lowers the amount of inert gases introduced into the SRU and improves PO 00000 Frm 00055 Fmt 4701 Sfmt 4702 36933 operational performance and reliability of the sulfur recovery plant. Air is approximately 20.9 percent by volume oxygen and 79.1-percent inert gases (predominately nitrogen with 1-percent argon and other inert gases). The inert gases introduced in the Claus burner become a significant portion of the overall tail gas flow. When oxygen enrichment is used in the Claus burner, there are fewer inert gases in the tail gas and a lower overall tail gas flow rate. The same molar flow rate of reduced sulfur compounds will be present in the tail gas, but without the additional flow of inerts from the ambient air, the concentration of the reduced sulfur compounds (or SO2) in the tail gas is higher. In developing Refinery NSPS Ja, we included a correlation equation that facilities can use to adjust the concentration limit based on the enriched-oxygen concentration used in the Claus burner. This equation is designed to allow the same mass of emissions for these units as is allowed for units using only ambient air. That is, the emission equation establishes a concentration limit for units using oxygen enrichment so that the mass emissions from the unit do not exceed the mass emissions allowed under the 250 ppmv SO2 (or 300 ppmv reduced sulfur compounds) emissions limits in Refinery NSPS J and in Refinery MACT 2. The new equation in Refinery NSPS Ja for large sulfur recovery plants (those with sulfur recovery greater than 20 LTD) provides an equivalent mass emissions rate of reduced sulfur HAP from the SRU as is currently required in Refinery MACT 2 while allowing a practice that improves the operational reliability of the unit. There are no costs to providing this option for units using oxygen-enriched air because: (1) It is an option that the owner or operator can elect to meet instead of the xisting 250 ppmv SO2 emissions limit and (2) owners or operators of SRU that use oxygen-enriched air are expected to already routinely monitor the inlet air oxygen concentration for operational purposes. Therefore, we are proposing that it is necessary, pursuant to CAA section 112(d)(6), to amend Refinery MACT 2 sulfur recovery requirements to include this equation that addresses the use of oxygen-enriched air as a development in practice in SRU process operations. The emission limits for large sulfur recovery plants (those with sulfur recovery greater than 20 LTD) in Refinery NSPS Ja are equivalent to those in Refinery MACT 2. We are proposing to allow owners or operators subject to Refinery NSPS Ja limits for sulfur E:\FR\FM\30JNP2.SGM 30JNP2 36934 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules recovery plants with a capacity greater than 20 LTD to comply with Refinery NSPS Ja as a means of complying with Refinery MACT 2. We have not identified any additional developments in practices, processes or control technologies for HAP from SRU since development of Refinery NSPS Ja. C. What are the results of the risk assessment and analyses? 1. Inhalation Risk Assessment Results Table 10 of this preamble provides an overall summary of the results of the inhalation risk assessment. TABLE 10—PETROLEUM REFINING SOURCE SECTOR INHALATION RISK ASSESSMENT RESULTS Maximum individual cancer risk (-in-1 million) a Estimated population at increased risk levels of cancer Estimated annual cancer incidence (cases per year) Maximum chronic non-cancer TOSHI b Maximum screening acute non-cancer HQ c Actual Emissions 60 ................................................. ≥ 1-in-1 million: 5,000,000 ........... ≥ 10-in-1 million: 100,000 ............ ≥ 100-in-1 million: 0 ..................... 0.3 0.9 0.6 1 HQREL = 5 (Nickel Compounds). Allowable Emissions d 100 ............................................... ≥ 1-in-1 million: 7,000,000 e ........ ≥ 10-in-1 million: Greater than 90,000 e. ≥ 100-in-1 million: 0 ..................... — a Estimated maximum individual excess lifetime cancer risk due to HAP emissions from the source category. TOSHI. The target organ with the highest TOSHI for the Petroleum Refining source sector is the thyroid system for actual emissions and the neurological system for allowable emissions. c The maximum off-site HQ acute value of 5 is driven by emissions of nickel from CCU. See section III.A.3 of this preamble for explanation of acute dose-response values. Acute assessments are not performed on allowable emissions because of a lack of detailed hourly emissions data. However, because of the conservative nature of the actual annual to actual hourly emissions rate multiplier, allowable acute risk estimates will be comparable to actual acute estimates. d The development of allowable emission estimates can be found in the memo entitled Refinery Risk Estimates for Modeled ‘‘Allowable’’ Emissions, which can be found in Docket ID Number EPA–HQ–OAR–2010–0682. e Population risks from allowable emissions were only calculated for the model plant emissions (REM) approach. For the 138 facilities modeled using the modeled plant approach the population risks greater than 10-in-1 million was estimated to be 90,000. If we consider the second approach to determining allowable emissions (combined the results of the actual and REM emissions estimates) we estimate that the allowable population risks greater than 10-in-1 million would be greater than 90,000 people. Further, the number of people above 1-in-1 million would also be higher than the 7,000,000 estimated using the REM model. emcdonald on DSK67QTVN1PROD with PROPOSALS2 b Maximum The inhalation risk modeling performed to estimate risks based on actual emissions relied primarily on emissions data from the ICR, updated based on our quality assurance review as described in section III.A.1 of this preamble. The results of the chronic baseline inhalation cancer risk assessment indicate that, based on estimates of current actual emissions, the maximum individual lifetime cancer risk (MIR) posed by the refinery source category is 60-in-1 million, with benzene and naphthalene emissions from equipment leaks and storage tanks accounting for 98 percent of the MIR risk. The total estimated cancer incidence from refinery emission sources based on actual emission levels is 0.3 excess cancer cases per year or one case in every 3.3 years, with emissions of naphthalene, benzene, and 2methylnaphthalene contributing 22 percent, 21 percent and 13 percent, respectively, to this cancer incidence. In addition, we note that approximately 100,000 people are estimated to have cancer risks greater than 10-in-1 million, and approximately 5,000,000 people are estimated to have risks greater than 1- VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 in-1 million as a result of actual emissions from these source categories. When considering the MACT-allowable emissions, the maximum individual lifetime cancer risk is estimated to be up to 100-in-1 million, driven by emissions of benzene and naphthalene from refinery fugitives (e.g., storage tanks, equipment leaks and wastewater) and the estimated cancer incidence is estimated to be 0.6 excess cancer cases per year or one excess case in every 1.5 years. Greater than 90,000 people were estimated to have cancer risks above 10in-1 million and approximately 7,000,000 people were estimated to have cancer risks above 1-in-1 million considering allowable emissions from all petroleum refineries. The maximum modeled chronic noncancer HI (TOSHI) value for the source sector based on actual emissions was estimated to be less than 1. When considering MACT-allowable emissions, the maximum chronic non-cancer TOSHI value was estimated to be about 1. 2. Acute Risk Results Our screening analysis for worst-case acute impacts based on actual emissions PO 00000 Frm 00056 Fmt 4701 Sfmt 4702 indicates the potential for five pollutants—acetaldehyde, acrolein, arsenic, benzene and nickel—to exceed an HQ value of 1, with an estimated worst-case maximum HQ of 5 for nickel based on the REL values. This REL occurred at a facility reporting nickel emissions from the FCCU vent. One hundred thirty-six of the 142 petroleum refineries had an estimated worst-case HQ less than or equal to 1 for all HAP; except for the one facility that had an estimated REL of 5, the remaining 5 refineries with an REL above 1 had an estimated worst-case HQ less than or equal to 3. To better characterize the potential health risks associated with estimated worst-case acute exposures to HAP, and in response to a key recommendation from the SAB’s peer review of EPA’s RTR risk assessment methodologies, we examine a wider range of available acute health metrics than we do for our chronic risk assessments. This is in acknowledgement that there are generally more data gaps and inconsistencies in acute reference values than there are in chronic reference values. By definition, the acute CalEPA REL represents a health- E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules protective level of exposure, with no risk anticipated below those levels, even for repeated exposures; however, the health risk from higher-level exposures is unknown. Therefore, when a CalEPA REL is exceeded and an AEGL–1 or ERPG–1 level is available (i.e., levels at which mild effects are anticipated in the general public for a single exposure), we have used them as a second comparative measure. Historically, comparisons of the estimated maximum off-site 1-hour exposure levels have not been typically made to occupational levels for the purpose of characterizing public health risks in RTR assessments. This is because occupational ceiling values are not generally considered protective for the general public since they are designed to protect the worker population (presumed healthy adults) for short-duration increases in exposure (less than 15 minutes). As a result, for most chemicals, the 15-minute occupational ceiling values are set at levels higher than a 1-hour AEGL–1, making comparisons to them irrelevant unless the AEGL–1 or ERPG–1 levels are also exceeded. Such is not the case when comparing the available acute inhalation health effect reference values for some of the pollutants considered in this analysis. The worst-case maximum estimated 1-hour exposure to acetaldehyde outside the facility fence line for the source categories is 1 mg/m3. This estimated worst-case exposure exceeds the 1-hour REL by a factor of 2 (HQREL=2) and is well below the 1-hour AEGL–1 (HQAEGL–1=0.01) and the ERPG–1 (HQERPG–1=0.05). The worst-case maximum estimated 1-hour exposure to acrolein outside the facility fence line for the source categories is 0.005 mg/m3. This estimated worst-case exposure exceeds the 1-hour REL by a factor of 2 (HQREL=2) and is below the 1-hour AEGL–1 (HQAEGL–1=0.1) and the ERPG– 1 (HQERPG–1=0.04). The worst-case maximum estimated 1-hour exposure to nickel compounds outside the facility fence line for the source categories is 0.001 mg/m3. This estimated worst-case exposure exceeds the 1-hour REL by a factor of 5 (HQREL=5). There are no AEGL, ERPG or short-term occupational values for nickel to use as comparison to the acute 1-hour REL value. The worst-case maximum estimated 1-hour exposure to arsenic compounds outside the facility fence line for the source categories is 0.0004 mg/m3. This estimated worst-case exposure exceeds the 1-hour REL by a factor of 2 (HQREL=2). There are no AEGL, ERPG or short-term occupational values for VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 arsenic to use as comparison to the acute 1-hour REL value. The maximum estimated 1-hour exposure to benzene outside the facility fence line is 2.7 mg/m3. This estimated exposure exceeds the REL by a factor of 2 (HQREL=2), but is significantly below both the 1-hour ERPG–1 and AEGL–1 value (HQ ERPG–1 (or AEGL–1) = 0.02). This exposure estimate neither exceeds the AEGL–1/ERPG–1 values, nor does it exceed workplace ceiling level guidelines designed to protect the worker population for short-duration exposure (less than 15 minutes) to benzene, as discussed below. The occupational short-term exposure limit (STEL) standard for benzene developed by the Occupational Safety and Health Administration is 16 mg/m3, ‘‘as averaged over any 15-minute period.’’ 33 Occupational guideline STEL for exposures to benzene have also been developed by the American Conference of Governmental Industrial Hygienists (ACGIH) 34 for less than 15 minutes 35 (ACGIH threshold limit value (TLV)– STEL value of 8.0 mg/m3), and by the National Institute for Occupational Safety and Health (NIOSH) 36 ‘‘for any 15 minute period in a work day’’ (NIOSH REL–STEL of 3.2 mg/m3). These shorter duration occupational values indicate potential concerns regarding health effects at exposure levels below the 1-hour AEGL–1 value. All other HAP and facilities modeled had worst-case acute HQ values less than 1, indicating that the HAP emissions are believed to be without appreciable risk of acute health effects. In characterizing the potential for acute non-cancer risks of concern, it is important to remember the upward bias of these exposure estimates (e.g., worstcase meteorology coinciding with a person located at the point of maximum concentration during the hour) and to consider the results along with the conservative estimates used to develop hourly emissions as described earlier, as well as the screening methodology. Refer to the memo in the docket for this rulemaking (Docket ID Number EPA– 33 29 CFR 1910.1028, Benzene. (2001) Benzene. In Documentation of the TLVs® and BEIs® with Other Worldwide Occupational Exposure Values. ACGIH, 1300 Kemper Meadow Drive, Cincinnati, OH 45240 (ISBN: 978–1–882417–74–1) and available online at https://www.acgih.org. 35 The ACGIH definition of a TLV–STEL states that ‘‘Exposures above the TLV–TWA up to the TLV–STEL should be less than 15 minutes, should occur no more than four times per day, and there should be at least 60 minutes between successive exposures in this range.’’ 36 NIOSH. Occupational Safety and Health Guideline for Benzene; https://www.cdc.gov/niosh/ docs/81-123/pdfs/0049.pdf. 34 ACGIH PO 00000 Frm 00057 Fmt 4701 Sfmt 4702 36935 HQ–OAR–2010–0682, Derivation of hourly emission rates for petroleum refinery emission sources used in the acute risk analysis) for a detailed description of how the hourly emissions were developed for this source sector. 3. Multipathway Risk Screening Results Results of the worst-case Tier I screening analysis indicate that PB– HAP emissions (based on estimates of actual emissions) from several facilities in this source sector exceed the screening emission rates for POM (PAH), CDDF, mercury compounds, and cadmium compounds. For the compounds and facilities that did not screen out at Tier I, we conducted a Tier II screen. The Tier II screen replaces some of the assumptions used in Tier I with site-specific data, including the land use around the facilities, the location of fishable lakes, and local wind direction and speed. The Tier II screen continues to rely on high-end assumptions about consumption of local fish and locally grown or raised foods (adult female angler at 99th consumption for fish 37 and 90th percentile for consumption of locally grown or raised foods 38) and uses an assumption that the same individual consumes each of these foods in high end quantities (i.e., that an individual has high end ingestion rates for each food). The result of this analysis was the development of site-specific emission screening levels for POM, CDDF, mercury compounds, and cadmium compounds. It is important to note that, even with the inclusion of some sitespecific information in the Tier II analysis, the multi-pathway screening analysis is a still a very conservative, health-protective assessment (e.g., upper-bound consumption of local fish, locally grown, and/or raised foods) and in all likelihood will yield results that serve as an upper-bound multi-pathway risk associated with a facility. While the screening analysis is not designed to produce a quantitative risk result, the factor by which the emissions exceed the screening value serves as a rough gauge of the ‘‘upper-limit’’ risks we would expect from a facility. Thus, for example, if a facility emitted a PB– HAP carcinogen at a level 2 times the screening value, we can say with a high degree of confidence that the actual maximum cancer risks will be less than 37 Burger, J. 2002. Daily consumption of wild fish and game: Exposures of high end recreationists. International Journal of Environmental Health Research 12:343–354. 38 U.S. EPA. Exposure Factors Handbook 2011 Edition (Final). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R–09/052F, 2011. E:\FR\FM\30JNP2.SGM 30JNP2 36936 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 2-in-1 million. Likewise, if a facility emitted a noncancer PB–HAP at a level 2 times the screening level, the maximum noncancer risks would represent a HQ less than 2. The high degree of confidence comes from the fact that the screens are developed using the very conservative (health-protective) assumptions that we describe above. Based on the Tier II screening analysis, one facility emits cadmium compounds above the Tier II screening level and exceeds that level by about a factor of 2. Twenty-three facilities emit CDDF as 2,3,7,8-tetrachlorodibenzo-pdioxin toxicity equivalent (TEQ) above the Tier II screening level, and the facility with the highest emissions of dioxins exceeds the Tier II screening level by about a factor of 40. No facilities emit mercury compounds above the Tier II screening levels. Fortyfour facilities emit POM as benzo(a)pyrene TEQ above the Tier II screening level, and the facility with the highest emissions of POM as benzo(a)pyrene TEQ exceeds its screening level by a factor of 30. Polychlorinated biphenyls (PCB) are PB–HAP that do not currently have multi-pathway screening values and so are not evaluated for potential noninhalation risks. These HAP, however, are not emitted in appreciable quantities (0.001 tpy) from refinery operations, and we do not believe they contribute to multi-pathway risks for this source category. Results of the analysis for lead indicate that the maximum annual offsite ambient lead concentration was only 2 percent of the NAAQS for lead, and even if the total annual emissions occurred during a 3-month period, the maximum 3-month rolling average concentrations would still be less than 8 percent of the NAAQS, indicating that there is no concern for multi-pathway risks due to lead emissions. emcdonald on DSK67QTVN1PROD with PROPOSALS2 4. Refined Multipathway Case Study To gain a better understanding of the uncertainty associated with the multipathway Tier I and II screening analysis, a refined multipathway case study using the TRIM.Fate model was conducted for a single petroleum refinery. The site, a refinery in St. John the Baptist Parish, Louisiana, was selected based upon its close proximity to nearby lakes and farms as well as having one of the highest potential multipathway risks for PAH based on the Tier II analysis. The refined analysis for this facility showed that the Tier II screen for each pollutant over-predicted VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 the potential risk when compared to the refined analysis results. For this site, the Tier II screen for mercury indicated that mercury emissions were 3 times lower than the screening value, indicating a potential maximum HQ for mercury of 0.3. In the refined analysis, the potential HQ was 0.04 or about 7 times lower than that predicted by the Tier II screen. For cadmium emissions, the Tier II screen for this facility indicated that cadmium emissions were about 20 times lower than the screening value, indicating a potential maximum HQ for mercury of 0.05. The results of the refined analysis for the selected site in Louisiana show a maximum cadmium HQ of 0.02 or about 3 times lower than that predicted by the Tier II screen. For PAH emissions, the site selected for the refined analysis had PAH emissions 20 times the PAH Tier II screening value, indicating a potential cancer risk of 20in-1 million. When the more refined analysis was conducted for this site, the potential cancer risks were estimated to be 2-in-1 million or about 14 times lower than predicted by the Tier II analysis. Finally, for the facility selected for the refined assessment, the emissions of CDDF as 2,3,7,8tetrachlorodibenzo-p-dioxin TEQ are 5 times higher than the dioxin Tier II screening value, indicating a potential maximum cancer risk of 5–in-1 million. In the refined assessment, the cancer risk from dioxins was estimated to be 2in-1 million, about one-third of the estimate from the Tier II screen. Overall, the refined analysis predicts a potential lifetime cancer risk of 4-in1 million to the maximum most exposed individual (MIR). The non-cancer HQ is predicted to be well below 1 for all target organs. The chronic inhalation cancer risk assessment estimated inhalation cancer risk around this same facility to be approximately 10-in-1 million, due in large part to emissions of naphthalene and 2methylnaphthalene (both nonpersistent, bioaccumulative, and toxic (PBT) HAP). Thus, although highly unlikely, if around this facility the person with the highest chronic inhalation cancer risk is also the same person with the highest individual multipathway cancer risk, then the combined, worst-case MIR for that facility could theoretically be 10-in-1 million (risk estimates are expressed as 1 significant figure). While this refined assessment was performed on only a single facility, the results of this single refined analysis indicate that if refined analyses were PO 00000 Frm 00058 Fmt 4701 Sfmt 4702 performed for other sites, the risk estimates would consistently be lower than those estimated by the Tier II analysis. In addition, the risks predicted by the multipathway analyses at most facilities are considerably lower than the risk estimates predicted by the inhalation assessment, indicating that the inhalation risk results are in all likelihood the primary factor in our residual risk determination for this source category. Further details on the site-specific case study can be found in Appendix 10 of the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, which is available in Docket ID Number EPA–HQ–OAR–2010–0682. 5. Environmental Risk Screening Results As described in the Draft Residual Risk Assessment for the Petroleum Refining Source Sector, which is available in Docket ID Number EPA– HQ–OAR–2010–0682, we conducted an environmental risk screening assessment for the petroleum refineries source category. In the Tier I screening analysis for PB–HAP (other than lead, which was evaluated differently, as noted in section III.A.6 of this preamble), the individual modeled Tier I concentrations for one facility in the source category exceeded some of the ecological benchmarks for mercury. In addition, Tier I modeled concentrations for four facilities exceeded sediment and soil ecological benchmarks for PAH. Therefore, we conducted a Tier II assessment. In the Tier II screening analysis for PB–HAP, none of the individual modeled concentrations for any facility in the source category exceeded any of the ecological benchmarks (either the LOAEL or NOAEL). For lead compounds, we did not estimate any exceedances of the secondary lead NAAQS. Therefore, we did not conduct further assessment for lead compounds. For acid gases, the average modeled concentration around each facility (i.e., the average concentration of all off-site data points in the modeling domain) did not exceed any ecological benchmark. In addition, for both HCL and HF, each individual concentration (i.e., each offsite data point in the modeling domain) was below the ecological benchmarks for all facilities. 6. Facility-Wide Risk Results Table 11 of this preamble displays the results of the facility-wide risk assessment. E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36937 TABLE 11—PETROLEUM REFINING FACILITY-WIDE RISK ASSESSMENT RESULTS Number of facilities analyzed .......................................................................................................................................................... Cancer Risk: Estimated maximum facility-wide individual cancer risk (-in-1 million) .................................................................................... Number of facilities with estimated facility-wide individual cancer risk of 10-in-1 million or more .......................................... Number of petroleum refining operations contributing 50 percent or more to facility-wide individual cancer risk of 10-in-1 million or more ...................................................................................................................................................................... Number of facilities with facility-wide individual cancer risk of 1-in-1 million or more ............................................................. Number of petroleum refining operations contributing 50 percent or more to facility-wide individual cancer risk of 1-in-1 million or more ...................................................................................................................................................................... Chronic Non-cancer Risk: Maximum facility-wide chronic non-cancer TOSHI ......................................................................................................................... Number of facilities with facility-wide maximum non-cancer TOSHI greater than 1 ............................................................... Number of petroleum refining operations contributing 50 percent or more to facility-wide maximum non-cancer TOSHI of 1 or more .............................................................................................................................................................................. The maximum individual cancer whole-facility risk from all HAP emissions at any petroleum refinery is estimated to be 70-in-1 million, based on actual emissions. Of the 142 facilities included in this analysis, 54 have facility-wide maximum individual cancer risks of 10-in-1 million or greater. At the majority of these facilities (50 of 54), the petroleum refinery operations account for over 50 percent of the risk. There are 115 facilities with facilitywide maximum individual cancer risks of 1-in-1 million or greater. At the majority of these facilities (107 of 115), the petroleum refinery operations account for over 50 percent of the risk. The facility-wide maximum individual chronic non-cancer TOSHI is estimated to be 4, based on actual emissions. Of the 142 refineries included in this analysis, five have a TOSHI value greater than 1. The highest non-cancer TOSHI results from emissions of chlorine from cooling towers. In each case, the petroleum refinery operations account for less than 20 percent of the TOSHI values greater than 1. Additional detail regarding the methodology and the results of the facility-wide analyses are included in the risk assessment documentation (Draft Residual Risk Assessment for the Petroleum Refining Source Sector), which is available in the docket for this rulemaking (Docket ID Number EPA– HQ–OAR–2010–0682). 7. What demographic groups might benefit from this regulation? To examine the potential for any environmental justice issues that might be associated with the source categories, we performed a demographic analysis of the population close to the facilities. In 142 70 54 50 115 107 4 5 0 this analysis, we evaluated the distribution of HAP-related cancer and non-cancer risks from petroleum refineries across different social, demographic, and economic groups within the populations living near facilities identified as having the highest risks. The methodology and the results of the demographic analyses are included in a technical report, Draft Risk and Technology Review—Analysis of Socio-Economic Factors for Populations Living Near Petroleum Refineries, available in the docket for this action (Docket ID Number EPA– HQ–OAR–2010–0682). The results of the demographic analysis are summarized in Table 12 of this preamble. These results, for various demographic groups, are based on the estimated risks from actual emissions levels for the population living within 50 km of the facilities. TABLE 12—PETROLEUM REFINING DEMOGRAPHIC RISK ANALYSIS RESULTS Population with cancer risk at or above 1-in-1 million Nationwide Total Population ......................................................................................................... Population with chronic hazard index above 1 312,861,265 5,204,234 0 72 28 50 50 0 0 72 13 1 14 50 28 1 21 0 0 0 0 17 83 29 71 0 0 14 86 21 79 0 0 Race by Percent White .......................................................................................................................... All Other Races ......................................................................................................... Race by Percent emcdonald on DSK67QTVN1PROD with PROPOSALS2 White .......................................................................................................................... African American ....................................................................................................... Native American ........................................................................................................ Other and Multiracial ................................................................................................. Ethnicity by Percent Hispanic ..................................................................................................................... Non-Hispanic ............................................................................................................. Income by Percent Below Poverty Level .................................................................................................. Above Poverty Level .................................................................................................. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00059 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 36938 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 12—PETROLEUM REFINING DEMOGRAPHIC RISK ANALYSIS RESULTS—Continued Population with cancer risk at or above 1-in-1 million Nationwide Population with chronic hazard index above 1 Education by Percent emcdonald on DSK67QTVN1PROD with PROPOSALS2 Over 25 and without High School Diploma ............................................................... Over 25 and with a High School Diploma ................................................................. The results of the demographic analysis indicate that emissions from petroleum refineries expose approximately 5,000,000 people to a cancer risk at or above 1-in-1 million. Implementation of the provisions included in this proposal is expected to reduce the number of people estimated to have a cancer risk greater than 1-in1 million due to HAP emissions from these sources from 5,000,000 people to about 4,000,000. Our analysis of the demographics of the population within 50 km of the facilities indicates potential disparities in certain demographic groups, including the African American, Other and Multiracial, Hispanic, Below the Poverty Level, and Over 25 without a High School Diploma. The population living within 50 km of the 142 petroleum refineries has a higher percentage of minority, lower income and lower education persons when compared to the nationwide percentages of those groups. For example, 50 percent are in one or more minority demographic group, compared to 28 percent nationwide. As noted above, approximately 5,000,000 people currently living within 50 km of a petroleum refinery have a cancer risk greater than 1-in-1 million. We would expect that half of those people are in one or more minority demographic groups. Because minority groups make up a large portion of the population living near refineries, as compared with their representation nationwide, those groups would similarly see a greater benefit from the implementation of the controls proposed in this rule, if finalized. For example, we estimate that after implementation of the controls proposed in this action (i.e., postcontrols), about 1,000,000 fewer people will be exposed to cancer risks greater than 1-in-1 million (i.e., 4,000,000 people). Further, we estimate that approximately 500,000 people no longer exposed to a cancer risk greater than 1in-1 million would be in a minority demographic group. The post-control risk estimates are discussed further in section III.A.5 of this preamble. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 15 85 Although the EPA’s proposed fenceline monitoring requirement is intended to ensure that owners and operators monitor, manage and, if necessary, reduce fugitive emissions of HAP, we also expect the collected fenceline data to help the EPA understand and identify emissions of benzene and other fugitive emissions that are impacting communities in close proximity to the facility. While currently-available emissions and monitoring data do not indicate that risks to nearby populations are unacceptable (see section IV.D.1 of this preamble), we recognize that the collection of additional data through routine fenceline monitoring can provide important information to communities concerned with potential risks associated with emissions from fugitive sources. We note that the data we are proposing to collect on a semiannual basis may include exceedances of the fenceline action level that a facility could have addressed or could still be actively addressing at the time of the report. As noted in section IV.B.1.h of this preamble, directly monitoring fugitive emissions from each potential emissions source at the facility is impractical. Fenceline monitoring offers a costeffective alternative for monitoring fugitive emissions from the entire facility. The EPA’s proposal to require the electronic reporting of fenceline monitoring data on a semiannual basis will ensure that communities have access to data on benzene levels near the facility, which is directly relevant to the potential health risks posed by the facility. The proposed requirements for fenceline monitoring and corrective action when fugitive emissions from a facility exceed the specified corrective action level will serve as an important backstop to protect the health of the populations surrounding the facility, including minority and low-income populations. PO 00000 23 77 D. What are our proposed decisions regarding risk acceptability, ample margin of safety and adverse environmental effects? 1. Risk Acceptability As noted in section II.A.1 of this preamble, the EPA sets standards under CAA section 112(f)(2) using ‘‘a two-step standard-setting approach, with an analytical first step to determine an ‘acceptable risk’ that considers all health information, including risk estimation uncertainty, and includes a presumptive limit on maximum individual lifetime risk (MIR) of approximately 1 in 10 thousand.[39] ’’ (54 FR 38045, September 14, 1989). In this proposal, we estimate risks based on actual emissions from petroleum refineries. We also estimate risks from allowable emissions; as discussed earlier, we consider our analysis of risk from allowable emissions to be conservative and as such to represent an upper bound estimate on risk from emissions allowed under the current MACT standards for the source categories. a. Estimated Risks From Actual Emissions The baseline inhalation cancer risk to the individual most exposed to emissions from sources regulated by Refinery MACT 1 and 2 is 60-in-1 million based on actual emissions. The estimated incidence of cancer due to inhalation exposures is 0.3 excess cancer cases per year, or 1 case every 3.3 years. Approximately 5,000,000 people face an increased cancer risk greater than 1-in-1 million due to inhalation exposure to actual HAP emissions from these source categories, and approximately 100,000 people face an increased risk greater than 10-in-1 million and up to 60-in-1 million. The agency estimates that the maximum chronic non-cancer TOSHI from inhalation exposure is 0.9 due to actual emissions of HCN from FCCU. 39 1-in-10 thousand is equivalent to 100-in-1 million. The EPA currently describes cancer risks as ‘n-in-1 million’. Frm 00060 Fmt 4701 Sfmt 4702 0 0 E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules The screening assessment of worstcase acute inhalation impacts from actual emissions indicates the potential for five pollutants—nickel, arsenic, acrolein, benzene and acetaldehyde—to exceed an HQ value of 1, with an estimated worst-case maximum HQ of 5 for nickel based on the REL values. One hundred thirty-six of the 142 petroleum refineries had an estimated worst-case HQ less than or equal to 1 for all HAP. One facility had an estimated worst-case maximum HQ of 5 and the remaining five refineries with an HQ above 1 had an estimated worst-case HQ less than or equal to 3. Considering the conservative, health-protective nature of the approach that is used to develop these acute estimates, it is highly unlikely that an individual would have an acute exposure above the REL. Specifically, the analysis is based on the assumption that worst-case emissions and meteorology would coincide with a person being at this exact location for a period of time long enough to have an exposure level above the conservative REL value. The Tier II multipathway screening analysis of actual emissions indicated the potential for PAH emissions that are about 30 times the screening level for cancer, dioxin and furans emissions that are about 40 times the cancer screening level and cadmium emissions that are about 2 times the screening level for non-cancer health effects. No facility’s emissions were above the screening level for mercury. As we note above, the Tier II multipathway screen is conservative in that it incorporates many health-protective assumptions. For example, we choose inputs from the upper end of the range of possible values for the influential parameters used in the Tier II screen and we assume that the exposed individual exhibits ingestion behavior that would lead to a high total exposure. A Tier II exceedance cannot be equated with a risk value or a HQ or HI. Rather, it represents a high-end estimate of what the risk or hazard may be. For example, an exceedance of 2 for a non-carcinogen can be interpreted to mean that we have high confidence that the HI would be lower than 2. Similarly, an exceedance of 30 for a carcinogen means that we have high confidence that the risk is lower than 30-in-1-million. Our confidence comes from the conservative, or health-protective, assumptions that are used in the Tier II screen. The refined analysis that we conducted for a specific facility showed that the Tier II screen for each pollutant over-predicted the potential risk when compared to the refined analysis results. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 That refined multipathway assessment showed that the Tier II screen resulted in estimated risks that are higher than the risks estimated by the refined analysis by 14 times for PAH, 3 times for dioxins and furans, and 3 times for cadmium. The refined assessment results indicate that the multipathway risks are considerably lower than the estimated inhalation risks, and our refined multipathway analysis indicates that multipathway risks are low enough that, while they are considered in our proposed decisions, they do not weigh heavily into those decisions because risks for the source category are driven by inhalation. b. Estimated Risks From Allowable Emissions We estimate that the baseline inhalation cancer risk to the individual most exposed to emissions from sources regulated by Refinery MACT 1 and 2 is as high as 100-in-1 million based on allowable emissions. The EPA estimates that the incidence of cancer due to inhalation exposures could be as high as 0.6 excess cancer cases per year, or 1 case approximately every 1.5 years. About 7,000,000 people face an increased cancer risk greater than 1-in1 million due to inhalation exposure to allowable HAP emissions from these source categories, and greater than 90,000 people face an increased risk greater than 10-in-1 million, and as high as 100-in-1 million. Further, we estimate that the maximum chronic non-cancer TOSHI from inhalation exposure values at all refineries is less than 1 based on allowable emissions. The baseline risks summarized above do not account for additional risk reductions that we anticipate due to the MACT standards or the technology review requirements we are proposing in this action. c. Acceptability Determination In determining whether risk is acceptable, the EPA considered all available health information and risk estimation uncertainty as described above. As noted above, the agency estimated risk from actual and allowable emissions. While there are uncertainties associated with both the actual and allowable emissions, we consider the allowable emissions to be an upper bound, based on the conservative methods we used to calculate allowable emissions. The results indicate that both the actual and 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. The MIR based on PO 00000 Frm 00061 Fmt 4701 Sfmt 4702 36939 actual emissions is 60-in-1 million, approximately 60 percent of the presumptive limit. Based on the results of the refined site-specific multipathway analysis summarized above and described in section IV.C.3 of this preamble, we also conclude that the ingestion cancer risk to the individual most exposed is significantly less than 100-in-1 million. In addition, the maximum chronic non-cancer TOSHI due to inhalation exposures is less than 1, and our refined multipathway analysis indicates that non-cancer ingestion risks are estimated to be less than non-cancer risk from inhalation. Finally, the evaluation of acute noncancer risks was very conservative, and showed acute risks below a level of concern. In determining risk acceptability, we also evaluated population impacts because of the large number of people living near facilities in the source category. The analysis indicates that there are approximately 5 million people exposed to actual emissions resulting in a cancer risk greater than 1in-1 million, and a substantially smaller number of people (100,000) are exposed to a cancer risk of greater than 10-in-1 million but less than 100-in-1 million (with a maximum risk of 60-in-1 million). The inhalation cancer incidence is approximately one case in every 3 years based on actual emissions. More detail on this risk analysis is presented in section IV.C and summarized in Tables 10 and 11 of this preamble. The results of the demographic analysis for petroleum refineries indicate that a greater proportion of certain minority groups and low-income populations live near refineries than the national demographic profile. More detail on these population impacts is presented in section IV.C.7 of this preamble. We did not identify any sensitivity to pollutants emitted from these source categories particular to minority and low income populations. Considering the above information, we propose that the risks remaining after implementation of the existing NESHAP for the Refinery MACT 1 and 2 source categories is acceptable. We also note that the estimated baseline risks for the refineries source categories include risks from emissions from DCU, which are a previously unregulated emission source. As discussed in section IV.A. of this preamble, we are proposing new MACT standards for these sources that would reduce emissions of HAP by 850 tpy. We estimate that these new standards would not affect the MIR, but would E:\FR\FM\30JNP2.SGM 30JNP2 36940 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 reduce the source category cancer incidence by 15 percent. We solicit comment on all aspects of our proposed acceptability determination. We note that while we are proposing that the risks estimated from actual and allowable emissions are acceptable, the risks based on allowable emissions are at the presumptive limit of acceptable risk. Furthermore, a significant number of people live in relative proximity to refineries across the country, and therefore a large population is exposed to risks greater than 1-in-1 million. In particular, we solicit comment on the methodology used to estimate allowable emissions. As noted above, we consider the allowable emissions to be an upper bound estimate based on the conservative methods used to calculate such emissions. We recognize, however, that some of the health information concerning allowable emissions arguably borders on the edge of acceptability. Specifically, the analysis of allowable emissions resulted in a MIR of 100-in-1 million, which is the presumptive limit of acceptability, a large number of people (7,000,000) estimated to be exposed at a cancer risk above 1-in-1 million, and an estimated high cancer incidence (one case approximately every 1.5 years). Although we believe that our allowable emissions represent an upper end estimate, we nonetheless solicit comment on whether the health information currently before the Agency should be deemed unacceptable. We also solicit comment on whether our allowable emissions analysis reflects a reasonable estimate of emissions allowed under the current MACT standards. Lastly, we solicit comment on the acceptability of risk considering individuals’ potential cumulative inhalation and ingestion pathway exposure. Please provide comments and data supporting your position. Such information will aid the Agency to make an informed decision on risk acceptability as it moves forward with this rulemaking. 2. Ample Margin of Safety We next considered whether the existing MACT standards provide an ample margin of safety to protect public health. In addition to considering all of the health risks and other health information considered in the risk acceptability determination, in the ample margin of safety analysis we evaluated the cost and feasibility of available control technologies and other measures that could be applied in these source categories to further reduce the risks due to emissions of HAP. For VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 purposes of the ample margin of safety analysis, we evaluated the changes in risk that would occur through adoption of a specific technology by looking at the changes to the risk due to actual emissions. Due to the nature of the allowable risk analysis, which is based on model plants and post processing to combine risk results,40 we did not evaluate the risk reductions resulting from reducing allowable emissions at individual emission sources. Such an approach would require an unnecessarily complex analysis that would not provide any more useful information than the analysis we undertook using actual emissions. We note that while we did not conduct a specific analysis for allowable emissions, it is reasonable to expect reductions in risk similar to those for actual emissions. As noted in our discussion of the technology review in section IV.B of this preamble, we identified a number of developments in practices, processes or control technologies for reducing HAP emissions from petroleum refinery processes. As part of the risk review, we evaluated these developments to determine if any of them could reduce risks and whether it is necessary to require any of these developments to provide an ample margin of safety to protect public health. We evaluated the health information and control options for all of the emission sources located at refineries, including: Storage vessels, equipment leaks, gasoline loading racks, marine vessel loading operations, cooling towers/heat exchange systems, wastewater collection and treatment, FCCU, flares, miscellaneous process vents, CRU and SRU. For each of these sources, we considered chronic cancer and non-cancer risk metrics as well as acute risk. Regarding our ample margin of safety analyses for chronic noncancer risk for the various emission sources, we note that the baseline TOSHIs are less than 1 for the entire source category and considerably less than 1 for all of the emission sources except for the FCCU (which had an TOSHI of 0.9). Therefore, we did not quantitatively evaluate reductions in the chronic non-cancer TOSHI for sources other than FCCU in the ample margin of safety analysis. Regarding our ample margin of safety analyses for acute risk 40 As described in the memorandum entitled Refinery Emissions and Risk Estimates for Modeled ‘‘Allowable’’ Emissions, available in Docket EPA– HQ–OAR–2010–0682, the use of model plants and post-processing was for the purpose of ensuring that our analysis would provide a conservative estimate of actual emissions and thus a conservative estimate of risk. PO 00000 Frm 00062 Fmt 4701 Sfmt 4702 for all of the various emission sources, we note that our analyses did not identify acute risks at a level of concern and, therefore, we did not quantitatively evaluate reductions in the acute HQ values for each individual emission source in the ample margin of safety analysis. Accordingly, the following paragraphs focus on cancer risk in the determination of whether the standards provide an ample margin of safety to protect public health. For storage vessels, as discussed in section IV.B of this preamble, we identified and evaluated three control options. Under the technology review, we determined that two of the options, which we call options 1 and 2, are cost effective. We are proposing option 2, which includes all of the requirements of option 1, as part of the technology review. The option 2 controls that we are proposing under the technology review would result in approximately 910 tpy reduction in HAP (a 40-percent reduction from this emission source). As described in section IV.B of this preamble, not only are these controls cost effective, but we estimate a net cost savings because the emission reductions translate into reduced product loss. These controls would reduce the cancer risk to the individual most exposed from 60-in-1 million to 50-in-1 million based on actual emissions at the facility where storage tank emissions were driving the risk. However, the MIR remains unchanged for the refinery source categories, at 60-in 1-million, because the facility with the next highest cancer risk is 60-in-1 million and this risk is driven by another emission source. The option 2 controls also would reduce cancer incidence by approximately 2 percent. Finally, we estimate that the option 2 controls reduce the number of people with a cancer risk greater than 10-in-1 million storage tanks from 3,000 to 60 and reduce the number of people with a cancer risk greater than 1-in-1 million from storage tanks from 140,000 to 72,000. Since these controls reduce cancer incidence, and reduce the number of people exposed to cancer risks greater than 1-in-10 million and 1in-1 million from storage tank emissions, and are cost effective, we propose that these controls are necessary to provide an ample margin of safety to protect public health. We also evaluated one additional control option for storage vessels, option 3, which incorporated both options 1 and 2 along with additional monitoring requirements. We estimate incremental HAP emission reductions (beyond those provided by option 2) of 90 tpy. The E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules incremental cost effectiveness for option 3 exceeds $60,000 per ton, which we do not consider cost effective. In addition, the option 3 controls do not result in quantifiable reductions in the cancer risk to the individual most exposed or the cancer incidence beyond the reductions estimated for the option 2 controls. For these reasons, we propose that it is not necessary to require the option 3 controls in order to provide an ample margin of safety to protect public health. For equipment leaks, we identified and evaluated three control options discussed previously in the technology review section of this preamble (section IV.B). These options are: • Option 1—monitoring and repair at lower leak definitions; • Option 2—applying monitoring and repair requirements to connectors; and • Option 3—optical gas imaging and repair. We estimate that these three independent control options reduce industry-wide emissions of organic HAP by 24 tpy, 86 tpy, and 24 tpy, respectively. We estimate that none of the control options would reduce the risk to the individual most exposed. We also estimate that the cancer incidence would not change perceptively if these controls were required. Finally, we estimate that the control options do not reduce the number of people with a cancer risk greater than 10-in-1 million or the number of people with a cancer risk greater than 1-in-1 million. As discussed above, the available control options for equipment leaks do not provide quantifiable risk reductions and, therefore, we propose that these controls are not necessary to provide an ample margin of safety. For gasoline loading racks, we identified and evaluated one control option discussed previously in the technology review section of this preamble (section IV.B). As discussed earlier, this option is a new development that results in emissions that are higher than the current level required under Refinery MACT 1. Since we estimate that no emission reductions would result from this new technology and thus no reduction in risk, we propose that this control option is not necessary to provide an ample margin of safety. For marine vessel loading operations, we identified and evaluated two control options discussed previously in the technology review section of this preamble (section IV.B). The first option would be to require submerged fill for small and offshore marine vessel loading operations. Based on actual emissions, we project no HAP emission VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 reductions for this option, as all marine vessels that are used to transport bulk refinery liquids are expected to already have the required submerged fill pipes. Accordingly, we do not project any changes in risk. While we are proposing this option under the technology review, because the option is not projected to reduce emissions or risk, we propose that a submerged loading requirement is not necessary to provide an ample margin of safety. We also identified and evaluated the use of addon controls for gasoline loading at small marine vessel loading operations. In the technology review, we rejected this control option because the cost effectiveness exceeded $70,000 ton of HAP reduced. We estimate that this option would not result in quantifiable changes to any of the risk metrics. Because add-on controls would not result in quantifiable risk reductions and we do not consider the controls to be cost effective, we are proposing that add-on controls for gasoline loading at small marine vessel loading operations are not necessary to provide an ample margin of safety. For cooling towers and heat exchangers, we did not identify as part of our technology review any developments in processes, practices or controls beyond those that we considered in our beyond-the-floor analysis at the time we set the MACT standards. We note that we issued MACT standards for heat exchange systems in a final rule on October 28, 2009 (74 FR 55686), but existing sources were not required to comply until October 29, 2012. As a result, the reductions were not reflected in the inventories submitted in response to the ICR for refineries and therefore were not included in our risk analysis based on actual emissions. We estimate that these MACT standards will result in an industry-wide reduction of over 600 tons HAP per year (or 85 percent). The projected contribution to risk associated with cooling tower emissions after implementation of these MACT standards for heat exchange systems is approximately 1 percent. Because we did not identify any control options beyond those required by the current standards for cooling towers and heat exchange systems, we are proposing that additional controls for these systems are not necessary to provide an ample margin of safety. For wastewater collection and treatment systems, we identified and evaluated three options for reducing emissions. We estimate implementing these independent control options would result in emission reductions of 158 tpy (4 percent), 549 tpy (15 PO 00000 Frm 00063 Fmt 4701 Sfmt 4702 36941 percent), and 929 tpy (25 percent), respectively. None of the control options would reduce the cancer risk to the individual most exposed from 60-in1 million. Option 1 would reduce the cancer incidence by less than 1 percent, and we expect any reduction in cancer incidence that would result from options 2 or 3 to be small because this source accounts for about 10 percent of the cancer incidence from refineries as a whole and the most stringent control option would reduce emissions from these source by only 25 percent. Finally, we estimate that control option 1 would not reduce the number of people with a cancer risk greater than 10-in-1 million or the number of people with a cancer risk greater than 1-in-1 million. We expect any changes to the number of people with a cancer risk greater than 1-in-1 million from implementation of options 2 or 3 to be small for the same reasons mentioned above for cancer incidence. We estimate the cost effectiveness of these options to be $26,600 per ton, $52,100 per ton, and $54,500 per ton of organic HAP reduced, and we do not consider any of these options to be cost effective. Because of the very small reductions in risk and the lack of cost-effective control options, we propose that these controls are not necessary to provide an ample margin of safety. For FCCU, we did not identify any developments in processes, practices or control technologies for organic HAP. For inorganic HAP from FCCU, in the technology review, we identified and evaluated one control option for an HCN emissions limit and one control option for a PM emissions limit. The PM limit was adopted for new sources in Refinery NSPS Ja as part of our review of Refinery NSPS J. We considered the costs and emission reductions associated with requiring existing sources to meet the new source level for PM under Refinery NSPS Ja (i.e., 0.5 g PM/kg of coke burn-off rather than 1.0 g PM/kg). As indicated in our promulgation of Refinery NSPS Ja, the cost effectiveness of lowering the PM limit for existing sources to the level we are requiring for new sources was projected to be $21,000 per ton of PM reduced (see 73 FR 35845, June 24, 2008). Based on the typical metal HAP concentration in PM from FCCU, the cost effectiveness of this option for HAP metals is approximately $1 million per ton of HAP reduced. We estimate that this control option would not reduce the cancer risk to the individual most exposed, would not change the cancer incidence, and would not change the number of people with estimated cancer E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36942 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules risk greater than 1-in-1 million or 10-in1 million. For the HCN emissions limit, we evaluated the costs of controlling HCN using combustion controls in combination with SCR. The cost effectiveness of this option was approximately $9,000 per ton of HCN. This control option would reduce the non-cancer HI from 0.9 to 0.8 and would not change any of the cancer risk metrics. Based on the cost effectiveness of these options and the limited reduction in cancer and non-cancer risk (the non-cancer risk is below a level of concern based on the existing standards), we propose that additional controls for FCCU are not necessary to provide an ample margin of safety. Flares are used as APCD to control emissions from several emission sources covered by Refinery MACT 1 and 2. In this proposed rule, under CAA sections 112(d)(2) and (3), we are proposing operating and monitoring requirements to ensure flares achieve the 98-percent HAP destruction efficiency identified as the MACT Floor in the initial MACT rulemaking in 1995. Flares are critical safety devices that effectively reduce emissions during startup, shutdown, and process upsets or malfunctions. In most cases, flares are the only means by which emissions from pressure relief devices can be controlled. Thus, we find that properly-functioning flares act to reduce HAP emissions, and thereby risk, from petroleum refinery operations. The changes to the flare requirements that we are proposing under CAA sections 112(d)(2) and (3) will result in sources meeting the level required by the original standards, and we did not identify any control options that would further reduce the HAP emissions from flares. Therefore, we are proposing that additional controls for flares are not necessary to provide an ample margin of safety. For the remaining emission sources within the Refinery MACT 1 and Refinery MACT 2 source categories, including miscellaneous process vents, CRU, and SRU, we did not identify any developments in processes practices and control technologies. Therefore, we are proposing that additional controls for these three Refinery MACT 1 and 2 emission sources are not necessary to provide an ample margin of safety. In summary, we propose that the original Refinery MACT 1 and 2 MACT standards, along with the proposed requirements for storage vessels described above, provide an ample margin of safety to protect public health. We are specifically requesting comment on whether there are additional control measures for emission sources subject to Refinery MACT 1 and Refinery MACT 2 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 that are necessary to provide an ample margin of safety to protect public health. In particular, we are requesting that states identify any controls they have already required for these facilities, controls they are currently considering, or other controls of which they may be aware. While not part of our decisions regarding residual risk, we note that DCU are an important emission source with respect to risk from refineries. As described in section IV.A of this preamble, we are proposing new MACT standards under CAA sections 112(d)(2) and (3) for DCU. For informational purposes, we also looked at the risk reductions that would result from implementation of those standards. We estimate no reduction in the cancer risk to the individual most exposed and a decrease in cancer incidence of 0.05 cases per year, or approximately 15 percent. While our decisions on risk acceptability and ample margin of safety are supported even in the absence of these reductions, if we finalize the proposed requirements for DCU, they would further strengthen our conclusions that the standards provide an ample margin of safety to protect public health. 3. Adverse Environmental Effects We conducted an environmental risk screening assessment for the petroleum refineries source category for lead, mercury, cadmium, PAH, dioxins and furans, HF, and HCl. For mercury, cadmium, PAH, and dioxins and furans, none of the individual modeled concentrations for any facility in the source category exceeded any of the Tier II ecological benchmarks (either the LOAEL or NOAEL). For lead, we did not estimate any exceedances of the secondary lead NAAQS. For HF and HCl, the average modeled concentration around each facility (i.e., the average concentration of all off-site data points in the modeling domain) did not exceed any ecological benchmark. Based on these results, EPA proposes 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. E. What other actions are we proposing? We are proposing the following changes to Refinery MACT 1 and 2 as described below: (1) Revising the SSM provisions in order to ensure that the subparts are consistent with the court decision in Sierra Club v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), which vacated two provisions that exempted sources from the requirement to comply with PO 00000 Frm 00064 Fmt 4701 Sfmt 4702 otherwise applicable section 112(d) emission standards during periods of SSM; (2) proposing to clarify requirements related to open-ended valves or lines; (3) adding electronic reporting requirements in Refinery MACT 1 and 2; and (4) updating the General Provisions cross-reference tables. 1. SSM In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the United States Court of Appeals for the District of Columbia Circuit vacated portions of two provisions in the EPA’s CAA section 112 regulations governing the emissions of HAP during periods of SSM. Specifically, the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that under section 302(k) of the CAA, emissions standards or limitations must be continuous in nature and that the SSM exemption violates the CAA’s requirement that some section 112 standards apply continuously. We are proposing the elimination of the SSM exemption in 40 CFR part 63, subparts CC and UUU. Consistent with Sierra Club v. EPA, we are proposing standards in these rules that apply at all times. We are also proposing 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) as explained in more detail below. For example, we are proposing to eliminate the incorporation of the General Provisions’ requirement that the source develop an SSM plan. We also are proposing to eliminate and revise certain recordkeeping and reporting requirements related to the SSM exemption as further described below. The EPA has attempted to ensure that the provisions we are proposing to eliminate are inappropriate, unnecessary, or redundant in the absence of the SSM exemption. We are specifically seeking comment on whether we have successfully done so. In proposing the standards in this rule, the EPA has taken into account startup and shutdown periods and, for the reasons explained below, we are proposing alternate standards for those periods for a few select emission sources. We expect facilities can meet nearly all of the emission standards in Refinery MACT 1 and 2 during startup and shutdown, including the amendments we are proposing in this action. For most of the emission sources, APCD are operating prior to process startup and continue to operate through process shutdown. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules For Refinery MACT 1 and 2, we identified three emission sources for which specific startup and shutdown provisions may be needed. First, as noted above, most APCD used to control metal HAP emissions from FCCU under Refinery MACT 2 (e.g., wet scrubber, fabric filter, cyclone) would be operating before emissions are routed to them and would be operating during startup and shutdown events in a manner consistent with normal operating periods, such that the monitoring parameter operating limits set during the performance test are maintained and met. However, we recognize that there are safety concerns associated with operating an ESP during startup of the FCCU, as described in the following paragraphs. Therefore, we are proposing specific PM standards for startup of FCCU controlled with an ESP under Refinery MACT 2. During startup of the FCCU, ‘‘torch oil’’ (heavy oil typically used as feed to the unit via the riser) is injected directly into the regenerator and burned to raise the temperature of the regenerator and catalyst to levels needed for normal operation. Given the poor mixing of fuel and air in the regenerator during this initial startup, it is difficult to maintain optimal combustion characteristics, and high CO concentrations are common. Elevated CO levels pose an explosion threat due to the high electric current and potential for sparks within the ESP. Consequently, it is common practice to bypass the ESP during startup of the FCCU. Once torch oil is shut off and the regenerator is fueled by catalyst coke burn-off, the CO levels in the FCCU regenerator off-gas will stabilize and the gas can be sent to the ESP safely. When the ESP is offline, the operating limits for the ESP are meaningless. During much of the startup process, either catalyst is not circulating between the FCCU regenerator and reactor or the catalyst circulation rate is much lower than during normal operations. While the catalyst is not circulating or is circulating at reduced rates, the PM and metal HAP emissions are expected to be much lower than during normal operations. Therefore, the cyclone separators that are internal to the FCCU regenerator should provide reasonable PM control during this initial startup. To ensure the internal cyclones are operating efficiently, we are proposing that FCCU using an ESP as the APCD meet a 30-percent opacity limit (on a 6minute rolling average basis) during the period that torch oil is used during FCCU startup. This opacity limit was selected because it has been used historically to assess compliance with the PM emission limit for FCCU in VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 Refinery NSPS J and because the emission limit can be assessed using manual opacity readings, eliminating the need to install a COMS. We note that Refinery NSPS J includes the exception for one 6-minute average of up to 60-percent opacity in a 1-hour period primarily to accommodate soot blowing events. As no soot blowing should be performed prior to the ESP coming on-line, we are not including this exception to the proposed 30percent opacity limit during startup for FCCU that are controlled by an ESP. Second, for emissions of organic HAP from FCCU under Refinery MACT 2, we also expect that APCD would be operating before emissions are routed to them, and would be operating during startup and shutdown events in a manner consistent with normal operating periods, such that the monitoring parameter operating limits set during the performance test are maintained and met. However, many FCCU operate in ‘‘complete combustion’’ mode without a postcombustion device. In other words, for FCCU without a post-combustion device, organic HAP are controlled by the FCCU itself, so there is no separate APCD that could be operating during startup and demonstrating continuous compliance with the monitoring parameter operating limits. Therefore, we are proposing specific CO standards for startup of FCCU without a postcombustion device under Refinery MACT 2. As mentioned previously, ‘‘torch oil’’ is injected directly into the regenerator and burned during FCCU startup to raise the temperature of the regenerator and catalyst to levels needed for normal operation. During this period, CO concentrations often will exceed the 500 ppm emissions limit due to the poor mixing of fuel and air in the regenerator. The emissions limit is based on CO emissions, as a surrogate for organic HAP emissions, and the emission limit is evaluated using a 1-hour averaging period. This 1-hour averaging period does not provide adequate time for short-term excursions that occur during startup to be offset by lower emissions during normal operational periods. Based on available data during normal operations, ensuring adequate combustion (indicated by CO concentration levels below 500 ppmv) minimizes organic HAP emissions. Low levels of CO in the exhaust gas are consistently achieved during normal operations when oxygen concentrations in the exhaust gas exceed 1-percent by volume (dry basis). Thus, maintaining an adequate level of excess oxygen for the combustion of fuel in the FCCU is PO 00000 Frm 00065 Fmt 4701 Sfmt 4702 36943 expected to minimize organic HAP emissions. Emissions of CO during startup result from a series of reactions with the fuel source and are dependent on mixing, local oxygen concentrations, and temperature. While the refinery owner or operator has direct control over air blast rates, CO emissions may not always directly correlate with the air blast rate. Exhaust oxygen concentrations are expected to be more directly linked with air blast rates and are, therefore, more directly under control of the refinery owner or operator. We are proposing an excess oxygen concentration of 1 volume percent (dry basis) based on a 1-hour average during startup. We consider the 1-hour averaging period for the oxygen concentration in the exhaust gas from the FCCU to be appropriate during periods of FCCU startup because air blast rates can be directly controlled to ensure adequate oxygen supply on a short-term basis. Third, we note that the SRU is unique in that it essentially is the APCD for the fuel gas system at the facility. The SRU would be operating if the refinery is operating, including during startup and shutdown events. There are typically multiple SRU trains at a facility. Different trains can be taken off-line as sour gas production decreases to maintain optimal operating characteristics of the operating SRU during startup or shutdown of a set of process units. Thus, the sulfur recovery plant is expected to run continuously and would only shut down its operation during a complete turnaround or shutdown of the facility. For these limited situations, the 12-hour averaging time provided for the SRU emissions limitation under Refinery MACT 2 may not be adequate time in which to shut down the unit without exceeding the emissions limitation. Therefore, we are proposing specific standards for SRU during periods of shutdown. We note also that, for SRU subject to Refinery NSPS J or electing to comply with Refinery NSPS J as provided in Refinery MACT 2, the emissions limit is in terms of SO2 concentration for SRU with oxidative control systems or reductive control systems followed by an incinerator. While the SO2 concentration limit provides a reasonable proxy of the reduced sulfur HAP emissions during normal operations, it does not necessarily provide a good indication of reduced sulfur HAP emissions during periods of shutdown. During periods of shutdown, the sulfur remaining in the unit is purged and combusted generally in a thermal oxidizer or a flare. Although the sulfur loading to the thermal oxidizer E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36944 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules during shutdown may be higher than during normal operations (thereby causing an increase in the SO2 concentration and exceedance of the SO2 emissions limitation), appropriate operation of the thermal oxidizer will adequately control emissions of reduced sulfur HAP. Thus, during periods of shutdown, the 300 ppmv reduced sulfur compound emission limit alternative (provided for SRU not subject to Refinery NSPS J) is a better indicator of reduced sulfur HAP emissions. In Refinery MACT 2, SRU that elect to comply with the 300 ppmv reduced sulfur compound emission limit (i.e., those not subject to Refinery NSPS J or electing to comply with Refinery NSPS J) and that use a thermal incinerator for sulfur HAP control are required to maintain a minimum temperature and excess oxygen level (as determined through a source test of the unit) to demonstrate compliance with the reduced sulfur compound emission limitation. In Refinery MACT 2, SRU subject to Refinery NSPS J (or that elect to comply with Refinery NSPS J) that use an incinerator to control sulfur HAP emissions are required to install an SO2 CEMS to demonstrate compliance with the SO2 emission limitation. For these units, it is impractical to require installation of a reduced sulfur compound monitor or to require a source test to establish operating parameters during shutdown of the SRU because of the few hours per year that the entire series of SRU trains are shutdown. Although the autoignition temperature of COS is unknown, based on the autoignition temperature of CS2 (between 200 and 250 °F) and the typical operating characteristics of thermal oxidizers used to control emissions from SRU, we are proposing that, for periods of SRU shutdown, diverting the 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 1200 °F and a minimum outlet oxygen concentration of 2 volume percent (dry basis). We believe that this provides adequate assurance of compliance with the 300 ppmv reduced sulfur compound emission limitation for SRU because incineration at these temperatures was determined to be the MACT floor in cases where no tail gas treatment units were used (i.e., units not subject to Refinery NSPS J). For all other emission sources, we believe that the requirements that apply during normal operations should apply during startup and shutdown. For VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 Refinery MACT 1, these emission sources include process vents, transfer operations, storage tanks, equipment leaks, heat exchange systems, and wastewater. Emission reductions for process vents and transfer operations, such as gasoline loading racks and marine tank vessel loading, are typically achieved by routing vapors to thermal oxidizers, carbon adsorbers, absorbers and flares. It is common practice to start an APCD prior to startup of the emissions source it is controlling, so the APCD would be operating before emissions are routed to it. We expect APCD would be operating during startup and shutdown events in a manner consistent with normal operating periods, and that these APCD will be operated to maintain and meet the monitoring parameter operating limits set during the performance test. We do not expect startup and shutdown events to affect emissions from equipment leaks, heat exchange systems, wastewater, or storage tanks. Leak detection programs associated with equipment leaks and heat exchange systems are in place to detect leaks, and, therefore, it is inconsequential whether the process is operating under normal operating conditions or is in startup or shutdown. Wastewater emissions are also not expected to be significantly affected by startup or shutdown events because the control systems used can operate while the wastewater treatment system is in startup or shutdown. Working and breathing losses from storage tanks are the same regardless of whether the process is operating under normal operating conditions or if it is in a startup or shutdown event. Degassing of a storage tank is common for shutdown of a process; the residual emissions in a storage tank are vented as part of the cleaning of the storage tank. We evaluated degassing controls as a control alternative for storage vessels and do not consider these controls to be cost effective (see memorandum Survey of Control Technology for Storage Vessels and Analysis of Impacts for Storage Vessel Control Options, Docket Item Number EPA–HQ–OAR–2010–0871–0027). Based on this review, we are not proposing specific standards for storage vessels during startup or shutdown. Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source’s operations. However, by contrast, malfunction is defined as a sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual PO 00000 Frm 00066 Fmt 4701 Sfmt 4702 manner (see 40 CFR 63.2). The EPA has determined that CAA section 112 does not require that emissions that occur during periods of malfunction be factored into development of section 112 standards. Under section 112, emissions standards for new sources must be no less stringent than the level ‘‘achieved’’ by the best-controlled similar source and for existing sources generally must be no less stringent than the average emission limitation ‘‘achieved’’ by the best-performing 12 percent of sources in the category. There is nothing in section 112 that directs the EPA to consider malfunctions in determining the level ‘‘achieved’’ by the best-performing sources when setting emission standards. As the D.C. Circuit has recognized, the phrase ‘‘average emissions limitation achieved by the best performing 12 percent of’’ sources ‘‘says nothing about how the performance of the best units is to be calculated.’’ Nat’l Ass’n of Clean Water Agencies v. EPA, 734 F.3d 1115, 1141 (D.C. Cir. 2013). While the EPA accounts for variability in setting emissions standards, nothing in section 112 requires the EPA to consider malfunctions as part of that analysis. A malfunction should not be treated in the same manner as the type of variation in performance that occurs during routine operations of a source. A malfunction is a failure of the source to perform in a ‘‘normal or usual manner’’ and no statutory language compels EPA to consider such events in setting standards based on ‘‘best performers.’’ Further, accounting for malfunctions in setting emissions standards would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category, and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not ‘‘reasonably’’ foreseeable. See, e.g., Sierra Club v. EPA, 167 F. 3d 658, 662 (D.C. Cir. 1999) (the EPA typically has wide latitude in determining the extent of data-gathering necessary to solve a problem. We generally defer to an agency’s decision to proceed on the basis of imperfect scientific information, rather than to ‘‘invest the resources to conduct the perfect study.’’). See also, Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (‘‘In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules ‘uncontrollable acts of third parties,’ such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-bycase enforcement discretion, not for specification in advance by regulation.’’). In addition, emissions during a malfunction event can be significantly higher than emissions at any other time of source operation, and thus, accounting for malfunctions in setting standards could lead to standards that are significantly less stringent than levels that are achieved by a well-performing nonmalfunctioning source. It is reasonable to interpret section 112 to avoid such a result. The EPA’s approach to malfunctions is consistent with CAA section 112 and is a reasonable interpretation of the statute. In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the goodfaith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source’s failure to comply with the CAA section 112(d) standard was, in fact, sudden, infrequent, not reasonably preventable and was not instead caused in part by poor maintenance or careless operation, as described in the definition of malfunction (see 40 CFR 63.2). Further, to the extent the EPA files an enforcement action against a source for violation of an emission standard, the source can raise any and all defenses in that enforcement action and the federal district court will determine what, if any, relief is appropriate. The same is true for citizen enforcement actions. Similarly, the presiding officer in an administrative proceeding can consider any defense raised and determine whether administrative penalties are appropriate. In several prior rules, the EPA had included an affirmative defense to civil penalties for violations caused by malfunctions in an effort to create a system that incorporates some flexibility, recognizing that there is a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission standards may be violated under circumstances entirely beyond the control of the source. Although the EPA recognized VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 that its case-by-case enforcement discretion provides sufficient flexibility in these circumstances, it included the affirmative defense to provide a more formalized approach and more regulatory clarity. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057–58 (D.C. Cir. 1978) (holding that an informal case-by-case enforcement discretion approach is adequate); but see Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272–73 (9th Cir. 1977) (requiring a more formalized approach to consideration of ‘‘upsets beyond the control of the permit holder.’’). Under the EPA’s regulatory affirmative defense provisions, if a source could demonstrate in a judicial or administrative proceeding that it had met the requirements of the affirmative defense in the regulation, civil penalties would not be assessed. Recently, the United States Court of Appeals for the District of Columbia Circuit vacated such an affirmative defense in one of the EPA’s section 112(d) regulations. NRDC v. EPA, No. 10–1371 (D.C. Cir. April 18, 2014) 2014 U.S. App. LEXIS 7281 (vacating affirmative defense provisions in section 112(d) rule establishing emission standards for Portland cement kilns). The court found that the EPA lacked authority to establish an affirmative defense for private civil suits and held that under the CAA, the authority to determine civil penalty amounts lies exclusively with the courts, not the EPA. Specifically, the Court found: ‘‘As the language of the statute makes clear, the courts determine, on a case-by-case basis, whether civil penalties are ‘appropriate.’ ’’ See NRDC, 2014 U.S. App. LEXIS 7281 at *21 (‘‘[U]nder this statute, deciding whether penalties are ‘appropriate’ in a given private civil suit is a job for the courts, not EPA.’’).41 In light of NRDC, the EPA is not including a regulatory affirmative defense provision in this rulemaking. As explained above, if a source is unable to comply with emissions standards as a result of a malfunction, the EPA may use its case-by-case enforcement discretion to provide flexibility, as appropriate. Further, as the D.C. Circuit recognized, in an EPA or citizen enforcement action, the court has the discretion to consider any defense raised and determine whether penalties are appropriate. Cf. NRDC, 2014 U.S. App. LEXIS 7281 at *24. (arguments that violation were caused by unavoidable technology failure can be 41 The court’s reasoning in NRDC focuses on civil judicial actions. The Court noted that ‘‘EPA’s ability to determine whether penalties should be assessed for Clean Air Act violations extends only to administrative penalties, not to civil penalties imposed by a court.’’ Id. PO 00000 Frm 00067 Fmt 4701 Sfmt 4702 36945 made to the courts in future civil cases when the issue arises). The same logic applies to EPA administrative enforcement actions. a. General Duty We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.6(e)(1)(i) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.6(e)(1)(i) by changing the ‘‘Yes’’ in the third column to a ‘‘No.’’ We are making this change because section 63.6(e)(1)(i) describes the general duty to minimize emissions and the current characterizes what the general duty entails during periods of SSM and that language is no longer necessary or appropriate in light of the elimination of the SSM exemption. We are proposing instead to add general duty regulatory text at 40 CFR 63.642(n) and 40 CFR 63.1570(c) that reflects the general duty to minimize emissions while eliminating the reference to periods covered by an SSM exemption. With the elimination of the SSM exemption, there is no need to differentiate between normal operations, startup and shutdown, and malfunction events in describing the general duty. Therefore the language the EPA is proposing does not include that language from 40 CFR 63.6(e)(1). We are also proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.6(e)(1)(ii) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are also proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.6(e)(1)(ii) by changing the ‘‘Yes’’ in the third column to a ‘‘No.’’ Section 63.6(e)(1)(ii) imposes requirements that are not necessary with the elimination of the SSM exemption or are redundant of the general duty requirement being added at 40 CFR 63.642(n) and 40 CFR 63.1570(c). b. SSM Plan We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entries for 63.6(e)(3)(i) and 63.6(e)(3)(iii)–63.6(e)(3)(ix) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entries for § 63.6(e)(3)(i)–(iii), § 63.6(e)(3)(iv), § 63.6(e)(3)(v)–(viii), § 63.6(e)(3)(ix) to be entries for 63.6(e)(3)(i) and 63.6(e)(3)(iii)– 63.6(e)(3)(ix) with ‘‘No’’ in the third column and § 63.6(e)(3)(ii) with ‘‘Not E:\FR\FM\30JNP2.SGM 30JNP2 36946 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Applicable’’ in the third column (that section is reserved). Generally, these paragraphs require development of an SSM plan and specify SSM recordkeeping and reporting requirements related to the SSM plan. As noted, the EPA is proposing to remove the SSM exemptions. Therefore, affected units will be subject to an emission standard during such events. The applicability of a standard during such events will ensure that sources have ample incentive to plan for and achieve compliance and thus the SSM plan requirements are no longer necessary. emcdonald on DSK67QTVN1PROD with PROPOSALS2 c. Compliance With Standards We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.6(f)(1) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.6(f)(1) by changing the ‘‘Yes’’ in the third column to a ‘‘No.’’ The current language of 40 CFR 63.6(f)(1) exempts sources from non-opacity standards during periods of SSM. As discussed above, the court in Sierra Club vacated the exemptions contained in this provision and held that the CAA requires that some section 112 standard apply continuously. Consistent with Sierra Club, the EPA is proposing to revise standards in this rule to apply at all times. We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.6(h)(1) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.6(h)(1) by changing the ‘‘Yes’’ in the third column to a ‘‘No.’’ The current language of 40 CFR 63.6(h)(1) exempts sources from opacity standards during periods of SSM. As discussed above, the court in Sierra Club vacated the exemptions contained in this provision and held that the CAA requires that some section 112 standard apply continuously. Consistent with Sierra Club, the EPA is proposing to revise standards in this rule to apply at all times. d. Performance Testing We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.7(e)(1) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.7(e)(1) by changing the ‘‘Yes’’ in the third column VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 to a ‘‘No.’’ Section 63.7(e)(1) describes performance testing requirements. The EPA is instead proposing to add performance testing requirements at 40 CFR 63.642(d)(3) and 40 CFR 63.1571(b)(1). The performance testing requirements we are proposing differ from the General Provisions performance testing provisions in several respects. The regulatory text does not include the language in 40 CFR 63.7(e)(1) that restated the SSM exemption. The regulatory text also does not preclude startup and shutdown periods from being considered ‘‘representative’’ for purposes of performance testing, however, the testing. However, the specific testing provisions proposed at 40 CFR 63.642(d)(3) and 40 CFR 63.1571(b)(1) do not allow performance testing during startup or shutdown. As in 40 CFR 63.7(e)(1), performance tests conducted under this subpart may not be conducted during malfunctions because conditions during malfunctions are often not representative of normal operating conditions. The EPA is proposing to add language that requires the owner or operator to record the process information that is necessary to document operating conditions during the test and include in such record an explanation to support that such conditions represent normal operation. Section 63.7(e) requires that the owner or operator make available to the Administrator such records ‘‘as may be necessary to determine the condition of the performance test’’ available to the Administrator upon request, but does not specifically require the information to be recorded. The regulatory text EPA is proposing to add to Refinery MACT 1 and 2 builds on that requirement and makes explicit the requirement to record the information. e. Monitoring We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entries for 63.8(c)(1)(i) and 63.8(c)(1)(iii) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.8(c)(1)(i) and § 63.8(c)(1)(iii) by changing the ‘‘Yes’’ in the third column to a ‘‘No.’’ The cross-references to the general duty and SSM plan requirements in those subparagraphs are not necessary in light of other requirements of 40 CFR 63.8 that require good air pollution control practices (40 CFR 63.8(c)(1)) and that set out the requirements of a quality control program for monitoring equipment (40 CFR 63.8(d)). PO 00000 Frm 00068 Fmt 4701 Sfmt 4702 We are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.8(d) to include separate entries for specific paragraphs of 40 CFR 63.8(d), including an entry for § 63.10(d)(3) with ‘‘No’’ in the third column. The final sentence in 40 CFR 63.8(d)(3) refers to the General Provisions’ SSM plan requirement which is no longer applicable. The EPA is proposing to add to the rule at 40 CFR 63.1576(b)(3) text that is identical to 40 CFR 63.8(d)(3) except that the final sentence is replaced with the following sentence: ‘‘The program of corrective action should be included in the plan required under § 63.8(d)(2).’’ f. Recordkeeping We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.10(b)(2)(i) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Section 63.10(b)(2)(i) describes the recordkeeping requirements during startup and shutdown. These recording provisions are no longer necessary because the EPA is proposing that recordkeeping and reporting applicable to normal operations will apply to startup and shutdown. In the absence of special provisions applicable to startup and shutdown, such as a startup and shutdown plan, there is no reason to retain additional recordkeeping for startup and shutdown periods. We are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.10(b) to include separate entries for specific paragraphs of 40 CFR 63.10(b), including an entry for § 63.10(b)(2)(i) with ‘‘No’’ in the third column. Section 63.10(b)(2)(i) describes the recordkeeping requirements during startup and shutdown. We are instead proposing to add recordkeeping requirements to 40 CFR 63.1576(a)(2). When a source is subject to a different standard during startup and shutdown, it will be important to know when such startup and shutdown periods begin and end in order to determine compliance with the appropriate standard. Thus, the EPA is proposing to add language to 40 CFR 63.1576(a)(2) requiring that sources subject to an emission standard during startup or shutdown that differs from the emission standard that applies at all other times must record the date, time, and duration of such periods. We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.10(b)(2)(ii) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are proposing to revise the 40 CFR part 63, E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules subpart UUU General Provisions table (Table 44) entry for § 63.10(b) to include separate entries for specific paragraphs of 40 CFR 63.10(b), including an entry for § 63.10(b)(2)(ii) with ‘‘No’’ in the third column. Section 63.10(b)(2)(ii) describes the recordkeeping requirements during a malfunction. The EPA is proposing to add such requirements to 40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2). The regulatory text we are proposing to add differs from the General Provisions language that was cross-referenced, which provides the creation and retention of a record of the occurrence and duration of each malfunction of process, air pollution control, and monitoring equipment. The proposed text would apply to any failure to meet an applicable standard and would require the source to record the date, time, and duration of the failure. The EPA is also proposing to add to 40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2) a requirement that sources keep records that include a list of the affected source or equipment and actions taken to minimize emissions, an estimate of the quantity of each regulated pollutant emitted over the standard for which the source failed to meet a standard, and a description of the method used to estimate the emissions. Examples of such methods would include productloss calculations, mass balance calculations, measurements when available, or engineering judgment based on known process parameters. The EPA is proposing to require that sources keep records of this information to ensure that there is adequate information to allow the EPA to determine the severity of any failure to meet a standard, and to provide data that may document how the source met the general duty to minimize emissions when the source has failed to meet an applicable standard. We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.10(b)(2)(iv) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.10(b) to include separate entries for specific paragraphs of 40 CFR 63.10(b), including an entry for § 63.10(b)(2)(iv)–(v) with ‘‘No’’ in the third column. When applicable, 40 CFR 63.10(b)(2)(iv) requires sources to record actions taken during SSM events when actions were inconsistent with their SSM plan. The requirement is no longer appropriate because SSM plans will no longer be required. The requirement previously applicable under 40 CFR VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 63.10(b)(2)(iv)(B) to record actions to minimize emissions and record corrective actions is now applicable by reference to 40 CFR 63.655(i)(11)(iii) and 40 CFR 63.1576(a)(2)(iii). We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entry for 63.10(b)(2)(v) by changing the ‘‘Yes’’ in the second column to a ‘‘No.’’ Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.10(b) to include separate entries for specific paragraphs of 40 CFR 63.10(b), including an entry for § 63.10(b)(2)(iv)–(v) with ‘‘No’’ in the third column. When applicable, 40 CFR 63.10(b)(2)(v) requires sources to record actions taken during SSM events to show that actions taken were consistent with their SSM plan. The requirement is no longer appropriate because SSM plans would no longer be required. We are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entry for § 63.10(c)(9)–(15) to include separate entries for specific paragraphs of 40 CFR 63.10(c), including an entry for § 63.10(c)(15) with ‘‘No’’ in the third column. The EPA is proposing that 40 CFR 63.10(c)(15) no longer apply. When applicable, the provision allows an owner or operator to use the affected source’s SSM plan or records kept to satisfy the recordkeeping requirements of the SSM plan, specified in 40 CFR 63.6(e), to also satisfy the requirements of 40 CFR 63.10(c)(10) through (12). The EPA is proposing to eliminate this requirement because SSM plans would no longer be required, and therefore 40 CFR 63.10(c)(15) no longer serves any useful purpose for affected units. g. Reporting We are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a ‘‘No’’ in the second column. Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a ‘‘No’’ in the third column. Section 63.10(d)(5) describes the reporting requirements for startups, shutdowns, and malfunctions. To replace the General Provisions reporting requirement, the EPA is proposing to add reporting requirements to 40 CFR 63.655(g)(12), 40 CFR 63.1575(c)(4), 40 CFR 63.1575(d), and 40 CFR 63.1575(e). The General Provisions requirement that was cross-referenced requires periodic SSM reports as a stand-alone report. In PO 00000 Frm 00069 Fmt 4701 Sfmt 4702 36947 its place, we are proposing language that requires sources that fail to meet an applicable standard at any time to report the information concerning such events in the periodic report already required under each of these rules. We are proposing that the report must contain the number, date, time, duration, and the cause of such events (including unknown cause, if applicable), a list of the affected source or equipment, an estimate of the quantity of each regulated pollutant emitted over any emission limit, and a description of the method used to estimate the emissions. Examples of methods that can be used to estimate emissions would include product-loss calculations, mass balance calculations, measurements when available, or engineering judgment based on known process parameters. The EPA is proposing this requirement to ensure that there is adequate information to determine compliance, to allow the EPA to determine the severity of the failure to meet an applicable standard, and to provide data that may document how the source met the general duty to minimize emissions during a failure to meet an applicable standard. We will no longer require owners or operators to determine whether actions taken to correct a malfunction are consistent with an SSM plan, because SSM plans would no longer be required. The proposed rule eliminates the crossreference to 40 CFR 63.10(d)(5)(i) that contains the description of the previously required SSM report format and submittal schedule from this section. These specifications are no longer necessary because the events will be reported in otherwise required reports with similar format and submittal requirements. As noted above, we are proposing to revise the 40 CFR part 63, subpart CC General Provisions table (Table 6) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a ‘‘No’’ in the second column. Similarly, we are proposing to revise the 40 CFR part 63, subpart UUU General Provisions table (Table 44) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a ‘‘No’’ in the third column. Section 63.10(d)(5)(ii) describes an immediate report for startups, shutdown, and malfunctions when a source fails to meet an applicable standard but does not follow the SSM plan. We are proposing to no longer require owners and operators to report when actions taken during a startup, shutdown, or malfunction were not consistent with an SSM plan, E:\FR\FM\30JNP2.SGM 30JNP2 36948 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 because such plans would no longer be required. 2. Electronic Reporting In this proposal, the EPA is describing a process to increase the ease and efficiency of performance test data submittal while improving data accessibility. Specifically, the EPA is proposing that owners and operators of petroleum refineries submit electronic copies of required performance test and performance evaluation reports by direct computer-to-computer electronic transfer using EPA-provided software. The direct computer-to-computer electronic transfer is accomplished through the EPA’s Central Data Exchange (CDX) using the Compliance and Emissions Data Reporting Interface (CEDRI). The CDX is EPA’s portal for submittal of electronic data. The EPAprovided software is called the Electronic Reporting Tool (ERT) which is used to generate electronic reports of performance tests and evaluations. The ERT generates an electronic report package which will be submitted using the CEDRI. The submitted report package will be stored in the CDX archive (the official copy of record) and the EPA’s public database called WebFIRE. All stakeholders will have access to all reports and data in WebFIRE and accessing these reports and data will be very straightforward and easy (see the WebFIRE Report Search and Retrieval link at https:// cfpub.epa.gov/webfire/ index.cfm?action=fire.search ERTSubmission). A description and instructions for use of the ERT can be found at https://www.epa.gov/ttn/chief/ ert/ and CEDRI can be accessed through the CDX Web site (www.epa.gov/cdx). A description of the WebFIRE database is available at: https:// cfpub.epa.gov/oarweb/index.cfm? action=fire.main. The proposal to submit performance test data electronically to the EPA applies only to those performance tests (and/or performance evaluations) conducted using test methods that are supported by the ERT. The ERT supports most of the commonly used EPA reference methods. A listing of the pollutants and test methods supported by the ERT is available at: https:// www.epa.gov/ttn/chief/ert/. We believe that industry would benefit from this proposed approach to electronic data submittal. Specifically, by using this approach, industry will save time in the performance test submittal process. Additionally, the standardized format that the ERT uses allows sources to create a more complete test report resulting in less VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 time spent on data backfilling if a source failed to include all data elements required to be submitted. Also through this proposal industry may only need to submit a report once to meet the requirements of the applicable subpart because stakeholders can readily access these reports from the WebFIRE database. This also benefits industry by cutting back on recordkeeping costs as the performance test reports that are submitted to the EPA using CEDRI are no longer required to be retained in hard copy, thereby reducing staff time needed to coordinate these records. Since the EPA will already have performance test data in hand, another benefit to industry is that fewer or less substantial data collection requests in conjunction with prospective required residual risk assessments or technology reviews will be needed. This would result in a decrease in staff time needed to respond to data collection requests. State, local and tribal air pollution control agencies (S/L/Ts) may also benefit from having electronic versions of the reports they are now receiving. For example, S/L/Ts may be able to conduct a more streamlined and accurate review of electronic data submitted to them. For example, the ERT would allow for an electronic review process, rather than a manual data assessment, therefore, making review and evaluation of the source provided data and calculations easier and more efficient. In addition, the public stands to benefit from electronic reporting of emissions data because the electronic data will be easier for the public to access. How the air emissions data are collected, accessed and reviewed will be more transparent for all stakeholders. One major advantage of the proposed submittal of performance test data through the ERT is a standardized method to compile and store much of the documentation required to be reported by this rule. The ERT clearly states what testing information would be required by the test method and has the ability to house additional data elements that might be required by a delegated authority. In addition the EPA must have performance test data to conduct effective reviews of CAA sections 111 and 112 standards, as well as for many other purposes including compliance determinations, emission factor development and annual emission rate determinations. In conducting these required reviews, the EPA has found it ineffective and time consuming, not only for us, but also for regulatory agencies and source owners and operators, to locate, collect and submit PO 00000 Frm 00070 Fmt 4701 Sfmt 4702 performance test data. In recent years, stack testing firms have typically collected performance test data in electronic format, making it possible to move to an electronic data submittal system that would increase the ease and efficiency of data submittal and improve data accessibility. A common complaint heard from industry and regulators is that emission factors are outdated or not representative of a particular source category. With timely receipt and incorporation of data from most performance tests, the EPA would be able to ensure that emission factors, when updated, represent the most current range of operational practices. Finally, another benefit of the proposed data submittal to WebFIRE electronically is that these data would greatly improve the overall quality of existing and new emissions factors by supplementing the pool of emissions test data for establishing emissions factors. 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 would save industry, state, local and tribal agencies and the EPA significant time, money and effort while also improving the quality of emission inventories and air quality regulations. In addition, we are proposing that the fenceline data at each monitor location (as proposed above) would be reported electronically on a semiannual basis. All data reported electronically would be submitted to CDX through CEDRI and made available to the public. 3. Technical Amendments to Refinery MACT 1 and 2 a. Open-Ended Valves and Lines Refinery MACT 1 requires an owner or operator to control emissions from equipment leaks according to the requirements of either 40 CFR part 60, subpart VV or 40 CFR part 63, subpart H. For open-ended valves and lines, both subparts require that the open end be equipped with a cap, blind flange, plug or second valve that ‘‘shall seal the open end at all times.’’ However, neither subpart defines ‘‘seal’’ or explains in practical and enforceable terms what constitutes a sealed open-ended valve or line. This has led to uncertainty on the part of the owner or operator as to whether compliance is being achieved. Inspections under the EPA’s Air Toxics LDAR initiative have provided evidence that while certain open-ended lines may be equipped with a cap, blind flange, plug or second valve, they are not E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules operating in a ‘‘sealed’’ manner as the EPA interprets that term. In response to this uncertainty, we are proposing to amend 40 CFR 63.648 to clarify what is meant by ‘‘seal.’’ This proposed amendment clarifies that, for the purpose of complying with the requirements of 40 CFR 63.648, openended valves and lines are ‘‘sealed’’ by the cap, blind flange, plug, or second valve when there are no detectable emissions from the open-ended valve or line at or above an instrument reading of 500 ppm. We solicit comment on this approach to reducing the compliance uncertainty associated with open-ended valves and lines and our proposed amendment. emcdonald on DSK67QTVN1PROD with PROPOSALS2 b. General Provisions Cross-Referencing We have reviewed the application of 40 CFR part 63, subpart A (General Provisions) to Refinery MACT 2. The applicable requirements of 40 CFR part 63, subpart A are contained in Table 44 of 40 CFR part 63, subpart UUU. As a result of our review, we are proposing several amendments to Table 44 of 40 CFR part 63, subpart UUU (in addition to those discussed in section IV.E.1 of this preamble that address SSM) to bring the table up-to-date with requirements of the General Provisions that have been amended since this table was created, to correct cross-references, and to incorporate additional sections of the General Provisions that are necessary to implement other subparts that are cross-referenced by this rule. Although we reviewed the application of the General Provisions to Refinery MACT 1 and amended Table 6 of 40 CFR part 63, subpart CC in 2009, we are proposing a few additional technical corrections to this table (in addition to those discussed in section IV.E.1 of this preamble that address SSM). We are not discussing the details of these proposed technical corrections in this preamble but the rationale for each change to Table 6 of 40 CFR part 63, subpart CC and Table 44 of 40 CFR part 63, subpart UUU (including the proposed amendments to address SSM discussed above), is included in Docket ID Number EPA–HQ–OAR–2010–0682. 4. Amendments to Refinery NSPS J and Ja As discussed in section II.B.2 of this preamble, we are addressing a number of technical corrections and clarifications for Refinery NSPS J and Ja to address some of the issues raised in the petition for reconsideration and to improve consistency and clarity of the rule requirements. These issues are addressed in detail in API’s amended petition, dated August 21, 2008 (see VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 Docket Item Number EPA–HQ–OAR– 2007–0011–0246) and the meeting minutes for a September 11, 2008 meeting between EPA and API (see Docket Item Number EPA–HQ–OAR– 2007–0011–0266). a. The Depressurization Work Practice Standard for Delayed Coking Units HOVENSA and the Industry Petitioners raised several issues with the analysis conducted to support the DCU work practice standard in Refinery NSPS Ja. With the promulgation and implementation of the standards we are proposing for the DCU under Refinery MACT 1, the DCU work practice standards in Refinery NSPS Ja are not expected to result in any further decreases in emissions from the DCU. Any DCU that becomes subject to Refinery NSPS Ja would already be in compliance with Refinery MACT 1, which is a more stringent standard than the DCU work practice standards in Refinery NSPS Ja. As such, we are contemplating various ideas for harmonizing the requirements for the DCU in these two regulations. One option is to amend Refinery NSPS Ja to incorporate the same requirements being proposed for Refinery MACT 1 (the DCU work practice standard in Refinery NSPS Ja is less stringent than the proposed requirements for Refinery MACT 1). Another option we are contemplating is deleting the DCU work practice standard within Refinery NSPS Ja once the DCU standards in Refinery MACT 1 are promulgated and fully implemented. We believe deletion of this work practice standard is consistent with the objectives of Executive Order 13563, ‘‘Improving Regulation and Regulatory Review.’’ We solicit comment on these options as well as any other comments regarding the interaction between the DCU requirements in these two rules (i.e., the need to keep the DCU work practice standard in Refinery NSPS Ja after promulgation of these revisions to Refinery MACT 1.) b. Technical Corrections and Clarifications In addition to their primary issues, the Industry Petitioners enumerated several points of clarification and recommended amendments to Refinery NSPS J and Ja. These issues are addressed in detail in API’s amended petition for reconsideration, dated August 21, 2008 (see Docket Item Number EPA–HQ–OAR–2007–0011– 0246) and the meeting minutes for a September 11, 2008 meeting between EPA and API (see Docket Item Number EPA–HQ–OAR–2007–0011–0266). We PO 00000 Frm 00071 Fmt 4701 Sfmt 4702 36949 are including several proposed amendments in this rulemaking to specifically address these issues. These amendments are discussed in the remainder of this section. We are addressing these issues now while we are proposing amendments for Refinery MACT 2 in an effort to improve consistency and clarity for sources regulated under both the NSPS and Refinery MACT 2. We are proposing a series of amendments to the requirements for sulfur recovery plants in 40 CFR 60.102a, to clarify the applicable emission limits for different types of sulfur recovery plants based on whether oxygen enrichment is used. These amendments also clarify that emissions averaging across a group of emission points within a given sulfur recovery plant is allowed from each of the different types of sulfur recovery plants, and that emissions averaging is specific to the SO2 or reduced sulfur standards (and not to the H2S limit). The 10 ppmv H2S limit for reduction control systems not followed by incineration must be met on a release point-specific basis. These amendments are being made to clarify the original intent of the Refinery NSPS Ja requirements for sulfur recovery plants. We are proposing a series of corresponding amendments in 40 CFR 60.106a to clarify the monitoring requirements, particularly when oxygen enrichment or emissions averaging is used. The monitoring requirements in Refinery NSPS Ja were incomplete for these provisions and did not specify all of the types of monitoring devices needed for implementation. We are also proposing in 40 CFR 60.106a to 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. The term ‘‘reduced sulfur compounds’’ is a defined term in Refinery NSPS Ja, and the emissions limit for sulfur recovery plants with reduction control systems not followed by incineration is specific to ‘‘reduced sulfur compounds.’’ Therefore, the proposed amendments to the monitoring provisions provide clarification of the requirements by using a consistent, defined term. We are proposing amendments to 40 CFR 60.102a(g)(1) to clarify that CO boilers, while part of the FCCU affected facility, can also be fuel gas combustion devices (FGCD). Industry Petitioners suggested that the CO boiler should only be subject to the FCCU NOX and SO2 E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36950 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules limits and should not be considered a FGCD. While Refinery NSPS Ja clearly states that the coke burn-off exhaust from the FCCU catalyst regenerator is not considered to be fuel gas, other fuels combusted in the CO boiler must meet the H2S concentration requirements for fuel gas like any other FGCD. This amendment is provided to clarify our original intent with respect to fuel gas. Industry Petitioners also noted that some CO boiler ‘‘furnaces’’ may be used as process heaters rather than steamgenerating boilers. While we did not originally contemplate that CO furnaces would be used as process heaters, available data from the detailed ICR suggests that there are a few CO furnaces used as process heaters. These CO furnaces are all forced-draft process heaters, and the newly amended NOX emissions limit in Refinery NSPS Ja for forced-draft process heaters is 60 ppmv, averaged over a 30-day period. Given the longer averaging time of the process heater NOX limits, these two emission limits (for FCCU NOX and for process heater NOX) are reasonably comparable and are not expected to result in a significant difference in the control systems selected for compliance. As such, we are not amending or clarifying the NOX standards for the FCCU or process heaters at this time. We are, however, clarifying (through this response) that if an emission source meets the definition of more than one affected facility, that source would need to comply with all requirements applicable to the emissions source. We are proposing to revise the annual testing requirement in 40 CFR 60.104a(b) to clarify our original intent. Instead of requiring a PM performance test at least once every 12 months, the rule would require a PM performance test annually and specify that annually means once per calendar year, with an interval of at least 8 months but no more than 16 months between annual tests. This provision will ensure that testing is conducted at a reasonable interval while giving owners and operators flexibility in scheduling the testing. We are also proposing 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 per coke burn-off emissions limit (rather than just the PM limit) in 40 CFR 60.102a(b)(1), to clarify that facilities electing to comply with the concentration limit using a PM CEMS would not also be required to install a COMS. We are also proposing to amend 40 CFR 60.104a(j) to delete the requirements to measure flow for the VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 H2S concentration limit for fuel gas, as these are not needed in the performance evaluation. We are proposing 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 are also proposing amendments to 40 CFR 60.105a(i) to include 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. These proposed amendments are necessary so that periods when the APCD operation is compromised are properly managed and/or reported. We are proposing amendments to 40 CFR 60.105(b)(1)(iv) and 60.107a(b)(1)(iv) to allow using tubes with a maximum span between 10 and 40 ppmv, inclusive, when 1≤N≤10, where N = number of pump strokes rather than requiring use of tubes with ranges 0–10/0–100 ppm (N = 10/1) because different length-of-stain tube manufacturers have different span ranges, and none of the commerciallyavailable tubes have a specific span of 0–10/0–100 ppm (N = 10/1). We are also proposing to amend 40 CFR 60.105(b)(3)(iii) and 40 CFR 60.107a(b)(3)(iii) to specify that the temporary daily stain sampling must be made 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. This proposed amendment clarifies this monitoring requirement, ensures the proper tube range is used, and provides some flexibility in span range to accommodate different manufacturers of the length-of-stain tubes. We also propose to delete the last sentence in 40 CFR 60.105(b)(3)(iii), as there is no longterm H2S concentration limit in Refinery NSPS J. We are proposing to clarify that flares are subject to the performance test requirements. We are also proposing to clarify those performance test requirements in 40 CFR 60.107a(e)(1)(ii) and 40 CFR 60.107a(e)(2)(ii) to remove the distinction between flares with or without routine flow. The term ‘‘routine flow’’ is not defined and it is difficult to make this distinction in practice. PO 00000 Frm 00072 Fmt 4701 Sfmt 4702 F. What compliance dates are we proposing? Amendments to Refinery MACT 1 and 2 proposed in this rulemaking for adoption under CAA section 112(d)(2) and (3) and CAA section 112(d)(6) are subject to the compliance deadlines outlined in the CAA under section 112(i). For all of the requirements we are proposing under CAA section 112(d)(2) and (3) or CAA section 112(d)(6) except for storage vessels, which we are also requiring under 112 (f)(2), we are proposing the following compliance dates. As provided in CAA section 112(i), new sources would be required to comply with these requirements by the effective date of the final amendments to Refinery MACT 1 and 2 or startup, whichever is later. For existing sources, CAA section 112(i) provides that the compliance date shall be as expeditiously as practicable, but no later than 3 years after the effective date of the standard. In determining what compliance period is as expeditious as practicable, we consider the amount of time needed to plan and construct projects and change operating procedures. Under CAA section 112(d)(2) and (3), we are proposing new operating requirements for DCU. In order to comply with these new requirements, we project that most DCU owners or operators would need to install additional controls (e.g., steam ejector systems). Similarly, the proposed revision in the CRU pressure limit exclusions would require operational changes and, in some cases, additional controls. The addition of new control equipment would require engineering design, solicitation and review of vendor quotes, contracting and installation of the equipment, which would need to be timed with process unit outage and operator training. Therefore, we are proposing that it is necessary to provide 3 years after the effective date of the final rule for these sources to comply with the DCU and CRU requirements. We are proposing new operating and monitoring requirements for flares under CAA section 112(d)(2) and (3). We anticipate that these requirements would require the installation of new flare monitoring equipment and we project most refineries would install new control systems to monitor and adjust assist gas (air or steam) addition rates. Similar to the addition of new control equipment, these new monitoring requirements for flares would require engineering evaluations, solicitation and review of vendor quotes, contracting and installation of the equipment, and operator training. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Installation of new monitoring and control equipment on flares will require the flare to be taken out of service. Depending on the configuration of the flares and flare header system, taking the flare out of service may also require a significant portion of the refinery operations to be shut down. Therefore, we are proposing that it is necessary to provide 3 years after the effective date of the final rule for owners or operators to comply with the new operating and monitoring requirements for flares. Under CAA section 112(d)(2) and (3), we are proposing new vent control requirements for bypasses. These requirements would typically require the addition of piping and potentially new control requirements. As these vent controls would most likely be routed to the flare, we are proposing to provide 3 years after the effective date of the final rule for owners or operators to afford coordination of these bypass modifications with the installation of the new monitoring equipment for the flares. Under our technology review, we are proposing to require fenceline monitoring pursuant to CAA section 112(d)(6). These proposed provisions would require refinery owners or operators to install a number of monitoring stations around the facility fenceline. While the diffusive tube sampling system is relatively low-tech and is easy to install, site-specific factors must be considered in the placement of the monitoring systems. We also assume all refinery owners or operators would invest in the analytical equipment needed to perform automated sample analysis on-site and time is needed to select an appropriate vendor for this equipment. Furthermore, additional monitoring systems may be needed to account for near-field contributing sources, for which the development and approval of a sitespecific monitoring plan. Considering all of the requirements needed to implement the fenceline monitoring system, we are proposing to provide 3 years from the effective date of the final rule for refinery owners or operators to install and begin collecting ambient air samples around the fenceline of their facility following an approved (if necessary) site-specific monitoring plan. As a result of our technology review for equipment leaks, we are proposing to allow the use of optical gas imaging devices in lieu of using EPA Method 21 of 40 CFR part 60, Appendix A–7 without the annual compliance demonstration with EPA Method 21 as required in the AWP (see 73 FR 73202, December 22, 2008), provided that the owner and operator follows the VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 provisions of Appendix K to 40 CFR part 60. Facilities could begin to comply with the optical gas imaging alternative as soon as Appendix K to 40 CFR part 60 is promulgated. Alternatively, as is currently provided in the AWP, the refinery owner or operator can elect to use the optical gas imaging monitoring option prior to installation and use of the fenceline monitoring system, provided they conduct an annual compliance demonstration using EPA Method 21 as required in the AWP. Under our technology review for marine vessel loading operations, we are proposing to add a requirement for submerged filling for small and for offshore marine vessel loading operations. We anticipate that the submerged fill pipes are already in place on all marine vessels used to transport petroleum refinery liquids, so we are proposing that existing sources comply with this requirement on the effective date of the final rule. We request comment regarding the need to provide additional time to comply with the submerged filling requirement; please provide in your comment a description of the vessels loaded that do not already have a submerged fill pipe, how these vessels comply with (or are exempt from) the Coast Guard requirements at 46 CFR 153.282, and an estimate of the time needed to add the required submerged fill pipes to these vessels. We are also proposing to require FCCU owners and operators currently subject to Refinery NSPS J (or electing that compliance option in Refinery MACT 2) to transition from the Refinery NSPS J option to one of the alternatives included in the proposed rule. We are also proposing altering the averaging times for some of the operating limits. A PM performance test is needed in order to establish these new operating limits prior to transitioning to the proposed requirements. Additionally, we are proposing that a PM performance test be conducted for each FCCU once every 5 years. We do not project any new control or monitoring equipment will be needed in order to comply with the proposed provisions; however, compliance with the proposed provisions is dependent on conducting a performance test. Establishing an early compliance date for the first performance test can cause scheduling issues as refinery owners or operators compete for limited number of testing contractors. Considering these scheduling issues, we propose to require the first performance test for PM and compliance with the new operating limits be completed no later than 18 months after the effective date of the final rule. PO 00000 Frm 00073 Fmt 4701 Sfmt 4702 36951 In this action, we are proposing revisions to the SSM provisions of Refinery MACT 1 and 2, including specific startup or shutdown standards for certain emission sources, and we are proposing electronic reporting requirements in Refinery MACT 1 and 2. The proposed monitoring requirements associated with the new startup and shutdown standards are expected to be present on the affected source, so we do not expect that owners or operators will need additional time to transition to these requirements. Similarly, the electronic reporting requirements are not expected to require a significant change in operation or equipment, so these requirements should be able to be implemented more quickly than those that require installation of new control or monitoring equipment. Based on our review of these requirements, we propose that these requirements become effective upon the effective date of the final rule. Finally, we are proposing additional requirements for storage vessels under CAA sections 112(d)(6) and (f)(2). The compliance deadlines for standards developed under CAA section 112(f)(2) are delineated in CAA sections 112(f)(3) and (4). As provided in CAA section 112(f)(4), risk standards shall not apply to existing sources until 90 days after the effective date of the rule, but the Administrator may grant a waiver for a particular source for a period of up to 2 years after the effective date. While additional controls will be necessary to comply with the proposed new control and fitting requirements for storage vessels, the timing for installation of these controls is specified within the Generic MACT (40 CFR part 63, subpart WW). Therefore, we propose that these new requirements for storage vessels become effective 90 days following the effective date of the final rule. V. Summary of Cost, Environmental and Economic Impacts A. What are the affected sources, the air quality impacts and cost impacts? The sources affected by significant amendments to the petroleum refinery standards include storage vessels, equipment leaks, fugitive emissions and DCU subject to Refinery MACT 1. The proposed 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 proposed amendments and standards is estimated at $239 million, $82.8 million from proposed amendments and $156 million from E:\FR\FM\30JNP2.SGM 30JNP2 36952 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules standards to ensure compliance. We estimate annualized costs to be approximately $4.53 million, which includes an estimated $14.4 million credit for recovery of lost product and the annualized cost of capital. We also estimate annualized costs of the summarizes the cost and emission reduction impacts of the proposed amendments, and Table 14 of this preamble summarizes the costs of the proposed standards to ensure compliance. proposed standards to ensure compliance to be approximately $37.9 million. The proposed amendments would achieve a nationwide HAP emission reduction of 1,760 tpy, with a concurrent reduction in VOC emissions of 18,800 tpy. Table 13 of this preamble TABLE 13—NATIONWIDE IMPACTS OF PROPOSED AMENDMENTS Total capital investment (million $) Affected source Total annualized cost without credit (million $/yr) Product recovery credit (million $/yr) Total annualized costs (million $/yr) VOC emission reductions (tpy) Cost effectiveness ($/ton VOC) HAP emission reductions (tpy) Cost effectiveness ($/ton HAP) Storage Vessels .......................... Delayed Coking Units ................. Fugitive Emissions (Fenceline Monitoring) ............................... 18.5 52.0 3.13 10.2 (8.16) (6.20) (5.03) 3.98 14,600 4,250 (345) 937 910 850 (5,530) 4,680 12.2 5.58 ............................ 5.58 ............................ ............................ ............................ ............................ Total ..................................... 82.8 (14.4) 4.53 18,800 241 1,760 2,570 18.9 TABLE 14—NATIONWIDE COSTS OF PROPOSED AMENDMENTS TO ENSURE COMPLIANCE emcdonald on DSK67QTVN1PROD with PROPOSALS2 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 1.36 36.3 0.21 ........................ ........................ ........................ 156 Total .................................................................................................... 42 The flare operational and monitoring requirements are projected to reduce methane emissions by 29,500 tpy while increasing CO2 emissions by 260,000 tpy, resulting in a net GHG reduction of 327,000 metric tonnes per year of CO2e, assuming a global warming potential of 21 for methane. Combined with methane emissions reduction of 18,000 tpy from the proposed controls on DCU, the overall GHG reductions of the proposed amendments is 670,000 metric tonnes per year of CO2e assuming a global warming potential of 21 for methane. Product recovery credit (million $/yr) 9.54 147 — Relief Valve Monitoring .............................................................................. Flare Monitoring ......................................................................................... FCCU Testing ............................................................................................ Note that any corrective actions taken in response to the fenceline monitoring program are not included in the impacts shown in Table 13. Any corrective actions associated with fenceline monitoring will result in additional emission reductions and additional costs. The impacts shown in Table 14 do not consider emission reductions associated with relief valve or flare monitoring provisions or emission reductions that may occur as a result of the additional FCCU testing requirements. The proposed operational and monitoring requirements for flares at refineries have the potential to reduce excess emissions from flares by approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 327,000 metric tonnes per year of CO2e. When added to the reductions in CO2e achieved from proposed controls on DCU, these proposed amendments are projected to result in reductions of 670,000 metric tonnes of CO2e due to reductions of methane emissions.42 Total annualized cost without credit (million $/yr) 37.9 Total capital investment (million $) Affected source — Total annualized costs (million $/yr) 1.36 36.3 0.21 37.9 B. What are the economic impacts? C. What are the benefits? We performed a national economic impact analysis for petroleum product producers. All petroleum product refiners will incur annual compliance costs of much 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 are 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 proposed rule (Docket ID Number EPA– HQ–OAR–2010–0682). The proposed rule is anticipated to result in a reduction of 1,760 tons of HAP (based on allowable emissions under the MACT standards) and 18,800 tons of VOC emissions per year, not including potential emission reductions that may occur as a result of the proposed provisions for flares or 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. PO 00000 Frm 00074 Fmt 4701 Sfmt 4702 VI. Request for Comments We solicit comments on all aspects of this proposed action. In addition to general comments on this proposed action, we are also interested in additional data that may improve the risk assessments and other analyses. We are specifically interested in receiving any improvements to the data used in the site-specific emissions profiles used for risk modeling. Such data should include supporting documentation in sufficient detail to allow characterization of the quality and representativeness of the data or information. Section VII of this preamble provides more information on submitting data. E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules VII. Submitting Data Corrections The site-specific emissions profiles used in the source category risk and demographic analyses and instructions are available on the RTR Web page at: https://www.epa.gov/ttn/atw/rrisk/ rtrpg.html. The data files include detailed information for each HAP emissions release point for the facilities in the source categories. If you believe that the data are not representative or are inaccurate, please identify the data in question, provide your reason for concern and provide any ‘‘improved’’ data that you have, if available. When you submit data, we request that you provide documentation of the basis for the revised values to support your suggested changes. To submit comments on the data downloaded from the RTR page, complete the following steps: 1. Within this downloaded file, enter suggested revisions to the data fields appropriate for that information. 2. Fill in the commenter information fields for each suggested revision (i.e., commenter name, commenter organization, commenter email address, commenter phone number and revision comments). 3. Gather documentation for any suggested emissions revisions (e.g., performance test reports, material balance calculations). 4. Send the entire downloaded file with suggested revisions in Microsoft® Access format and all accompanying documentation to Docket ID Number EPA–HQ–OAR–2010–0682 (through one of the methods described in the ADDRESSES section of this preamble). 5. If you are providing comments on a single facility or multiple facilities, you need only submit one file for all facilities. The file should contain all suggested changes for all sources at that facility. We request that all data revision comments be submitted in the form of updated Microsoft® Excel files that are generated by the Microsoft® Access file. These files are provided on the RTR Web page at: https://www.epa.gov/ttn/ atw/rrisk/rtrpg.html. emcdonald on DSK67QTVN1PROD with PROPOSALS2 VIII. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review Under Executive Order 12866 (58 FR 51735, October 4, 1993), this action is a ‘‘significant regulatory action’’ because it raises novel legal and policy issues. Accordingly, the EPA submitted this action to the Office of Management and Budget (OMB) for review under VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes made in response to OMB recommendations have been documented in the docket for this action (Docket ID Number EPA–HQ–OAR– 2010–0682). B. Paperwork Reduction Act The information collection requirements in this rule have been submitted for approval to OMB under the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. Revisions and burden associated with amendments to 40 CFR part 63, subparts CC and UUU are discussed in the following paragraphs. OMB has previously approved the information collection requirements contained in the existing regulations in 40 CFR part 63, subparts CC and UUU under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501, et seq., OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. Burden is defined at 5 CFR 1320.3(b). 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 53,619 hours; the frequency of response is semiannual for all 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 $17 million, which includes monitoring equipment for bypass valves, fenceline monitoring, relief valves, and flares), a total operation and maintenance component (about $16 million per year for fenceline and flare monitoring), and a labor cost component (about $4.5 million per year, the cost of the additional 53,619 labor hours). 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 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 1844.07. Burden changes associated with these PO 00000 Frm 00075 Fmt 4701 Sfmt 4702 36953 amendments would result from new testing, recordkeeping and reporting requirements being proposed with this action. The estimated average burden per response is 26 hours; the frequency of response is both once and 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 $356,000 per year over the first 3 years for the initial performance test and $213,000 per year starting in the fourth year), and a labor cost component (approximately $238,000 per year for 2,860 additional labor hours). 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. To comment on the agency’s need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, the EPA has established a public docket for this rule, which includes the ICR, under Docket ID Number EPA–HQ–OAR–2010–0682. Submit any comments related to the ICR to the EPA and OMB. See the ADDRESSES section at the beginning of this preamble for where to submit comments to the EPA. Send comments to OMB at the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention: Desk Office for the EPA. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after June 30, 2014, a comment to OMB is best assured of having its full effect if OMB receives it by July 30, 2014. The final rule will respond to any OMB or public comments on the information collection requirements contained in this proposal. C. Regulatory Flexibility Act The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities (SISNOSE). Small entities include small businesses, small organizations and small governmental jurisdictions. For purposes of assessing the impacts of this proposed rule on small entities, a small entity is defined as: (1) A small business in the petroleum refining industry E:\FR\FM\30JNP2.SGM 30JNP2 36954 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 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. After considering the economic impacts of this proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. The small entities subject to the requirements of this proposed rule are small refiners. We have determined that 36 companies (59 percent of the 61 total) employ fewer than 1,500 workers and are considered to be small businesses. For small businesses, the average cost-to-sales ratio is about 0.05 percent, the median cost-to-sales ratio is 0.02 percent and the maximum cost-tosales ratio is 0.55 percent. The potential costs do not have a more significant impact on small refiners and because no small firms are expected to have cost-tosales ratios greater than 1 percent, we determined that the cost impacts for this rulemaking will not have a SISNOSE. Although not required by the RFA to convene a Small Business Advocacy Review (SBAR) Panel; because the EPA has determined that this proposal would not have a significant economic impact on a substantial number of small entities, the EPA originally convened a panel to obtain advice and recommendations from small entity representatives potentially subject to this rule’s requirements. The panel was not formally concluded; however, a summary of the outreach conducted and the written comments submitted by the small entity representatives can be found in the docket for this proposed rule (Docket ID Number EPA–HQ–OAR– 2010–0682). We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts. D. Unfunded Mandates Reform Act This proposed rule does not contain a federal mandate under the provisions of Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531–1538 that may result in expenditures of $100 million or more for state, local and tribal governments, in the aggregate, or the private sector in any one year. As discussed earlier in this preamble, these amendments result in nationwide costs of $42.4 million per year for the private sector. Thus, this VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 proposed rule is not subject to the requirements of sections 202 or 205 of the UMRA. This proposed rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments because it contains no requirements that apply to such governments and does not impose obligations upon them. E. Executive Order 13132: Federalism This rule does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. None of the facilities subject to this action are owned or operated by state governments, and, because no new requirements are being promulgated, nothing in this proposal will supersede state regulations. Thus, Executive Order 13132 does not apply to this rule. In the spirit of Executive Order 13132, and consistent with the EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicits comment on this proposed rule from state and local officials. F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments This action does not have tribal implications, as specified in Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have substantial direct effects on tribal governments, on the relationship between the federal government and Indian tribes, or on the distribution of power and responsibilities between the federal government and Indian tribes as specified in Executive Order 13175. Thus, Executive Order 13175 does not apply to this action. Although Executive Order 13175 does not apply to this action, the EPA consulted with tribal officials in developing this action. The EPA sent out letters to tribes nationwide to invite them to participate in a tribal consultation meeting and solicit their input on this rulemaking. The EPA conducted the tribal consultation meeting on December 14, 2011. Participants from eight tribes attended the meeting, but they were interested only in outreach, and none of the tribes had delegation for consultation. The EPA presented all the information prepared for the consultation and PO 00000 Frm 00076 Fmt 4701 Sfmt 4702 conducted a question and answer session where participants asked clarifying questions about the information that was presented and generally expressed their support of the rulemaking requirements. The EPA specifically solicits additional comment on this proposed action from tribal officials. G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks This action is not subject to Executive Order 13045 (62 FR 19885, April 23, 1997) because it is not economically significant as defined in Executive Order 12866, and because the agency 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 sections III.A and B and sections IV.C and D of this preamble. The public is invited to submit comments or identify peer-reviewed studies and data that assess effects of early life exposure to emissions from petroleum refineries. H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use This action is not a ‘‘significant energy action’’ as defined under Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not likely to have significant adverse effect on the supply, distribution or use of energy. The overall economic impact of this proposed rule should be minimal for the refining industry and its consumers. I. National Technology Transfer and Advancement Act Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Public Law No. 104–113, 12(d) (15 U.S.C. 272 note) directs the EPA to use voluntary consensus standards (VCS) in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. VCS are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by VCS bodies. The NTTAA directs the EPA to provide Congress, through OMB, explanations when the agency decides not to use available and applicable VCS. This proposed rulemaking involves technical standards. The EPA proposes to use ISO 16017–2, ‘‘Air quality Sampling and analysis of volatile organic compounds in ambient air, E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 indoor air and workplace air by sorbent tube/thermal desorption/capillary gas chromatography Part 2: Diffusive sampling’’ as an acceptable alternative to EPA Method 325A. This method is available at https://www.iso.org. This method was chosen because it meets the requirements of EPA Method 301 for equivalency, documentation and validation data for diffusive tube sampling. The EPA welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the public to identify potentially-applicable VCS and to explain why such standards should be used in this regulation. 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 United States. The EPA has determined that this proposed 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 the provisions of this rule will provide an ample margin of safety to protect public health of all demographic groups. To examine the potential for any environmental justice issues that might be associated with the refinery source categories associated with today’s proposed rule, we evaluated the percentages of various social, demographic and economic groups within the at-risk populations living near the facilities where these source categories 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, VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 including the African American, Other and Multiracial, Hispanic, Below the Poverty Level, and Over 25 without a High School Diploma groups. In addition, the population living within 50 km of the 142 petroleum refineries has a higher percentage of minority, lower income and lower education persons when compared to the nationwide percentages of those groups. These groups stand to benefit the most from the emission reductions achieved by this proposed rulemaking, and this proposed rulemaking is projected to result in 1 million fewer people exposed to risks greater than 1-in-1 million. The EPA defines ‘‘Environmental Justice’’ to include 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. To promote meaningful involvement, the EPA conducted numerous outreach activities and discussions, including targeted outreach (such as conference calls and Webinars) to communities and environmental justice organizations. In addition, after the rule is proposed, the EPA will be conducting a webinar to inform the public about the proposed rule and to outline how to submit written comments to the docket. Further stakeholder and public input is expected through public comment and follow-up meetings with interested stakeholders. List of Subjects 40 CFR Part 60 Environmental protection, Administrative practice and procedure, Air pollution control, Incorporation by reference, Intergovernmental relations, Reporting and recordkeeping requirements. 40 CFR Part 63 Environmental protection, Air pollution control, Hazardous substances, Incorporation by reference, Reporting and recordkeeping requirements, Volatile organic compounds. Dated: May 15, 2014. Gina McCarthy, Administrator. For the reasons stated in the preamble, title 40, chapter I, of the Code of Federal Regulations is proposed to be amended as follows: PO 00000 Frm 00077 Fmt 4701 Sfmt 4702 36955 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—[AMENDED] 2. Section 60.105 is amended by: a. Revising paragraph (b)(1)(iv) and ■ b. Revising paragraph (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, Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,’’ 1986 Revision (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. The owner or operator must begin monitoring according to the requirements in paragraphs (a)(1) or (a)(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 E:\FR\FM\30JNP2.SGM 30JNP2 36956 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules * § 60.102a Subpart Ja—[AMENDED] 3. Section 60.100a is amended by revising the first sentence of paragraph (b) to read as follows: ■ * * * * (b) Except for flares, 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’’ to read as follows: § 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. * * * * * emcdonald on DSK67QTVN1PROD with PROPOSALS2 * 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 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), each owner or operator of an affected sulfur recovery plant shall comply with the applicable emission limits in paragraphs (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 paragraphs (f)(1)(i) or (f)(1)(ii) of this section. If the 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 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 PO 00000 Frm 00078 Fmt 4701 Sfmt 4702 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 paragraphs (f)(1)(i) or (f)(1)(ii) of this section 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 paragraphs (f)(1)(i) or (f)(1)(ii) of this section 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. 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. (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 paragraphs (f)(2)(i) or (f)(2)(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 paragraphs (f)(2)(i) or (f)(2)(ii) of this E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.058</GPH> § 60.100a Applicability, designation of affected facility, and reconstruction. 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: ■ a. Revising paragraphs (b)(1)(i) and (iii); ■ b. Revising paragraph (f); and ■ c. Revising paragraph (g)(1). The revisions read as follows: exceedance of the 3-hour H2S concentration limit. * * * * * Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36957 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. 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) of this section for all fuel gas streams combusted in these units. * * * * * ■ 6. Section 60.104a is amended by: ■ a. Revising the first sentence of paragraph (a); ■ b. Revising paragraph (b); ■ c. Revising paragraph (f) introductory text; ■ d. Revising paragraph (h) introductory text; ■ e. Adding paragraph (h)(6); and ■ f. Removing and reserving paragraphs (j)(1) through (3). The revisions and additions read as follows: 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 60.102a(f)(2)(i) and the reduced sulfur compounds and H2S emissions limits for sulfur recovery plants in §§ 60.102a(f)(1)(ii), 60.102a(f)(1)(iii), 60.102a(f)(2)(ii) and 60.102a(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 during the test runs using the procedures in § 60.106a(a)(5) or (6). * * * * * ■ 7. Section 60.105a is amended by: ■ a. Revising paragraph (b)(1)(i); ■ b. Revising paragraph (b)(1)(ii)(A); (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) 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 § 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 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 PO 00000 Frm 00079 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.059</GPH> 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 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 section 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 paragraphs (f)(2)(i) or (f)(2)(ii) of this section for each process train or release point individually. For a sulfur recovery plant with a design production capacity of 20 36958 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules c. Revising paragraph (b)(2); d. Revising paragraph (h)(1); e. Revising paragraph (h)(3)(i); f. Revising paragraph (i)(1); g. Redesignating paragraphs (i)(2) through (6) as (i)(3) through (7); ■ h. Adding paragraph (i)(2); and ■ i. 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). emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * (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 § 60.105a(h)(3). (i) The owner or operator shall install, operate, and maintain each CO2 and O2 monitor according to Performance Specification 3 of Appendix B to part 60. (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 part 60. The owner or operator shall use Method 3 of Appendix A–3 to part 60 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 4 or 4A of Appendix B to part 60. 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 part 60. The owner or operator shall use Method 10, 10A, or 10B of Appendix A– 3 to part 60 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 part 60, 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 part 60. 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 part 60. 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 part 60 and employ the sample conditioning system of Method 10A of appendix A–4 to part 60, the alternative relative accuracy test procedure in section 10.1 of Performance Specification 2 of appendix B to part 60 may be used in place of the relative accuracy test. * * * * * (i) * * * (1) If a CPMS is used according to § 60.105a(b)(1), all 3-hour periods during which the average PM control device operating characteristics, as measured by the continuous monitoring systems under § 60.105a(b)(1), fall below the levels established during the performance test. If the alternative to PO 00000 Frm 00080 Fmt 4701 Sfmt 4702 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 § 60.105a(c), each day in which the cause of an alarm is not alleviated within the time period specified in § 60.105a(c)(3). * * * * * (7) All 1-hour periods during which the average CO concentration as measured by the CO continuous monitoring system under § 60.105a(h) 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 § 60.105a(h)(4) 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 paragraph (a)(2) introductory text; ■ d. Revising paragraphs (a)(2)(i) and (ii); ■ e. Revising the first sentence of paragraph (a)(2)(iii); ■ f. Removing paragraphs (a)(2)(iv) and (v); ■ g. Redesignating (a)(2)(vi) through (ix) as (a)(2)(iv) through (vii); ■ h. Revising the first sentence of paragraph (a)(3) introductory text; ■ i. Revising paragraph (a)(3)(i); ■ j. Adding paragraphs (a)(4) through (7); and ■ k. 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 part 60. (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 E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules O2 monitor according to the requirements of § 60.13(c) and Performance Specification 3 of Appendix B to part 60. The owner or operator shall use Methods 3, 3A, or 3B of Appendix A–2 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, ‘‘Flue and Exhaust Gas Analyses,’’ (incorporated by reference— see § 60.17) is an acceptable alternative to EPA Method 3B of Appendix A–2 to part 60. (vii) The owner or operator shall comply with the applicable quality assurance procedures of Appendix F to part 60 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 § 60.102a(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 part 60. (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 part 60. * * * * * * * * (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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 § 60.102a(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 part 60. (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 part 60. The owner or operator shall use Methods 11 or 15 of appendix A–5 to part 60 or Method 16 of appendix A–6 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, ‘‘Flue and Exhaust Gas Analyses,’’ (incorporated by reference— see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A–5 to part 60. (iv) The owner or operator shall install, operate, and maintain each O2 monitor according to Performance Specification 3 of appendix B to part 60. (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 part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, ‘‘Flue and Exhaust Gas Analyses,’’ (incorporated by reference— see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A–2 to part 60. (vii) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to part 60 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 00081 Fmt 4701 Sfmt 4702 36959 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 part 60. (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 part 60. The owner or operator shall use Methods 3, 3A, or 3B of appendix A–2 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, ‘‘Flue and Exhaust Gas Analyses,’’ (incorporated by reference— see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A–2 to part 60. (iv) The owner or operator shall comply with the applicable quality assurance procedures of appendix F to part 60 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) The owner or operator shall install locate the monitor in a position that E:\FR\FM\30JNP2.SGM 30JNP2 36960 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules (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. the reduced sulfur compounds emission limit in § 60.102a(f)(1)(ii) or § 60.102a(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) The owner or operator shall install locate the monitor in a position that provides a representative measurement of the total gas flow rate. (B) Use a flow sensor with a measurement sensitivity of no more than 5 percent of the flow rate 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: emcdonald on DSK67QTVN1PROD with PROPOSALS2 (v) The owner or operator shall use the hourly average O2 concentration determined using Equation 8 of this section 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 § 60.102a(f)(2)(i) or 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; VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00082 Fmt 4701 Sfmt 4725 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.002</GPH> EP30JN14.003</GPH> (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. EP30JN14.001</GPH> provides a representative measurement of the total gas flow rate. (B) Use a flow sensor with a measurement sensitivity of no more than 5 percent of the flow rate 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. Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules a. Revising paragraphs (a)(1)(i) and (ii); ■ b. Revising paragraph (b)(1)(iv); ■ c. Revising the first sentence of paragraph (b)(3)(iii); ■ d. Revising paragraph (d)(3); ■ e. Revising paragraph (e)(1) introductory text; ■ f. Revising paragraph (e)(1)(ii); ■ g. Revising paragraph (e)(2) introductory text; ■ h. Revising paragraph (e)(2)(ii); ■ i. Revising paragraph (e)(2)(vi)(C); ■ j. Revising paragraph (e)(3); and ■ k. Revising paragraph (h)(5). The revisions read as follows: ■ § 60.107a Monitoring of emissions and operations for fuel gas combustion devices and flares. emcdonald on DSK67QTVN1PROD with PROPOSALS2 (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 paragraphs (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 the applicable emission limit (dry basis, 0 percent excess air). ■ 9. Section 60.107a is amended by: (a) * * * (1) * * * (i) The owner or operator shall install, operate, and maintain each SO2 monitor according to Performance Specification 2 of appendix B to part 60. 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 part 60. The owner or operator shall use Methods 6, 6A, or 6C of appendix A–4 to part 60 for conducting the relative accuracy evaluations. The method ANSI/ASME PTC 19.10–1981, ‘‘Flue and Exhaust Gas Analyses,’’ (incorporated by reference— see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A– 4 to part 60. Samples taken by Method 6 of appendix A–4 to part 60 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 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. * VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 * * Frm 00083 * Fmt 4701 * Sfmt 4702 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, Test for Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of Stain Tubes,’’ 1986 Revision (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). (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 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.004</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 § 60.102a(f)(2)(i)] or reduced sulfur compounds [if complying with the reduced sulfur compounds emission limit in § 60.102a(f)(1)(ii) or § 60.102a(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). 36961 36962 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 § 60.13(c) and Performance Specification 5 of Appendix B to part 60. The owner or operator of each total reduced sulfur monitor shall use EPA Method 15A of Appendix A–5 to part 60 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 part 60. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (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 part 60. The owner or operator shall use EPA Method 11, 15 or 15A of Appendix A–5 to part 60 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 part 60. The alternative relative accuracy procedures described in section 16.0 of Performance Specification 2 of Appendix B to part 60 (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-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. 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. § 63.14 * * * * (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. Where: TSFG = Total sulfur concentration, as SO2, in the fuel gas, ppmv. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 * * * * (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 10. The authority citation for part 63 continues to read as follows: ■ Authority: 42 U.S.C. 7401, et seq. Subpart A—[Amended] 11. Section 63.14 is amended by: a. Revising paragraph (g)(14); b. Adding paragraphs (g)(95) and (96); c. Adding paragraph (i)(2); d. Adding paragraphs (l)(21) through (23); and ■ e. Adding paragraphs (m)(3) and (s). The revisions and additions read as follows: ■ ■ ■ ■ ■ PO 00000 Frm 00084 Fmt 4701 Sfmt 4702 * * * * (g) * * * (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). * * * * * (95) ASTM D6196–03 (Reapproved 2009), Standard Practice for Selection of Sorbents, Sampling, and Thermal Desorption Analysis Procedures for Volatile Organic Compounds in Air, IBR approved for appendix A to part 63: Method 325A, Sections 1.2 and 6.1, and Method 325B, Sections 1.3, 7.1.2, 7.1.3, and A.1.1. (96) ASTM UOP539–12, Refinery Gas Analysis by Gas Chromatography, IBR approved for § 63.670(j). * * * * * (i) * * * (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, IBR approved for appendix A to part 63: Method 325A, Section 1.2, and Method 325B, Sections 1.3, 7.1.3, and A.1.1. * * * * * (l) * * * (21) EPA–454/R–99–005, Office of Air Quality Planning and Standards (OAQPS), Meteorological Monitoring E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.060</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * Incorporation by reference. * Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Guidance for Regulatory Modeling Applications, February 2000, IBR approved for appendix A to part 63: Method 325A, Section 8.3. (22) 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 2008, IBR approved for § 63.658(d) and appendix A to part 63: Method 325A, Sections 8.1.4 and 10.0. (23) EPA–454/B–13–003, Office of Air Quality Planning and Standards (OAQPS), Quality Assurance Handbook for Air Pollution Measurement Systems, Volume II: Ambient Air Quality Monitoring Program, May 2013, IBR approved for § 63.658(c) and appendix A to part 63: Method 325A, Section 4.1. (m) * * * (3) ISO 16017–2:2003, Indoor, Ambient and Workplace Air—Sampling and Analysis of Volatile Organic Compounds by Sorbent Tube/Thermal Desorption/Capillary Gas Chromatography—Part 2: Diffusive Sampling, First edition, June 11, 2003, IBR approved for appendix A to part 63: Method 325A, Sections 1.2, 6.1, and 6.5, and Method 325B, Sections 1.3, 7.1.2, 7.1.3, and A.1.1. * * * * * (s) U.S. Department of the Interior, 1849 C Street NW., Washington, DC 20240, (202) 208–3100, www.doi.gov. (1) Bulletin 627, Bureau of Mines, Flammability Characteristics of Combustible Gases and Vapors, 1965, IBR approved for § 63.670(l). (2) [Reserved] Subpart Y—[Amended] 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. * * * * * emcdonald on DSK67QTVN1PROD with PROPOSALS2 Subpart CC—[Amended] 13. Section 63.640 is amended by: a. Revising paragraph (a) introductory text; ■ b. Revising paragraph (c) introductory text; ■ c. Adding paragraph (c)(9); ■ d. Revising paragraph (d)(5); ■ e. Revising paragraph (h); ■ f. Revising paragraph (k)(1); ■ g. Revising paragraph (l) introductory text; ■ ■ VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 h. Revising paragraph (l)(2) introductory text; ■ i. Revising paragraph (l)(2)(i); ■ j. Revising paragraph (l)(3) introductory text; ■ k. Revising paragraph (m) introductory text; ■ l. Revising paragraph (n) introductory text; ■ m. Revising paragraphs (n)(1) through (5); ■ n. Revising paragraph (n)(8) introductory text; ■ o. Revising paragraph (n)(8)(ii); ■ p. Adding paragraphs (n)(8)(vii) and (viii); ■ q. Revising paragraph (n)(9)(i); ■ r. Adding paragraph (n)(10); ■ s. Revising paragraph (o)(2)(i) introductory text; ■ t. Adding paragraph (o)(2)(i)(D); ■ u. Revising paragraph (o)(2)(ii) introductory text; ■ v. Adding paragraph (o)(2)(ii)(C); and ■ w. Revising paragraph (p)(2). 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 (c)(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 of this subpart, provided that on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas from that fuel gas system are in compliance with § 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 PO 00000 Frm 00085 Fmt 4701 Sfmt 4702 36963 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 63.661, 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. (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 (h)(3)(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 paragraphs (i) or (j) of this section, the requirements in paragraphs (l)(1) through (4) of this E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36964 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 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 unit shall be in compliance with the applicable requirements in item (4) of table 11 of this subpart by the dates specified in paragraphs (l)(2)(i) or (l)(2)(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 (l)(3)(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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 subpart CC with other regulations for storage vessels. As applicable, paragraphs (n)(1), (n)(3), (n)(4), (n)(6), and (n)(7) of this section apply for Group 2 storage vessels and paragraphs (n)(2) and (n)(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 CFR part 61, subpart Y is required to comply only with the requirements of 40 CFR part 60, 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 PO 00000 Frm 00086 Fmt 4701 Sfmt 4702 also subject to the provisions of 40 CFR part 60, subparts 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 (n)(8)(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 (n)(8)(vii) 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 subpart Kb or to inspect the vessel to determine compliance with § 60.113b(a) of subpart Kb 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 § 63.120(b)(7)(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 § 63.1063(c)(2)(iv)(B) of subpart WW. * * * * * (vii) To be in compliance with § 60.112b(a)(2)(ii) of this chapter, floating roof storage vessels must be equipped with guidepole controls as described in Appendix I: Acceptable Controls for Slotted Guidepoles Under the Storage Tank Emissions Reduction Partnership Program (available at https://www.epa.gov/ttn/atw/petrefine/ petrefpg.html). (viii) If a flare is used as a control device for a storage vessel, on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 subpart Ka 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 § 63.120(b)(7)(ii) of subpart G (only up to the compliance date specified in paragraph (h) of this section for E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules compliance with § 63.660, as applicable) or either § 63.1063(c)(2)(iv)(A) or § 63.1063(c)(2)(iv)(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 (n)(8)(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 (n)(10)(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 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 § 63.120(b)(7)(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 § 63.1063(c)(2)(iv)(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 § 61.272(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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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(b)(3) of this chapter, floating roof storage vessels must be equipped with guidepole controls as described in Appendix I: Acceptable Controls for Slotted Guidepoles Under the Storage Tank Emissions Reduction Partnership Program (available at https:// www.epa.gov/ttn/atw/petrefine/ petrefpg.html). (viii) If a flare is used as a control device for a storage vessel, on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. (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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. (p) * * * PO 00000 Frm 00087 Fmt 4701 Sfmt 4702 36965 (2) Equipment leaks that are also subject to the provisions of 40 CFR part 60, subpart GGGa, are required to comply only with the provisions specified in 40 CFR part 60, subpart GGGa. Owners and operators of equipment leaks that are subject to the provisions of 40 CFR part 60, subpart GGGa and subject to this subpart may elect to monitor equipment leaks following the provisions in § 63.661, provided that the equipment is in compliance with all other provisions of 40 CFR part 60, subpart GGGa. * * * * * ■ 14. Section 63.641 is amended by: ■ a. Adding, in alphabetical order, new 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,’’ ‘‘Halogenated vent stream or halogenated stream,’’ ‘‘Halogens and hydrogen halides,’’ ‘‘Lower steam,’’ ‘‘Net heating value,’’ ‘‘Perimeter assist air,’’ ‘‘Pilot gas,’’ ‘‘Premix assist air,’’ ‘‘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 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. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36966 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 delayed coker vent to 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 vent that is typically intermittent in nature, and usually occurs only 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, but instead is routed to the atmosphere through the delayed coking unit’s blowdown system. 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 minimum amount of gas necessary 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 minimum amount of gas necessary 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), flare sweep gas, flare purge gas and flare supplemental gas, but does not include pilot gas, total steam or assist air. * * * * * Group 1 storage vessel means: (1) Prior to [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]: (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 PO 00000 Frm 00088 Fmt 4701 Sfmt 4702 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 storedliquid 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 [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]: (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 E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules greater than 2 percent by weight total organic HAP. * * * * * Halogenated vent stream or halogenated stream means a stream determined to have a mass rate of halogen atoms of 0.45 kilograms per hour or greater, determined by the procedures presented in § 63.115(d)(2)(v). The following procedures may be used as alternatives to the procedures in § 63.115(d)(2)(v)(A): (1) Process knowledge that halogen or hydrogen halides are present in a vent stream and that the vent stream is halogenated, or (2) Concentration of compounds containing halogen and hydrogen halides measured by Method 26 or 26A of part 60, Appendix A–8 of this chapter, or (3) Concentration of compounds containing hydrogen halides measured by Method 320 of Appendix A of this part. Halogens and hydrogen halides means hydrogen chloride (HCl), chlorine (Cl2), hydrogen bromide (HBr), bromine (Br2), and hydrogen fluoride (HF). * * * * * 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 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas from the fuel gas system are in compliance with § 63.670; (2) Relief valve discharges regulated under § 63.648; (3) Leaks from equipment regulated under § 63.648; (4) [Reserved]; (5) In situ sampling systems (onstream analyzers) until [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. 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, PO 00000 Frm 00089 Fmt 4701 Sfmt 4702 36967 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 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 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); (iii) An external floating roof converted to an internal floating roof meeting the specifications of § 63.1063(a)(1)(i) and (b); 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 (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 (b)(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. * * * * * 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 paragraph (d)(3); E:\FR\FM\30JNP2.SGM 30JNP2 36968 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules c. Revising paragraph (e); d. Revising paragraph (i); e. Revising paragraph (k) introductory text; ■ f. Revising paragraph (k)(1); ■ g. Revising paragraph (l) introductory text; ■ h. Revising paragraph (l)(2); and ■ i. Adding paragraph (n). The revisions and additions read as follows: ■ ■ ■ § 63.642 General standards. emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * (b) The emission standards set forth in this subpart shall apply at all times. * * * * * (d) * * * (3) 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 § 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 or 63.661, 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 or 63.661, 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. ■ 16. Section 63.643 is amended by revising paragraph (a)(1) to read as follows: § 63.643 Miscellaneous process vent provisions. (a) * * * (1) Reduce emissions of organic HAP’s using a flare. On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the PO 00000 Frm 00090 Fmt 4701 Sfmt 4702 requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements of § 63.11(b) of subpart A or the requirements of § 63.670. * * * * * ■ 17. Section 63.644 is amended by: ■ a. Revising paragraph (a) introductory text; ■ b. Revising paragraph (a)(2); and ■ c. Revising paragraph (c). The revisions read as follows: § 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), (a)(2), (a)(3), or (a)(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 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 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 is an emissions standards violation. Equipment such as low leg drains and equipment subject to § 63.648 are not subject to this paragraph. E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules (1) Install, operate, calibrate, and maintain a continuous parameter monitoring system for flow, as specified in paragraphs (c)(1)(i) through (iii) of this section. (i) Install a continuous parameter monitoring system for flow at the entrance to any bypass line. The continuous parameter monitoring system must record the volume of the gas stream that bypassed the control device and must meet the applicable minimum accuracy, calibration and quality control requirements specified in table 13 of this subpart. (ii) Equip the continuous parameter monitoring system for flow with an alarm system that will alert an operator immediately and automatically when flow is detected in the bypass line. Locate the alarm such that an operator can easily detect and recognize the alert. (iii) Reports and records shall be generated as specified in § 63.655(g) and (i). (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: § 63.645 Test methods and procedures for miscellaneous process vents. emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * (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: ■ a. Adding introductory text to § 63.646; and ■ b. Revising paragraph (b)(2). The revisions and additions 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 § 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). * * * * * ■ 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PO 00000 Frm 00091 Fmt 4701 Sfmt 4702 36969 PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. Revising paragraph (a) introductory text; ■ b. Adding paragraphs (a)(3) and (4); ■ c. Revising paragraph (c) introductory text; ■ d. Revising paragraph (c)(2)(ii); ■ e. Adding paragraphs (c)(11) and (12); and ■ f. Adding paragraph (j). The revisions and additions read as follows: § 63.648 Equipment leak standards. (a) Each owner or operator of an existing source subject to the provisions of this subpart shall comply with the provisions of part 60, subpart VV of this chapter and paragraph (b) of this section except as provided in paragraphs (a)(1), (a)(2), and (c) through (i) of this section. Each owner or operator of a new source subject to the provisions of this subpart shall comply with subpart H of this part except as provided in paragraphs (c) through (i) of this section. As an alternative to the monitoring requirements of part 60, subpart VV of this chapter or subpart H of this part, as applicable, the owner or operator may elect to monitor equipment leaks following the provisions in § 63.661. * * * * * (3) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of complying with the requirements of § 60.482–6(a)(2) of this chapter, the term ‘‘seal’’ or ‘‘sealed’’ means that instrument monitoring of the openended valve or line conducted according to the method specified in § 60.485(b) and, as applicable, § 60.485(c) of this chapter indicates no readings of 500 parts per million or greater. (4) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the applicable requirements of part 60, subpart VV of this chapter, or the requirements of § 63.670. * * * * * E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36970 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules (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 of this part except as provided in paragraphs (c)(1) through (c)(12) and (e) through (i) of this section. * * * * * (2) * * * (ii) If an owner or operator elects to monitor connectors according to the provisions of § 63.649, paragraphs (b), (c), or (d), then the owner or operator shall monitor valves at the frequencies specified in table 9 of this subpart. If an owner or operator elects to comply with § 63.649, the owner or operator cannot also elect to comply with § 63.661. * * * * * (11) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of complying with the requirements of § 63.167(a)(2), the term ‘‘seal’’ or ‘‘sealed’’ means that instrument monitoring of the open-ended valve or line conducted according to the method specified in § 63.180(b) and, as applicable, § 63.180(c) of this chapter indicates no readings of 500 parts per million or greater. (12) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 operator must comply with the requirements specified in paragraphs (j)(1) and (2) of this section for relief valves 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 paragraph (j)(4) of this section, the owner or operator must also comply with the requirements specified in paragraph (j)(3) of this section for all relief valves in organic HAP service. (1) Operating requirements. Except during a pressure release, operate each relief valve in organic HAP gas or vapor service with an instrument reading of VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 less than 500 ppm above background as detected by Method 21 of 40 CFR part 60, Appendix A–7. (2) Pressure release requirements. For relief valves in organic HAP gas or vapor service, the owner or operator must comply with either paragraph (j)(2)(i) or (ii) of this section following a pressure release. (i) If the relief valve 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 relief valve returns to organic HAP gas or vapor service following a pressure release to verify that the relief valve is operating with an instrument reading of less than 500 ppm. (ii) If the relief valve consists of or includes 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 must also conduct instrument monitoring, as specified in § 60.485(b) or § 63.180(c), as applicable, no later than 5 calendar days after the relief valve returns to organic HAP gas or vapor service following a pressure release to verify that the relief valve is operating with an instrument reading of less than 500 ppm. (3) Pressure release management. Except as specified in paragraph (j)(4) of this section, emissions of organic HAP may not be discharged to the atmosphere from relief valves in organic HAP service, and on or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the owner or operator shall comply with the requirements specified in paragraphs (j)(3)(i) and (ii) of this section for all relief valves in organic HAP service. (i) The owner or operator must equip each relief valve in organic HAP service with a device(s) or use a monitoring system that is capable of: (1) Identifying the pressure release; (2) recording the time and duration of each pressure release; and (3) 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) If any relief valve in organic HAP service vents or releases to atmosphere as a result of a pressure release event, PO 00000 Frm 00092 Fmt 4701 Sfmt 4702 the owner or operator must calculate the quantity of organic HAP released during each pressure release event and report this quantity as required in § 63.655(g)(10)(iii). Calculations may be based on data from the relief valve monitoring alone or in combination with process parameter monitoring data and process knowledge. (4) Relief valves routed to a control device. If all releases and potential leaks from a relief valve in organic HAP service are routed through a closed vent system to a control device, the owner or operator is not required to comply with paragraphs (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, all references to ‘‘Group 1 miscellaneous process vent’’ in 63.644 mean ‘‘relief valve.’’ ■ 22. 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, §§ 63.421, 63.422(a) through (c) and (e), 63.425(a) through (c) and (i), 63.425(e) through (h), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3), and (k). * * * * * (d) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the applicable requirements of subpart R of this part, or the requirements of § 63.670. ■ 23. Section 63.651 is amended by revising paragraph (a) 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 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules the requirements of §§ 63.560 through 63.568. * * * * * (e) If a flare is used as a control device, on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the applicable requirements of subpart Y of this part, or the requirements of § 63.670. ■ 24. Section 63.652 is amended by: ■ a. Revising paragraph (a); ■ b. Removing and reserving paragraph (f)(2); ■ c. Revising paragraph (g)(2)(iii)(B)(1); ■ d. Revising paragraph (h)(3); ■ e. Revising paragraph (k) introductory text; and ■ f. Revising paragraph (k)(3). The revisions and additions read as follows: emcdonald on DSK67QTVN1PROD with PROPOSALS2 § 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 of this subpart, as applicable, or a boiler or process heater meeting the criteria in § 63.645(d) of this subpart or § 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 § 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 (b)(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) Sections 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) Sections 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) Sections 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 according to §§ 63.643 through 63.645, 63.646 or 63.660, 63.647, 63.650, and 63.651, as applicable. * * * * * ■ 25. Section 63.653 is amended by: ■ a. Revising paragraph (a) introductory text; ■ b. Revising paragraphs (a)(3)(i) and (ii); and ■ c. Revising paragraph (a)(7). The revisions read as follows: PO 00000 Frm 00093 Fmt 4701 Sfmt 4702 36971 § 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. * * * * * ■ 26. Section 63.655 is amended by: ■ a. Revising paragraph (f) introductory text; ■ b. Revising paragraph (f)(1) introductory text; ■ c. Revising paragraph (f)(1)(i)(A) introductory text; ■ d. Revising paragraphs (f)(1)(i)(A)(2) and (3); ■ e. Revising paragraph (f)(1)(i)(B) introductory text; ■ f. Revising paragraph (f)(1)(i)(B)(2); ■ g. Revising paragraph (f)(1)(i)(D)(2); ■ h. Revising paragraph (f)(1)(iv) introductory text; ■ i. Revising paragraph (f)(1)(iv)(A); ■ j. Adding paragraph (f)(1)(vii); ■ k. Revising paragraph (f)(2) introductory text; ■ l. Revising paragraph (f)(3) introductory text; ■ m. Revising paragraph (f)(6); ■ n. Revising paragraph (g) introductory text; E:\FR\FM\30JNP2.SGM 30JNP2 36972 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules o. Revising paragraphs (g)(1) through (5); ■ p. Revising paragraph (g)(6)(iii); ■ q. Revising paragraph (g)(7)(i); ■ r. Adding paragraphs (g)(10) through (13); ■ s. Removing and reserving paragraph (h)(1); ■ t. Revising paragraph (h)(2) introductory text; ■ u. Revising paragraph (h)(2)(i)(B); ■ v. Revising paragraph (h)(2)(ii); ■ w. Adding paragraphs (h)(8) and (9); ■ x. Adding paragraph (i) introductory text; ■ y. Revising paragraph (i)(1) introductory text; ■ z. Revising paragraph (i)(1)(ii); ■ aa. Adding paragraphs (i)(1)(v) and (vi); ■ bb. Redesignating paragraph (i)(4) and (5) as (i)(5) and (6) respectively; ■ cc. Adding paragraph (i)(4); ■ dd. Revising newly redesignated paragraph (i)(5) introductory text; and ■ ee. Adding paragraphs (i)(7) through (11). The revisions and additions read as follows: ■ § 63.655 Reporting and recordkeeping requirements. emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * (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 (f)(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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 § 63.640(h) of this subpart. (1) The Notification of Compliance Status report shall include the information specified in paragraphs (f)(1)(i) through (f)(1)(vii) 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 (f)(1)(i)(A)(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; PO 00000 Frm 00094 Fmt 4701 Sfmt 4702 (A) All visible emission readings, heat content determinations, flow rate measurements, and exit velocity determinations made during the compliance determination required by § 63.645 of this subpart and § 63.116(a) of subpart G of this part or § 63.670(h) of this subpart, as applicable, and * * * * * (vii) For relief valves in organic HAP service, a description of the monitoring system to be implemented, including the relief valves 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. (2) If initial performance tests are required by §§ 63.643 through 63.653 of this subpart, the Notification of Compliance Status report shall include one complete test report for each test method used for a particular source. On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 (f)(3)(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. Six-month periods shall be the same 6month periods specified in paragraph (g) of this section. The Notification of Compliance Status report shall include the information specified in paragraphs (f)(1) through (f)(5) 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, as part of the periodic report, or in any combination of these four. If the required information has been submitted before the date 60 days after the end of the 6-month period in which the addition of the Group 1 emission E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules point took place, a separate Notification of Compliance Status report is not required within 60 days after the end of the 6-month period. If an owner or operator submits the information specified in paragraphs (f)(1) through (f)(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. (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 (12) 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 paragraph (g)(1) through (7) of this section or paragraphs (g)(9) through (12) 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 if the reports contain the information required by paragraphs (g)(1) through (12) of this section. (1) For storage vessels, Periodic Reports shall include the information specified for Periodic Reports in paragraph (g)(2) through (g)(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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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)(C) 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. (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 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 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 (g)(2)(ii)(C) of this section apply. (A) A failure is defined in § 63.1063(d)(1) of subpart WW. PO 00000 Frm 00095 Fmt 4701 Sfmt 4702 36973 (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) and (B) 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), (b)(4), (b)(5), or (b)(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 § 63.120(b)(3) and (b)(4) of subpart G. (3) A description of any seal condition specified in § 63.120(b)(5) or (b)(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 E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36974 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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). (B) An owner or operator who elects to use an extension in accordance with § 63.1063(e)(2) or § 63.1063(c)(2)(iv)(B) of subpart WW shall, in the next Periodic Report, submit the documentation required by those paragraphs. (4) An owner or operator who elects to comply with § 63.646 or § 63.660 by using an external floating roof converted to an internal floating roof shall comply with the periodic reporting requirements of paragraph (g)(2)(i) of this section. (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 (g)(5)(iii) 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 (e)(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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER] 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 of this part and shall include: Identification of the flare that does not meet the general requirements specified in § 63.11(b) of subpart A of this part, and reasons the flare did not meet the general requirements specified in § 63.11(b) of subpart A of this part. (iv) If a flare is used on and after compliance with the requirements in § 63.670 is elected, which can be no later than [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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) * * * (iii) For closed vent systems, include the records of periods when vent stream flow was detected in the bypass line or diverted from the control device, a flow indicator was not operating or a bypass of the system was indicated, as specified in paragraph (i)(4) of this section. (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 PO 00000 Frm 00096 Fmt 4701 Sfmt 4702 average of all runs, and the values of the monitored operating parameters. * * * * * (10) For relief valves, Periodic Reports must include the information specified in paragraphs (g)(10)(i) through (iii) of this section. (i) For relief valves in organic HAP gas or vapor service, pursuant to § 63.648(j), report any instrument reading of 500 ppm or greater, more than 5 days after the relief valve returns to service after a pressure release. (ii) For relief valves in organic HAP gas or vapor service subject to § 63.648(j)(2), report confirmation that all monitoring to show compliance was conducted within the reporting period. (iii) For relief valves in organic HAP service, report each pressure release to the atmosphere, including duration of the pressure release and estimate of quantity of substances released. (11) For flares subject to § 63.670, Periodic Reports must include the information specified in paragraphs (g)(11)(i) through (iii) of this section. (i) Records as specified in paragraph (i)(9)(i) of this section for each period when regulated material is routed to a flare and a pilot flame is not present. (ii) Visible emission records as specified in paragraph (i)(9)(ii) 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 15-minute block average operating parameters determined following the methods in § 63.670(k) through (o) as applicable, and an indication of whether the three criteria in § 63.670(e)(vi) were all met for that 15-minute block period. (iv) Records as specified in paragraph (i)(9)(x) of this section for each period when a halogenated vent stream as defined in § 63.641 is discharged to the flare. (12) If a source fails to meet an applicable standard, report such events in the Periodic Report. Report the number of failures to meet an applicable standard. For each instance, report the date, time and duration of each failure. For each failure the report must include a list of the affected sources or equipment, an estimate of the quantity of each regulated pollutant emitted over any emission limit, and a description of the method used to estimate the emissions. (13) Any changes in the information provided in a previous Notification of Compliance Status report. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules (h) * * * (2) For storage vessels, notifications of inspections as specified in paragraphs (h)(2)(i) and (h)(2)(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), § 63.120(a)(3), or § 63.120(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 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 (b)(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. * * * * * (8) For fenceline monitoring systems subject to § 63.658, within 45 calendar days after the end of each semiannual reporting period, each owner or operator shall submit the following information to the EPA’s Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through the EPA’s Central Data Exchange (CDX) (www.epa.gov/cdx). 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 episode during the semiannual 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 decimal degrees with at least five decimal places. (ii) The biweekly 12-month rolling average concentration difference (Dc) values for benzene for the semiannual 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 [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], if required to submit the results of a performance test or CEMS performance evaluation, the owner or operator shall submit the results using EPA’s Electronic Reporting Tool (ERT) 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 according to the method specified by either paragraph (h)(9)(i)(A) or (h)(9)(i)(B) of this section. (A) For data collected using test methods supported by the EPA’s ERT as listed on the EPA’s ERT Web site (https://www.epa.gov/ttn/chief/ert/ index.html), the owner or operator must submit the results of the performance test to the CEDRI accessed through the EPA’s CDX (https://cdx.epa.gov/epa_ home.asp), unless the Administrator approves another approach. Performance test data must be submitted in a file format generated through the use of the EPA’s ERT. 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, including information claimed to be CBI, on a compact disc or other commonly used electronic storage media (including, but not limited to, flash drives) by registered letter to the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404–02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to the EPA via CDX as described earlier in this paragraph. (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, the owner or operator must submit the results of the performance PO 00000 Frm 00097 Fmt 4701 Sfmt 4702 36975 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 according to the method specified by either paragraph (h)(9)(ii)(A) or (h)(9)(ii)(B) of this section. (A) For data collection of relative accuracy test audit (RATA) pollutants that are supported by the EPA’s ERT as listed on the ERT Web site, the owner or operator must submit the results of the performance evaluation to the CEDRI that is accessed through the EPA’s CDX, unless the Administrator approves another approach. Performance evaluation data must be submitted in a file format generated through the use of the EPA’s ERT. 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, including information claimed to be CBI, on a compact disc or other commonly used electronic storage media (including, but not limited to, flash drives) by registered letter to the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404–02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to the EPA via CDX as described earlier in this paragraph. (B) For any performance evaluation data with RATA pollutants that are not supported by the EPA’s ERT as listed on the EPA’s ERT Web site, the owner or operator must submit the results of the 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 (11) 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 of this part except as specified in paragraphs (i)(1)(i) E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36976 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 of this part 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. (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 to the atmosphere, or cause air intrusion into the control device, 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 any alarms triggered because flow was detected in the bypass line, including the date and time the alarm was triggered and the duration of the flow in the bypass line. The owner or operator shall also maintain records of all periods when the vent stream is diverted from the control device or air intrudes into the control device. 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. (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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 emissions of organic HAP that bypassed the control device. (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 of the average pressure 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. (8) For fenceline monitoring systems subject to § 63.658, each owner or operator shall keep the records specified in paragraphs (i)(8)(i) through (ix) of this section on an ongoing basis. (i) Coordinates of all passive monitors, including replicate samplers and field blanks, and 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) Daily unit vector wind direction, calculated daily sigma theta, daily average temperature and daily average 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 episode and the two samples used to determine it, whether background correction was used, and the 12-month rolling average Dc calculated after each sampling episode. (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. (9) For each flare subject to § 63.670, each owner or operator shall keep the PO 00000 Frm 00098 Fmt 4701 Sfmt 4702 records specified in paragraphs (i)(9)(i) through (vii) 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 periods during which the pilot flame is not present when regulated material is routed to a flare for a minimum of 5 years. (ii) Daily visible emissions observations, as required in § 63.670(c), as well as any observations required in § 63.670(h). 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. (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 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 or total hydrocarbon 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 (m), as applicable. (vi) The 15-minute block average olefins, hydrogen, and olefins plus E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules hydrogen concentration in the combustion zone used to determine if the criteria in § 63.670(e)(4) are met. If process knowledge and engineering calculations are used, retain records of the information used in the assessment and records of all compositional analyses required in § 63.670(o)(ii). Identify all 15-minute block averages for which all three criteria in § 63.670(e)(4) are met or are assumed to be met. (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) All periods during which a halogenated vent stream, as defined in § 63.641, is discharged to the flare. Records shall include the start time and date of the event, the end time and date of the event, and an estimate of the cumulative flow of the halogenated vent stream over the duration of the event. (10) If the owner or operator elects to comply with § 63.661, the owner or operator shall keep the records described in paragraphs (i)(10)(i) through (v) of this section. (i) The equipment and process units for which the owner or operator chooses to use the optical gas imaging instrument. (ii) All records required by part 60, Appendix K of this chapter, as applicable. (iii) A video record to document the leak survey results. The video record must include a time and date stamp for each monitoring event. (iv) Identification of the equipment screened and the time and date of the screening. (v) Documentation of repairs attempted and repairs delayed. If repair of a leak is confirmed using the optical gas imaging instrument, then instead of the maximum instrument reading measured by Method 21 of part 60, Appendix A–7 of this chapter, the owner or operator shall keep a video record following repair to confirm the equipment is repaired. (11) Other records must be kept as specified in paragraphs (i)(11)(i) through (iii) of this section. (i) In the event that an affected unit fails to meet an applicable standard, record the number of failures. For each VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 failure, record the date, time and duration of each failure. (ii) 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. (iii) Record actions taken to minimize emissions in accordance with § 63.642(n), and any corrective actions taken to return the affected unit to its normal or usual manner of operation. ■ 27. Section 63.656 is amended by: ■ a. Revising paragraph (c) introductory text; ■ b. Revising paragraph (c)(1); and ■ c. Adding paragraph (c)(5). The revisions and additions read as follows: § 63.656 Implementation and enforcement. * * * * * (c) The authorities that cannot be delegated to state, local, or Tribal agencies are as specified in paragraphs (c)(1) through (5) of this section. (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 63.661, 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. * * * * * (5) Approval of the corrective action plan under § 63.658(h). ■ 28. Section 63.657 is added to read as follows: § 63.657 Delayed coking unit decoking operation standards. (a) 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 is 2 pounds per square inch gauge (psig) or less prior to venting to the atmosphere, draining or deheading the coke drum at the end of the cooling cycle. (b) Each owner or operator of a delayed coking unit shall install, operate, calibrate, and maintain a continuous parameter monitoring system to determine the coke drum vessel pressure. The pressure monitoring system must be capable of measuring a pressure of 2 psig within ±0.5 psig. PO 00000 Frm 00099 Fmt 4701 Sfmt 4702 36977 (c) The owner or operator of a delayed coking unit shall determine the coke drum vessel pressure on a 5-minute rolling average basis while the coke drum is vented to the closed blowdown system to demonstrate compliance the requirement in paragraph (a) of this section. Pressure 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 for the purpose of compliance with the requirement in paragraph (a) of this section. ■ 29. 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. (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. General guidance for siting passive monitors can be found in EPA–454/R– 98–004, Quality Assurance Handbook for Air Pollution Measurement Systems, Volume II: Part 1: Ambient Air Quality Monitoring Program Quality System Development, August 1998 (incorporated by reference—see § 63.14). Alternatively, the owner or operator may elect to place monitors at 2 kilometers intervals as measured along the property boundary, provided additional monitors are located, if necessary, as required in Section 8.2.2.5 in Method 325A of Appendix A of this part. (1) As it pertains to this subpart, known emission source, as used in Section 8.2.2.5 in Method 325A of Appendix A of this part for siting passive monitors means a wastewater treatment unit or a Group 1 storage vessel. (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 plant, the background sampler(s) should be E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36978 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 episode and at least two field blanks per sampling episode, 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 use a dedicated meteorological station in accordance with Section 8.3 of Method 325A of Appendix A of this part. (1) The owner or operator shall collect and record hourly average meteorological data, including wind speed, wind direction and temperature. (2) The owner or operator shall follow the calibration and standardization procedures for meteorological measurements in EPA–454/B–08–002, Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final), March 2008 (incorporated by reference—see § 63.14). (e) The length of the sampling episode must be fourteen days, unless a shorter sampling episode is determined to be necessary under paragraph (g) or (i) of this section. A sampling episode is defined as the period during which the owner or operator collects the sample and does not include the time required to analyze the sample. (f) Within 30 days of completion of each sampling episode, the owner or operator shall determine whether the results are above or below the action level as follows: (1) For each sampling episode, the owner or operator shall determine the highest and lowest sample results for benzene from the sample pool and calculate the difference in concentration (Dc). (i) The owner or operator shall adhere to the following procedures when one or more samples for the sampling episode 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 operator shall use the method detection limit as the highest sample result. (ii) If the owner or operator identifies an offsite upwind source or an onsite source excluded under § 63.640(g) that contributes to the benzene concentration at any passive monitor and collects background samples according to an approved site-specific monitoring plan, 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 average the Dc values collected over the twelve months prior to and including the most recent sampling episode. The owner or operator shall update this value after receiving the results of each sampling episode. (3) The action level for benzene is 9 micrograms per cubic meter (mg/m3). If the 12-month rolling average Dc value for benzene is less than 9 mg/m3, the concentration is below the action level. If the 12-month rolling average Dc value for benzene is equal to or 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 12-month rolling average and no longer than 35 days after completion of the sampling episode, the owner or operator shall initiate a root cause analysis to determine the cause of such exceedance and to determine appropriate corrective action, as described in paragraphs (g)(1) through (4) of this section. The root cause analysis and corrective action analysis shall be completed 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 as specified in § 63.661 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 episodes for Methods 325A and 325B of Appendix A of this part, or using active sampling techniques), or employing additional monitors to determine contributing offsite sources. PO 00000 Frm 00100 Fmt 4701 Sfmt 4702 (h) If, upon completion of the corrective actions described in paragraph (g) of this section, the action level is exceeded for the next sampling episode following the completion of the corrective action, 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 Administrator within 60 days after determining the action level was exceeded during the sampling episode following the completion of the initial corrective action. 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 90day period shall begin when the Administrator receives the plan. (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. (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 for each monitoring location, the near field source or sources that are expected to contribute to fenceline 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 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules concentration contribution for each monitoring location. (v) If more frequent monitoring is proposed or if a monitoring station other than a passive diffusive tub monitoring station is proposed, provide a detailed description of the measurement methods, measurement frequency, and recording frequency proposed 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 Dc for comparison with the 9 mg/m3 action level using the requirements specified in paragraphs (2)(i) through (iii) of this section. (i) For each monitoring location, calculate Dci using the following equation. Dci = MCFi ¥ NFSi ¥ UB emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 specified included in the site-specific monitoring plan, mg/m3. If no additional measurement location is 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 episode 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 detection, 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 detection, 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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. (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 process for a site-specific monitoring plan. Factors that the EPA will consider in reviewing the request for a sitespecific 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. PO 00000 Frm 00101 Fmt 4701 Sfmt 4702 36979 (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 or if a monitoring station other than a passive diffusive tub monitoring station is proposed, the adequacy of the description of the measurement methods, measurement frequency, and recording frequency proposed and the adequacy of the rationale for using the alternative monitoring frequency or method. (j) The owner or operator shall comply with the applicable recordkeeping and reporting requirements in § 63.655(h) and (i). ■ 30. 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 subpart 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, subpart WW, or subpart SS of this part. The definitions of ‘‘Group 1 storage vessel’’ (item 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, E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 36980 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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) In addition to the options presented in §§ 63.1063(a)(2)(vii)(A), 63.1063(a)(2)(vii)(B), and 63.1064, an external floating roof storage vessel may comply with § 63.1063(a)(2)(vii) using a flexible enclosure system as described in item 6 of Appendix I: Acceptable Controls for Slotted Guidepoles Under the Storage Tank Emissions Reduction Partnership Program (available at https:// www.epa.gov/ttn/atw/petrefine/ petrefpg.html). (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 [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. (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 [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. (4) All references to ‘‘the proposal date of the relevant standard established pursuant to CAA section 112(f)’’ in 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 emissions by 95 percent or to an outlet concentration of 20 ppmv. (d) For an existing storage vessel fixed roof that meets the definition of Group 1 storage vessel (item 2) in § 63.641 but not the definition of Group 1 storage vessel (item 1) in § 63.641, the requirements of § 63.1062 do not apply until the next time the storage vessel is completely emptied and degassed, or [THE DATE 10 YEARS AFTER PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 (c)(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 § 63.985(a)(3)(i) or (ii) for each closed vent system that contains bypass lines that could divert a vent stream to the atmosphere. Use of the bypass at any time to divert a Group 1 storage vessel to the atmosphere is an emissions standards violation. Equipment such as low leg drains and equipment subject to § 63.648 are not subject to this paragraph. (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 paragraph § 63.984(a)(1) does not apply. ■ 31. Section 63.661 is added to read as follows: § 63.661 Alternative means of emission limitation: Monitoring equipment leaks using optical gas imaging. (a) Applicability. The owner or operator may only use an optical gas imaging instrument to screen for leaking equipment, as required by § 63.648, if the requirements in paragraphs (a)(1) through (3) of this section are met. PO 00000 Frm 00102 Fmt 4701 Sfmt 4702 (1) The owner or operator may only use the optical gas imaging instrument as an alternative to provisions in § 63.648 that would otherwise require monitoring according to § 60.485(b) or § 63.180(b)(1) through (5), as applicable. The owner or operator shall continue to comply with all other requirements in § 63.648 (e.g., weekly inspections of pumps; for relief valves, installation of a device that is capable of identifying and recording the time and duration of each pressure release, if applicable; sampling connection system requirements). (2) The owner or operator must be in compliance with the fenceline monitoring provisions of § 63.658. (3) The optical gas imaging instrument must be able to meet all of the criteria and requirements specified in part 60, Appendix K of this chapter, and the owner or operator shall conduct monitoring according to part 60, Appendix K of this chapter. (b) Compliance requirements. The owner or operator shall meet the requirements of paragraphs (b)(1) through (3) of this section. (1) The owner or operator shall identify the equipment and process units for which the optical gas imaging instrument will be used to identify leaks. (2) The owner or operator shall repair leaking equipment as required in the applicable section of part 60, subpart VV of this chapter or subpart H of this part. (3) Monitoring to confirm repair of leaking equipment must be conducted using the procedures referenced in paragraph (a)(2) of this section. (c) Recordkeeping. The owner or operator shall comply with the applicable requirements in § 63.655(i). ■ 32. Section 63.670 is added to read as follows: § 63.670 Requirements for flare control devices. On or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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) Halogenated vent streams. The owner or operator shall not use a flare E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36981 being routed to the flare. The owner or operator shall monitor Vtip using the procedures specified in paragraph (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 at all times regulated material is being routed to the flare. The owner or operator shall monitor Vtip using the procedures specified in paragraph (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. less than or equal to the target values in paragraphs (e)(2)(i) or (ii), as applicable, when regulated material is being routed to the flare. The owner or operator shall monitor and calculate LFLcz as specified in paragraph (m) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target LFLcz value is 0.11 volume fraction. (ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this section, the target LFLcz value is 0.15 volume fraction. (3) The total volumetric fraction of hydrogen and combustible organic components present in the combustion zone gas (Ccz), as propane, must be greater than or equal to the target values in paragraphs (e)(3)(i) or (ii), as applicable, when regulated material is being routed to the flare. The owner or operator shall monitor and calculate Ccz as specified in paragraph (m) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target Ccz value is 0.23 volume fraction as propane. (ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this section, the target Ccz value is 0.18 volume fraction as propane. (4) More stringent combustion zone gas target properties apply only during those flare flow periods when all three conditions in paragraphs (e)(4)(i) through (iii) simultaneously exist. The owner or operator shall monitor and calculate hydrogen and cumulative olefin combustion zone concentrations as specified in paragraph (o) of this section: (i) The concentration of hydrogen in the combustion zone is greater than 1.2 percent by volume. (ii) The cumulative concentration of olefins in the combustion zone is greater than 2.5 percent by volume. (iii) The cumulative concentration of olefins in the combustion zone plus the concentration of hydrogen in the combustion zone is greater than 7.4 percent by volume. (f) Target dilution parameters for flares with perimeter assist air. For each flare actively receiving perimeter assist air, the owner or operator shall comply with the applicable requirements in either paragraph (f)(1), (2), or (3) of this section in addition to complying with the target combustion zone gas properties as specified in paragraph (e) of this section. The owner or operator may elect to comply with any of these applicable requirements at any time (e.g., may elect to comply with the requirements in paragraph (f)(1) during certain flow conditions and comply with the requirements in paragraph (f)(2) or (f)(3) under different flow conditions) provided that the owner or operator has the appropriate monitoring equipment to determine compliance with the specified requirement. (1) The net heating value dilution parameter (NHVdil) must be greater than or equal to the target values in paragraphs (f)(1)(i) or (ii), as applicable, when regulated material is being routed to the flare. The owner or operator shall monitor and calculate NHVdil as specified in paragraph (n) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target NHVdil value is 31 (e) Target combustion zone gas properties. For each flare, the owner or operator shall comply with the applicable requirements in either paragraph (e)(1), (2), or (3) of this section. The owner or operator may elect to comply with any of these applicable requirements at any time (e.g., may elect to comply with the requirements in paragraph (e)(1) during certain flow conditions and comply with the requirements in paragraph (e)(2) or (e)(3) under different flow conditions) provided that the owner or operator has the appropriate monitoring equipment to determine compliance with the specified requirement. (1) The net heating value of flare combustion zone gas (NHVcz) must be greater than or equal to the target values in paragraphs (e)(1)(i) or (ii), as applicable, when regulated material is being routed to the flare. The owner or operator shall monitor and calculate NHVcz as specified in paragraph (m) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target NHVcz value is 380 British thermal units per standard cubic feet (Btu/scf). (ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this section, the target NHVcz value is 270 Btu/scf. (2) The lower flammability limit of the combustion zone gas (LFLcz) must be VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00103 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.005</GPH> operator shall monitor for visible emissions from the flare as specified in paragraph (b) of this section. (d) Flare tip velocity. For each flare, the owner or operator shall comply with either paragraph (d)(1) or (d)(2) of this section, provided the appropriate monitoring systems are in-place. If a total hydrocarbon analyzer is used for compositional analysis as allowed under section (j)(4) of this section, then the owner or operator must comply with paragraph (d)(1) of this section. (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 when regulated material is 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 to control halogenated vent streams as defined in § 63.641. (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. The pilot system must be equipped with an automated device to relight the pilot if extinguished. The owner or operator shall monitor for the presence of a pilot flame as specified in paragraph (g) of this section. (c) Visible emissions. Each flare must be designed for and operated with no visible emissions, except for periods not to exceed a total of 5 minutes during any 2 consecutive hours. The owner or Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules British thermal units per square foot (Btu/ft2). (ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this section, the target NHVdil value is 22 Btu/ft2. (2) The lower flammability limit dilution parameter (LFLdil) must be less than or equal to the target values in paragraphs (f)(2)(i) or (ii), as applicable, when regulated material is being routed to the flare. The owner or operator shall monitor and calculate LFLdil as specified in paragraph (n) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target LFLdil value is 1.6 volume fraction per foot (volume fraction/ft). (ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this section, the target LFLdil value is 2.2 volume fraction/ft. (3) The combustibles concentration dilution parameter (Cdil) must be greater than or equal to the target values in paragraphs (f)(3)(i) or (ii), as applicable, when regulated material is being routed to the flare. The owner or operator shall monitor and calculate Cdil as specified in paragraph (n) of this section. (i) For flares meeting all three requirements in paragraph (e)(4) of this section, the target Cdil value is 0.015 volume fraction-ft. (ii) For all flares other than those meeting all three requirements in paragraph (e)(4) of this section, the target Ccz value is 0.012 volume fractionft. (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 at a minimum of once per day 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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. (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. 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. (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 atm). The flare vent gas flow rate monitoring system(s) must also be able to output flow in actual conditions for use in the flare tip velocity calculation. (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 PO 00000 Frm 00104 Fmt 4701 Sfmt 4702 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 paragraphs (j)(1) or (j)(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 or the combustibles concentration following the methods provided in paragraphs (j)(4) of this section.. The owner or operator electing to directly monitor the net heating value of the flare vent gas must comply with the net heating value operating limits in paragraph (e) and, if applicable, paragraph (f) of this section. The owner or operator electing to directly monitor the combustibles concentration in the flare vent gas must comply with the combustibles concentration operating limits in paragraph (e) and, if applicable, paragraph (f) of this section, and must comply with the maximum velocity requirements in paragraph (d)(1) of this section. (1) Except as provided in paragraph (j)(5) 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 paragraph (j)(5) 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 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.006</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 36982 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 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. 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. (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 paragraph (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 parameters. The owner or operator shall determine the net heating value, lower flammability limit, and/or combustibles concentration vent gas of the flare (NHVvg, LFLvg, and/or Cvg, respectively) based on the composition monitoring data on a 15-minute block average basis according to the following requirements. (1) 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. (2) When a continuous monitoring system is used to determine flare vent gas composition, net heating value, or total hydrocarbon content: (i) Use the results from the first sample collected during an event, (for periodic flare vent gas flow events) for the first and second 15-minute block associated with that event. PO 00000 Frm 00105 Fmt 4701 Sfmt 4702 (ii) For all other 15-minute block periods, 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 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. (3) 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 the purpose of this requirement, use the time the sample was collected rather than the time the analytical results become available. (4) The owner or operator shall determine NHVvg from compositional analysis data by using the following equation. If the owner or operator uses a monitoring system(s) capable of continuously measuring, calculating, and recording NHVvg, as provided in paragraph (j)(3) of this section, the owner or operator shall use the NHVvg as determined by the continuous NHVvg monitor. 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. E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.008</GPH> 60, Appendix A–6, ASTM D1945–03 (Reapproved 2010) (incorporated by reference—see § 63.14), or ASTM UOP539–12 (incorporated by reference—see § 63.14). (3) The owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording NHVvg. at standard conditions. (4) The owner or operator shall install, operate, calibrate, and maintain a monitoring system capable of continuously measuring, calculating, and recording total hydrocarbon content (as propane) as a surrogate for combustibles concentration. (5) Direct compositional monitoring is not required for pipeline quality natural gas streams. In lieu of monitoring the composition of a pipeline quality natural gas stream, the following composition can be used for any pipeline quality natural gas stream. (i) 93.2 volume percent (vol %) methane. (ii) 3.2 vol % ethane. (iii) 0.6 vol % propane. (iv) 0.3 vol % butane. (v) 2.0 vol % hydrogen. (vi) 0.7 vol % nitrogen. (k) Calculation methods for 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 vent gas does not exit through them. (2) The owner or operator shall determine the cumulative volumetric flow of 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. (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 of operator shall, at a minimum, determine the 15-minute block average temperature and pressure 36983 EP30JN14.007</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules (5) The owner or operator shall calculate LFLvg using the following equation: Where: LFLvg = Lower flammability limit of flare vent gas, volume fraction. n = Number of components in the vent gas. i = Individual component in the vent gas. ci = Concentration of component i in the vent gas, volume percent (vol %). LFLi = Lower flammability limit of component i according to table 12 of this subpart, vol %. If the component is not specified in table 12 of this subpart, the owner or operator shall use the LFL value as published in Appendix A of Flammability Characteristics of Combustible Gases and Vapors, U.S. Bureau of Mines, Bulletin 627, 1965 (incorporated by reference—see § 63.14). All inerts, including nitrogen, shall be assumed to have an infinite lower flammability limit (e.g., LFLN2 = ∞, so that cN2/LFLN2 = 0). (6) The owner or operator shall calculate Cvg using the following equation. If the owner or operator uses a total hydrocarbon analyzer, the owner or operator may substitute the ‘‘èci’’ term in the following equation with the total volumetric hydrocarbon concentration present in the flare vent gas (vol % as propane), and the owner or operator may choose to ignore the concentration of hydrogen in the flare vent gas. (m) Calculation methods for determining combustion zone parameters. The owner or operator shall determine the net heating value, lower flammability limit and combustibles concentration of the combustion zone gas (NHVcz, LFLcz, and Ccz, respectively) based on the vent gas and assist gas flow rates on a 15-minute block average basis according to the following requirements. For periods when there is no assist steam flow or premix assist air flow, the combustion zone parameters are equal to the vent gas parameters. (1) The owner or operator shall calculate 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. 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. (2) The owner or operator shall calculate LFLcz using the following equation: Where: LFLcz = Lower flammability limit of combustion zone gas, volume fraction. LFLvg = Lower flammability limit of flare vent gas determined for the 15-minute block period, volume fraction. 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. (3) The owner or operator shall calculate Ccz using the following equation: Where: Ccz = Combustibles concentration in the combustion zone gas, volume fraction. Cvg = Combustibles concentration of flare vent gas determined for the 15-minute block period, volume fraction. 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. (n) Calculation methods for determining dilution parameters. The owner or operator shall determine the net heating value, lower flammability limit and combustibles concentration dilution parameters (NHVdil, LFLdil, and Cdil, respectively) based on the vent gas and perimeter assist air flow rates on a 15-minute block average basis according to the following requirements 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 dilution parameters do not need to be calculated. EP30JN14.010</GPH> EP30JN14.011</GPH> VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00106 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.009</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 EP30JN14.012</GPH> Where: Cvg = Total volumetric fraction of hydrogen and combustible organic components present in the flare vent gas, volume fraction. For the purposes of Cvg, carbon dioxide is not considered to be a combustible organic component, but carbon monoxide may be included in Cvg. n = Number of individual combustible organic components in flare vent gas. i = Individual combustible organic component in flare vent gas. ci = Concentration of combustible organic component i in flare vent gas, vol %. CMNi = Carbon mole number of combustible organic component i in flare vent gas, mole carbon atoms per mole of compound. E.g., CMN for ethane (C2H6) is 2; CMN for propane (C3H8) is 3. ch = Concentration of hydrogen in flare vent gas, vol %. 100% = Constant, used to convert volume percent to volume fraction. EP30JN14.013</GPH> 36984 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00107 Fmt 4701 Sfmt 4725 E:\FR\FM\30JNP2.SGM 30JNP2 36985 EP30JN14.014</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules (o) Special provisions for assessing olefins and hydrogen combustion zone VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 concentrations. The owner or operator shall determine the olefins and PO 00000 Frm 00108 Fmt 4701 Sfmt 4702 hydrogen content of the flare vent gas and calculate the combustion zone E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.015</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 36986 concentrations for the purposes of assessing the criteria in paragraph (e)(4) of this section on a 15-minute block average according to the following requirements. (1) The olefins concentration shall be determined as the cumulative sum of the following flare gas constituents: ethylene, acetylene, propylene, propadiene, all isomers of n- or isobutene, and all isomers of butadiene. (2) If individual component concentrations are determined following the methods specified in paragraphs (j)(1) or (j)(2) of this section, the measured vent gas concentrations shall be used to determine the hydrogen, olefins, and hydrogen plus olefins concentration in the combustion zone using the following general equation. The methods specified in paragraphs (l)(1) through (3) of this section, as applicable, shall be used to assign the vent gas concentration results to a specific 15-minute block period. emcdonald on DSK67QTVN1PROD with PROPOSALS2 Where: Acz = Concentration of target compound(s) ‘‘A’’ (representing either the olefins concentration, the hydrogen concentration, or the sum of the olefins and hydrogen concentration) in the combustion zone gas, volume fraction. Avg = Concentration of target compound(s) ‘‘A’’ (representing either the olefins concentration, the hydrogen concentration, or the sum of the olefins and hydrogen concentration) in the flare vent gas determined for the 15-minute block period, volume fraction. 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. (3) If NHVvg or total hydrocarbon monitoring systems are used as provided in paragraphs (j)(3) or (j)(4) of this section, the owner or operator may elect to determine the hydrogen and olefins concentrations using any of the following methods. (i) The owner or operator may elect to assume the hydrogen concentration, the olefins concentration, and the olefins plus hydrogen concentration in the combustion zone gas exceed all three criteria in (e)(4) at all times without making specific measurements of olefins or hydrogen concentrations. (ii) The owner or operator may elect to use process knowledge and engineering calculations to determine VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 the highest flare vent gas concentrations of olefins and hydrogen that can reasonably be expected to be discharged to the flare and the highest concentration of olefins plus hydrogen that can reasonably be expected to be discharged to the flare while the flare vent gas concentrations exceed the target combustion zone concentrations in paragraphs (e)(4)(i) and (ii) of this section at the same time. The owner or operator shall take daily flare vent gas samples for fourteen days or for 7 flaring events, whichever results in the greatest number of grab samples to verify that the calculated values are representative of the highest concentrations that reasonably be expected to be discharged to the flare. (A) If the highest flare vent gas concentrations of olefins, hydrogen, and olefins plus hydrogen that can reasonably be expected to be discharged to the flare do not exceed all three combustion zone concentration criteria in paragraph (e)(4) of this section, for example, if the flare does not service any process units that contain olefins, then the engineering assessment is sufficient to document that all three criteria in paragraph (e)(4) of this section are not met and that the more stringent operating limits do not apply at any time. (B) If the highest flare vent gas concentrations of olefins, hydrogen, and olefins plus hydrogen that can reasonably be expected to be discharged to the flare exceed all three combustion zone concentration criteria in paragraph (e)(4), then the owner or operator will use the concentrations determined from the engineering analysis as the vent gas concentrations that exist in the vent gas at all times and use the equation in paragraph (o)(2) of this section to determine the combustion zone concentrations of olefins. (C) If the operation of process units connected to the flares change or new connections are made to the flare and these changes can reasonably be expected to alter the highest vent gas concentrations of olefins, hydrogen, and/or olefins plus hydrogen received by the flare, a new engineering assessment and sampling period for verification will be conducted following the requirements of paragraph (o)(3)(ii) of this section. (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 PO 00000 Frm 00109 Fmt 4701 Sfmt 4702 36987 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 test 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 test plan prior to conducting any flare performance test intended for use in developing site-specific operating limits. The site-specific test 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 test plan, the owner or operator shall conduct a performance test for the flare following the procedures described in the site-specific test 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 test. 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 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.017</GPH> Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 36988 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 test. A sufficient number of test runs shall be conducted to identify the point at which the combustion/destruction efficiency of the flare deteriorates. (viii) If the flare can receive vent gases containing olefins and hydrogen above the levels specified for the combustion zone gas in paragraph (e)(4) of this section, a sufficient number of tests must be conducted while exceeding these limits to assess whether more stringent operating limits are required under these conditions. (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, 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 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. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 (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 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 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 test conducted following the methods in an approved site-specific test 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 40 CFR 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. PO 00000 Frm 00110 Fmt 4701 Sfmt 4702 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 test 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 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 E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules specified in paragraphs (a)(1) through (8) of this section. (1) All monitoring equipment must meet the 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 maintenance periods, instrument adjustments or checks to maintain precision and accuracy, calibration checks, and zero and span adjustments, the owner or operator shall operate all CPMS and collect data continuously 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, the owner or operator shall comply with the out-ofcontrol procedures described in paragraphs (c) of this section. The CPMS monitoring plan must be submitted to the Administrator for approval upon request. (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. 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 (airassisted only, steam-assisted only, airand steam-assisted, pressure-assisted, or non-assisted). VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 (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 (c)(3)(i) through (viii) of this section. (i) Manufacturer and model number for all monitoring equipment components. (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. (v) Span of the analyzer. The span must encompass all expected concentrations and meet the requirements of paragraph (b)(10) of this section. (vi) How data outside of the analyzer’s span 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 PO 00000 Frm 00111 Fmt 4701 Sfmt 4702 36989 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 (c)(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 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, 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 E:\FR\FM\30JNP2.SGM 30JNP2 36990 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules CPMS 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 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 the compounds that exist in the flare gas stream. 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. (ii) The owner or operator must use a surrogate calibration gas consisting of C1 through C7 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 the following paragraphs. (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) Unknown compounds that elute after n-heptane must either be identified and quantified using an identical compound standard, or the owner or operator must extend the calibration range to include the additional normal hydrocarbons necessary to perform the unknown hydrocarbon quantitation procedure. ■ 34. Table 6 to Subpart CC is amended by: ■ a. Revising the entry ‘‘63.5(d)(1)(ii)’’; ■ b. Revising the entry ‘‘63.5(f)’’; ■ c. Removing the entry ‘‘63.6(e)’’; ■ d. Adding, in numerical order, the entries ‘‘63.6(e)(1)(i) and (ii)’’ and ‘‘63.6(e)(1)(iii)’’; ■ e. Revising the entries ‘‘63.6(e)(3)(i)’’ and ‘‘63.6(e)(3)(iii)–63.6(e)(3)(ix)’’; ■ f. Revising the entry ‘‘63.6(f)(1)’’; ■ g. Removing the entry ‘‘63.6(f)(2) and (3)’’; ■ h. Adding, in numerical order, the entries ‘‘63.6(f)(2)’’ and ‘‘63.6(f)(3)’’; ■ i. Removing the entry ‘‘63.6(h)(1) and 63.6(h)(2)’’; j. Adding, in numerical order, the entries ‘‘63.6(h)(1)’’ and ‘‘63.6(h)(2)’’; ■ k. Revising the entry ‘‘63.7(b)’’; ■ l. Revising the entry ‘‘63.7(e)(1)’’; ■ m. Removing the entry ‘‘63.8(a)’’; ■ n. Adding, in numerical order, the entries ‘‘63.8(a)(1) and (2),’’ ‘‘63.8(a)(3)’’ and ‘‘63.8(a)(4)’’; ■ o. Revising the entry ‘‘63.8(c)(1)’’; ■ p. Adding, in numerical order, the entries ‘‘63.8(c)(1)(i)’’ and ‘‘63.8(c)(1)(iii)’’; ■ q. Revising the entries ‘‘63.8(c)(4)’’ and ‘‘63.8(c)(5)–63.8(c)(8)’’; ■ r. Revising the entries ‘‘63.8(d)’’ and ‘‘63.8(e)’’; ■ s. Revising the entry ‘‘63.8(g)’’; ■ t. Revising the entries ‘‘63.10(b)(2)(i)’’ and ‘‘63.10(b)(2)(ii)’’; ■ u. Revising the entries ‘‘63.10(b)(2)(iv)’’ and ‘‘63.10(b)(2)(v)’’; ■ v. Revising the entry ‘‘63.10(b)(2)(vii)’’; ■ w. Removing the entry ‘‘63.10(c)(9)– 63.10(c)(15)’’; ■ x. 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)’’; ■ y. Removing the entries ‘‘63.10(d)(5)(i)’’ and ‘‘63.10(d)(5)(ii)’’; ■ z. Adding, in numerical order, the entry ‘‘63.10(d)(5)’’; ■ aa. Removing the entry ‘‘63.11– 63.16’’; ■ bb. Adding, in numerical order, the entries ‘‘63.11’’ and ‘‘63.12–63.16’’; ■ cc. Removing footnote b. The revisions and additions read as follows: ■ 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 subpart CC, 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) ....................................... * * * * Except that the cross-reference in § 63.5(f)(2) to § 63.9(b)(2) does not apply. * Yes ............ * * 63.6(e)(1)(i) and (ii) .................. 63.6(e)(1)(iii) ............................. emcdonald on DSK67QTVN1PROD with PROPOSALS2 Reference * * * See § 63.642(n) for general duty requirement. * * No .............. Yes. * * 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) .................................. No. VerDate Mar<15>2010 19:35 Jun 27, 2014 * * * * * * * * * * Except the phrase ‘‘as specified in § 63.7(c)’’ in § 63.6(f)(2)(iii)(D) does not apply because subpart CC does not require a site-specific test plan. Except the cross-references to § 63.6(f)(1) and § 63.6(e)(1)(i) are changed to § 63.642(n). * Jkt 232001 PO 00000 * Frm 00112 Fmt 4701 * Sfmt 4702 E:\FR\FM\30JNP2.SGM * 30JNP2 * 36991 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART CC a—Continued Reference Applies to subpart CC 63.6(h)(2) .................................. Yes ............ Except § 63.6(h)(2)(ii), which is reserved. * * 63.7(b) ...................................... Yes ............ * * * * * Except subpart CC requires notification of performance test at least 30 days (rather than 60 days) prior to the performance test. * * 63.7(e)(1) .................................. 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. * * 63.8(c)(4) .................................. Yes ............ 63.8(c)(5)–63.8(c)(8) ................. 63.8(d) ...................................... 63.8(e) ...................................... No .............. No .............. 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 .............. * * 63.10(c)(9) ................................ 63.10(c)(10)–63.10(c)(11) ......... 63.10(c)(12)–63.10(c)(15) ......... No .............. No .............. No. * * 63.10(d)(5) ................................ No .............. * * 63.11 ......................................... 63.12–63.16 .............................. Yes ............ Yes. Comment * * * * * * * * * 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 § 63.8(c)(iii). See § 63.642(n). * * * * * * * * Except that for sources other than flares, subpart CC specifies the monitoring cycle frequency specified in § 63.8(c)(4)(ii) is ‘‘once every hour’’ rather than ‘‘for each successive 15-minute period.’’ Subpart CC specifies continuous monitoring system requirements. Subpart CC specifies quality control procedures for continuous monitoring systems. * * * * Subpart CC specifies data reduction procedures in §§ 63.655(i)(3) and 63.671(d). * * * * * * See § 63.655(i)(11) 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 to minimize emissions and correct the failure. * * * * * * * * * * § 63.655(i) of subpart CC specifies records to be kept for parameters measured with continuous monitors. * * * * Reserved. See § 63.655(i)(11) for malfunctions recordkeeping requirements. * * * * See § 63.655(g)(12) for malfunctions reporting requirements. * * * * * * * Except that flares complying with § 63.670 are not subject to the requirements of § 63.11(b). emcdonald on DSK67QTVN1PROD with PROPOSALS2 a Wherever subpart A 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. Table 10 to Subpart CC is amended by: ■ a. Redesignating the entry ‘‘Flare’’ as ‘‘Flare (if meeting the requirements of 63.643 and 63.644)’’; ■ VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 b. Adding the entry ‘‘Flare (if meeting the requirements of 63.670 and 63.671)’’ after the newly redesignated entry ‘‘Flare (if meeting the requirements of 63.643 and 63.644)’’; ■ PO 00000 Frm 00113 Fmt 4701 Sfmt 4702 c. Revising the entry ‘‘All control devices’’; and ■ d. Revising footnote i. The revisions and additions read as follows: ■ E:\FR\FM\30JNP2.SGM 30JNP2 36992 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 Control device Parameters to be monitored a * * Flare (if meeting the requirements of 63.670 and 63.671). * * The parameters specified in 63.670 ...... All control devices .................................. Volume of the gas stream diverted to the atmosphere from the control device (63.644(c)(1)) or Monthly inspections of sealed valves (63.644(c)(2)). Recordkeeping and reporting requirements for monitored parameters * * 1. Records as specified in 63.655(i)(9). * 2. Report information as specified in 63.655(g)(11)—PR g. 1. Continuous records c. 2. 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. 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. records’’ is defined in § 63.641. 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. c ‘‘Continuous 36. Table 11 is added to Subpart CC to read as follows: ■ 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, through 63.658 b. (a) Upon initial startup or [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], whichever is later. (a) Upon initial startup or October 28, 2009, whichever is later. (a) Upon initial startup ............................ (1) § 63.640(k), (l) and (m). (a) On or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. (a) On or before [THE DATE 90 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. (a) Upon initial startup or October 28, 2009, whichever is later. (a) Upon initial startup or August 18, 1995, whichever is later. (1) § 63.640(k), (l) and (m). (2) After September 4, 2007 but on or before June 30, 2014. (iii) Requirements for new sources in § 63.660 c. emcdonald on DSK67QTVN1PROD with PROPOSALS2 (3) After July 14, 1994 but on or before September 4, 2007. (iv) 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, through 63.658 d. (iii) Requirements for new sources in § 63.660 e. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00114 (a) On or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. (a) On or before [THE DATE 90 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 (1) § 63.640(k), (l) and (m). (1) § 63.640(k), (l) and (m). (1) § 63.640(k), (l) and (m). (1) § 63.640(k), (l) and (m). (1) § 63.640(k), (l) and (m). (1) § 63.640(k), (l) and (m). (1) § 63.640(k), (l) and (m). Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36993 TABLE 11—COMPLIANCE DATES AND REQUIREMENTS—Continued 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 . . . (a) On or before October 29, 2012 ........ (1) § 63.640(k), (l) and (m). (4) On or before July 14, 1994. (iv) 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. (a) On or before August 18, 1998 .......... (1) § 63.640(k), (l) and (m) (ii) Requirements for existing sources in §§ 63.640 through 63.645, §§ 63.647 through 63.653, and §§ 63.656 through 63.658 f. (iii) Requirements for existing sources in § 63.660 g. (iii) The existing source requirements in § 63.654 for heat exchange systems. (a) On or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. (a) On or before [THE DATE 90 DAYS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. (a) On or before October 29, 2012 ........ (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. (1) § 63.640(k), (l) and (m). (1) § 63.640(k), (l) and (m). (1) § 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)(a) and (2)(ii)(a) 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)(a) and (2)(iii)(a) of this table, the owner or operator may elect to comply with either the requirements in item (2)(i) or item (2)(iii) of this table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(iii) of this table. d Between the compliance dates in items (3)(i)(a) and (3)(ii)(a) 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)(a) and (3)(iii)(a) of this table, the owner or operator may elect to comply with either the requirements in item (3)(i) or item (3)(iii) of this table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(iii) of this table. f Between the compliance dates in items (4)(i)(a) and (4)(ii)(a) 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)(a) and (4)(iii)(a) of this table, the owner or operator may elect to comply with either the requirements in item (4)(i) or item (4)(iii) of this table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(iii) of this table. 37. Table 12 is added to Subpart CC to read as follows: ■ TABLE 12—INDIVIDUAL COMPONENT PROPERTIES MWi (pounds per pound-mole) emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 ........................................................ Methane ......................................................... C2H2 .................... C6H6 .................... C4H6 .................... C4H6 .................... C4H10 ................... C4H10 ................... C4H8 .................... C4H8 .................... C4H8 .................... CO2 ..................... CO ....................... C3H6 .................... C2H6 .................... C2H4 .................... H2 ........................ CH4 ...................... VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00115 Fmt 4701 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 16.04 Sfmt 4702 NHVi (British thermal units per standard cubic foot) CMNi (mole per mole) E:\FR\FM\30JNP2.SGM 2 6 4 4 4 4 4 4 4 1 1 3 2 2 0 1 30JNP2 1,404 3,591 2,794 2,690 2,957 2,968 2,830 2,928 2,826 0 316 2,185 1,595 1,477 274 896 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 5.0 36994 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 12—INDIVIDUAL COMPONENT PROPERTIES—Continued MWi (pounds per pound-mole) Component Molecular formula Methyl-Acetylene ............................................ Nitrogen .......................................................... Oxygen ........................................................... Pentane+ (C5+) .............................................. Propadiene ..................................................... Propane .......................................................... Propylene ....................................................... Water .............................................................. C3H4 .................... N2 ........................ O2 ........................ C5H12 ................... C3H4 .................... C3H8 .................... C3H6 .................... H2O ..................... NHVi (British thermal units per standard cubic foot) CMNi (mole per mole) 40.06 28.01 32.00 72.15 40.06 44.10 42.08 18.02 3 0 0 5 3 3 3 0 2,088 0 0 3,655 2,066 2,281 2,150 0 LFLi (volume %) 1.7 ∞ ∞ 1.4 2.16 2.1 2.4 ∞ 38. Table 13 is added to Subpart CC to read as follows: ■ TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS Parameter Accuracy requirements Calibration requirements Temperature ................... ±1 percent over the normal range of temperature measured or 2.8 degrees Celsius (5 degrees Fahrenheit), whichever is greater, for non-cryogenic temperature ranges. ±2.5 percent over the normal range of temperature measured or 2.8 degrees Celsius (5 degrees Fahrenheit), whichever is greater, for cryogenic temperature ranges. ±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 rate. Performance evaluation annually and following any period of more than 24 hours throughout which the temperature exceeded the maximum rated temperature of the sensor, or the data recorder was off scale. Visual inspections and checks of CPMS operation every 3 months, unless the CPMS has a redundant temperature sensor. Select a representative measurement location. Flow Rate ....................... Pressure ......................... ±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 rate. ±5 percent over the normal range measured for mass flow rate. ±5 percent over the normal range measured or 0.12 kilopascals (0.5 inches of water column), whichever is greater. emcdonald on DSK67QTVN1PROD with PROPOSALS2 Net Heating Value by Calorimeter. ±2 percent of span .............................. Net Heating Value by Gas Chromatograph. As specified in Performance Specification 9 of 40 CFR part 60, Appendix B. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00116 Performance evaluation annually and following any period of more than 24 hours throughout which the flow rate exceeded the maximum rated flow rate of the sensor, or the data recorder was off scale. Checks of all mechanical connections for leakage monthly. Visual inspections and checks of CPMS operation every 3 months, unless the CPMS has a redundant flow sensor. Select a representative measurement location where swirling flow or abnormal velocity distributions due to upstream and downstream disturbances at the point of measurement are minimized. Checks for obstructions at least once each process operating day (e.g., pressure tap pluggage). Performance evaluation annually and 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. Checks of all mechanical connections for leakage monthly. Visual inspection of all components for integrity, oxidation and galvanic corrosion every 3 months, unless the CPMS has a redundant pressure sensor. Select a representative measurement location that 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. Follow the procedure in Performance Specification 9 of 40 CFR part 60, Appendix B Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 36995 TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS—Continued Net Heating Value by Total Hydrocarbon Monitor. Accuracy requirements Calibration requirements Calibration drift ≤3% of instrument span at each level. Calibration drift check daily. Follow the procedure in Sections 4.1 and 4.2 of Procedure 1 in 40 CFR part 60, Appendix F. Cylinder Gas Audit Accuracy ≤5% of instrument span at each level. Cylinder gas audit quarterly. Follow the procedure in Section 5.1.2 of Procedure 1 in 40 CFR part 60, Appendix F, except the audit shall be performed every quarter. For both the calibration drift and error tests, the calibration gases should be injected into the sampling system as close to the sampling probe outlet as practical and must pass through all filters, scrubbers, conditioners, and other monitor components used during normal sampling. Select a measurement location that meets the requirements of Section 3.1 of Performance Specification 8A of Appendix B to 40 CFR part 60. ■ ■ ■ 39. Section 63.1562 is amended by: (a) Revising paragraph (b)(3) and (b) Revising paragraph (f)(5). The revisions 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas from the fuel gas system are in compliance with § 63.670. ■ 40. Section 63.1564 is amended by: ■ a. Revising paragraph (a)(1) introductory text; ■ b. Revising paragraph (a)(1)(i); ■ c. Revising paragraph (a)(1)(ii); emcdonald on DSK67QTVN1PROD with PROPOSALS2 * 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 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 (a)(2), as applicable, to calculate Qr; Qa = Volumetric flow rate of air to catalytic cracking unit catalyst regenerator, as VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 (a) * * * (1) 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 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 (iv) of this section: (i) You can elect to comply with the PM per coke burn-off emission limit (Option 1); (ii) You can elect to comply with the PM concentration emission limit (Option 2); * * * * * (iv) You can elect to comply with the Ni per coke burn-off emission limit (Option 4). * * * * * (5) During periods of startup only, if your catalytic cracking unit is followed by an electrostatic precipitator, 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 paragraphs (a)(1) and (2) of this section; or (ii) You can elect to maintain the opacity in the exhaust gas from your catalyst regenerator at or below 30 percent opacity on a 6-minute average basis. (b) * * * (4) * * * (i) If you elect Option 1 in paragraph (a)(1)(i) of this section, compute the PM emission rate (lb/1,000 lb of coke burnoff) 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: 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 (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-%)); 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). d. Revising paragraph (a)(1)(iv); e. Adding paragraph (a)(5); f. Revising paragraph (b)(4)(i); g. Revising paragraph (b)(4)(ii); h. Revising paragraph (b)(4)(iv); i. Adding paragraph (c)(5). The revisions and additions read as follows: ■ ■ ■ ■ ■ ■ Subpart UUU—[Amended] § 63.1564 What are my requirements for metal HAP emissions from catalytic cracking units? PO 00000 Frm 00117 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.018</GPH> Parameter 36996 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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)). AMENDMENTS IN THE FEDERAL REGISTER], A=0.18 g/million cal (0.10 lb/million Btu). On or after [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 2 in paragraph (a)(1)(ii) 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)(iv) 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). 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 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00118 Fmt 4701 Sfmt 4725 30JNP2 EP30JN14.022</GPH> EP30JN14.023</GPH> E:\FR\FM\30JNP2.SGM EP30JN14.020</GPH> EP30JN14.021</GPH> section for each of the performance test runs, mg/kg coke. EP30JN14.019</GPH> VerDate Mar<15>2010 EP30JN14.024</GPH> Qsd = Volumetric flow rate of the catalytic cracking unit catalyst regenerator flue gas as measured by Method 2 in appendix A to part 60 of this chapter, dscm/hr (dscf/hr); 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 [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE emcdonald on DSK67QTVN1PROD with PROPOSALS2 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); Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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) During periods of startup only, if you elect to comply with the alternative limit in paragraph (a)(5)(ii) of this section, determine continuous compliance by: collecting opacity readings using either a continuous opacity monitoring system according to § 63.1572 or manual opacity observations following EPA Method 9 in Appendix A–4 to part 60 of this chapter; and maintaining each 6-minute average opacity at or below 30 percent. ■ 41. Section 63.1565 is amended by: ■ a. Adding paragraph (a)(5); ■ b. Adding paragraph (b)(1)(iv); and ■ c. Adding paragraph (c)(3). The additions read as follows: emcdonald on DSK67QTVN1PROD with PROPOSALS2 § 63.1565 What are my requirements for organic HAP emissions from catalytic cracking units? (a) * * * (5) During periods of startup only, if your catalytic cracking unit is not followed by a CO boiler, thermal oxidizer, incinerator, flare or similar combustion device, 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). (b) * * * (1) * * * (iv) If you elect to comply with the alternative limit for periods of startup in paragraph (a)(5)(ii) of this section, you must also install, operate, and maintain a continuous parameter monitoring system to measure and record the oxygen content (percent, dry basis) in the catalyst regenerator vent. * * * * * (c) * * * (3) Demonstrate continuous compliance with the alternative limit in paragraph (a)(5)(ii) of this section by 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). ■ 42. Section 63.1566 is amended by: ■ a. Revising paragraph (a)(1) introductory text; VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 ■ ■ b. Revising paragraph (a)(1)(i); and c. Revising paragraph (a)(4). The revisions 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the control device requirements in § 63.11(b) or the requirements of § 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. * * * * * ■ 43. Section 63.1568 is amended by: ■ a. Revising paragraph (a)(1) introductory text; ■ b. Revising paragraph (a)(1)(i); ■ c. Adding paragraph (a)(4); ■ d. Revising paragraph (b)(1); and ■ e. Adding paragraphs (c)(3) and (4). The revisions and additions 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 in § 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: PO 00000 Frm 00119 Fmt 4701 Sfmt 4702 36997 (i) You can elect to meet the NSPS requirements in § 60.104(a)(2) or in § 60.102a(f)(1) of this chapter (Option 1); or * * * * * (4) During periods of shutdown only, 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 shutdown purge gases to a flare. On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 shutdown purge gases to a to a thermal oxidizer or incinerator operated at a minimum hourly average temperature of 1,200 degrees Fahrenheit and a minimum hourly average outlet oxygen (O2) concentration of 2 volume percent (dry basis). (b) * * * (1) Install, operate, and maintain a continuous monitoring system according to the requirements in § 63.1572 and Table 31 of this subpart. Except: (i) If you elect to comply with the alternative limit for periods of shutdown in paragraph (a)(4)(ii) of this section, then on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must also install, operate, calibrate, and maintain monitoring systems as specified in §§ 63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must either install, operate, and maintain 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 install, operate, calibrate, and maintain monitoring systems as specified in §§ 63.670 and 63.671. (ii) If you elect to comply with the alternative limit for periods of E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 shutdown in paragraph (a)(4)(iii) of this section, you must also install, operate, and maintain continuous parameter monitoring system to measure and record the temperature and oxygen content (percent, dry basis) in the vent from the thermal oxidizer or incinerator. * * * * * (c) * * * (3) Demonstrate continuous compliance with the alternative limit in paragraph (a)(4)(ii) of this section by meeting the requirements of either paragraph (c)(3)(i) or (ii) of this section. (i) On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must meet the requirements of paragraphs (c)(3)(i)(A) through (C) of this section. (A) Collect the flare monitoring data according to §§ 63.670 and 63.671. (B) Keep the records specified in § 63.655(i)(9). (C) Maintain the selected operating parameters as specified in § 63.670. (ii) Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must either meet the requirements of paragraph (c)(3)(i) of this section or meet the requirements of paragraphs (c)(3)(ii)(A) through (D) of this section. (A) Collect the flare monitoring data according to § 63.1572. (B) Record for each 1-hour period whether the monitor was continuously operating and the pilot light was continuously present during each 1hour period. (C) Maintain the net heating value of the gas being combusted at or above the applicable limits in § 63.11. (D) Maintain the exit velocity at or below the applicable maximum exit velocity specified in § 63.11. (4) Demonstrate continuous compliance with the alternative limit in paragraph (a)(4)(iii) of this section by collecting the hourly average temperature and oxygen concentration monitoring data according to § 63.1572; maintaining the hourly average temperature at or above 1,200 degrees Fahrenheit; and maintaining the hourly average oxygen concentration at or above 2 volume percent (dry basis). VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 44. Section 63.1570 is amended by: a. Revising paragraphs (a) through (d); and ■ b. Removing and reserving paragraph (g). The revisions 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 detailing the operation and maintenance of the process and emissions control equipment. * * * * * ■ 45. Section 63.1571 is amended by: ■ a. Adding paragraph (a)(5); ■ b. Revising paragraph (b)(1); ■ c. Removing paragraph (b)(4); ■ d. Redesignating paragraph (b)(5) as (b)(4); ■ e. Revising paragraphs (d)(2) and (d)(4). The revisions and additions read as follows: PO 00000 Frm 00120 Fmt 4701 Sfmt 4702 § 63.1571 How and when do I conduct a performance test or other initial compliance demonstration? (a) * * * (5) Conduct a performance test for PM or Ni, as applicable, from catalytic cracking units at least once every 5 years for those units monitored with CPMS, BLD, or COMS. You must conduct the first periodic performance test no later than [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. Those units monitoring PM concentration with a PM CEMS are not required to conduct a periodic PM performance test. (b) * * * (1) Conduct performance tests under such conditions as the Administrator specifies to you based on representative performance of the affected source for the period being tested. Representative conditions exclude periods of startup and shutdown unless specified by the Administrator or an applicable subpart. 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 such conditions represent normal operation. 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. Section 63.1564(b)(2) allows you to adjust the laboratory measurements of the equilibrium catalyst Ni concentration to the maximum level. You must make this adjustment using Equation 2 of this section as follows: E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.025</GPH> 36998 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Where: NiEmR2st = Average Ni emission rate calculated as the arithmetic average Ni emission rate using Equation 8 of § 63.1564 for each performance test run, mg/kg coke burn-off. * * * * * (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. * * * * * ■ 46. Section 63.1572 is amended by: ■ a. Revising paragraphs (c) introductory text, (c)(1), (c)(3) and (c)(4); and ■ b. Revising paragraphs (d)(1) and (2). The revisions read as follows: § 63.1572 What are my monitoring installation, operation, and maintenance requirements? emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * (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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must install, operate, calibrate, and maintain monitoring systems as specified in §§ 63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 meet the requirements in Table 41 of this subpart for BLD systems. * * * * * (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. ■ 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); ■ c. Revising newly redesignated paragraph (c) introductory text; ■ d. Revising newly redesignated paragraph (d) introductory text; ■ e. Revising newly redesignated paragraph (f) introductory text; and ■ f. Revising newly redesignated paragraph (g)(1). 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 PO 00000 Frm 00121 Fmt 4701 Sfmt 4702 36999 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 paragraph (c)(1) or (2) of this section for a catalytic reforming unit. * * * * * (d) Can I use another type of monitoring system? You may request approval from your permitting authority to 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. Your request must contain a 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 (a)(3) to read as follows: § 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 E:\FR\FM\30JNP2.SGM 30JNP2 37000 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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. * * * * * ■ 49. Section 63.1575 is amended by: ■ a. Revising paragraphs (d) introductory text, (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 (e)(6); ■ f. Revising paragraphs (f)(1) and (2); ■ g. Removing and reserving paragraph (h); and ■ h. Adding paragraph (k). The revisions and additions read as follows: § 63.1575 when? What reports must I submit and emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * (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. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 (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. (1) [Reserved] * * * * * (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 (c)(1)(i) or (c)(1)(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 PO 00000 Frm 00122 Fmt 4701 Sfmt 4702 conditions during the test; record of 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. On and after [THE DATE 3 YEARS AFTER DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], if required to submit the results of a performance test or CEMS performance evaluation, you must submit the results using EPA’s Electronic Reporting Tool (ERT) 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 according to the method specified by either paragraph (k)(1)(i) or (k)(1)(ii) of this section. (i) For data collected using test methods supported by the EPA’s ERT as listed on the EPA’s ERT Web site (https://www.epa.gov/ttn/chief/ert/ index.html), you must submit the results of the performance test to the Compliance and Emissions Data Reporting Interface (CEDRI) accessed through the EPA’s Central Data Exchange (CDX) (https://cdx.epa.gov/ epa_home.asp), unless the Administrator approves another approach. Performance test data must be submitted in a file format generated through use of the EPA’s ERT. 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, including information claimed to be CBI, on a compact disc or other commonly used electronic storage media (including, but not limited to, flash drives) by registered letter to the EPA. The electronic media must be clearly marked as CBI and mailed to E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 U.S. EPA/OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404–02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to the EPA via CDX as described earlier in this paragraph. (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, 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 test required by § 63.1571(a) and (b), you must submit the results of the performance evaluation according to the method specified by either paragraph (k)(2)(i) or (k)(2)(ii) of this section. (i) For data collection of relative accuracy test audit (RATA) pollutants that are supported by the EPA’s ERT as listed on the ERT Web site, the owner or operator must submit the results of the performance evaluation to the CEDRI that is accessed through the EPA’s CDX, unless the Administrator approves another approach. Performance evaluation data must be submitted in a file format generated through the use of the EPA’s ERT. 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, including information claimed to be CBI, on a compact disc or other commonly used electronic storage media (including, but not limited to, flash drives) by registered letter to the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404–02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be submitted to the EPA via CDX as described earlier in this paragraph. (ii) For any performance evaluation data with RATA pollutants that are not supported by the EPA’s ERT as listed on the EPA’s ERT Web site, you must VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 submit the results of the performance evaluation to the Administrator at the appropriate address listed in § 63.13. ■ 50. Section 63.1576 is amended by: ■ a. Revising paragraph (a)(2); ■ b. Revising paragraphs (b)(3) and (5). The revisions 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). * * * * * PO 00000 Frm 00123 Fmt 4701 Sfmt 4702 37001 (5) Records of the date and time that each deviation started and stopped. * * * * * ■ 51. Section 63.1579 is amended by: ■ a. Revising section introductory text and ■ b. 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 this part (§§ 63.1 through 63.15), and in this section as listed. If the same term is defined in subpart A 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. * * * * * 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. E:\FR\FM\30JNP2.SGM 30JNP2 37002 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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. PM emissions must not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/ 1,000 lb) of coke burn-off. Before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent excess air. 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. 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i) .......................... 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii) .......................... 4. Option 1: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). 5. Option 2: PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). 6. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). 7. Option 4: Ni per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). 53. Table 2 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 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 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. a. Continuous opacity monitoring system used to comply with the 30 percent opacity limit in 40 CFR 60.102 before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]. b. Continuous opacity monitoring system used to comply with a site-specific opacity limit. Not applicable ............................... Not applicable. Cyclone, fabric filter, or electrostatic precipitator. c. Continuous parameter monitoring systems. emcdonald on DSK67QTVN1PROD with PROPOSALS2 For each new or existing catalytic cracking unit . . . Electrostatic precipitator ............... d. Continuous parameter monitoring systems. Wet scrubber ................................ 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. Maintain the daily average coke burn-off rate or daily average flow rate no higher than the limit established in the performance test; and maintain the 3hour rolling average total power and secondary current above the limit established in the performance test. Maintain the 3-hour rolling average pressure drop above the limit established in the performance test; and maintain the 3hour rolling average liquid-togas ratio above the limit established in the performance test. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00124 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37003 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 . . . Not applicable ............................... Cyclone or electrostatic precipitator. Electrostatic precipitator ............... Wet scrubber ................................ e. Bag leak detection (BLD) system. Fabric filter .................................... Any ................................................ Any ................................................ 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 a. PM CEMS ................................. Maintain particulate loading below the BLD alarm set point established in the initial adjustment of the BLD system or allowable seasonal adjustments. Not applicable. d. Continuous parameter monitoring systems. 21:35 Jun 27, 2014 Fabric filter .................................... c. Continuous parameter monitoring systems. VerDate Mar<15>2010 You shall meet this operating limit . . . b. Continuous opacity monitoring system used to comply with a site-specific opacity limit. 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii). 4. Option 1: PM per coke burn-off limit not subject to the NSPS for PM in 40 CFR 60.102 or 40 CFR 60.102a(b)(1). For this type of control device . . . e. Bag leak detection (BLD) system. 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i). For this type of continuous monitoring system . . . i. Electrostatic precipitator ............ Jkt 232001 PO 00000 Frm 00125 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 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. Maintain the daily average coke burn-off rate or daily average flow rate no higher than the limit established in the performance test; and maintain the 3hour rolling average total power and secondary current above the limit established in the performance test. Maintain the 3-hour rolling average pressure drop above the limit established in the performance test; and maintain the 3hour rolling average liquid-togas ratio above the limit established in the performance test. 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. 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. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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) Maintain the daily average gas flow rate or daily average coke burn-off rate no higher than the limit established in the performance test. 30JNP2 37004 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 ............................ c. Bag leak detection (BLD) system. emcdonald on DSK67QTVN1PROD with PROPOSALS2 5. Option 2: PM concentration limit not subject to the NSPS for PM in 40 CFR 60.102 or 40 CFR 60.102a(b)(1). 6. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 CFR 60.102. VerDate Mar<15>2010 21:35 Jun 27, 2014 Fabric filter .................................... PM CEMS ..................................... Any ................................................ a. Continuous opacity monitoring system. Cyclone, fabric filter, or electrostatic precipitator. Jkt 232001 PO 00000 Frm 00126 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM (2) Maintain the 3-hour rolling average total power and secondary current above the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you may maintain the daily average voltage and secondary current (or total power input) above the limit established in the performance test. (1) Maintain the 3-hour rolling average pressure drop above the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 jetejector design). (2) Maintain the 3-hour rolling average liquid-to-gas ratio above the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you may maintain the daily average liquid-to-gas ratio above the limit established in the performance test. Maintain particulate loading below the BLD alarm set point established in the initial adjustment of the BLD system or allowable seasonal adjustments. Not applicable. Maintain the 3-hour rolling average Ni operating value no higher than the limit established during the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you may maintain the daily average Ni operating value no higher than the limit established during the performance test. 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37005 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 . . . b. Continuous parameter monitoring systems. i. Electrostatic precipitator ............ (1) Maintain the daily average gas flow rate or daily average coke burn-off rate no higher than the limit established during the performance test. (2) Maintain the monthly rolling average of the equilibrium catalyst Ni concentration no higher than the limit established during the performance test. (3) Maintain the 3-hour rolling average total power and secondary current above the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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) Maintain the 3-hour rolling average pressure drop above the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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). (3) Maintain the 3-hour rolling average liquid-to-gas ratio above the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you may maintain the daily average liquid-to-gas ratio above the limit established during the performance test. emcdonald on DSK67QTVN1PROD with PROPOSALS2 ii. Wet scrubber ............................ VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00127 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37006 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . 7. 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, baghouse, 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 [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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) Maintain the 3-hour rolling average total power and secondary current above the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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) Maintain the 3-hour rolling average pressure drop above the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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). (3) Maintain the 3-hour rolling average liquid-to-gas ratio above the limit established in the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you may maintain the daily average liquid-to-gas ratio above the limit established during the performance test. emcdonald on DSK67QTVN1PROD with PROPOSALS2 ii. Wet scrubber ............................ VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00128 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 54. Table 3 to subpart UUU of part 63 is revised to read as follows: ■ 37007 As stated in § 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 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. a. Cyclone ......................................... Any .................................................... 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 and the total power and secondary current to the control device. Continuous parameter monitoring system to measure and record the pressure drop across the scrubber,2 coke burn-off rate or the gas flow rate entering or exiting the control device,1 and total liquid (or scrubbing liquor) flow rate to the control device. Alternatively, before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], continuous opacity monitoring system to measure and record the opacity of emissions from each catalyst regenerator vent. Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent or a 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. 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,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. Continuous emission monitoring system to measure and record the concentration of PM and oxygen from each catalyst regenerator vent. See item 2 of this table. Any .................................................... See item 3 of this table. b. Electrostatic precipitator ................ c. Wet scrubber ................................. d. Fabric Filter ................................... 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i) electing to meet the PM per coke burn-off limit. a. Cyclone ......................................... b. Electrostatic precipitator ................ c. Wet scrubber ................................. d. Fabric Filter ................................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i) 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. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 Any .................................................... PO 00000 Frm 00129 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37008 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . 6. Option 1: PM per coke burn-off limit not subject to the NSPS for PM in 40 CFR 60.102 or 40 CFR 60.120a(b)(1). 7. Option 2: PM concentration limit not subject to the NSPS for PM in 40 CFR 60.102 or 40 CFR 60.120a(b)(1). 8. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). Any .................................................... See item 1 of this table. Any .................................................... See item 3 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 coke burn-off rate or 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 coke burn-off rate or 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 8.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 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 coke burn-off rate or 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 9.a of this table. b. Electrostatic precipitator ................ c. Wet scrubber ................................. d. Fabric Filter ................................... 9. Option 4: Ni lb/1,000 lbs of coke burn-off limit not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). a. Cyclone ......................................... b. Electrostatic precipitator ................ c. Wet scrubber ................................. d. Fabric Filter ................................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 VerDate Mar<15>2010 22:21 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00130 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 55. Table 4 to subpart UUU of part 63 is revised to read as follows: ■ 37009 As stated in § 63.1564(b)(2), 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 NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM) 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, 2F in Appendix A–1 to part 60 of this chapter, or 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. c. Conduct gas molecular weight analysis. 2. Option 1: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). 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. a. Measure PM emissions ............ b. Compute coke burn-off rate and PM emission rate (lb/1,000 lb of coke burn-off). c. Measure opacity of emissions .. emcdonald on DSK67QTVN1PROD with PROPOSALS2 3. Option 2: PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). VerDate Mar<15>2010 22:21 Jun 27, 2014 a. Measure PM concentration ...... Jkt 232001 PO 00000 Frm 00131 Fmt 4701 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 dry standard cubic meters per minute (dscm/min) (0.53 dry standard cubic feet per minute (dscf/ min). opacity monitoring Method 5, 5B, or 5F (40 CFR part 60, Appendix A–3) to determine PM concentration and associated moisture content for units without wet scrubbers Method 5 or 5B (40 CFR part 60, Appendix A–3) to determine PM concentration and associated moisture content for unit with wet scrubber. Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37010 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM)—Continued For each new or existing catalytic cracking unit catalyst regenerator vent . . . According to these requirements . . . emcdonald on DSK67QTVN1PROD with PROPOSALS2 Equation 5 of § 63.1564. 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. d. If you use a continuous opacity monitoring system, establish your site-specific Ni operating limit. 21:35 Jun 27, 2014 Method 29 (40 CFR part 60, Appendix A–8). b. Compute Ni emission rate (lb/ 1,000 lb of coke burn-off). c. Determine the equilibrium catalyst Ni concentration. VerDate Mar<15>2010 a. Measure concentration of Ni .... d. If you use a continuous opacity monitoring system, establish your site-specific Ni operating limit. 5. Option 4: Ni per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). Using . . . b. Compute Ni emission rate (lb/ hr). c. Determine the equilibrium catalyst Ni concentration. 4. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). You must . . . i. Jkt 232001 PO 00000 Frm 00132 Fmt 4701 XRF procedure in Appendix A to this subpart; 1 or EPA Method 6010B or 6020 or EPA Method 7520 or 7521 in SW–846; 2 or an alternative to the SW–846 method satisfactory to the Administrator. See item 4.c. of this table ............ 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 4702 E:\FR\FM\30JNP2.SGM You must obtain 1 sample for each of the 3 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 hourly average opacity from all the 6-minute averages. (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 from all the readings. You must obtain 1 sample for each of the 3 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 hourly average opacity from all the 6-minute averages. (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 from all the readings. 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37011 TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM)—Continued For each new or existing catalytic cracking unit catalyst regenerator vent . . . 6. If you elect Option 1 in item 4 in Table 1, Option 3 in item 6 in Table 1, or Option 4 in item 7 in Table 1 of this subpart and you use continuous parameter monitoring systems. You must . . . According to these requirements . . . Using . . . 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. 21:35 Jun 27, 2014 i. Data from the continuous parameter monitoring systems and applicable performance test methods. d. Electrostatic precipitator or wet scrubber: equilibrium catalyst Ni concentration. VerDate Mar<15>2010 i. Data from the continuous parameter monitoring systems and applicable performance test methods. c. Electrostatic precipitator: voltage and secondary current (or total power input). emcdonald on DSK67QTVN1PROD with PROPOSALS2 b. Electrostatic precipitator or wet scrubber: gas flow rate. Results of analysis for equilibrium catalyst Ni concentration. Jkt 232001 PO 00000 Frm 00133 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM (1) You must collect gas flow rate monitoring data every 15 minutes during the entire period of the initial performance test. (2) You must determine and record the 3-hr average gas flow rate from all the readings. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 and the 3hr average secondary current. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you may determine and record the minimum hourly average voltage and secondary current (or total power input) from all the readings. 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. 30JNP2 37012 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM)—Continued For each new or existing catalytic cracking unit catalyst regenerator vent . . . i. Data from the continuous parameter monitoring systems and applicable performance test methods. i. Data from the continuous parameter monitoring systems and applicable performance test methods. g. Alternative procedure for gas flow rate. emcdonald on DSK67QTVN1PROD with PROPOSALS2 According to these requirements . . . f. Wet scrubber: liquid-to-gas ratio 21:56 Jun 27, 2014 Using . . . e. Wet scrubber: pressure drop (not applicable to non-venturi scrubber of jet ejector design). VerDate Mar<15>2010 You must . . . i. Data from the continuous parameter monitoring systems and applicable performance test methods. (1) You must collect pressure drop monitoring data every 15 minutes during the entire period of the initial performance test. (2) You must determine and record the 3-hr average pressure drop from all the readings. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. (2) You must determine and record the hourly average liquid-to-gas ratio from all the readings. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you may determine and record the hourly average rate of all the readings. Jkt 232001 PO 00000 Frm 00134 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37013 TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR PARTICULATE MATTER (PM)—Continued For each new or existing catalytic cracking unit catalyst regenerator vent . . . You must . . . According to these requirements . . . Using . . . (3) You must determine and record the maximum gas flow rate using Equation 1 of § 63.1573. 1 Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure). 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 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. 2 EPA 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 . . . 1. Subject to the NSPS for PM in 40 CFR 60.102. emcdonald on DSK67QTVN1PROD with PROPOSALS2 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i), electing to meet the PM per coke burn-off limit. VerDate Mar<15>2010 21:56 Jun 27, 2014 Jkt 232001 For the following emission limit . . . You have demonstrated initial compliance if . . . PM emissions must not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/1,000 lb) of coke burnoff. Before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 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 0.5 g/kg (0.5 lb PM/1,000 lb) of coke burn-off or, 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. PO 00000 Frm 00135 Fmt 4701 Sfmt 4702 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. E:\FR\FM\30JNP2.SGM 30JNP2 37014 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS—Continued For the following emission limit . . . You have demonstrated initial compliance if . . . 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 1.0 g/kg coke burn-off (1 lb/1000 lb coke burn-off). 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, 0.020 grain per dry standard cubic feet (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. If a PM CEMS is used, 0.040 gr/dscf corrected to 0 percent excess air. 6. Option 1: PM per coke burn-off limit not subject to the NSPS for PM in 40 CFR 60.102 or 40 CFR 60.120a(b)(1). emcdonald on DSK67QTVN1PROD with PROPOSALS2 For each new and existing catalytic cracking unit catalyst regenerator vent . . . PM emissions must not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/1,000 lb) of coke burnoff. Before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 6minute average opacity reading in any 1-hour period. PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent excess air. 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 0.5 kg/1,000 kg (0.5 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 0.020 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. 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 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), 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 § 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. 7. Option 2: PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00136 Fmt 4701 Sfmt 4702 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), 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. E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37015 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 . . . 8. Option 3: not subject to the NSPS for PM. Nickel (Ni) emissions from your catalyst regenerator vent must not exceed 13,000 mg/hr (0.029 lb/hr). 9. 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 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. The average Ni emission rate, measured using Method 29 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 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 For each new and existing catalytic cracking unit . . . a. PM emissions must not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/1,000 lb) of coke burnoff. Before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 6minute 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. ii. Maintaining PM emission rate below 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off. iii. Conducting a performance test before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER] and once every five years thereafter. iv. Collecting the applicable continuous parametric monitoring system data according to § 63.1572 and maintaining each rolling 3-hr average above or below (as applicable) the average determined during the performance test. VerDate Mar<15>2010 21:56 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00137 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37016 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . PM emissions must not exceed 0.5 g/kg (0.5 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 coke burn-off (1 lb/1,000 lb coke burn-off). 4. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i), electing to meet the PM concentration limit. 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 grain per dry standard cubic feet (gr/dscf) corrected to 0 percent excess air. If a PM CEMS is used, 0.040 gr/dscf corrected to 0 percent excess air. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00138 Fmt 4701 Sfmt 4702 You shall demonstrate continuous compliance by . . . v. Collecting the continuous opacity monitoring data for each catalyst regenerator vent according to § 63.1572 and maintaining each 6minute average at or below the site-specific opacity determined during the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], collecting the continuous opacity monitoring data for each catalyst regenerator vent according to § 63.1572 and maintaining each 6-minute average at or below 30 percent, except that one 6minute average during a 1-hour period can exceed 30 percent. vi. Before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 0.5 g/kg (0.5 lb PM/1,000 lb) of coke burn-off; conducting a performance test once every year; collecting the applicable continuous parametric monitoring system data according to § 63.1572 and maintaining each rolling 3-hr average above or below (as applicable) the average determined during the performance test; collecting the continuous opacity monitoring data for each regenerator vent according to § 63.1572 and maintaining each 6-minute average at or below the site-specific opacity determined during the performance test. 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/1,000 lb) of coke burn-off; conducting a performance test once every year; collecting the applicable continuous parametric monitoring system data according to § 63.1572 and maintaining each rolling 3-hr average above or below (as applicable) the average determined during the performance test; collecting the continuous opacity monitoring data for each regenerator vent according to § 63.1572 and maintaining each 6-minute average at or below the site-specific opacity determined during the performance test. Maintaining PM concentration below 0.020 gr/ dscf corrected to 0 percent excess air. Maintaining PM concentration below 0.040 gr/ dscf corrected to 0 percent excess air. E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37017 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 . . . 6. Option 1: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). 7. Option 2: PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). 8. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). See item 1 of this table ......................................... See item 1 of this table. PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent excess air. See item 5 of this table. Ni emissions must not exceed 13,000 mg/hr (0.029 lb/hr). 9. Option 4: Ni per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 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. Maintaining Ni emission rate below 13,000 mg/hr (0.029 lb/hr); conducting a performance test before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER] and once every five years thereafter; and collecting the applicable continuous parametric monitoring system data according to § 63.1572 and maintaining each rolling 3-hr average above or below (as applicable) the average determined during the performance test. 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; conducting a performance test before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER] and once every five years thereafter; and collecting the applicable continuous parametric monitoring system data according to § 63.1572 and maintaining each rolling 3-hr average above or below (as applicable) the average determined during the performance test. 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 . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 1. Subject to NSPS for PM in 40 CFR 60.102. emcdonald on DSK67QTVN1PROD with PROPOSALS2 For each new or existing catalytic cracking unit . . . a. Continuous opacity monitoring system used to comply with 30 percent opacity limit.. b. Continuous parametric monitoring systems—electrostatic precipitator. Not applicable ............................... Complying with Table 6 of this subpart. 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 gas flow rate monitoring data according to § 63.1572; and maintaining the 3-hr rolling 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. The average total power and secondary current to the control device must not fall below the operating limit established during the performance test. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00139 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37018 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 parametric monitoring systems—wet scrubber. The average pressure drop across the scrubber must not fall below the operating limit established during the performance test. Collecting the hourly and 3-hr rolling average pressure drop monitoring data according to § 63.1572; and maintaining the 3-hr rolling average pressure drop 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. 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. 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 limit established during the performance test. See items 1.b, 1.c, 1.d, and 1.e of this table. The average liquid-to-gas ratio must not fall below the operating limit established during the performance test. d. BLD—fabric filter ...................... e. Continuous opacity monitoring system, used for site-specific opacity limit—Cyclone or electrostatic precipitator. emcdonald on DSK67QTVN1PROD with PROPOSALS2 2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii), electing to meet the PM per coke burn-off limit. 3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1), electing to meet the PM concentration limit. 4. Option 1: PM per coke burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1). VerDate Mar<15>2010 21:35 Jun 27, 2014 Increases in relative particulate .... The average opacity must not exceed the opacity established during the performance test. Any ................................................ Any ................................................ PM CEMS ..................................... Not applicable. .............................. Complying with Table 6 of this subpart. 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. Collecting the 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. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. Jkt 232001 PO 00000 Frm 00140 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37019 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 . . . b. Continuous parameter 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 gas flow rate monitoring data according to § 63.1572; and maintaining the 3-hr rolling average gas flow rate at or below the limit established during the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], collecting the hourly and daily average gas flow rate monitoring data according to § 63.1572; 1 and maintaining the daily 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 [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. Collecting the hourly and 3-hr rolling average pressure drop monitoring data according to § 63.1572; and maintaining the 3-hr rolling average pressure drop at or above the limit established during the performance test. Alternatively, before [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. ii. The average voltage and secondary current (or total power input) to the control device must not fall below the operating limit established during the performance test.. emcdonald on DSK67QTVN1PROD with PROPOSALS2 c. Continuous parameter monitoring systems—wet scrubber. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00141 Fmt 4701 i. The average pressure drop across the scrubber must not fall below the operating limit established during the performance test. Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37020 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . ii. The average liquid-to-gas ratio must not fall below the operating limit established during the performance test. If you use . . . 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 [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 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. 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 limit established during the performance test. Complying with Table 6 of this subpart. d. BLD—fabric filter ...................... e. Continuous opacity monitoring system, used for site-specific opacity limit—Cyclone or electrostatic precipitator. emcdonald on DSK67QTVN1PROD with PROPOSALS2 5. Option 2: PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or in 40 CFR 60.102a(b)(1).. 6. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40 CFR 60.102. VerDate Mar<15>2010 21:35 Jun 27, 2014 Increases in relative particulate .... The average opacity must not exceed the opacity established during the performance test. PM CEMS ..................................... Not applicable ............................... 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. Jkt 232001 PO 00000 Frm 00142 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM (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. 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37021 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 c. Continuous parameter monitoring systems—wet scrubber. d. BLD—fabric filter ...................... e. Continuous opacity monitoring system, used for site-specific opacity limit—Cyclone or electrostatic precipitator. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 You shall demonstrate continuous compliance by . . . For this operating limit . . . Frm 00143 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 voltage and secondary current (or total power input) 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 pressure drop must not fall below the operating limit established in the performance test. ii. The average liquid-to-gas ratio must not fall below the operating limit established during the performance test. iii. The monthly rolling average equilibrium catalyst Ni concentration must not exceed the level established during the performance test. Increases in relative particulate .... The average opacity must not exceed the opacity established during the performance test. Sfmt 4702 E:\FR\FM\30JNP2.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 [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 4.b.i of this table. See item 4.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 4.c.i of this table. See item 4.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 4.d of this table. See item 4.e of this table. 30JNP2 37022 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . 7. 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.. 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 daily average gas flow rate to the control device must not exceed the level established in the performance test. ii. The daily 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 daily average pressure drop must not fall below the operating limit established in the performance test. ii. The daily average liquid-to-gas ratio must not fall below the operating limit established during the performance test. iii. The monthly rolling average equilibrium catalyst Ni concentration must not exceed the level established during the performance test. Increases in relative particulate .... The average opacity must not exceed the opacity established during the performance test. (1) Collecting the hourly average continuous opacity monitoring system data according to § 63.1572; collecting the hourly average gas flow rate monitoring data according to § 63.1572; 1 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 [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 4.b.i of this table. c. Continuous parameter monitoring systems—wet scrubber. .................................................. emcdonald on DSK67QTVN1PROD with PROPOSALS2 .................................................. d. BLD—fabric filter ...................... e. Continuous opacity monitoring system, used for site-specific opacity limit—Cyclone or electrostatic precipitator. See item 4.b.ii of this table. See item 6.b.iii of this table. See item 4.c.i of this table. See item 4.c.ii of this table. See item 6.c.iii of this table. See item 4.d of this table. See item 4.e of this table. 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. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00144 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37023 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 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. 59. Table 8 to subpart UUU of part 63 is amended by revising the entry for item 2 to read as follows: * * * * * ■ 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 . . . * * 2. Not subject to the NSPS for CO in 40 CFR 60.103. * * * * * 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. 60. Table 9 to subpart UUU of part 63 is amended by revising the entry for item 2 to read as follows: * * * * * ■ TABLE 9 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING UNITS For this type of continuous monitoring system . . . * * 2. Not subject to the NSPS for CO in 40 CFR 60.103. emcdonald on DSK67QTVN1PROD with PROPOSALS2 For each new or existing catalytic cracking unit . . . For this type of control device . . . You shall meet this operating limit . . . * * * a. Continuous emission monitoring Not applicable ............................... system. b. Continuous parameter moni- i. Thermal incinerator .................... toring systems. 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. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00145 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM * Not applicable. * 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. 30JNP2 37024 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 9 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC 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 . . . iii. Flare ......................................... On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. 61. Table 10 to subpart UUU of part 63 is amended by revising the entry for item 2 to read as follows: * * * * * ■ 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 . . . * * 2. Not subject to the NSPS for CO in 40 CFR 60.103. emcdonald on DSK67QTVN1PROD with PROPOSALS2 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; 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 or boiler with a design heat Continuous emission monitoring system to measinput capacity under 44 MW or process heater ure and record the concentration by volume or boiler in which all vent streams are not intro(dry basis) of CO emissions from each catalyst duced into the flame zone. regenerator vent; or continuous parameter monitoring systems to measure and record the combustion zone temperature. c. Flare ................................................................... On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the monitoring systems required in §§ 63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. d. No control device ............................................... Continuous emission monitoring system to measure and record the concentration by volume (dry basis) of CO emissions from each catalyst regenerator vent. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00146 Fmt 4701 Sfmt 4702 You shall install, operate, and maintain this type of continuous monitoring system . . . E:\FR\FM\30JNP2.SGM 30JNP2 37025 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 62. Table 11 to subpart UUU of part 63 is amended by revising 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 . . . For . . . You must . . . Using . . . * * 3. Each catalytic cracking unit catalyst regenerator vent if you use continuous parameter monitoring systems. * * * a. Measure the CO concentration Method 10, 10A, or 10B in appen(dry basis) of emissions exiting dix A to part 60 of this chapter, the control device. as applicable. 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. f. If you use a flare, conduct visible emission observations. VerDate Mar<15>2010 21:35 Jun 27, 2014 Data from the continuous parameter monitoring systems. Data from the continuous parameter monitoring systems. * Data from the continuous parameter monitoring systems. d. Thermal incinerator: oxygen, content (percent, dry basis) in the incinerator vent stream. emcdonald on DSK67QTVN1PROD with PROPOSALS2 b. Establish each operating limit in Table 9 of this subpart that applies to you. c. Thermal incinerator combustion zone temperature. * Jkt 232001 PO 00000 Frm 00147 Fmt 4701 Data from the continuous parameter monitoring systems. Method 22 (40 CFR part 60, appendix A). Sfmt 4702 E:\FR\FM\30JNP2.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. On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. 30JNP2 37026 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 amended by revising the entry for item 2 to read as follows: * * * * * ■ TABLE 12 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS For the following emission limit . . . * * 2. Not subject to the NSPS for CO in 40 CFR 60.103. emcdonald on DSK67QTVN1PROD with PROPOSALS2 For each new and existing catalytic cracking unit . . . * * * * * a. CO emissions from your catalyst regenerator i. If you use a continuous parameter monitoring vent or CO boiler serving the catalytic cracking system, the average CO emissions measured unit must not exceed 500 ppmv (dry basis). by Method 10 over the period of the initial performance test are less than or equal to 500 ppmv (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 § 63.1572. b. If you use a flare, visible emissions must not On and after [THE DATE 3 YEARS AFTER THE exceed a total of 5 minutes during any 2 operDATE OF PUBLICATION OF THE FINAL ating hours. RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare meets the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. You have demonstrated initial compliance if . . . 64. Table 13 to subpart UUU of part 63 is amended by revising the entry for item 2 to read as follows: * * * * * ■ VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00148 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37027 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . * * 2. Not subject to the NSPS for CO in 40 CFR 60.103. * * * i. CO emissions from your catalyst Continuous emission monitoring regenerator vent or CO boiler system. serving the catalytic cracking unit must not exceed 500 ppmv (dry basis). ii. CO emissions from your cata- Continuous parameter monitoring lyst regenerator vent or CO boilsystem. er serving the catalytic cracking unit must not exceed 500 ppmv (dry basis). iii. Visible emissions from a flare Control device-flare ....................... must not exceed a total of 5 minutes during any 2-hour period. You shall demonstrate continuous compliance by . . . If you must . . * Same as above. * Maintaining the hourly average CO concentration below 500 ppmv (dry basis). On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], meeting the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], maintaining visible emissions below a total of 5 minutes during any 2-hour operating period, or meeting the requirements of § 63.670. 65. Table 14 to subpart UUU of part 63 is amended by revising the entry for item 2 to read as follows: * * * * * ■ TABLE 14 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING UNITS If you use . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . * 2. Not subject to the NSPS for CO in 40 CFR 60.103. * * a. Continuous emission monitoring system. * * Not applicable ..................................... * * Complying with Table 13 of this subpart. b. Continuous parameter monitoring systems—thermal incinerator. emcdonald on DSK67QTVN1PROD with PROPOSALS2 For each new existing catalytic cracking unit . . . 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. ii. The daily average oxygen concentration in the vent stream (percent, dry basis) must not fall below the level established during the performance test. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00149 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37028 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 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. d. Continuous parameter monitoring system—flare. The daily combustion zone temperature must not fall below the level established in 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. On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], meeting the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. 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. 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 . . . 1. Option 1 ...................................... * You shall meet this emission limit during initial catalyst depressuring and catalyst purging operations . . . On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], vent emissions to a flare that meets the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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: * * * * * emcdonald on DSK67QTVN1PROD with PROPOSALS2 ■ VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00150 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 * 37029 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. * * * * * * * 68. Table 17 to subpart UUU of part 63 is amended by revising the entry for item 1 to read as follows: * * * * * ■ 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the monitoring systems required in §§ 63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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: ■ ■ ■ * * a. Revising the column headings and b. Revising the entry for item 1. * * * The revisions read as follows: * * * * TABLE 18 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS You must . . . Using . . . According to these requirements . . . 1. Option 1: Vent to a flare. emcdonald on DSK67QTVN1PROD with PROPOSALS2 For each new or existing catalytic reforming unit . . . a. Conduct visible emission observations. Method 22 (40 CFR part 60, appendix A). On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER],2hour 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. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00151 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37030 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 18 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS—Continued For each new or existing catalytic reforming unit . . . You must . . . Using . . . According to these requirements . . . 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare meets the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. * * * * * * * 71. Table 20 to subpart UUU of part 63 is amended by revising the entry for item 1 to read as follows: * * * * * ■ TABLE 20 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS emcdonald on DSK67QTVN1PROD with PROPOSALS2 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. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00152 Fmt 4701 Sfmt 4702 You shall demonstrate continuous compliance during initial catalyst depressuring and catalyst purging operations by . . . On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], meeting the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], maintaining visible emissions from a flare below a total of 5 minutes during any 2 consecutive hours, or meeting the requirements of § 63.670. E:\FR\FM\30JNP2.SGM 30JNP2 37031 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 20 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS—Continued For each applicable process vent for a new or existing catalytic reforming unit . . . * * For this emission limit . . . * * You shall demonstrate continuous compliance during initial catalyst depressuring and catalyst purging operations by . . . * * * 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 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. * * * * You shall demonstrate continuous compliance during initial catalyst depressuring and purging operations by . . . On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], meeting the requirements of § 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 For . . . You shall meet this emission limit for each applicable catalytic reforming unit process vent during coke burn-off and catalyst rejuvenation . . . * * * 2. Each existing cyclic or continuous catalytic reforming unit. 3. Each new semi-regenerative, 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. Reduce uncontrolled emissions of HCl by 97 percent by weight or to a 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 emcdonald on DSK67QTVN1PROD with PROPOSALS2 ■ Items 2 through 4 and footnote 2 to read as follows: * * * * * TABLE 24 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR INORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS If you use this type of control device for your vent . . . VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 You shall install and operate this type of continuous monitoring system . . . Frm 00153 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37032 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 24 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR INORGANIC HAP EMISSIONS FROM CATALYTIC REFORMING UNITS—Continued If you use this type of control device for your vent . . . You shall install and operate this type of continuous monitoring system . . . * * * 2. Internal scrubbing system or no control device (e.g., hot regen system) to meet HCl outlet concentration limit. * * * * Colormetric tube sampling system to measure the HCl concentration in 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. 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 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. 3. Internal scrubbing system to meet HCl percent reduction standard. 4. Fixed-bed gas-solid adsorption system ......................... * * * * * * * * * * * * 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 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 . . . Using . . . According to these requirements . . . * 2. Wet scrubber .................. * * a. Establish operating limit for pH level or alkalinity. * i. Data from continuous parameter monitoring systems. * * * 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. 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. ii. Alternative pH procedure in § 63.1573 (b)(1). emcdonald on DSK67QTVN1PROD with PROPOSALS2 iii. Alternative alkalinity method in § 63.1573(c)(2). * 4. Internal scrubbing system meeting HCl percent reduction standard. VerDate Mar<15>2010 * * a. Establish operating limit for pH level or alkalinity. 21:35 Jun 27, 2014 Jkt 232001 PO 00000 * i. Data from continuous parameter monitoring system. Frm 00154 Fmt 4701 Sfmt 4702 * * * 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. E:\FR\FM\30JNP2.SGM 30JNP2 37033 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . You shall . . . Using . . . According to these requirements . . . ii. Alternative pH method in § 63.1573(c)(1). Measure and 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 of the 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. iii. Alternative alkalinity method in § 63.1573(c)(2). * * * * * * * * * * * * 76. Table 28 to subpart UUU of part 63 is amended by revising the entry for item 5 and footnote 1 to read as follows: ■ * The revisions 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 . . . * * 5. Moving-bed gas-solid adsorption system (e.g., ChlorsorbTM System. For this operating limit . . . You shall demonstrate continuous compliance during coke burn-off and catalyst rejuvenation by . . . * * * * * a. The daily average temperature Collecting the hourly and daily average temperature monitoring data of the gas entering or exiting the according to § 63.1572; and maintaining the daily average temperaadsorption system must not exture below the operating limit established during the performance ceed the limit established during test. the performance test. b. The weekly average chloride Collecting samples of the sorbent exiting the adsorption system three level on the sorbent entering the times per week (on non-consecutive days); and analyzing the samadsorption system must not exples for total chloride; 3 and determining and recording the weekly ceed the design or manufacturaverage chloride concentration; and maintaining the chloride coner’s recommended limit (1.35 centration below the design or manufacturer’s recommended limit weight percent for the (1.35 weight percent for the ChlorsorbTM System). ChlorsorbTM System). c. The weekly average chloride Collecting samples of the sorbent exiting the adsorption system three level on the sorbent exiting the times per week (on non-consecutive days); and analyzing the samadsorption system must not exples for total chloride concentration; and determining and recording ceed the design or manufacturthe weekly average chloride concentration; and maintaining the er’s recommended limit (1.8 chloride concentration below the design or manufacturer’s recweight percent for the ommended limit (1.8 weight percent ChlorsorbTM System). ChlorsorbTM System). emcdonald on DSK67QTVN1PROD with PROPOSALS2 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. * * * * * 77. Table 29 to subpart UUU of part 63 is revised to read as follows: ■ VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 As stated in § 63.1568(a)(1), you shall meet each emission limitation in the following table that applies to you. PO 00000 Frm 00155 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37034 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 long tons per day and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or in 40 CFR 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. 2. 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 in 40 CFR 60.102a(f)(1): Option 1 (Elect NSPS). 3. 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 in 40 CFR 60.102a(f)(1): Option 2 (TRS limit). 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. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 long tons per day and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or in 40 CFR 60.102a(f)(1). 2. 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 in 40 CFR 60.102a(f)(1): Option 1 (Elect NSPS). 3. 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 in 40 CFR 60.102a(f)(1): Option 2 (TRS limit), if using continuous emissions monitoring systems. 4. 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 in 40 CFR 60.102a(f)(1): Option 2 (TRS limit), if using continuous parameter monitoring systems. Not applicable ............. Not applicable. Not applicable ............. Not applicable. Not applicable ............. Not applicable. 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. 79. Table 31 to subpart UUU is revised to read as follows: ■ As stated in § 63.1568(b)(1), you shall meet each requirement in the following table that applies to you. emcdonald on DSK67QTVN1PROD with PROPOSALS2 TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS For . . . For this limit . . . You shall install and operate this continuous monitoring system . . . 1. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 long tons per day and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or in 40 CFR 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. 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 Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00156 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37035 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. Complete either item 1.a or item 1.b; and you must also install and operate a continuous emission monitoring system to measure and record the O2 concentration for the inlet air/ oxygen supplied to the system. 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. Complete either item 2.a or item 2.b; and you must also install and operate a continuous emission monitoring system to measure and record the O2 concentration for the inlet air/ oxygen supplied to the system. 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 paragraph (a) (2) of 40 CFR 60.104 or in 40 CFR 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 in 40 CFR 60.102a(f)(1). 300 ppmv of total reduced sulfur (TRS) compounds, expressed as an equivalent SO2 concentration (dry basis) at zero percent oxygen. 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. ■ VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00157 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37036 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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. Each new and existing sulfur recovery unit: Option 1 (Elect NSPS). 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. 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. 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. Data from continuous emission monitoring system. 2. Each new and existing sulfur recovery unit: Option 2 (TRS limit), using CEMS. Measure the concentration of reduced sulfur (or SO2 if you use an instrument to convert the reduced sulfur to SO2). Data from continuous emission monitoring system. 3. Each new and existing sulfur recovery unit: Option 2 (TRS limit), if using continuous parameter monitoring systems. 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. 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 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. 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, 2F, or 2G in appendix A to part 60 of this chapter, as applicable. Method 3, 3A, or 3B in appendix A 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 to part 60 of this chapter. emcdonald on DSK67QTVN1PROD with PROPOSALS2 e. Measure the concentration of TRS. 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. VerDate Mar<15>2010 21:35 Jun 27, 2014 Method 15 or 15A in appendix A to part 60 of this chapter, as applicable. Take the samples simultaneously with reduced sulfur or moisture samples. 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. Jkt 232001 PO 00000 Frm 00158 Fmt 4701 Data from the continuous parameter monitoring system. Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37037 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 You must . . . Using . . . According to these requirements . . . i. Measure thermal incinerator: combustion zone temperature. Data from the continuous parameter monitoring system. j. Measure thermal incinerator: oxygen concentration (percent, dry basis) in the vent stream. For . . . 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. 81. Table 33 to subpart UUU of part 63 is revised to read as follows: ■ As stated in § 63.1568(b)(5), you shall meet each requirement in the following table that applies to you. 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. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 long tons per day and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or in 40 CFR 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 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 in 40 CFR 60.102a(f)(1). VerDate Mar<15>2010 21:35 Jun 27, 2014 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. Jkt 232001 PO 00000 Frm 00159 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37038 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 33 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY UNITS—Continued For the following emission limit . . . For . . . 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 in 40 CFR 60.102a(f)(1). You have demonstrated initial compliance if . . . 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 TRS compounds expressed as an equivalent SO2 concentration (dry basis) at zero percent oxygen. 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. 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. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 long tons per day and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or in 40 CFR 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) according to § 63.1572; determining and recording each 12-hour rolling average concentration of SO2; maintaining each 12hour 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. 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 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. 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. Collecting the hourly average reduced sulfur (and air or O2 dilution and oxidation) 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 12-hour rolling average concentration of reduced sulfur greater than the applicable emission limitation in the semiannual compliance report required by § 63.1575. Collecting the hourly average SO2 data (dry basis, percent excess air) according to § 63.1572; determining and recording each 12hour rolling average concentration of SO2; maintaining each 12hour 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 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 12-hour 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 emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 in 40 CFR 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 in 40 CFR 60.102a(f)(1). VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00160 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37039 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 . . . 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. 83. Table 35 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 35 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS For . . . For this operating limit . . . You shall demonstrate continuous compliance by . . . 1. Each new or existing Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater than 20 long tons per day and subject to the NSPS for sulfur oxides in paragraph 40 CFR 60.104(a)(2) or in 40 CFR 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 in 40 CFR 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 in 40 CFR 60.102a(f)(1). Not applicable ................................ Meeting the requirements of Table 34 of this subpart. 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. b. The daily average oxygen concentration in the vent stream (percent, dry basis) must not fall below the level 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. 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 emcdonald on DSK67QTVN1PROD with PROPOSALS2 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. CO2, O2, and CO monitors for coke burn-off rate. 4. CO continuous emission monitoring system .. Performance specification 1 (40 CFR part 60, Appendix B). The requirements in 40 CFR 60.105a(d). VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 The requirements in 40 CFR 60.105a(b)(2). 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. PO 00000 Frm 00161 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37040 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 . . . 5. CO continuous emission monitoring system used to demonstrate emissions average under 50 ppm (dry basis). 6. 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. Performance specification 4 (40 CFR part 60, Appendix B); and span value of 100 ppm. 7. 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. 8. 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. 9. TRS continuous emission monitoring system for sulfur recovery unit; this monitor must include an O2 monitor for correcting the data for excess air. 10. O2 monitor for oxygen concentration ............ 11. O2 monitor for oxygen concentration in inlet or supply. 85. Table 41 to subpart UUU of part 63 is revised to read as follows: ■ 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. 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 for certifying the reduced sulfur monitor and 3A or 3B 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). 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. Install, operate, and maintain each O2 monitor according to Performance Specification 3 of Appendix B to part 60; the span value for the O2 monitor must be selected between 20 and 100 percent; conduct performance evaluations for O2 monitor according to Performance Specification 3 of Appendix B to part 60, and must use Method 3A or 3B of Appendix A–2 to part 60 for conducting relative accuracy evaluations; comply with applicable quality assurance procedures of Appendix F to part 60 for each monitor, including annual accuracy determinations for each O2 monitor and daily calibration drift determinations. 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 You shall . . . 1. pH strips ...................................... 2. pH meter ..................................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 If you use . . . 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. Follow the requirements in 40 CFR 60.105a(c). Use meters with an accuracy of at least ± 5 percent over the operating range. 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 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; and record the results of each calibration check and inspection. 3. Colormetric tube sampling system. 4. BLD ............................................. 5. Voltage, secondary current, or total power input sensors. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00162 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37041 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 . . . 6. Pressure/Pressure drop 1 sensors. Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure; minimizes or eliminates pulsating pressure, vibration, and internal and external corrosion. Use a gauge with an accuracy of at least ± 5 percent over the operating range or 0.5 inches of water column, whichever is greater. Check pressure tap for plugs at least once a week; using a manometer, check gauge calibration quarterly and transducer calibration monthly; conduct calibration checks following any period of more than 24 hours throughout which the sensor exceeds the manufacturer’s specified maximum operating pressure range or install a new pressure sensor; at least monthly, inspect all components for integrity, all electrical connections for continuity, and all mechanical connections for leakage; 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, or 0.5 gallons per minute for liquid flow, or 10 cubic feet per minute for gas flow, whichever is greater. Conduct a flow sensor calibration check at least semiannually; conduct calibration checks following any period of more than 24 hours throughout which the sensor exceeds the manufacturer’s specified maximum operating range or install a new flow sensor; at least monthly, inspect all components for leakage; 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 of the temperature being 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 sensor exceeds the manufacturer’s specified maximum operating temperature range, or install a new temperature sensor; at least monthly, inspect all components for integrity and all electrical connections for continuity, oxidation, and galvanic corrosion; 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. Conduct calibration checks at least quarterly; conduct calibration checks following any period of more than 24 hours throughout which the sensor exceeds the manufacturer’s specified maximum operating range, or install a new oxygen sensor; at least monthly, inspect all components for integrity and all electrical connections for continuity; record the results of each calibration and inspection. 7. Air flow rate, gas flow rate, or total water (or scrubbing liquid) flow rate sensors. 8. Temperature sensors .................. 9. Oxygen content sensors 2 ........... 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. These requirements 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: ■ As stated in § 63.1575(a), you shall meet each requirement in the following table that applies to you. TABLE 43 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR REPORTS The report must contain . . . You shall submit the report . . . 1. A compliance report .................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 You must submit . . . If there are not 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00163 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM Within 60 days after the date of completing each test according to the requirements in § 63.1575(k). 30JNP2 37042 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 87. Table 44 to subpart UUU of part 63 is revised to read as follows: 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] ......................... § 63.1(b)(1) .......................... Initial Applicability Determination for this part. [Reserved] ......................... § 63.1(b)(2) .......................... § 63.1(b)(3) .......................... § 63.1(c)(1) ........................... § 63.1(c)(2) ........................... § 63.1(c)(3)–(4) .................... § 63.1(c)(5) ........................... § 63.1(d) ............................... § 63.1(e) ............................... § 63.2 ................................... § 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) .................... § 63.5(b)(5) .......................... § 63.5(b)(6) .......................... § 63.5(c) ............................... § 63.5(d)(1)(i) ....................... Applicability of this part after a Relevant Standard has been set under this part. [Reserved] ......................... [Reserved] ......................... Applicability of Permit Program. Definitions .......................... Units and Abbreviations .... Prohibited Activities [Reserved] ......................... Circumvention and Fragmentation. Construction and Reconstruction [Reserved] ......................... [Reserved] ......................... [Reserved] ......................... Application for Approval of Construction or Reconstruction—General Application Requirements. Not applicable Yes .................................... Except the correct mail drop (MD) number is C404– 04. Except that subpart UUU specifies calendar or operating day. Yes Not applicable Yes Yes No ...................................... Not applicable Yes Not applicable Yes Area sources are not subject to subpart UUU. Yes .................................... § 63.1579 of subpart UUU specifies that if the same term is defined in subparts A and UUU, it shall have the meaning given in subpart UUU. Yes Yes .................................... Not applicable Yes Yes Yes Not applicable Yes .................................... Not applicable Yes Not applicable Yes .................................... § 63.5(d)(1)(ii) ...................... Yes .................................... § 63.5(d)(1)(iii) ...................... No ...................................... § 63.5(d)(2) .......................... § 63.5(d)(3) .......................... § 63.5(d)(4) .......................... § 63.5(e) ............................... In § 63.5(b)(4), replace the reference to § 63.9(b) with § 63.9(b)(4) and (5). Except subpart UUU 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. 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. Subpart UUU specifies submission of notification of compliance status. Yes Yes Yes Yes § 63.5(f)(1) ........................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 Explanation Approval of Construction or Reconstruction. Approval of Construction or Reconstruction Based on State Review. § 63.5(f)(2) ........................... § 63.6(a) ............................... § 63.6(b)(1)–(4) .................... Yes .................................... Compliance with Standards and Maintenance—Applicability. Compliance Dates for New and Reconstructed Sources. § 63.6(b)(5) .......................... § 63.6(b)(6) .......................... VerDate Mar<15>2010 21:35 Jun 27, 2014 Yes Yes Yes Yes .................................... [Reserved] ......................... Jkt 232001 PO 00000 Except that the cross-reference to § 63.9(b)(2) does not apply. Except that subpart UUU specifies different compliance dates for sources. Not applicable Frm 00164 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37043 TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— Continued Citation Subject § 63.6(b)(7) .......................... Compliance Dates for New and Reconstructed Area Sources That Become Major. Compliance Dates for Existing Sources. Yes [Reserved] ......................... Compliance Dates for Existing Area Sources That Become Major. [Reserved] ......................... General Duty to Minimize Emissions. Requirement to Correct Malfunctions as Soon as Possible. Compliance with Standards and Maintenance Requirements. [Reserved] ......................... Startup, Shutdown, and Malfunction Plan Requirements. [Reserved] ......................... Not applicable Yes § 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) ............ Applies to subpart UUU SSM Exemption ................. Compliance with Standards and Maintenance Requirements. § 63.6(f)(2)(iii)(D) .................. § 63.6(f)(2)(iv)–(v) ................ § 63.6(f)(3) ........................... § 63.6(g) ............................... § 63.6(h)(1) .......................... § 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) ...................... § 63.6(h)(7)(iii) ...................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 § 63.6(h)(7)(iv) ..................... § 63.6(h)(7)(v) ...................... § 63.6(h)(8) .......................... § 63.6(h)(9) .......................... § 63.6(i)(1)–(14) ................... § 63.6(i)(15) .......................... § 63.6(i)(16) .......................... VerDate Mar<15>2010 21:35 Jun 27, 2014 Yes .................................... Not applicable No ...................................... [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. 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 .. [Reserved] ......................... Jkt 232001 PO 00000 Except that subpart UUU specifies different compliance dates for sources subject to Tier II gasoline sulfur control requirements. See § 63.1570(c) for general duty requirement. No Yes Not applicable No Not applicable No No Yes Yes Yes Yes .................................... Alternative Standard .......... SSM Exemption for Opacity/VE Standards. Determining Compliance with Opacity/VE Standards. [Reserved] ......................... Explanation Except the cross-references to § 63.6(f)(1) § 63.6(e)(1)(i) are changed to § 63.1570(c). and Yes No No ...................................... Subpart UUU specifies methods. Not applicable Yes Not applicable Yes .................................... Applies to Method 22 tests. No Yes .................................... Applies to Method 22 observations. Yes No Yes Yes Yes Yes Yes Yes .................................... 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). Not applicable Yes Frm 00165 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37044 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— Continued Citation Subject § 63.6(j) ................................ § 63.7(a)(2) .......................... Presidential Compliance Exemption. Performance Test Requirements Applicability. 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. Performance Test Facilities Performance Testing ......... Conduct of Tests ............... Alternative Test Method .... Data Analysis, Recordkeeping, Reporting. Yes § 63.7(a)(1) .......................... § 63.7(d) ............................... § 63.7(e)(1) .......................... § 63.7(e)(2)–(4) .................... § 63.7(f) ................................ § 63.7(g) ............................... § 63.7(h) ............................... § 63.8(a)(1) .......................... § 63.8(a)(2) .......................... § 63.8(a)(3) .......................... § 63.8(a)(4) .......................... § 63.8(b)(1) .......................... § 63.8(b)(2)–(3) .................... Waiver of Tests ................. Monitoring Requirements— Applicability. Performance Specifications [Reserved] ......................... Monitoring with Flares ....... Explanation Yes Yes .................................... Yes No ...................................... Yes Yes Yes .................................... Except that subpart UUU 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 subpart UUU specifies notification at least 30 days prior to the scheduled test date rather than 60 days. 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. Yes Yes Yes Not applicable Yes .................................... 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. Monitoring System Installation. Yes Yes .................................... 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 § 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 .................................... Except that for a flare complying with § 63.670, the cross-reference to § 63.11 in this paragraph does not include § 63.11(b). Yes § 63.8(c)(1) ........................... § 63.8(c)(1)(i) ....................... § 63.8(c)(1)(ii) ....................... § 63.8(c)(1)(iii) ...................... § 63.8(c)(2)–(3) .................... § 63.8(c)(4) ........................... § 63.8(c)(5) ........................... § 63.8(c)(6) ........................... § 63.8(c)(7)–(8) .................... § 63.8(d)(1)–(2) .................... § 63.8(d)(3) .......................... emcdonald on DSK67QTVN1PROD with PROPOSALS2 Applies to subpart UUU § 63.8(e) ............................... VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Subpart UUU specifies the required monitoring locations. Yes No ...................................... See § 63.1570(c). Yes No Yes .................................... Except that subpart UUU 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. Yes No Yes .................................... Frm 00166 Fmt 4701 Sfmt 4702 Except that results are to be submitted as part of the Notification Compliance Status due 150 days after the compliance date. Except that subpart UUU 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. E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37045 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(g)(5) .......................... § 63.9(a) ............................... Data Reduction .................. Notification Requirements—Applicability. Initial Notifications ............. No ...................................... Yes .................................... Subpart UUU 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. [Reserved] ......................... Initial Notification Information. Request for Extension of Compliance. New Source Notification for Special Compliance Requirements. Notification of Performance Test. Notification of VE/Opacity Test. Additional Notification Requirements for Sources with Continuous Monitoring Systems. Notification of Compliance Status. Not applicable Yes .................................... Adjustment of Deadlines ... Change in Previous Information. Recordkeeping and Reporting Applicability. General Recordkeeping Requirements. Recordkeeping of Occurrence and Duration of Startups and Shutdowns. Recordkeeping of Malfunctions. Yes Yes 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. Additional CMS Recordkeeping Requirements. Use of SSM Plan ............... General Reporting Requirements. Yes No § 63.9(b)(1)–(2) .................... § 63.9(b)(3) .......................... § 63.9(b)(4)–(5) .................... § 63.9(c) ............................... § 63.9(d) ............................... § 63.9(e) ............................... § 63.9(f) ................................ § 63.9(g) ............................... § 63.9(h) ............................... § 63.9(i) ................................ § 63.9(j) ................................ 63.10(a) ............................... § 63.10(b)(1) ........................ § 63.10(b)(2)(i) ..................... § 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) .................. emcdonald on DSK67QTVN1PROD with PROPOSALS2 § 63.10(c)(7)–(8) .................. § 63.10(c)(9) ......................... § 63.10(c)(10) ....................... § 63.10(c)(11) ....................... § 63.10(c)(12)–(14) .............. § 63.10(c)(15) ....................... § 63.10(d)(1) ........................ VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Yes .................................... Except § 63.9(b)(4)(ii)–(iv), which are Reserved and do not apply. Yes Yes Yes .................................... Except that notification is required at least 30 days before test. Yes Yes Yes .................................... Except that subpart UUU 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 Yes No No ...................................... 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 Yes Yes Yes .................................... Except § 63.10(c)(2)–(4), which are Reserved and do not apply. Yes Not applicable No ...................................... No ...................................... See § 63.1576(a)(2) for malfunctions recordkeeping requirements. See § 63.1576(a)(2) for malfunctions recordkeeping requirements. Yes No Yes Frm 00167 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 37046 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU— Continued Citation Subject Applies to subpart UUU Explanation § 63.10(d)(2) ........................ Performance Test Results No ...................................... Subpart UUU requires performance test results to be reported as part of the Notification of Compliance Status due 150 days after the compliance date. § 63.10(d)(3) ........................ Yes § 63.10(d)(4) ........................ § 63.10(d)(5) ........................ Opacity or VE Observations. Progress Reports .............. SSM Reports ..................... 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 ...................................... § 63.10(e)(4) ........................ § 63.10(f) .............................. § 63.11(a) ............................. § 63.11(b) ............................. § 63.11(c)-(e) ....................... § 63.12 ................................. § 63.13 ................................. § 63.14 ................................. § 63.15 ................................. § 63.16 ................................. Alternative Work Practice for Monitoring Equipment for Leaks. State Authority and Delegations. Addresses .......................... Incorporation by Reference Availability of Information and Confidentiality. Performance Track Provisions. * * * 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. * * * emcdonald on DSK67QTVN1PROD with PROPOSALS2 * * * * * 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. * * * * * Appendix A to Part 63—[AMENDED] 89. Appendix A to part 63 is amended by adding Method 325A and Method 325B to read as follows: ■ VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 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 Sampler Deployment and VOC Sample Collection Appendix A to Subpart UUU of Part 63—Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure) * Yes Yes Method 325A—Volatile Organic Compounds From Fugitive and Area Sources 88. Appendix A to subpart UUU of part 63 is amended by: ■ a. Revising the first sentence of section 2.1; and ■ b. Revising section 7.1.3. The revisions read as follows: ■ * 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. Subpart UUU specifies the applicable requirements. 1.0 Scope and Application 1.1 This method describes collection of volatile organic compounds (VOCs) at 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 and 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 unless the compound or sorbent has already been validated and reported in one of the following national/international standard methods: ISO 16017–2:2003 (incorporated by reference—see § 63.14), ASTM D6196– 03(2009) (incorporated by reference—see PO 00000 Frm 00168 Fmt 4701 Sfmt 4702 § 63.14), or BS EN 14662–4:2005 (incorporated by reference—see § 63.14), or 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 (mg/m3) to at least 500 mg/m3 when industry standard (3.5 inch long x 0.25 inch outside diameter (o.d.) x 5 mm inner diameter (i.d.)) stainless steel sorbent tubes packed with Carbograph 1 TDTM, Carbopack BTM, or Carbopack 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 over an extended period of time using multiple sampling episodes (e.g., 26 x 14-day sampling episodes). The duration of each sampling period must be 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. E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 the fenceline or facility 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 the facility fenceline or property boundaries and collection of local meteorological data. It may be used to determine average concentration of VOC at a facility fenceline or property boundaries 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 VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 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. 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 Retention volume is the maximum mass of VOC that can be collected before the capacity of the sorbent is exceeded and back diffusion of the VOC from the tube occurs. 3.8 Sampling episode is the length of time each passive sampler is exposed during field monitoring. The sampling episode for this method is 14 days. 3.9 Sorbent tube (Also referred to as tube, PS tube, sorbent tube, and sampling tube) is a stainless steel or inert coated stainless steel tube. Standard PS tube dimensions for this method are 3.5-inch (89 mm) long x 0.25inch (6.4 mm) o.d. stainless steel tubes 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. General guidance for siting can be found in EPA–454/B–13–003, Quality Assurance Handbook for Air Pollution Measurement Systems, Volume II: Ambient Air Quality Monitoring Program, May 2013 PO 00000 Frm 00169 Fmt 4701 Sfmt 4702 37047 (Reference 3) (incorporated by reference—see § 63.14). 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 excludes 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 °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 retention E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules volume (i.e., 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 emcdonald on DSK67QTVN1PROD with PROPOSALS2 This section describes the equipment and supplies needed to deploy passive sampling monitoring equipment at a facility fenceline or property boundary. Details of the passive sampling tubes themselves and equipment 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 (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 VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 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 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 that 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 (2009) (Reference 14) (incorporated by reference—see § 63.14) and ISO 16017–2:2003 (Reference 13) (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). the performance requirements of Method 325A/B and must be submitted with the test plan for your measurement program. 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 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 PO 00000 Frm 00170 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.026</GPH> 37048 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37049 size of the area (or subarea) or at different distances based on the size and boundary 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. 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. 8.2.2.1.1 For regularly shaped facilities with an area of less than or equal to 750 acres, measure angles around the center point of 30 degrees for a total of twelve 30 degree measurements. 8.2.2.1.2 For regularly shaped facilities covering an area greater than 750 acres but less than or equal to 1,500 acres, measure from the center point angles of 20 degrees for a total of eighteen 20 degree measurements. 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. 8.2.2.1.4 Place samplers securely on a pole or supporting structure at 1.5 to 3 meters above ground level at each point just beyond the intersection where the measured angle intersects the property boundary. 8.2.2.1.5 Extra samplers must be placed near known sources of VOCs at the test facility. In the case that a potential emission source is within 50 meters of the property 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) to provide sufficient coverage of all area sources. 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 VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00171 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.027</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 (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, Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final), March 2008 (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 boundary. You will place passive samplers on the facility property boundary at different angles circling the geometric center of the facility based on the 37050 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules of 30 degrees from the center point for a total of twelve 30 degree measurements. center for a total of twenty-four 15 degree measurements. 8.2.2.3 Locate each sampling point just beyond the intersection of the measured angle and the outer property boundary. 8.2.2.4 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 more than one point along the subarea’s outer boundary. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00172 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.028</GPH> 8.2.2.2.1 If a subarea is less than or equal to 750 acres (e.g., Figure 8.2), measure angles 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 8.3), measure angles of 20 degrees from the center point for a total of eighteen 20 degree measurements. 8.2.2.2.3 If a subarea is greater than 1,500 acres, measure angles of 15 degrees from the emcdonald on DSK67QTVN1PROD with PROPOSALS2 determine the geometric center point of each of the subareas. Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 8.2.3.2 For facilities with a boundary length greater than 24,000 feet, sampling locations are spaced 2,000 ±250 feet apart. 8.2.3.4 Place samplers securely on a pole or supporting structure at 1.5 to 3 meters above ground level. 8.2.3.5 Extra samplers must be placed near known sources of VOCs at the test facility. In the case that a potential emission PO 00000 Frm 00173 Fmt 4701 Sfmt 4702 source is within 50 meters of the property 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 8.4, the facility added three additional monitors (i.e., light shaded sampler locations) to provide sufficient coverage of all area sources. E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.029</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 8.2.3 Option 2 for Determining Sampling Locations. 8.2.3.1 For facilities with a boundary length of less than 24,000 feet, a minimum of twelve sampling locations evenly spaced ± 10 percent of the location interval is required. 37051 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 8.3 Siting a Meteorological Station. A dedicated 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, Meteorological Monitoring Guidance for Regulatory Modeling Applications, February 2000 (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. 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 from large paved areas. 8.3.4 Collect and record meteorological data, including wind speed, wind direction, and temperature and average data on an hourly basis. Collect daily unit vector wind direction data plus average temperature and barometric pressure measurements of the VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 sampled air to enable calculation of concentrations at standard conditions. 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 from 48 hours 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. The sampling tubes must 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. PO 00000 Frm 00174 Fmt 4701 Sfmt 4702 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 at a height of 1.5 to 2 meters 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 at at least one monitoring location during each field monitoring exercise. 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.) 8.5.9 Expose the sampling tubes for the 14-day sampling period. 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. One field blank tube is required for every 10 sampled tubes on a monitoring exercise. No E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.030</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 37052 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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. 8.6.6 Collect daily unit vector wind direction data plus average temperature and barometric pressure measurements to enable calculation of concentrations at standard conditions. You must supply this information to the laboratory with the samples. 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 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 episodes 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 VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 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 PO 00000 Frm 00175 Fmt 4701 Sfmt 4702 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, Quality Assurance Handbook for Air Pollution Measurement Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final), 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) can be calculated for any specified period at each PS location using Equation 12.1. 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. 12.3.3 Information on published or documented events on- and off-site may also be included in the associated sampling episode report to explain elevated concentrations if relevant. For example, you E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.031</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 less than two field blanks should be collected, regardless of the size of the monitoring study. Record the tube number(s) for the field blank(s) on the field sample data sheet. 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 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 37053 37054 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 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. 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 emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 Measurement Systems, Volume II: Ambient Air Quality Monitoring VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 Program, EPA–454/B–13–003, May 2013. Available at https://www.epa.gov/ ttnamti1/files/ambient/pm25/qa/QAHandbook-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. PO 00000 Frm 00176 Fmt 4701 Sfmt 4702 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, 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(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\30JNP2.SGM 30JNP2 EP30JN14.033</GPH> 37055 VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00177 Fmt 4701 Sfmt 4725 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.032</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37056 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Method 325B—Volatile Organic Compounds From Fugitive and Area Sources emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 Carbopack X or equivalent 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 a given compound or set of the compounds listed in 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 Appendix A to this method unless the compound or sorbent has already been validated and reported in one of the following national/ international standard methods: ISO 16017– 2:2003(incorporated by reference—see § 63.14), ASTM D6196–03(2009) (incorporated by reference—see § 63.14), or BS EN 14662–4:2005 (incorporated by reference—see § 63.14), or in the peerreviewed 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. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 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 desorping the sampling tube, refocusing on a focusing trap, desorping 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 back diffusion becomes significant—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 Calibration verification sample. 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. PO 00000 Frm 00178 Fmt 4701 Sfmt 4702 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 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 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. 3.10 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. 3.11 o.d. is outer diameter. 3.12 ppbv is parts per billion by volume. 3.13 Retention volume is the volume of gas required to move an analyte vapor plug through the sorbent tube at a given temperature during active (pumped) sampling. Note that retention volume provides another measure of the strength of sorbent:sorbate (analyte) affinity and is closely related to breakthrough volume—See discussion in Section 3.2 above. 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 means 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 polymer 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. E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37057 nitrile gloves to prevent contamination with body oils, hand lotions, perfumes, etc. 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. 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 only be used for tube conditioning only 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. 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 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 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 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 VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 5.0 PO 00000 Safety Frm 00179 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.034</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 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 37058 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 through the septum of a conventional GC 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. Highresolution, 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. 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 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 VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 (incorporated by reference—see § 63.14) or ASTM D6196–03(2009) (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 unless the compound or sorbent has already been validated and reported in one of the following national/international standard methods: ISO 16017–2:2003 (incorporated by reference—see § 63.14), ASTM D6196– 03(2009) (incorporated by reference—see § 63.14), or BS EN 14662–4:2005 (incorporated by reference—see § 63.14)—or 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. 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 yearly 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 PO 00000 Frm 00180 Fmt 4701 Sfmt 4702 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 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, 99.999percent or higher purity helium as carrier E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 37059 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 temperature (°C) Sampling sorbent emcdonald on DSK67QTVN1PROD with PROPOSALS2 Carbotrap C® ............................................................................................................. Carbopack C® Anasorb® GCB2 Carbograph 1 TD Carbotrap® Carbopack B® Anasorb® GCB1 Tenax® TA ................................................................................................................. Carbopack® 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 samplers will also be required: Laboratory blanks as specified in Section 9.3.2 (two per sampling episode minimum), field blanks as specified in Section 9.3.4 (two per sampling episode minimum), calibration verification tubes as specified in Section 10.9.4. (at least one per analysis sequence or every 24 hours), and paired (duplicate) samples as specified in Section 9.4 (at least one pair of duplicate samples 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 longterm storage cap at the sampling end of the tube is replaced with a diffusion cap and the whole assembly is arranged vertically, with VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 Fmt 4701 Sfmt 4702 350 100 mL/min. 350 9.0 Quality Control 9.1 Analytical System Blank. The analytical system must be demonstrated to be contaminant free by carrying out an analysis without a sorbent tube—i.e., by desorbing an empty tube or by desorbing the focusing trap alone. Since no internal standards can be added directly to the empty tube, the system blank must have less than or equal to 0.2 ppbv or three times the detection limit for each target compound, whichever is larger based on the response factors for the Frm 00181 Carrier gas flow rate >400 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 inside the refrigerator must be clean and free of organic solvents. PO 00000 Conditioning temperature (°C) 330 100 mL/min. continuing calibration verification sample. Perform a system 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. Flag all sample data from analytical sequences that fail the system blank check and provide a narrative on how the failure affects the data use. 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 (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 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 and Laboratory Blanks. 9.3.1 Field and laboratory 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 At least two laboratory blanks are required per monitoring episode. These laboratory blanks must be stored in the laboratory under clean controlled ambient temperature conditions throughout the monitoring period. Analyze one laboratory blank at the beginning and one at the end of the associated field sample runs. 9.3.3 Laboratory blank/artifact levels must meet the requirements of Section 9.2.2 (see also Table 17.1). Flag all data that do not meet this criterion with a note that associated results are estimated, and likely to be biased high due to laboratory blank background. E:\FR\FM\30JNP2.SGM 30JNP2 37060 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 daily single-level calibration verification checks may also be applied for this purpose. 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. 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. 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 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 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 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 hg 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. VerDate Mar<15>2010 21:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00182 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.036</GPH> EP30JN14.037</GPH> deviation for the seven replicate concentrations, and multiply this value by three. The results should demonstrate that the method is able to measure analytes such as benzene at concentrations as low as 10 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 routine, singlelevel calibration verification 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. EP30JN14.035</GPH> 9.4 Duplicate Samples. Duplicate (collocated) 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 Limit of Detection. Determine the limit of detection under the analytical conditions selected (see Section 11.3) using the procedure in Section 15 of Method 301. The limit of detection 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 Where: Spiked Value = A known mass of VOCs added to the tube. Measured Value = Mass determined from analysis of the tube. emcdonald on DSK67QTVN1PROD with PROPOSALS2 9.3.4 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 (see Method 325B). The long-term storage caps must be in place and must be stored outside the shipping container at the sampling location (see Method 325B). 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. 9.3.5 Field blanks must contain no greater than one-third of the measured target analyte or compliance limit for field samples (see Table 17.1). 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. Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37061 TABLE 9.1—GC/MS TUNING CRITERIA 1 Target mass Rel. to mass 50 ........................................................................................................................... 75 ........................................................................................................................... 95 ........................................................................................................................... 96 ........................................................................................................................... 173 ......................................................................................................................... 174 ......................................................................................................................... 175 ......................................................................................................................... 176 ......................................................................................................................... 177 ......................................................................................................................... Lower limit % 95 95 95 95 174 95 174 174 176 8 30 100 5 0 50 4 93 5 Upper limit % 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 9.13 Routine Calibrations Checks at the Start of a Sequence. Run single-level calibration checks 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 routine calibration check 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 daily calibration standard. The percent deviation between the initial calibration and the daily calibration check for all compounds must be within 30 percent. 9.14 Calibration Verification at the End of a Sequence. Run another single level standard after running each sequence of samples. The initial calibration check for a subsequent set of samples may be used as the final calibration check 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 calibration verification. 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, VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 5.0 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 ml aliquots of liquid standards to the sampling end of sorbent tubes in a flow of carrier gas using a precision syringe and an unheated injector (Section 6.6). 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 PO 00000 Frm 00183 Fmt 4701 Sfmt 4702 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 and allowed to warm to the temperature of the injection body. The liquid is then quickly injected. The result is the cool liquid contacts the hot syringe tip and the sample is completely forced into the injector and onto the sorbent cartridge. A bias occurs with this method when sample is drawn continuously up into the syringe to the specified volume 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 E:\FR\FM\30JNP2.SGM 30JNP2 37062 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules should be refrigerated if there is any risk of chemical interaction or degradation. 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 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 single-level calibration verification 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 Single-level calibrations checks must be carried out on a regular routine basis as described in Section 9.6. 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. performance criteria given in Section 9.1 and relevant parts of Section 9.5. 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 TABLE 10.1—CLEAN AIR ACT VOLATILE ORGANIC COMPOUNDS FOR PASSIVE SORBENT SAMPLING Compound 1,1-Dichloroethene ............... 3-Chloropropene .................. 1,1,2-Trichloro-1,2,2trifluoroethane ................... 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 ............... a Pressure b Molecular emcdonald on DSK67QTVN1PROD with PROPOSALS2 11.0 75–35–4 107–05–1 32 44.5 ........................ 75–34–3 .......................... 57.0 107–06–2 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 MW b Primary 500 340 96.9 76.5 61 76 96 41, 39, 78 .......................... 99 .............................. 63 99 133.4 78 153.8 113 131.4 133.4 92 165.8 112.6 106 106.2 ............................ 230 145 144 173 Secondary 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 91 104 106.2 147 104 106 146 78 91 111, 148 61.5 100 76.0 90.0 42.0 20.0 19.0 22.0 14.0 8.8 7.0 6.5 6.6 5.0 0.60 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 A calibration verification. 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 A single-level calibration verification standard tube after 10 field samples. 11.1.1.7 A single-level calibration verification standard tube at the end of the sample batch. 11.2 Pre-desorption System Checks and Procedures. VerDate Mar<15>2010 Characteristic ion(s) Vapor pressure (mmHg)a BP (°C) CAS No. 19:35 Jun 27, 2014 Jkt 232001 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. 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 PO 00000 Frm 00184 Fmt 4701 Sfmt 4702 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 E:\FR\FM\30JNP2.SGM 30JNP2 emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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 °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) VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 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 PO 00000 Frm 00185 Fmt 4701 Sfmt 4702 37063 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 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 routine, single-level calibration verification standards are within 30 percent of the most recent 5-point calibration (see Section 10.9.5). Include relevant routine, single-level calibration data in the supporting information in the data report for each set of samples. 11.3.2.5 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 episode. 12.1.3 Keep records of sorbent tube packing if tubes are manually prepared in the 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 daily unit vector wind direction, daily average temperature, and daily average barometric pressure for the sample collection period. See Section 8.6.5 of Method 325A. 12.1.8 Laboratory personnel must record the sample receipt date, and analysis date. E:\FR\FM\30JNP2.SGM 30JNP2 37064 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 12.2.1.2 Standard deviation of the response factors (SDRF). Calculate the SDRF using Equation 12.2: 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 calibration verification). 12.2.2 Determine the equivalent concentration of compounds in atmospheres as follows. 12.2.3 For passive sorbent tube samples, calculate the concentration of the target compound(s) in the sampled air, in mg/m3 by using Equation 12.5 (Reference 21). 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). U = The diffusive uptake rate (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 limits of detection 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. VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 TABLE 12.1—VALIDATED SORBENTS AND UPTAKE RATES FOR SELECTED CLEAN AIR ACT COMPOUNDS TABLE 12.1—VALIDATED SORBENTS AND UPTAKE RATES FOR SELECTED CLEAN AIR ACT COMPOUNDS—Continued Compound Carbopack X uptake rate (ml/min) a Compound 1,1-Dichloroethene ............... 3-Chloropropene ................... 1,1-Dichloroethane ............... 1,2-Dichloroethane ............... 1,1,1-Trichloroethane ............ Benzene ................................ Carbon tetrachloride ............. 1,2-Dichloropropane ............. PO 00000 Frm 00186 Fmt 4701 Sfmt 4702 0.57±0.14 0.51±0.3 0.57±0.1 0.57±0.08 0.51±0.1 0.66±0.06 0.51±0.06 0.52±0.1 Trichloroethene ..................... 1,1,2-Trichloroethane ............ Toluene ................................. Tetrachloroethene ................. Chlorobenzene ..................... Ethylbenzene ........................ m,p-Xylene ............................ Styrene ................................. o-Xylene ................................ E:\FR\FM\30JNP2.SGM 30JNP2 Carbopack X uptake rate (ml/min) a 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 EP30JN14.041</GPH> Where: RFi = RF for each of the calibration compounds. EP30JN14.039</GPH> EP30JN14.040</GPH> Ais = Peak area for the characteristic ion of the internal standard. Ms = Mass of the analyte. Mis = Mass of the internal standard. EP30JN14.042</GPH> calibration quality control criteria (see also Table 17.1). 12.2.1.1 Response factor (RF). Calculate the RF using Equation 12.1: EP30JN14.038</GPH> calibration, sample, and quality control results from each sampling episode. 12.2 Calculations. 12.2.1 Complete the calculations in this section to determine compliance with Where: As = Peak area for the characteristic ion of the analyte. emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules TABLE 12.1—VALIDATED SORBENTS AND UPTAKE RATES FOR SELECTED CLEAN AIR ACT COMPOUNDS—Continued Compound p-Dichlorobenzene ................ a Reference 37065 12.2.4 Correct target concentrations determined at the sampling site temperature and atmospheric pressure to standard conditions (25 °C and 760 mm mercury) using Equation 12.6 (Reference 22). Carbopack X uptake rate (ml/min) a 0.45±0.05 3, McClenny, J. Environ. Monit. emcdonald on DSK67QTVN1PROD with PROPOSALS2 Where: tss = The temperature at the sampling site (K). Pss = The pressure at the sampling site (mm Hg). 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. 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). 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 X solid adsorbent followed by thermal 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 PO 00000 Frm 00187 Fmt 4701 Sfmt 4702 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 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.043</GPH> 7:248–256. 37066 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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. ASTM D4597–10, Standard Practice for Sampling Workplace Atmospheres to collect Gases or Vapors with Solid Sorbent Diffusive Samplers. 22. 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. 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: 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 Performance Check. Five point calibration bracketing the expected sample concentration. Daily a prior to sample analysis .... Evaluation criteria presented in Section 9.5 and Table 9.2. 1) Percent Deviation (%DEV) of response factors ±30%. 1) Retune and or 2) Perform Maintenance. 1) Repeat calibration sample analysis. 2) 2) Repeat linearity check Following any major change, repair or maintenance or if daily CCV does not meet method requirements. Recalibration not to exceed three months. Relative Retention Times (RRTs) for target peaks ±0.06 units from mean RRT. Calibration Verification (CCV Second source calibration verification check). Following the calibration curve .... The response factor ±30% DEV from calibration curve average response factor. System Blank Analysis .................... Daily a following bromofluorobenzene and calibration check; prior to sample analysis. 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. Blank Sorbent Tube Certification .... Samples—Internal Standards ......... emcdonald on DSK67QTVN1PROD with PROPOSALS2 a Every One tube analyzed for each batch of tubes cleaned or 10 percent of tubes whichever is greater. All samples ................................... <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. 3) Prepare new calibration standards as necessary and repeat analysis. 1) Repeat calibration check 2) Repeat calibration curve. 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 Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00188 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00189 Fmt 4701 Sfmt 4725 E:\FR\FM\30JNP2.SGM 30JNP2 37067 EP30JN14.044</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37068 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00190 Fmt 4701 Sfmt 4702 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.045</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 BILLING CODE 6560–50–P VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00191 Fmt 4701 Sfmt 4725 E:\FR\FM\30JNP2.SGM 30JNP2 37069 EP30JN14.046</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules BILLING CODE 6560–50–C 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00192 Fmt 4701 Sfmt 4702 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, unless the compound or E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.047</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 37070 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules sorbent has already been validated and reported in one of the following national/ international standard methods: ISO 16017– 2:2003 (incorporated by reference—see § 63.14), ASTM D6196–03(2009) (incorporated by reference—see § 63.14), or BS EN 14662–4:2005 (incorporated by reference—see § 63.14), or 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. emcdonald on DSK67QTVN1PROD with PROPOSALS2 A.2 Summary of Method 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 for an example exposure chamber). 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 active SUMMA canister sampling. 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 SUMMA canisters. 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 generate a minimum of four exposed 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 less than 0.2 ppbv of the target VOC. PO 00000 Frm 00193 Fmt 4701 Sfmt 4702 37071 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 measure the relative humidity in the test gas as part of the record of the passive sorbent sampler evaluation. 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 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 50 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 equal 100 percent of the volume of the chamber per minute (i.e., one chamber air change per minute) and 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 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 E:\FR\FM\30JNP2.SGM 30JNP2 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules emcdonald on DSK67QTVN1PROD with PROPOSALS2 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). VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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 hourly intervals or at the beginning, PO 00000 Frm 00194 Fmt 4701 Sfmt 4725 middle, and end of the exposure time, whichever is greater. 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. E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.048</GPH> 37072 emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 house 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 VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 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. PO 00000 Frm 00195 Fmt 4701 Sfmt 4702 37073 A.10.2.2 To verify exposure chamber concentrations using SUMMA canisters, 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 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.049</GPH> Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37074 Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 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. 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.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 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 X of 1.3 to 10 percent compared to active sampling using the following uptake rates. 1,3-butadiene uptake rate mL/min Carbopack 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, 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 X solid adsorbent followed by thermal desorption/GC/MS analysis—laboratory studies. J. Environ. Monit. 7:248–256. 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). 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. Where: Mx = The mass of analyte measured on the sampling tube (hg). Ce = The theoretical exposure chamber concentration (hg/mL). 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 Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00196 Fmt 4701 Sfmt 4725 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.051</GPH> EP30JN14.052</GPH> EP30JN14.050</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 EP30JN14.053</GPH> A.13.2 Data Analysis and Calculations for Method Evaluation Federal Register / Vol. 79, No. 125 / Monday, June 30, 2014 / Proposed Rules 37075 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. XA = 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. 2014–12167 Filed 6–26–14; 8:45 am] References 1. ISO TC 146/SC 02 N 361 Workplace atmospheres—Protocol for evaluating the performance of diffusive samplers. EP30JN14.055</GPH> BILLING CODE 6560–50–P VerDate Mar<15>2010 19:35 Jun 27, 2014 Jkt 232001 PO 00000 Frm 00197 Fmt 4701 Sfmt 9990 E:\FR\FM\30JNP2.SGM 30JNP2 EP30JN14.054</GPH> emcdonald on DSK67QTVN1PROD with PROPOSALS2 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 79, Number 125 (Monday, June 30, 2014)]
[Proposed Rules]
[Pages 36879-37075]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-12167]

[[Page 36879]]

Vol. 79

Monday,

No. 125

June 30, 2014

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; Proposed Rule

Federal Register / Vol. 79 , No. 125 / Monday, June 30, 2014 /
Proposed Rules

[[Page 36880]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2010-0682; FRL-9720-4]
RIN 2060-AQ75

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

AGENCY: Environmental Protection Agency.

ACTION: Proposed rule.

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SUMMARY: This action proposes amendments to the national emission
standards for hazardous air pollutants for petroleum refineries to
address the risk remaining after application of the standards
promulgated in 1995 and 2002. This action also proposes amendments to
the national emission standards for hazardous air pollutants for
petroleum refineries based on the results of the Environmental
Protection Agency (EPA) review of developments in practices, processes
and control technologies and includes new monitoring, recordkeeping and
reporting requirements. The EPA is also proposing new requirements
related to emissions during periods of startup, shutdown and
malfunction to ensure that the standards are consistent with court
opinions issued since promulgation of the standards. This action also
proposes technical corrections and clarifications for new source
performance standards for petroleum refineries to improve consistency
and clarity and address issues raised after the 2008 rule promulgation.
Implementation of this proposed rule will result in projected
reductions of 1,760 tons per year (tpy) of hazardous air pollutants
(HAP), which will reduce cancer risk and chronic health effects.

DATES:
Comments. Comments must be received on or before August 29, 2014. A
copy of comments on the information collection provisions should be
submitted to the Office of Management and Budget (OMB) on or before
July 30, 2014.
Public Hearing. The EPA will hold public hearings on this proposed
rule on July 16, 2014, at Banning's Landing Community Center, 100 E.
Water Street, Wilmington, California 90744, and on August 5, 2014, at
the Alvin D. Baggett Recreation Building 1302 Keene Street in Galena
Park, Texas, 77547.

ADDRESSES:
Comments. Submit your comments, identified by Docket ID Number EPA-
HQ-OAR-2010-0682, by one of the following methods:
https://www.regulations.gov: Follow the on-line
instructions for submitting comments.
Email: a-and-r-docket@epa.gov. Attention Docket ID Number
EPA-HQ-OAR-2010-0682.
Fax: (202) 566-9744. Attention Docket ID Number EPA-HQ-
OAR-2010-0682.
Mail: U.S. Postal Service, send comments to: EPA Docket
Center, William Jefferson Clinton (WJC) West Building (Air Docket),
Attention Docket ID Number EPA-HQ-OAR-2010-0682, U.S. Environmental
Protection Agency, Mailcode: 28221T, 1200 Pennsylvania Ave. NW.,
Washington, DC 20460. Please include a total of two copies. In
addition, please mail a copy of your comments on the information
collection provisions to the Office of Information and Regulatory
Affairs, Office of Management and Budget (OMB), Attn: Desk Officer for
EPA, 725 17th Street NW., Washington, DC 20503.
Hand Delivery: U.S. Environmental Protection Agency, WJC
West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW.,
Washington, DC 20004. Attention Docket ID Number EPA-HQ-OAR-2010-0682.
Such deliveries are only accepted during the Docket's normal hours of
operation, and special arrangements should be made for deliveries of
boxed information.
Instructions. Direct your comments to Docket ID Number EPA-HQ-OAR-
2010-0682. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at https://www.regulations.gov, including any personal
information provided, unless the comment includes information claimed
to be confidential business information (CBI) or other information
whose disclosure is restricted by statute. Do not submit information
that you consider to be CBI or otherwise protected through https://www.regulations.gov or email. The https://www.regulations.gov Web site
is an ``anonymous access'' system, which means the EPA will not know
your identity or contact information unless you provide it in the body
of your comment. If you send an email comment directly to the EPA
without going through https://www.regulations.gov, your email address
will be automatically captured and included as part of the comment that
is placed in the public docket and made available on the Internet. If
you submit an electronic comment, the EPA recommends that you include
your name and other contact information in the body of your comment and
with any disk or CD-ROM you submit. If the EPA cannot read your comment
due to technical difficulties and cannot contact you for clarification,
the EPA may not be able to consider your comment. Electronic files
should not include special characters or any form of encryption and be
free of any defects or viruses. For additional information about the
EPA's public docket, visit the EPA Docket Center homepage at: https://www.epa.gov/dockets.
Docket. The EPA has established a docket for this rulemaking under
Docket ID Number EPA-HQ-OAR-2010-0682. All documents in the docket are
listed in the regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy. Publicly available docket
materials are available either electronically in regulations.gov or in
hard copy at the EPA Docket Center, WJC West Building, Room 3334, 1301
Constitution Ave. NW., Washington, DC. The Public Reading Room is open
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal
holidays. The telephone number for the Public Reading Room is (202)
566-1744, and the telephone number for the EPA Docket Center is (202)
566-1742.
Public Hearing. The public hearing will be held in Wilmington,
California on July 16, 2014 at Banning's Landing Community Center, 100
E. Water Street, Wilmington, California 90744. The hearing will convene
at 9 a.m. and end at 8 p.m. A lunch break will be held from 1 p.m.
until 2 p.m. A dinner break will be held from 5 p.m. until 6 p.m. The
public hearing in Galena Park, Texas will be held on August 5, 2014, at
the Alvin D. Baggett Recreation Building 1302 Keene Street Galena Park,
Texas 77547. The hearing will convene at 9 a.m. and will end at 8 p.m.
A lunch break will be held from noon until 1 p.m. A dinner break will
be held from 5 p.m. until 6 p.m. Please contact Ms. Virginia Hunt at
(919) 541-0832 or at hunt.virginia@epa.gov to register to speak at the
hearing. The last day to pre-register in advance to speak at the
hearing is July 11, 2014, for the Wilmington, California hearing and
August 1, 2014, for the Galena Park, Texas hearing. Additionally,
requests to speak will be taken the day of the hearing at the hearing
registration desk, although preferences on speaking times may not be
able to be fulfilled. If you require the service of a translator or

[[Page 36881]]

special accommodations such as audio description, please let us know at
the time of registration.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed
action, contact Ms. Brenda Shine, Sector Policies and Programs Division
(E143-01), Office of Air Quality Planning and Standards (OAQPS), 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 (OAQPS), 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
National Emissions Standards for Hazardous Air Pollutants (NESHAP) or
the New Source Performance Standards (NSPS) to a particular entity,
contact Maria Malave, Office of Enforcement and Compliance Assurance
(OECA), 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
ACGIH American Conference of Governmental Industrial Hygienists
ADAF age-dependent adjustment factors
AEGL acute exposure guideline levels
AERMOD air dispersion model used by the HEM-3 model
APCD air pollution control devices
API American Petroleum Institute
BDT best demonstrated technology
BLD bag leak detectors
BSER best system of emission reduction
Btu/ft\2\ British thermal units per square foot
Btu/scf British thermal units per standard cubic foot
CAA Clean Air Act
CalEPA California EPA
CBI confidential business information
CCU catalytic cracking units
Ccz combustion zone combustibles concentration
CDDF chlorinated dibenzodioxins and furans
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS continuous emissions 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
CRU catalytic reforming units
CS2 carbon disulfide
DCU delayed coking units
DIAL differential absorption light detection and ranging
EBU enhanced biological unit
EPA Environmental Protection Agency
ERPG emergency response planning guidelines
ERT Electronic Reporting Tool
ESP electrostatic precipitator
FCCU fluid catalytic cracking units
FGCD fuel gas combustion devices
FR Federal Register
FTIR Fourier transform infrared spectroscopy
g PM/kg grams particulate matter per kilogram
GC gas chromatograph
GHG greenhouse gases
GPS global positioning system
H2S hydrogen sulfide
HAP hazardous air pollutants
HCl hydrogen chloride
HCN hydrogen cyanide
HEM-3 Human Exposure Model, Version 1.1.0
HF hydrogen fluoride
HFC highest fenceline concentration
HI hazard index
HQ hazard quotient
ICR Information Collection Request
IRIS Integrated Risk Information System
km kilometers
lb/day pounds per day
LDAR leak detection and repair
LFL lower flammability limit
LFLcz combustion zone lower flammability limit
LMC lowest measured concentration
LOAEL lowest-observed-adverse-effect level
LTD long tons per day
MACT maximum achievable control technology
mg/kg-day milligrams per kilogram per day
mg/L milligrams per liter
mg/m\3\ milligrams per cubic meter
Mg/yr megagrams per year
MFC measured fenceline concentration
MFR momentum flux ratio
MIR maximum individual risk
mph miles per hour
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NAS National Academy of Sciences
NATA National Air Toxics Assessment
NEI National Emissions Inventory
NESHAP National Emissions Standards for Hazardous Air Pollutants
NFS near-field interfering source
NHVcz combustion zone net heating value
Ni nickel
NIOSH National Institutes for Occupational Safety and Health
NOAEL no-observed-adverse-effect level
NOX nitrogen oxides
NRC National Research Council
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
OMB Office of Management and Budget
OSC off-site source contribution
OTM other test method
PAH polycyclic aromatic hydrocarbons
PB-HAP hazardous air pollutants known to be persistent and bio-
accumulative in the environment
PBT persistent, bioaccumulative, and toxic
PCB polychlorinated biphenyls
PEL probable effect level
PM particulate matter
PM2.5 particulate matter 2.5 micrometers in diameter and
smaller
POM polycyclic organic matter
ppm parts per million
ppmv parts per million by volume
ppmw parts per million by weight
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
RfC reference concentration
RfD reference dose
RTR residual risk and technology review
SAB Science Advisory Board
SBA Small Business Administration
SBAR Small Business Advocacy Review
SCR selective catalytic reduction
SISNOSE significant economic impact on a substantial number of small
entities
S/L/Ts state, local and tribal air pollution control agencies
SO2 sulfur dioxide
SRU sulfur recovery unit
SSM startup, shutdown and malfunction
STEL short-term exposure limit
TEQ toxicity equivalent
TLV threshold limit value
TOC total organic carbon
TOSHI target organ-specific hazard index
tpy tons per year
TRIM.FaTE Total Risk Integrated Methodology.Fate, Transport, and
Ecological Exposure model
UB uniform background
UF uncertainty factor
UMRA Unfunded Mandates Reform Act
URE unit risk estimate
UV-DOAS ultraviolet differential optical absorption spectroscopy
VCS voluntary consensus standards
VOC volatile organic compounds
WJC William Jefferson Clinton
[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

The EPA also defines the following abbreviations for regulations
cited within this preamble:

[[Page 36882]]

AWP Alternative Work Practice To Detect Leaks From Equipment (40 CFR
63.11(c), (d) and (e))
Benzene NESHAP National Emission Standards for Hazardous Air
Pollutants: Benzene Emissions from Maleic Anhydride Plants,
Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene
Equipment Leaks, and Coke By-Product Recovery Plants (40 CFR part
61, subpart L as of publication in the Federal Register at 54 FR
38044, September 14, 1989)
BWON National Emission Standard for Benzene Waste Operations (40 CFR
part 61, subpart FF)
Generic MACT National Emission Standards for Storage Vessels (40 CFR
part 63, subpart WW)
HON National Emission Standards for Organic Hazardous Air Pollutants
(40 CFR part 63, subparts F, G and H)
Marine Vessel MACT National Emission Standards for Marine Tank
Vessel Loading Operations (40 CFR part 63, subpart Y)
Refinery MACT 1 National Emission Standards for Hazardous Air
Pollutants From Petroleum Refineries (40 CFR part 63, subpart CC)
Refinery MACT 2 National Emission Standards for Hazardous Air
Pollutants for Petroleum Refineries: Catalytic Cracking Units,
Catalytic Reforming Units, and Sulfur Recovery Units (40 CFR part
63, subpart UUU)
Refinery NSPS J Standards of Performance for Petroleum Refineries
(40 CFR part 60, subpart J)
Refinery NSPS Ja Standards of Performance for Petroleum Refineries
for which Construction, Reconstruction, or Modification Commenced
After May 14, 2007 (40 CFR part 60, subpart Ja)

Organization of This Document. The information in 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. What should I consider as I prepare my comments for the EPA?
D. Public Hearing
II. Background
A. What is the statutory authority for this action?
B. What are the source categories and how do the NESHAP and NSPS
regulate emissions?
C. What data collection activities were conducted to support
this action?
D. What other relevant background information and data are
available?
III. Analytical Procedures
A. How did we estimate post-MACT risks posed by the source
categories?
B. How did we consider the risk results in making decisions for
this proposal?
C. How did we perform the technology review?
IV. Analytical Results and Proposed Decisions
A. What actions are we taking pursuant to CAA sections 112(d)(2)
and 112(d)(3)?
B. What are the results and proposed decisions based on our
technology review?
C. What are the results of the risk assessment and analyses?
D. What are our proposed decisions regarding risk acceptability,
ample margin of safety and adverse environmental effects?
E. What other actions are we proposing?
F. What compliance dates are we proposing?
V. Summary of Cost, Environmental and Economic Impacts
A. What are the affected sources, the air quality impacts and
cost impacts?
B. What are the economic impacts?
C. What are the benefits?
VI. Request for Comments
VII. Submitting Data Corrections
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
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
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations

A redline version of the regulatory language that incorporates the
proposed changes in this action is available in the docket for this
action (Docket ID No. EPA-HQ-OAR-2010-0682).

I. General Information

A. Does this action apply to me?

Table 1 of this preamble lists the industries that are the subject
of this proposal. Table 1 is not intended to be exhaustive but rather
to provide a guide for readers regarding the entities that this
proposed action is likely to affect. These proposed standards, once
promulgated, will be directly applicable to the affected sources. Thus,
federal, state, local and tribal government entities would not be
affected by this proposed action. As defined in the ``Initial List of
Categories of Sources Under Section 112(c)(1) of the Clean Air Act
Amendments of 1990'' (see 57 FR 31576, July 16, 1992), the ``Petroleum
Refineries--Catalytic Cracking (Fluid and other) Units, Catalytic
Reforming Units, and Sulfur Plant Units'' source category and the
``Petroleum Refineries--Other Sources Not Distinctly Listed'' both
consist of any facility engaged in producing gasoline, naphthas,
kerosene, jet fuels, distillate fuel oils, residual fuel oils,
lubricants, or other products from crude oil or unfinished petroleum
derivatives. The first of these source categories includes process
vents associated with the following refinery process units: Catalytic
cracking (fluid and other) units, catalytic reforming units and sulfur
plant units. The second source category includes all emission sources
associated with refinery process units except the process vents listed
in the Petroleum Refineries--Catalytic Cracking (Fluid and Other)
Units, Catalytic Reforming Units, and Sulfur Plant Units Source
Category. The emission sources included in this source category
include, but are not limited to, miscellaneous process vents (vents
other than those listed in Petroleum Refineries--Catalytic Cracking
(Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant
Units Source Category), equipment leaks, storage vessels, wastewater,
gasoline loading, marine vessel loading, and heat exchange systems.

Table 1--Industries Affected by This Proposed Action
----------------------------------------------------------------------------------------------------------------
NAICS\a\
Industry Code Examples of regulated entities
----------------------------------------------------------------------------------------------------------------
Petroleum Refining Industry..................................... 324110 Petroleum refinery sources that
are subject to 40 CFR part 60,
subpart J and Ja and 40 CFR part
63, subparts CC and UUU.
----------------------------------------------------------------------------------------------------------------
\a\ North American Industry Classification System.

[[Page 36883]]

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

Following signature by the EPA Administrator, the EPA will post a
copy of this proposed action at: https://www.epa.gov/ttn/atw/petref.html. Following publication in the Federal Register, the EPA
will post the Federal Register version of the proposal and key
technical documents at the Web site. Information on the overall
residual risk and technology review (RTR) program is available at the
following Web site: https://www.epa.gov/ttn/atw/rrisk/rtrpg.html.

C. What should I consider as I prepare my comments for the EPA?

Submitting CBI. Do not submit information containing CBI to the EPA
through https://www.regulations.gov or email. Clearly mark the part or
all of the information that you claim to be CBI. For CBI information on
a disk or CD-ROM that you mail to the EPA, mark the outside of the disk
or CD-ROM as CBI and then identify electronically within the disk or
CD-ROM the specific information that is claimed as CBI. In addition to
one complete version of the comments that includes information claimed
as CBI, you must submit a copy of the comments that does not contain
the information claimed as CBI for inclusion in the public docket. If
you submit a CD-ROM or disk that does not contain CBI, mark the outside
of the disk or CD-ROM clearly that it does not contain CBI. Information
not marked as CBI will be included in the public docket and the EPA's
electronic public docket without prior notice. Information marked as
CBI will not be disclosed except in accordance with procedures set
forth in 40 Code of Federal Regulations (CFR) part 2. Send or deliver
information identified as CBI only to the following address: Roberto
Morales, OAQPS Document Control Officer (C404-02), OAQPS, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711, Attention Docket ID Number EPA-HQ-OAR-2010-0682.

D. Public Hearing

The hearing will provide interested parties the opportunity to
present data, views or arguments concerning the proposed action. The
EPA will make every effort to accommodate all speakers who arrive and
register. The EPA may ask clarifying questions during the oral
presentations but will not respond to the presentations at that time.
Written statements and supporting information submitted during the
comment period will be considered with the same weight as oral comments
and supporting information presented at the public hearing. Written
comments on the proposed rule must be postmarked by August 29, 2014.
Commenters should notify Ms. Virginia Hunt if they will need specific
equipment, or if there are other special needs related to providing
comments at the hearing. Oral testimony will be limited to 5 minutes
for each commenter. The EPA encourages commenters to provide the EPA
with a copy of their oral testimony electronically (via email or CD) or
in hard copy form. Verbatim transcripts of the hearings and written
statements will be included in the docket for the rulemaking. The EPA
will make every effort to follow the schedule as closely as possible on
the day of the hearing; however, please plan for the hearing to run
either ahead of schedule or behind schedule. Information regarding the
hearing will be available at: https://www.epa.gov/ttnatw01/petrefine/petrefpg.html.

II. Background

A. What is the statutory authority for this action?

1. NESHAP
Section 112 of the Clean Air Act (CAA) establishes a two-stage
regulatory process to address emissions of HAP from stationary sources.
In the first stage, after the EPA has identified categories of sources
emitting one or more of the HAP listed in CAA section 112(b), CAA
section 112(d) requires us to promulgate technology-based national
emissions standards for hazardous air pollutants (NESHAP) for those
sources. ``Major sources'' are those that emit or have the potential to
emit 10 tpy or more of a single HAP or 25 tpy or more of any
combination of HAP. For major sources, the technology-based NESHAP must
reflect the maximum degree of emissions reductions of HAP achievable
(after considering cost, energy requirements and non-air quality health
and environmental impacts) and are commonly referred to as maximum
achievable control technology (MACT) standards.
MACT standards must reflect the maximum degree of emissions
reduction achievable through the application of measures, processes,
methods, systems or techniques, including, but not limited to, measures
that (1) reduce the volume of or eliminate pollutants through process
changes, substitution of materials or other modifications; (2) enclose
systems or processes to eliminate emissions; (3) capture or treat
pollutants when released from a process, stack, storage or fugitive
emissions point; (4) are design, equipment, work practice or
operational standards (including requirements for operator training or
certification); or (5) are a combination of the above. CAA section
112(d)(2)(A)-(E). The MACT standards may take the form of design,
equipment, work practice or operational standards where the EPA first
determines either that (1) a pollutant cannot be emitted through a
conveyance designed and constructed to emit or capture the pollutant,
or that any requirement for, or use of, such a conveyance would be
inconsistent with law; or (2) the application of measurement
methodology to a particular class of sources is not practicable due to
technological and economic limitations. CAA section 112(h)(1)-(2).
The MACT ``floor'' is the minimum control level allowed for MACT
standards promulgated under CAA section 112(d)(3) and may not be based
on cost considerations. For new sources, the MACT floor cannot be less
stringent than the emissions control that is achieved in practice by
the best-controlled similar source. The MACT floor for existing sources
can be less stringent than floors for new sources but not less
stringent than the average emissions limitation achieved by the best-
performing 12 percent of existing sources in the category or
subcategory (or the best-performing five sources for categories or
subcategories with fewer than 30 sources). In developing MACT
standards, the EPA must also consider control options that are more
stringent than the floor. We may establish standards more stringent
than the floor based on considerations of the cost of achieving the
emission reductions, any non-air quality health and environmental
impacts and energy requirements.
The EPA is then required to review these 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. CAA section 112(d)(6). In conducting this
review, the EPA is not required to recalculate the MACT floor. Natural
Resources Defense Council (NRDC) v. EPA, 529 F.3d 1077, 1084 (D.C. Cir.
2008). Association of Battery Recyclers, Inc. v. EPA, 716 F.3d 667
(D.C. Cir. 2013).
The second stage in standard-setting focuses on reducing any
remaining (i.e., ``residual'') risk according to CAA section 112(f).
Section 112(f)(1) required that the EPA by November 1996 prepare a
report to Congress discussing (among

[[Page 36884]]

other things) methods of calculating the risks posed (or potentially
posed) by sources after implementation of the MACT standards, the
public health significance of those risks and the EPA's recommendations
as to legislation regarding such remaining risk. The EPA prepared and
submitted the Residual Risk Report to Congress, EPA-453/R-99-001 (Risk
Report) in March 1999. CAA section 112(f)(2) then provides that if
Congress does not act on any recommendation in the Risk Report, the EPA
must analyze and address residual risk for each category or subcategory
of sources 8 years after promulgation of such standards pursuant to CAA
section 112(d).
Section 112(f)(2) of the CAA requires the EPA to determine for
source categories subject to MACT standards whether the emission
standards provide an ample margin of safety to protect public health.
Section 112(f)(2)(B) of the CAA expressly preserves the EPA's use of
the two-step process for developing standards to address any residual
risk and the agency's interpretation of ``ample margin of safety''
developed in the National Emissions Standards for Hazardous Air
Pollutants: Benzene Emissions from Maleic Anhydride Plants,
Ethylbenzene/Styrene Plants, Benzene Storage Vessels, Benzene Equipment
Leaks, and Coke By-Product Recovery Plants (Benzene NESHAP) (54 FR
38044, September 14, 1989). The EPA notified Congress in the Risk
Report that the agency intended to use the Benzene NESHAP approach in
making CAA section 112(f) residual risk determinations (EPA-453/R-99-
001, p. ES-11). The EPA subsequently adopted this approach in its
residual risk determinations and in a challenge to the risk review for
the Synthetic Organic Chemical Manufacturing source category, the
United States Court of Appeals for the District of Columbia Circuit
upheld as reasonable the EPA's interpretation that subsection 112(f)(2)
incorporates the standards established in the Benzene NESHAP. See NRDC
v. EPA, 529 F.3d 1077, 1083 (D.C. Cir. 2008) (``[S]ubsection
112(f)(2)(B) expressly incorporates the EPA's interpretation of the
Clean Air Act from the Benzene standard, complete with a citation to
the Federal Register.''); see also A Legislative History of the Clean
Air Act Amendments of 1990, vol. 1, p. 877 (Senate debate on Conference
Report).
The first step in the process of evaluating residual risk is the
determination of acceptable risk. If risks are unacceptable, the EPA
cannot consider cost in identifying the emissions standards necessary
to bring risks to an acceptable level. The second step is the
determination of whether standards must be further revised in order to
provide an ample margin of safety to protect public health. The ample
margin of safety is the level at which the standards must be set,
unless an even more stringent standard is necessary to prevent, taking
into consideration costs, energy, safety and other relevant factors, an
adverse environmental effect.
a. Step 1--Determining Acceptability
The agency in the Benzene NESHAP concluded ``that the acceptability
of risk under section 112 is best judged on the basis of a broad set of
health risk measures and information'' and that the ``judgment on
acceptability cannot be reduced to any single factor.'' Id. at 38046.
The determination of what represents an ``acceptable'' risk is based on
a judgment of ``what risks are acceptable in the world in which we
live'' (Risk Report at 178, quoting NRDC v. EPA, 824 F. 2d 1146, 1165
(D.C. Cir. 1987) (en banc) (``Vinyl Chloride''), recognizing that our
world is not risk-free.
In the Benzene NESHAP, we stated that ``EPA will generally presume
that if the risk to [the maximum exposed] individual is no higher than
approximately one in 10 thousand, that risk level is considered
acceptable.'' 54 FR at 38045, September 14, 1989. We discussed the
maximum individual lifetime cancer risk (or maximum individual risk
(MIR)) as being ``the estimated risk that a person living near a plant
would have if he or she were exposed to the maximum pollutant
concentrations for 70 years.'' Id. We explained that this measure of
risk ``is an estimate of the upper bound of risk based on conservative
assumptions, such as continuous exposure for 24 hours per day for 70
years.'' Id. We acknowledged that maximum individual lifetime cancer
risk ``does not necessarily reflect the true risk, but displays a
conservative risk level which is an upper-bound that is unlikely to be
exceeded.'' Id.
Understanding that there are both benefits and limitations to using
the MIR as a metric for determining acceptability, we acknowledged in
the Benzene NESHAP that ``consideration of maximum individual risk * *
* must take into account the strengths and weaknesses of this measure
of risk.'' Id. Consequently, the presumptive risk level of 100-in-1
million (1-in-10 thousand) provides a benchmark for judging the
acceptability of maximum individual lifetime cancer risk, but does not
constitute a rigid line for making that determination. Further, in the
Benzene NESHAP, we noted that:

[p]articular attention will also be accorded to the weight of
evidence presented in the risk assessment of potential
carcinogenicity or other health effects of a pollutant. While the
same numerical risk may be estimated for an exposure to a pollutant
judged to be a known human carcinogen, and to a pollutant considered
a possible human carcinogen based on limited animal test data, the
same weight cannot be accorded to both estimates. In considering the
potential public health effects of the two pollutants, the Agency's
judgment on acceptability, including the MIR, will be influenced by
the greater weight of evidence for the known human carcinogen.

Id. at 38046. The agency also explained in the Benzene NESHAP that:

[i]n establishing a presumption for MIR, rather than a rigid line
for acceptability, the Agency intends to weigh it with a series of
other health measures and factors. These include the overall
incidence of cancer or other serious health effects within the
exposed population, the numbers of persons exposed within each
individual lifetime risk range and associated incidence within,
typically, a 50 km exposure radius around facilities, the science
policy assumptions and estimation uncertainties associated with the
risk measures, weight of the scientific evidence for human health
effects, other quantified or unquantified health effects, effects
due to co-location of facilities, and co-emission of pollutants.

Id. at 38045. In some cases, these health measures and factors taken
together may provide a more realistic description of the magnitude of
risk in the exposed population than that provided by maximum individual
lifetime cancer risk alone.
As noted earlier, in NRDC v. EPA, the court held that section
112(f)(2) ``incorporates the EPA's interpretation of the Clean Air Act
from the Benzene Standard.'' The court further held that Congress'
incorporation of the Benzene standard applies equally to carcinogens
and non-carcinogens. 529 F.3d at 1081-82. Accordingly, we also consider
non-cancer risk metrics in our determination of risk acceptability and
ample margin of safety.
b. Step 2--Determination of Ample Margin of Safety
CAA section 112(f)(2) requires the EPA to determine, for source
categories subject to MACT standards, whether those standards provide
an ample margin of safety to protect public health. As explained in the
Benzene NESHAP, ``the second step of the inquiry, determining an `ample
margin of safety,' again includes consideration of all of the health
factors, and whether to reduce the risks even further. . . .

[[Page 36885]]

Beyond that information, additional factors relating to the appropriate
level of control will also be considered, including costs and economic
impacts of controls, technological feasibility, uncertainties and any
other relevant factors. Considering all of these factors, the agency
will establish the standard at a level that provides an ample margin of
safety to protect the public health, as required by section 112.'' 54
FR at 38046, September 14, 1989.
According to CAA section 112(f)(2)(A), if the MACT standards for
HAP ``classified as a known, probable, or possible human carcinogen do
not reduce lifetime excess cancer risks to the individual most exposed
to emissions from a source in the category or subcategory to less than
one in one million,'' the EPA must promulgate residual risk standards
for the source category (or subcategory), as necessary to provide an
ample margin of safety to protect public health. In doing so, the EPA
may adopt standards equal to existing MACT standards if the EPA
determines that the existing standards (i.e., the MACT standards) are
sufficiently protective. 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.'') The EPA must
also adopt more stringent standards, if necessary, to prevent an
adverse environmental effect,\1\ but must consider cost, energy, safety
and other relevant factors in doing so.
---------------------------------------------------------------------------

\1\ ``Adverse environmental effect'' is defined as any
significant and widespread adverse effect, which may be reasonably
anticipated to wildlife, aquatic life or natural resources,
including adverse impacts on populations of endangered or threatened
species or significant degradation of environmental qualities over
broad areas. CAA section 112(a)(7).
---------------------------------------------------------------------------

The CAA does not specifically define the terms ``individual most
exposed,'' ``acceptable level'' and ``ample margin of safety.'' In the
Benzene NESHAP, 54 FR at 38044-38045, September 14, 1989, we stated as
an overall objective:

In protecting public health with an ample margin of safety under
section 112, EPA strives to provide maximum feasible protection
against risks to health from hazardous air pollutants by (1)
protecting the greatest number of persons possible to an individual
lifetime risk level no higher than approximately 1-in-1 million and
(2) limiting to no higher than approximately 1-in-10 thousand [i.e.,
100-in-1 million] the estimated risk that a person living near a
plant would have if he or she were exposed to the maximum pollutant
concentrations for 70 years.

The agency further stated that ``[t]he EPA also considers incidence
(the number of persons estimated to suffer cancer or other serious
health effects as a result of exposure to a pollutant) to be an
important measure of the health risk to the exposed population.
Incidence measures the extent of health risks to the exposed population
as a whole, by providing an estimate of the occurrence of cancer or
other serious health effects in the exposed population.'' Id. at 38045.
In the ample margin of safety decision process, the agency again
considers all of the health risks and other health information
considered in the first step, including the incremental risk reduction
associated with standards more stringent than the MACT standard or a
more stringent standard that EPA has determined is necessary to ensure
risk is acceptable. In the ample margin of safety analysis, the agency
considers additional factors, including costs and economic impacts of
controls, technological feasibility, uncertainties and any other
relevant factors. Considering all of these factors, the agency will
establish the standard ``at a level that provides an ample margin of
safety to protect the public health,'' as required by CAA section
112(f). 54 FR 38046, September 14, 1989.
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 new source
performance standards (NSPS) which 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 to sources that are constructed, modified or reconstructed
after the EPA proposes the NSPS for the relevant source category.\2\
---------------------------------------------------------------------------

\2\ 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.

[[Page 36886]]

B. What are the source categories and how do the NESHAP and NSPS
regulate emissions?

The source categories include petroleum refineries engaged 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.
Petroleum refinery activities start with the receipt of crude oil for
storage at the refinery, include all 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 refinery-
specific process units include fluid catalytic cracking units (FCCU)
and catalytic reforming units (CRU), as well as units and processes
found at many types of manufacturing facilities (including petroleum
refineries), such as 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). Criteria pollutants and other non-
hazardous air pollutants that are also emitted include nitrogen oxides
(NOX), particulate matter (PM), sulfur dioxide
(SO2), volatile organic compounds (VOC), carbon monoxide
(CO), greenhouse gases (GHG), and total reduced sulfur.
The federal emission standards that are the primary subject of this
proposed rulemaking are:
National Emission Standards for Hazardous Air Pollutants
from Petroleum Refineries (40 CFR part 63, subpart CC) (Refinery MACT
1);
National Emission Standards for Hazardous Air Pollutants
for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming
Units, and Sulfur Recovery Units (40 CFR part 63, subpart UUU)
(Refinery MACT 2);
Standards of Performance for Petroleum Refineries (40 CFR
part 60, subpart J) (Refinery NSPS J); and
Standards of Performance for Petroleum Refineries for
which Construction, Reconstruction, or Modification Commenced After May
14, 2007 (40 CFR part 60, subpart Ja) (Refinery NSPS Ja).
1. Refinery MACT Standards
The EPA promulgated MACT standards pursuant to CAA section
112(d)(2) and (3) for refineries located at major sources in three
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 emission sources from
petroleum refinery process units, except those listed separately under
the section 112(c) source category list expected to be regulated by
other MACT standards. Some of the emission sources regulated in
Refinery MACT 1 include miscellaneous process vents, storage vessels,
wastewater, equipment leaks, gasoline loading racks, marine tank vessel
loading and heat exchange systems.
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 were subsequently regulated under a second MACT
standard specific to these petroleum refinery process vents, codified
as 40 CFR part 63, subpart UUU, which we promulgated on April 11, 2002
(67 FR 17762). This standard, which is referred to as ``Refinery MACT
2,'' covers process vents on catalytic cracking units (CCU) (including
FCCU), CRU and sulfur recovery units (SRU).
Finally, on October 28, 2009, we promulgated 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 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 has reached an agreement to settle that litigation. In a
consent decree filed January 13, 2014 in the U.S. District Court for
the District of Columbia, the EPA commits to perform the risk and
technology review for Refinery MACT 1 and 2 and by May 15, 2014, either
propose any regulations or propose that additional regulations are not
necessary. Under the Consent Decree, the EPA commits to take final
action by April 17, 2015, establishing regulations pursuant to the risk
and technology review or to issue a final determination that revision
to the existing rules is not necessary.
2. Refinery NSPS
Refinery NSPS subparts J and Ja regulate criteria pollutant
emissions, including PM, SO2, NOX and CO from
FCCU catalyst regenerators, fuel gas combustion devices (FGCD) and
sulfur recovery plants. Refinery NSPS Ja also regulates criteria
pollutant emissions from fluid coking units and delayed coking units
(DCU).
The NSPS for petroleum refineries (40 CFR part 60, subpart J;
Refinery NSPS 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 Refinery NSPS J, the EPA
developed separate standards of performance for new process units (40
CFR part 60, subpart Ja; Refinery NSPS Ja). However, the EPA received
petitions for reconsideration and granted reconsideration on issues
related to those standards. On December 22, 2008, the EPA addressed
petition issues related to process heaters and flares by proposing
amendments to certain provisions. Final amendments to Refinery NSPS Ja
were promulgated on September 12, 2012 (77 FR 56422).
In this action, we are proposing amendments to address technical
corrections and clarifications raised in a 2008 industry petition for
reconsideration applicable to Refinery NSPS Ja. We are addressing these
issues in this proposal because they also affect sources included
within these proposed amendments to Refinery MACT 1 and 2.

C. What data collection activities were conducted to support this
action?

In 2010, the EPA began a significant effort to gather additional
information and perform analyses to determine how to address statutory
obligations for the Refinery MACT standards and the NSPS. This effort
focused on gathering comprehensive information through an industry-wide
Information Collection Request (ICR) on petroleum refineries, conducted
under CAA section 114 authority. The information not claimed as CBI by
respondents is available in the docket (see Docket Item Nos. EPA-HQ-
OAR-2010-0682-0064 through 0069). The EPA issued a single ICR (OMB
Control Number 2060-0657) for sources covered under Refinery MACT 1 and
2 and Refinery NSPS J and Ja.
On April 1, 2011, the ICR was sent out to the petroleum refining
industry. In a comprehensive manner, the ICR

[[Page 36887]]

collected information on processing characteristics, crude slate
characteristics, emissions inventories and source testing to fill known
data gaps. The ICR had four components: (1) A questionnaire on
processes and controls to be completed by all petroleum refineries
(Component 1); (2) an emissions inventory to be developed by all
petroleum refineries using the emissions estimation protocol developed
for this effort (Component 2); (3) distillation feed sampling and
analysis to be conducted by all petroleum refineries (Component 3); and
(4) emissions source testing to be completed in accordance with an EPA-
approved protocol for specific sources at specific petroleum refineries
(Component 4). We received responses from 149 refineries. We have since
learned that seven refineries are synthetic minor sources, bringing the
total number of major source refineries operating in 2010 to 142.
Information collected through the ICR was used to establish the
baseline emissions and control levels for purposes of the regulatory
reviews, to identify the most effective control measures, and to
estimate the environmental and cost impacts associated with the
regulatory options considered. As part of the information collection
process, we provided a protocol for survey respondents to follow in
developing the emissions inventories under Component 2 (Emission
Estimation Protocol for Petroleum Refineries, available as Docket Item
Number EPA-HQ-OAR-2010-0682-0060). The protocol contained detailed
guidance for estimating emissions from typical refinery emission
sources and was intended to provide a measure of consistency and
replicability for emission estimates across the refining industry.
Prior to issuance of the ICR, the protocol was publicly disseminated
and underwent several revisions after public comments were received.
Draft and final versions of the emission estimation protocol are
provided in the docket to this rule (Docket ID Number EPA-HQ-OAR-2010-
0682). The protocol provided a hierarchy of methodologies available for
estimating emissions that corresponded to the level of information
available at refineries. For each emission source, the various emission
measurement or estimation methods specific to that source were ranked
in order of preference, with ``Methodology Rank 1'' being the preferred
method, followed by ``Methodology Rank 2,'' and so on. Refinery owners
and operators were requested through the ICR to use the highest ranked
method (with Methodology Rank 1 being the highest) for which data were
available. Methodology Ranks 1 or 2 generally relied on continuous
emission measurements. When continuous measurement data were not
available, engineering calculations or site-specific emission factors
(Methodology Ranks 3 and 4) were specified in the protocol by EPA;
these methods generally needed periodic, site-specific measurements.
When site-specific measurement or test data were not available, default
emission factors (Methodology Rank 5) were provided in the protocol by
EPA.
As we reviewed the ICR-submitted emissions inventories, we
determined that, in some cases, refiners either did not follow the
protocol methodology or made an error in their calculations. This was
evident because pollutants that we expected to be reported from certain
emission sources were either not reported or were reported in amounts
that were not consistent with the protocol methodology. In these cases,
we contacted the refineries and, based on their replies, made
corrections to emission estimates. The original Component 2 submittals,
documentation of the changes as a result of our review, and the final
emissions inventories we relied on for our analyses are available in
the technical memorandum entitled Emissions Data Quality Memorandum and
Development of the Risk Model Input File, in Docket ID Number EPA-HQ-
OAR-2010-0682.
Collected emissions test data (test reports, continuous emissions
monitoring system (CEMS) data and other continuous monitoring system
data) were used to assess the effectiveness of existing control
measures, to fill data gaps and to examine variability in emissions.
The ICR requested source testing for a total of 90 specific process
units at 75 particular refineries across the industry. We received a
total of 72 source tests; in some cases, refinery sources claimed that
units we requested to be tested were no longer in operation, did not
exist or did not have an emission point to the atmosphere (this was the
case for hydrocrackers). In other cases, refiners claimed they were not
able to conduct testing because of process characteristics. For
example, source testing of DCU proved to be difficult because the
moisture content of the steam vent required a significant amount of gas
to be sampled to account for dilution. Venting periods of less than 20
minutes did not accommodate this strategy and, therefore, if refiners
vented for less than 20 minutes, they did not sample their steam vent.
As a result, only two DCU tests out of eight requested were received as
part of Component 4. Results of the stack test data are compiled and
available in Docket ID Number EPA-HQ-OAR-2010-0682.

D. What other relevant background information and data are available?

Over the past several years, the EPA has worked with the Texas
Commission on Environmental Quality and industry representatives to
better characterize proper flare performance. Flares are used to
control emissions from various vents at refineries as well as at other
types of facilities not in the petroleum refinery source categories,
such as chemical and petrochemical manufacturing facilities. In April
2012, we released a technical report for peer review that discussed our
observations regarding the operation and performance of flares. The
report was a result of the analysis of several flare efficiency studies
and flare performance test reports. To provide an objective evaluation
of our analysis, we asked a third party to facilitate an ad hoc peer
review process of the technical report. This third party established a
balanced peer review panel of reviewers from outside the EPA. These
reviewers consisted of individuals that could be considered ``technical
combustion experts'' within four interest groups: the refinery
industry, industrial flare consultants, academia, and environmental
stakeholders.
The EPA developed a charge statement with ten charge questions for
the review panel. The peer reviewers were asked to perform a thorough
review of the technical report and answer the charge questions to the
extent possible, based on their technical expertise. The details of the
peer review process and the charge questions, as well as comments
received from the peer review process, were posted online to the
Consolidated Petroleum Refinery Rulemaking Repository at the EPA's
Technology Transfer Network Air Toxics Web site (see https://www.epa.gov/ttn/atw/petref.html). These items are also provided in a
memorandum entitled Peer Review of ``Parameters for Properly Designed
and Operated Flares'' (see Docket ID Number EPA-HQ-OAR-2010-0682).
After considering the comments received from the peer review process,
we developed a final technical memorandum (see technical memorandum,
Flare Performance Data: Summary of Peer Review Comments and Additional
Data Analysis for Steam-

[[Page 36888]]

Assisted Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).

III. Analytical Procedures

In this section, we describe the analyses performed to support the
proposed decisions for the RTR and other issues addressed in this
proposal.

A. How did we estimate post-MACT risks posed by the source categories?

The EPA conducted a risk assessment that provided estimates of the
MIR posed by the HAP emissions from each source in the source
categories, the hazard index (HI) for chronic exposures to HAP with the
potential to cause non-cancer health effects, and the hazard quotient
(HQ) for acute exposures to HAP with the potential to cause non-cancer
health effects. The assessment also provided estimates of the
distribution of cancer risks within the exposed populations, cancer
incidence and an evaluation of the potential for adverse environmental
effects for each source category. The eight sections that follow this
paragraph describe how we estimated emissions and conducted the risk
assessment. The docket for this rulemaking (Docket ID Number EPA-HQ-
OAR-2010-0682) contains the following document which provides more
information on the risk assessment inputs and models: Draft Residual
Risk Assessment for the Petroleum Refining Source Sector. The methods
used to assess risks (as described in the eight primary steps below)
are consistent with those peer-reviewed by a panel of the EPA's Science
Advisory Board (SAB) in 2009 and described in their peer review report
issued in 2010 \3\; they are also consistent with the key
recommendations contained in that report.
---------------------------------------------------------------------------

\3\ U.S. EPA SAB. Risk and Technology Review (RTR) Risk
Assessment Methodologies: For Review by the EPA's Science Advisory
board with Case Studies--MACT I Petroleum Refining Sources and
Portland Cement Manufacturing, May 2010.
---------------------------------------------------------------------------

1. How did we estimate actual emissions and identify the emissions
release characteristics?
We compiled data sets using the ICR emission inventory submittals
as a starting point. The data sets were refined following an extensive
quality assurance check of source locations, emission release
characteristics, annual emission estimates and FCCU release parameters.
They were then updated based on additional information received from
refineries. In addition, we supplemented these data with results from
stack testing, which were required later than the inventories under the
ICR. As the stack test information was received, we compared these data
against the refined emission inventories and the default emission
factors provided in the Emission Estimation Protocol for Petroleum
Refineries (Docket Item Number EPA-HQ-OAR-2010-0682-0060).
Based on the stack test data for FCCU, we calculated that, on
average, HCN emissions were a factor of 10 greater than the average
emission factor of 770 pounds per barrel FCCU feed provided in the
protocol. Therefore, we revised the HCN emissions for FCCU in the
emissions inventory used for the risk modeling runs (the results are
presented in this preamble). For the 10 facilities that performed a
stack test to determine HCN emissions from their FCCU, we used the
actual emissions measured during the stack tests in place of the
inventories originally supplied in response to the ICR. For those
facilities that did not perform a stack test, but reported HCN
emissions in the emissions inventory portion of the ICR, we increased
the emissions of HCN by a factor of 10, assuming the original emission
inventory estimates for FCCU HCN emissions were based on the default
emission factor in the protocol. The emissions inventory from the ICR
and documentation of the changes made to the file as a result of our
review are contained in the technical memorandum entitled Emissions
Data Quality Memorandum and Development of the Risk Model Input File,
in Docket ID Number EPA-HQ-OAR-2010-0682 and available on our Web
site.\4\
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\4\ The emissions inventory and the revised emissions modeling
file can also be found at https://www.epa.gov/ttn/atw/petref.htm.
---------------------------------------------------------------------------

2. How did we estimate MACT-allowable emissions?
The available emissions data in the RTR dataset (i.e., the
emissions inventory) include estimates of the mass of HAP emitted
during the specified annual time period. In some cases, these
``actual'' emission levels are lower than the emission levels required
to comply with the MACT standards. The emissions level allowed to be
emitted by the MACT standards is referred to as the ``MACT-allowable''
emissions level. We discussed the use of both MACT-allowable and actual
emissions in the final Coke Oven Batteries residual risk rule (70 FR
19998-19999, April 15, 2005) and in the proposed and final Hazardous
Organic NESHAP residual risk rules (71 FR 34428, June 14, 2006, and 71
FR 76609, December 21, 2006, respectively). In those previous actions,
we noted that assessing the risks at the MACT-allowable level is
inherently reasonable since these risks reflect the maximum level
facilities could emit and still comply with national emission
standards. We also explained that it is reasonable to consider actual
emissions, where such data are available, in both steps of the risk
analysis, in accordance with the Benzene NESHAP approach. (54 FR 38044,
September 14, 1989.)
We requested allowable emissions data in the ICR. However, unlike
for actual emissions, where the ICR specified the use of the Emission
Estimation Protocol for Petroleum Refineries (available as Docket Item
Number EPA-HQ-OAR-2010-0682-0060), we did not specify a method to
calculate allowable emissions. As a result, in our review of these data
and when comparing estimates between facilities, we found that
facilities did not estimate allowable emissions consistently across the
industry. In addition, facilities failed to report allowable emissions
for many emission points, likely because they did not know how to
translate a work practice or performance standard into an allowable
emission estimate and they did not know how to speciate individual HAP
where the MACT standard is based on a surrogate, such as PM or VOC.
Therefore, the ICR-submitted information for allowable emissions did
not include emission estimates for all HAP and sources of interest.
Consequently, we used our Refinery Emissions Model (REM Model) to
estimate allowable emissions. The REM model 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.
The risks associated with the allowable emissions were evaluated
using the same dispersion modeling practices, exposure assumptions and
health benchmarks as the actual risks. However, because each refinery's
allowable emissions were calculated by using model plants, selected
based on each refinery's actual capacities and throughputs, emission
estimates for point sources are not specific to a particular latitude/
longitude location. Therefore, for risk modeling purposes, all
allowable emissions were assumed to be released from the centroid of
the facility. (Note: for fugitive (area) sources, the surface area was
selected by the size of the model plant and the release point was
shifted to the southwest so the center of the fugitive area was near
the centroid of the facility). The emission and risk estimates for the
actual emission inventory were compared to the

[[Page 36889]]

allowable emissions and risk estimates. For most work practices, where
allowable emission estimates are difficult to predict, the actual risk
estimates were higher than those projected using the REM Model
estimates. Consequently, we post-processed the two risk files, taking
the higher risk estimates from the actual emissions inventory for
sources subject to work practice standards, such as process equipment
leaks, and sources that were not covered in the REM Model, combining
them with the risk estimates from sources with more readily determined
allowable emissions. The combined post-processed allowable risk
estimates provide a high estimate of the risk allowed under Refinery
MACT 1 and 2. The REM Model assumptions and emission estimates, along
with the post-processing of risk estimate results that produced the
final risk estimates for the allowable emissions, are provided in the
docket (see Refinery Emissions and Risk Estimates for Modeled
``Allowable'' Emissions in Docket ID Number EPA-HQ-OAR-2010-0682).
3. How did we conduct dispersion modeling, determine inhalation
exposures and estimate individual and population inhalation risks?
Both long-term and short-term inhalation exposure concentrations
and health risks from the source categories addressed in this proposal
were estimated using the Human Exposure Model (Community and Sector
HEM-3 version 1.1.0). The HEM-3 performs three primary risk assessment
activities: (1) Conducting dispersion modeling to estimate the
concentrations of HAP in ambient air, (2) estimating long-term and
short-term inhalation exposures to individuals residing within 50
kilometers (km) of the modeled sources \5\, and (3) estimating
individual and population-level inhalation risks using the exposure
estimates and quantitative dose-response information.
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\5\ This metric comes from the Benzene NESHAP. See 54 FR 38046,
September 14, 1989.
---------------------------------------------------------------------------

The air dispersion model used by the HEM-3 model (AERMOD) is one of
the EPA's preferred models for assessing pollutant concentrations from
industrial facilities.\6\ To perform the dispersion modeling and to
develop the preliminary risk estimates, HEM-3 draws on three data
libraries. The first is a library of meteorological data, which is used
for dispersion calculations. This library includes 1 year (2011) of
hourly surface and upper air observations for 824 meteorological
stations, selected to provide coverage of the United States and Puerto
Rico. A second library of United States Census Bureau census block \7\
internal point locations and populations provides the basis of human
exposure calculations (U.S. Census, 2010). In addition, for each census
block, the census library includes the elevation and controlling hill
height, which are also used in dispersion calculations. A third library
of pollutant unit risk factors and other health benchmarks is used to
estimate health risks. These risk factors and health benchmarks are the
latest values recommended by the EPA for HAP and other toxic air
pollutants. These values are available at: https://www.epa.gov/ttn/atw/toxsource/summary.html and are discussed in more detail later in this
section.
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\6\ U.S. EPA. Revision to the Guideline on Air Quality Models:
Adoption of a Preferred General Purpose (Flat and Complex Terrain)
Dispersion Model and Other Revisions (70 FR 68218, November 9,
2005).
\7\ A census block is the smallest geographic area for which
census statistics are tabulated.
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In developing the risk assessment for chronic exposures, we used
the estimated annual average ambient air concentrations of each HAP
emitted by each source for which we have emissions data in the source
category. The air concentrations at each nearby census block centroid
were used as a surrogate for the chronic inhalation exposure
concentration for all the people who reside in that census block. We
calculated the MIR for each facility as the cancer risk associated with
a continuous lifetime (24 hours per day, 7 days per week, and 52 weeks
per year for a 70-year period) exposure to the maximum concentration at
the centroid of inhabited census blocks. Individual cancer risks were
calculated by multiplying the estimated lifetime exposure to the
ambient concentration of each of the HAP (in micrograms per cubic meter
([micro]g/m\3\)) by its unit risk estimate (URE). The URE is an upper
bound estimate of an individual's probability of contracting cancer
over a lifetime of exposure to a concentration of 1 microgram of the
pollutant per cubic meter of air. For residual risk assessments, we
generally use URE values from the EPA's Integrated Risk Information
System (IRIS). For carcinogenic pollutants without EPA IRIS values, we
look to other reputable sources of cancer dose-response values, often
using California EPA (CalEPA) URE values, where available. In cases
where new, scientifically credible dose-response values have been
developed in a manner consistent with the EPA guidelines and have
undergone a peer review process similar to that used by the EPA, we may
use such dose-response values in place of, or in addition to, other
values, if appropriate.
We note here that several carcinogens emitted by facilities in
these source categories have a mutagenic mode of action. For these
compounds, we applied the age-dependent adjustment factors (ADAF)
described in the EPA's Supplemental Guidance for Assessing
Susceptibility from Early-Life Exposure to Carcinogens.\8\ This
adjustment has the effect of increasing the estimated lifetime risks
for these pollutants by a factor of 1.6. Although only a small fraction
of the total polycyclic organic matter (POM) emissions were reported as
individual compounds, the EPA expresses carcinogenic potency of POM
relative to the carcinogenic potency of benzo[a]pyrene, based on
evidence that carcinogenic POM have the same mutagenic mode of action
as does benzo[a]pyrene. The EPA's Science Policy Council recommends
applying the ADAF to all carcinogenic polycyclic aromatic hydrocarbons
(PAH) for which risk estimates are based on potency relative to
benzo[a]pyrene. Accordingly, we have applied the ADAF to the
benzo[a]pyrene-equivalent mass portion of all POM mixtures.
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\8\ Supplemental Guidance for Assessing Susceptibility from
Early-Life Exposure to Carcinogens. Risk Assessment Forum, U.S.
Environmental Protection Agency, Washington, DC. EPA/630/R-03/003F.
March 2005. Available at https://www.epa.gov/ttn/atw/childrens_supplement_final.pdf.
---------------------------------------------------------------------------

The EPA estimated incremental individual lifetime cancer risks
associated with emissions from the facilities in the source categories
as the sum of the risks for each of the carcinogenic HAP (including
those classified as carcinogenic to humans, likely to be carcinogenic
to humans, and suggestive evidence of carcinogenic potential \9\)
emitted by the modeled sources. Cancer incidence and the distribution
of individual cancer risks for the population within 50 km of the
sources were also estimated for the source categories as part of this
assessment by summing individual risks. A distance of 50 km is
consistent with both the analysis supporting the

[[Page 36890]]

1989 Benzene NESHAP (54 FR 38044, September 14, 1989) and the
limitations of Gaussian dispersion models, including AERMOD.
---------------------------------------------------------------------------

\9\ These classifications also coincide with the terms ``known
carcinogen, probable carcinogen, and possible carcinogen,''
respectively, which are the terms advocated in the EPA's previous
Guidelines for Carcinogen Risk Assessment, published in 1986 (51 FR
33992, September 24, 1986). Summing the risks of these individual
compounds to obtain the cumulative cancer risks is an approach that
was recommended by the EPA's SAB in their 2002 peer review of EPA's
National Air Toxics Assessment (NATA) entitled, NATA--Evaluating the
National-scale Air Toxics Assessment 1996 Data--an SAB Advisory,
available at: https://yosemite.epa.gov/sab/sabproduct.nsf/
214C6E915BB04E14852570CA007A682C/$File/ecadv02001.pdf.
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To assess the risk of non-cancer health effects from chronic
exposures, we summed the HQ for each of the HAP that affects a common
target organ system to obtain the HI for that target organ system (or
target organ-specific HI, TOSHI). The HQ is the estimated exposure
divided by the chronic reference level, which is a value selected from
one of several sources. First, the chronic reference level can be the
EPA Reference Concentration (RfC) (https://www.epa.gov/riskassessment/glossary.htm), defined as ``an estimate (with uncertainty spanning
perhaps an order of magnitude) of a continuous inhalation exposure to
the human population (including sensitive subgroups) that is likely to
be without an appreciable risk of deleterious effects during a
lifetime.'' Alternatively, in cases where an RfC from the EPA's IRIS
database is not available or where the EPA determines that using a
value other than the RfC is appropriate, the chronic reference level
can be a value from the following prioritized sources: (1) The Agency
for Toxic Substances and Disease Registry Minimum Risk Level (https://www.atsdr.cdc.gov/mrls/index.asp), which is defined as ``an estimate of
daily human exposure to a hazardous substance that is likely to be
without an appreciable risk of adverse non-cancer health effects (other
than cancer) over a specified duration of exposure''; (2) the CalEPA
Chronic Reference Exposure Level (REL) (https://www.oehha.ca.gov/air/hot_spots/pdf/HRAguidefinal.pdf), which is defined as ``the
concentration level (that is expressed in units of [micro]g/m\3\ for
inhalation exposure and in a dose expressed in units of milligram per
kilogram per day (mg/kg-day) for oral exposures), at or below which no
adverse health effects are anticipated for a specified exposure
duration''; or (3), as noted above, a scientifically credible dose-
response value that has been developed in a manner consistent with the
EPA guidelines and has undergone a peer review process similar to that
used by the EPA, in place of or in concert with other values.
The EPA also evaluated screening estimates of acute exposures and
risks for each of the HAP at the point of highest off-site exposure for
each facility (i.e., not just the census block centroids), assuming
that a person is located at this spot at a time when both the peak
(hourly) emissions rate and worst-case dispersion conditions occur. The
acute HQ is the estimated acute exposure divided by the acute dose-
response value. In each case, the EPA calculated acute HQ values using
best available, short-term dose-response values. These acute dose-
response values, which are described below, include the acute REL,
acute exposure guideline levels (AEGL) and emergency response planning
guidelines (ERPG) for 1-hour exposure durations. As discussed below, we
used realistic assumptions based on knowledge of the emission point
release characteristics for emission rates, and conservative
assumptions for meteorology and exposure location for our acute
analysis.
As described in the CalEPA's Air Toxics Hot Spots Program Risk
Assessment Guidelines, Part I, The Determination of Acute Reference
Exposure Levels for Airborne Toxicants, an acute REL value (https://www.oehha.ca.gov/air/pdf/acuterel.pdf) is defined as ``the
concentration level at or below which no adverse health effects are
anticipated for a specified exposure duration.'' Id. at page 2. Acute
REL values are based on the most sensitive, relevant, adverse health
effect reported in the peer-reviewed medical and toxicological
literature. Acute REL values are designed to protect the most sensitive
individuals in the population through the inclusion of margins of
safety. Because margins of safety are incorporated to address data gaps
and uncertainties, exceeding the REL value does not automatically
indicate an adverse health impact.
AEGL values were derived in response to recommendations from the
National Research Council (NRC). As described in Standing Operating
Procedures (SOP) of the National Advisory Committee on Acute Exposure
Guideline Levels for Hazardous Substances (https://www.epa.gov/oppt/aegl/pubs/sop.pdf),\10\ ``the NRC's previous name for acute exposure
levels--community emergency exposure levels--was replaced by the term
AEGL to reflect the broad application of these values to planning,
response, and prevention in the community, the workplace,
transportation, the military, and the remediation of Superfund sites.''
Id. at 2.
---------------------------------------------------------------------------

\10\ National Academy of Sciences (NAS), 2001. Standing
Operating Procedures for Developing Acute Exposure Levels for
Hazardous Chemicals, page 2.
---------------------------------------------------------------------------

This document also states that AEGL values ``represent threshold
exposure limits for the general public and are applicable to emergency
exposures ranging from 10 minutes to eight hours.'' Id. at 2. The
document lays out the purpose and objectives of AEGL by stating that
``the primary purpose of the AEGL program and the National Advisory
Committee for Acute Exposure Guideline Levels for Hazardous Substances
is to develop guideline levels for once-in-a-lifetime, short-term
exposures to airborne concentrations of acutely toxic, high-priority
chemicals.'' Id. at 21. In detailing the intended application of AEGL
values, the document states that ``[i]t is anticipated that the AEGL
values will be used for regulatory and nonregulatory purposes by U.S.
Federal and state agencies and possibly the international community in
conjunction with chemical emergency response, planning and prevention
programs. More specifically, the AEGL values will be used for
conducting various risk assessments to aid in the development of
emergency preparedness and prevention plans, as well as real-time
emergency response actions, for accidental chemical releases at fixed
facilities and from transport carriers.'' Id. at 31.
The AEGL-1 value is then specifically defined as ``the airborne
concentration (expressed as ppm (parts per million) or mg/m \3\
(milligrams per cubic meter)) of a substance above which it is
predicted that the general population, including susceptible
individuals, could experience notable discomfort, irritation, or
certain asymptomatic nonsensory effects. However, the effects are not
disabling and are transient and reversible upon cessation of
exposure.'' Id. at 3. The document also notes that, ``Airborne
concentrations below AEGL-1 represent exposure levels that can produce
mild and progressively increasing but transient and nondisabling odor,
taste, and sensory irritation or certain asymptomatic, nonsensory
effects.'' Id. Similarly, the document defines AEGL-2 values as ``the
airborne concentration (expressed as parts per million or milligrams
per cubic meter) of a substance above which it is predicted that the
general population, including susceptible individuals, could experience
irreversible or other serious, long-lasting adverse health effects or
an impaired ability to escape.'' Id.
ERPG values are derived for use in emergency response, as described
in the American Industrial Hygiene Association's ERP Committee document
entitled, ERPGS Procedures and Responsibilities, which states that,
``Emergency Response Planning Guidelines were developed for emergency
planning and are intended as health-based guideline concentrations for
single exposures to

[[Page 36891]]

chemicals.'' \11\ Id. at 1. The ERPG-1 value is defined as ``the
maximum airborne concentration below which it is believed that nearly
all individuals could be exposed for up to 1 hour without experiencing
other than mild transient adverse health effects or without perceiving
a clearly defined, objectionable odor.'' Id. at 2. Similarly, the ERPG-
2 value is defined as ``the maximum airborne concentration below which
it is believed that nearly all individuals could be exposed for up to
one hour without experiencing or developing irreversible or other
serious health effects or symptoms which could impair an individual's
ability to take protective action.'' Id. at 1.
---------------------------------------------------------------------------

\11\ ERP Committee Procedures and Responsibilities. November 1,
2006. American Industrial Hygiene Association. Available at https://www.aiha.org/get-involved/AIHAGuidelineFoundation/EmergencyResponsePlanningGuidelines/Documents/ERP-SOPs2006.pdf.
---------------------------------------------------------------------------

As can be seen from the definitions above, the AEGL and ERPG values
include the similarly-defined severity levels 1 and 2. For many
chemicals, a severity level 1 value AEGL or ERPG has not been developed
because the types of effects for these chemicals are not consistent
with the AEGL-1/ERPG-1 definitions; in these instances, we compare
higher severity level AEGL-2 or ERPG-2 values to our modeled exposure
levels to screen for potential acute concerns. When AEGL-1/ERPG-1
values are available, they are used in our acute risk assessments.
Acute REL values for 1-hour exposure durations are typically lower
than their corresponding AEGL-1 and ERPG-1 values. Even though their
definitions are slightly different, AEGL-1 values are often the same as
the corresponding ERPG-1 values, and AEGL-2 values are often equal to
ERPG-2 values. Maximum HQ values from our acute screening risk
assessments typically result when basing them on the acute REL value
for a particular pollutant. In cases where our maximum acute HQ value
exceeds 1, we also report the HQ value based on the next highest acute
dose-response value (usually the AEGL-1 and/or the ERPG-1 value).
To develop screening estimates of acute exposures in the absence of
hourly emissions data, generally we first develop estimates of maximum
hourly emissions rates by multiplying the average actual annual hourly
emissions rates by a default factor to cover routinely variable
emissions. However, for the petroleum refineries category, we
incorporated additional information and process knowledge in order to
better characterize acute emissions, as described below. The ICR
included input fields for both annual emissions and maximum hourly
emissions. The maximum hourly emission values were often left blank or
appeared to be reported in units other than those required for this
emissions field (pounds per hour). Consequently, instead of relying on
the inadequate data provided in response to the ICR, we elected to
estimate the hourly emissions based on the reported annual emissions
(converted to average hourly emissions in terms of pounds per hour) and
then to apply an escalation factor, considering the different types of
emission sources and their inherent variability, in order to calculate
maximum hourly rates. For sources with relatively continuous operations
and steady state emissions, such as FCCU, sulfur recovery plants, and
continuous catalytic reformers, a factor of 2 was used to estimate the
maximum hourly rates from the average hourly emission rates. For
sources with relatively continuous emissions, but with more
variability, like storage tanks and wastewater systems, a factor of 4
was used to estimate the maximum hourly rates from the average hourly
emission rates. For non-continuous emission sources with more
variability, such as DCU, cyclic CRU, semi-regenerative CRU, and
transfer and loading operations, the number of hours in the venting
cycle and the variability of emissions expected in that cycle were used
to determine the escalation factor for each emissions source. The
escalation factors for these processes range from 10 to 60. For more
detail regarding escalation factors and the rationale for their
selection, see Derivation of Hourly Emission Rates for Petroleum
Refinery Emission Sources Used in the Acute Risk Analysis, available in
the docket for this rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682).
As part of our acute risk assessment process, for cases where acute
HQ values from the screening step were less than or equal to 1 (even
under the conservative assumptions of the screening analysis), acute
impacts were deemed negligible and no further analysis was performed.
In cases where an acute HQ from the screening step was greater than 1,
additional site-specific data were considered to develop a more refined
estimate of the potential for acute impacts of concern. For these
source categories, the data refinements employed consisted of using the
site-specific facility layout to distinguish facility property from an
area where the public could be exposed. These refinements are discussed
more fully in the Draft Residual Risk Assessment for the Petroleum
Refining Source Sector, which is available in the docket for this
rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682). Ideally, we would
prefer to have continuous measurements over time to see how the
emissions vary by each hour over an entire year. Having a frequency
distribution of hourly emissions rates over a year would allow us to
perform a probabilistic analysis to estimate potential threshold
exceedances and their frequency of occurrence. Such an evaluation could
include a more complete statistical treatment of the key parameters and
elements adopted in this screening analysis. Recognizing that this
level of data is rarely available, we instead rely on the multiplier
approach.
To better characterize the potential health risks associated with
estimated acute exposures to HAP, and in response to a key
recommendation from the SAB's peer review of the EPA's RTR risk
assessment methodologies,\12\ we generally examine a wider range of
available acute health metrics (e.g., REL, AEGL) than we do for our
chronic risk assessments. This is in response to the SAB's
acknowledgement that there are generally more data gaps and
inconsistencies in acute reference values than there are in chronic
reference values. In some cases, e.g., when Reference Value Arrays \13\
for HAP have been developed, we consider additional acute values (i.e.,
occupational and international values) to provide a more complete risk
characterization.
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\12\ The SAB peer review of RTR Risk Assessment Methodologies is
available at: https://yosemite.epa.gov/sab/sabproduct.nsf/
4AB3966E263D943A8525771F00668381/$File/EPA-SAB-10-007-unsigned.pdf.
\13\ U.S. EPA. (2009) Chapter 2.9 Chemical Specific Reference
Values for Formaldehyde in Graphical Arrays of Chemical-Specific
Health Effect Reference Values for Inhalation Exposures (Final
Report). U.S. Environmental Protection Agency, Washington, DC, EPA/
600/R-09/061, and available on-line at https://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=211003.
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4. How did we conduct the multipathway exposure and risk screening?
The EPA conducted a screening analysis examining the potential for
significant human health risks due to exposures via routes other than
inhalation (i.e., ingestion). We first determined whether any sources
in the source categories emitted any hazardous air pollutants known to
be persistent and bio-accumulative in the environment (PB-HAP). The PB-
HAP compounds or compound classes are

[[Page 36892]]

identified for the screening from the EPA's Air Toxics Risk Assessment
Library (available at https://www.epa.gov/ttn/fera/risk_atra_vol1.html).
For the petroleum refinery source categories, we identified
emissions of cadmium compounds, chlorinated dibenzodioxins and furans
(CDDF), lead compounds, mercury compounds, polychlorinated biphenyls
(PCB), and polycylic organic matter (POM). Because PB-HAP are emitted
by at least one facility, we proceeded to the second step of the
evaluation. In this step, we determined whether the facility-specific
emission rates of each of the emitted PB-HAP were large enough to
create the potential for significant non-inhalation human health risks
under reasonable worst-case conditions. To facilitate this step, we
developed emissions rate screening levels for each PB-HAP using a
hypothetical upper-end screening exposure scenario developed for use in
conjunction with the EPA's ``Total Risk Integrated Methodology. Fate,
Transport, and Ecological Exposure'' (TRIM.FaTE) model. We conducted a
sensitivity analysis on the screening scenario to ensure that its key
design parameters would represent the upper end of the range of
possible values, such that it would represent a conservative but not
impossible scenario. The facility-specific emissions rates of each of
the PB-HAP were compared to their corresponding emission rate screening
values to assess the potential for significant human health risks via
non-inhalation pathways. We call this application of the TRIM.FaTE
model the Tier I TRIM- Screen or Tier I screen.
For the purpose of developing emissions rates for our Tier I TRIM-
Screen, we derived emission levels for each PB-HAP (other than lead) at
which the maximum excess lifetime cancer risk would be 1-in-1 million
or, for HAP that cause non-cancer health effects, the maximum HQ would
be 1. If the emissions rate of any PB-HAP exceeds the Tier I screening
emissions rate for any facility, we conduct a second screen, which we
call the Tier II TRIM-screen or Tier II screen. In the Tier II screen,
the location of each facility that exceeded the Tier I emission rate is
used to refine the assumptions associated with the environmental
scenario while maintaining the exposure scenario assumptions. We then
adjust the risk-based Tier I screening level for each PB-HAP for each
facility based on an understanding of how exposure concentrations
estimated for the screening scenario change with meteorology and
environmental assumptions. PB-HAP emissions that do not exceed these
new Tier II screening levels are considered to pose no unacceptable
risks. When facilities exceed the Tier II screening levels, it does not
mean that multi-pathway impacts are significant, only that we cannot
rule out that possibility based on the results of the screen. These
facilities may be further evaluated for multi-pathway risks using the
TRIM.FaTE model.
In evaluating the potential for multi-pathway risk from emissions
of lead compounds, rather than developing a screening emissions rate
for them, we compared modeled maximum estimated chronic inhalation
exposures with the level of the current National Ambient Air Quality
Standards (NAAQS) for lead.\14\ Values below the level of the primary
(health-based) lead NAAQS were considered to have a low potential for
multi-pathway risk.
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\14\ In doing so, EPA notes that the legal standard for a
primary NAAQS--that a standard is requisite to protect public health
and provide an adequate margin of safety (CAA Section 109(b))--
differs from the Section 112(f) standard (requiring among other
things that the standard provide an ``ample margin of safety'').
However, the lead NAAQS is a reasonable measure of determining risk
acceptability (i.e., the first step of the Benzene NESHAP analysis)
since it is designed to protect the most susceptible group in the
human population--children, including children living near major
lead emitting sources. 73 FR 67002/3; 73 FR 67000/3; 73 FR 67005/1,
November 12, 2008. In addition, applying the level of the primary
lead NAAQS at the risk acceptability step is conservative, since
that primary lead NAAQS reflects an adequate margin of safety.
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For further information on the multi-pathway analysis approach, see
the Draft Residual Risk Assessment for the Petroleum Refining Source
Sector, which is available in the docket for this action (Docket ID
Number EPA-HQ-OAR-2010-0682).
5. How did we assess risks considering emissions control options?
In addition to assessing baseline inhalation risks and screening
for potential multipathway risks, we also estimated risks considering
the potential emission reductions that would be achieved by the control
options under consideration. We used the same emissions inventory that
we used for the risk modeling and applied emission reduction estimates
for the control options we are proposing to calculate the post-control
risk. We note that for storage vessels, in response to the ICR some
facilities reported emissions for their tank farm or a group of storage
vessels rather than for each individual storage vessel. In order to
calculate emissions for each storage vessel, we used unit-specific data
from the ICR to estimate the pre- and post-control emissions based on
the operating characteristics and controls reported for each unit. For
example, HAP emissions from each storage vessel were estimated based on
the size, contents, and controls reported for that storage vessel. If
additional controls would be necessary to comply with proposed
requirements for storage vessels, the HAP emissions were again
estimated based on the upgraded controls. The pre- and post-control
emissions were summed across all storage vessels at the facility to
determine a facility-specific emission reduction factor. The facility-
specific emission reduction factor was then used to adjust the
emissions for each of the pollutants reported for storage vessels at
that facility to account for the post-control emissions. In this
manner, the expected emission reductions were applied to the specific
HAP and emission points in the source category dataset to develop
corresponding estimates of risk and incremental risk reductions. The
resulting emission file used for post-control risk analysis is
available in the docket for this action (Docket ID Number EPA-HQ-OAR-
2010-0682).
6. How did we conduct the environmental risk screening assessment?
a. Adverse Environmental Effect
The EPA has developed a screening approach to examine the potential
for adverse environmental effects as required under section
112(f)(2)(A) of the CAA. Section 112(a)(7) of the CAA defines ``adverse
environmental effect'' as ``any significant and widespread adverse
effect, which may reasonably be anticipated, to wildlife, aquatic life,
or other natural resources, including adverse impacts on populations of
endangered or threatened species or significant degradation of
environmental quality over broad areas.''
b. Environmental HAP
The EPA focuses on seven HAP, which we refer to as ``environmental
HAP,'' in its screening analysis: five PB-HAP and two acid gases. The
five PB-HAP are cadmium, dioxins/furans, POM, mercury (both inorganic
mercury and methyl mercury) and lead compounds. The two acid gases are
HCl and HF. The rationale for including these seven HAP in the
environmental risk screening analysis is presented below.
HAP that persist and bioaccumulate are of particular environmental
concern because they accumulate in the soil, sediment and water. The
PB-HAP are

[[Page 36893]]

taken up, through sediment, soil, water, and/or ingestion of other
organisms, by plants or animals (e.g., small fish) at the bottom of the
food chain. As larger and larger predators consume these organisms,
concentrations of the PB-HAP in the animal tissues increases as does
the potential for adverse effects. The five PB-HAP we evaluate as part
of our screening analysis account for 99.8 percent of all PB-HAP
emissions nationally from stationary sources (on a mass basis from the
2005 National Emissions Inventory (NEI)).
In addition to accounting for almost all of the mass of PB-HAP
emitted, we note that the TRIM.Fate model that we use to evaluate
multipathway risk allows us to estimate concentrations of cadmium
compounds, dioxins/furans, POM and mercury in soil, sediment and water.
For lead compounds, we currently do not have the ability to calculate
these concentrations using the TRIM.Fate model. Therefore, to evaluate
the potential for adverse environmental effects from lead, we compare
the estimated HEM-modeled exposures from the source category emissions
of lead with the level of the secondary NAAQS for lead.\15\ We consider
values below the level of the secondary lead NAAQS to be unlikely to
cause adverse environmental effects.
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\15\ The secondary lead NAAQS is a reasonable measure of
determining whether there is an adverse environmental effect since
it was established considering ``effects on soils, water, crops,
vegetation, man-made materials, animals, wildlife, weather,
visibility and climate, damage to and deterioration of property, and
hazards to transportation, as well as effects on economic values and
on personal comfort and well-being.''
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Due to their well-documented potential to cause direct damage to
terrestrial plants, we include two acid gases, HCl and HF, in the
environmental screening analysis. According to the 2005 NEI, HCl and HF
account for about 99 percent (on a mass basis) of the total acid gas
HAP emitted by stationary sources in the U.S. In addition to the
potential to cause direct damage to plants, high concentrations of HF
in the air have been linked to fluorosis in livestock. Air
concentrations of these HAP are already calculated as part of the human
multipathway exposure and risk screening analysis using the HEM3-AERMOD
air dispersion model, and we are able to use the air dispersion
modeling results to estimate the potential for an adverse environmental
effect.
The EPA acknowledges that other HAP beyond the seven HAP discussed
above may have the potential to cause adverse environmental effects.
Therefore, the EPA may include other relevant HAP in its environmental
risk screening in the future, as modeling science and resources allow.
The EPA invites comment on the extent to which other HAP emitted by the
source categories may cause adverse environmental effects. Such
information should include references to peer-reviewed ecological
effects benchmarks that are of sufficient quality for making regulatory
decisions, as well as information on the presence of organisms located
near facilities within the source categories that such benchmarks
indicate could be adversely affected.
c. Ecological Assessment Endpoints and Benchmarks for PB-HAP
An important consideration in the development of the EPA's
screening methodology is the selection of ecological assessment
endpoints and benchmarks. Ecological assessment endpoints are defined
by the ecological entity (e.g., aquatic communities including fish and
plankton) and its attributes (e.g., frequency of mortality). Ecological
assessment endpoints can be established for organisms, populations,
communities or assemblages, and ecosystems.
For PB-HAP, we evaluated the following community-level ecological
assessment endpoints to screen for organisms directly exposed to HAP in
soils, sediment and water:
Local terrestrial communities (i.e., soil invertebrates,
plants) and populations of small birds and mammals that consume soil
invertebrates exposed to PB-HAP in the surface soil.
Local benthic (i.e., bottom sediment dwelling insects,
amphipods, isopods and crayfish) communities exposed to PB-HAP in
sediment in nearby water bodies.
Local aquatic (water-column) communities (including fish
and plankton) exposed to PB-HAP in nearby surface waters.
For PB-HAP, we also evaluated the following population-level
ecological assessment endpoint to screen for indirect HAP exposures of
top consumers via the bioaccumulation of HAP in food chains.
Piscivorous (i.e., fish-eating) wildlife consuming PB-HAP-
contaminated fish from nearby water bodies.
For cadmium compounds, dioxins/furans, POM and mercury, we
identified the available ecological benchmarks for each assessment
endpoint. An ecological benchmark represents a concentration of HAP
(e.g., 0.77 micrograms of HAP per liter of water) that has been linked
to a particular environmental effect level (e.g., a no-observed-
adverse-effect level (NOAEL)) through scientific study. For PB-HAP we
identified, where possible, ecological benchmarks at the following
effect levels:
Probable effect level (PEL): Level above which adverse
effects are expected to occur frequently.
Lowest-observed-adverse-effect level (LOAEL): The lowest
exposure level tested at which there are biologically significant
increases in frequency or severity of adverse effects.
No-observed-adverse-effect level (NOAEL): The highest
exposure level tested at which there are no biologically significant
increases in the frequency or severity of adverse effect.
We established a hierarchy of preferred benchmark sources to allow
selection of benchmarks for each environmental HAP at each ecological
assessment endpoint. In general, the EPA sources that are used at a
programmatic level (e.g., Office of Water, Superfund Program) were
used, if available. If not, the EPA benchmarks used in regional
programs (e.g., Superfund) were used. If benchmarks were not available
at a programmatic or regional level, we used benchmarks developed by
other federal agencies (e.g., NOAA) or state agencies.
Benchmarks for all effect levels are not available for all PB-HAP
and assessment endpoints. In cases where multiple effect levels were
available for a particular PB-HAP and assessment endpoint, we use all
of the available effect levels to help us to determine whether
ecological risks exist and, if so, whether the risks could be
considered significant and widespread.
d. Ecological Assessment Endpoints and Benchmarks for Acid Gases
The environmental screening analysis also evaluated potential
damage and reduced productivity of plants due to direct exposure to
acid gases in the air. For acid gases, we evaluated the following
ecological assessment endpoint:
Local terrestrial plant communities with foliage exposed
to acidic gaseous HAP in the air.
The selection of ecological benchmarks for the effects of acid
gases on plants followed the same approach as for PB-HAP (i.e., we
examine all of the available chronic benchmarks). For HCl, the EPA
identified chronic benchmark concentrations. We note that the benchmark
for chronic HCl exposure to plants is greater than the reference
concentration for chronic inhalation exposure for human health. This
means

[[Page 36894]]

that where EPA includes regulatory requirements to prevent an
exceedance of the reference concentration for human health, additional
analyses for adverse environmental effects of HCl would not be
necessary.
For HF, EPA identified chronic benchmark concentrations for plants
and evaluated chronic exposures to plants in the screening analysis.
High concentrations of HF in the air have also been linked to fluorosis
in livestock. However, the HF concentrations at which fluorosis in
livestock occur are higher than those at which plant damage begins.
Therefore, the benchmarks for plants are protective of both plants and
livestock.
e. Screening Methodology
For the environmental risk screening analysis, the EPA first
determined whether any petroleum refineries emitted any of the seven
environmental HAP. For the petroleum refinery source categories, we
identified emissions of cadmium, dioxins/furans, POM, mercury (both
inorganic mercury and methyl mercury), lead, HCl and HF.
Because one or more of the seven environmental HAP evaluated are
emitted by at least one petroleum refinery, we proceeded to the second
step of the evaluation.
f. PB-HAP Methodology
For cadmium, mercury, POM and dioxins/furans, the environmental
screening analysis consists of two tiers, while lead is analyzed
differently as discussed earlier. In the first tier, we determined
whether the maximum facility-specific emission rates of each of the
emitted environmental HAP were large enough to create the potential for
adverse environmental effects under reasonable worst-case environmental
conditions. These are the same environmental conditions used in the
human multipathway exposure and risk screening analysis.
To facilitate this step, TRIM.FaTE was run for each PB-HAP under
hypothetical environmental conditions designed to provide
conservatively high HAP concentrations. The model was set to maximize
runoff from terrestrial parcels into the modeled lake, which in turn,
maximized the chemical concentrations in the water, the sediments, and
the fish. The resulting media concentrations were then used to back-
calculate a screening threshold emission rate that corresponded to the
relevant exposure benchmark concentration value for each assessment
endpoint. To assess emissions from a facility, the reported emission
rate for each PB-HAP was compared to the screening threshold emission
rate for that PB-HAP for each assessment endpoint. If emissions from a
facility do not exceed the Tier I threshold, the facility ``passes''
the screen, and therefore, is not evaluated further under the screening
approach. If emissions from a facility exceed the Tier I threshold, we
evaluate the facility further in Tier II.
In Tier II of the environmental screening analysis, the screening
emission thresholds are adjusted to account for local meteorology and
the actual location of lakes in the vicinity of facilities that did not
pass the Tier I screen. The modeling domain for each facility in the
Tier II analysis consists of eight octants. Each octant contains five
modeled soil concentrations at various distances from the facility (5
soil concentrations x 8 octants = total of 40 soil concentrations per
facility) and one lake with modeled concentrations for water, sediment
and fish tissue. In the Tier II environmental risk screening analysis,
the 40 soil concentration points are averaged to obtain an average soil
concentration for each facility for each PB-HAP. For the water,
sediment and fish tissue concentrations, the highest value for each
facility for each pollutant is used. If emission concentrations from a
facility do not exceed the Tier II threshold, the facility passes the
screen, and is typically not evaluated further. If emissions from a
facility exceed the Tier II threshold, the facility does not pass the
screen and, therefore, may have the potential to cause adverse
environmental effects. Such facilities are evaluated further to
investigate factors such as the magnitude and characteristics of the
area of exceedance.
g. Acid Gas Methodology
The environmental screening analysis evaluates the potential
phytotoxicity and reduced productivity of plants due to chronic
exposure to acid gases. The environmental risk screening methodology
for acid gases is a single-tier screen that compares the average off-
site ambient air concentration over the modeling domain to ecological
benchmarks for each of the acid gases. Because air concentrations are
compared directly to the ecological benchmarks, emission-based
thresholds are not calculated for acid gases as they are in the
ecological risk screening methodology for PB-HAP.
For purposes of ecological risk screening, EPA identifies a
potential for adverse environmental effects to plant communities from
exposure to acid gases when the average concentration of the HAP around
a facility exceeds the LOAEL ecological benchmark. In such cases, we
further investigate factors such as the magnitude and characteristics
of the area of exceedance (e.g., land use of exceedance area, size of
exceedance area) to determine if there is an adverse environmental
effect.
For further information on the environmental screening analysis
approach, see section IV.C.5 of this preamble and the Draft Residual
Risk Assessment for the Petroleum Refining Source Sector, which is
available in the docket for this action (Docket ID Number EPA-HQ-OAR-
2010-0682).
7. How did we conduct facility-wide assessments?
To put the source category risks in context, following the
assessment approach outlined in the SAB (2010) review, we examine the
risks from the entire ``facility,'' where the facility includes all
HAP-emitting operations within a contiguous area and under common
control. In other words, we examine the HAP emissions not only from the
source category emission points of interest, but also emissions of HAP
from all other emission sources at the facility for which we have data.
The emissions inventories provided in response to the ICR included
emissions information for all emission sources at the facilities that
are part of the refineries source categories. Generally, only a few
emission sources located at refineries are not subject to either
Refinery MACT 1 or 2; the most notable are boilers, process heaters and
internal combustion engines, which are addressed by other MACT
standards.
We analyzed risks due to the inhalation of HAP that are emitted
``facility-wide'' for the populations residing within 50 km of each
facility, consistent with the methods used for the source category
analysis described above. For these facility-wide risk analyses, the
modeled source category risks were compared to the facility-wide risks
to determine the portion of facility-wide risks that could be
attributed to each of the source categories addressed in this proposal.
We specifically examined the facility that was associated with the
highest estimates of risk and determined the percentage of that risk
attributable to the source category of interest. The Draft Residual
Risk Assessment for the Petroleum Refining Source Sector available
through the docket for this action (Docket ID Number EPA-HQ-OAR-2010-
0682) provides the methodology and results of the facility-wide
analyses, including all facility-wide risks and the percentage of
source category contribution to facility-wide risks.

[[Page 36895]]

8. How did we consider uncertainties in risk assessment?
In the Benzene NESHAP we concluded that risk estimation uncertainty
should be considered in our decision-making under the ample margin of
safety framework. Uncertainty and the potential for bias are inherent
in all risk assessments, including those performed for this proposal.
Although uncertainty exists, we believe that our approach, which used
conservative tools and assumptions, ensures that our decisions are
health protective and environmentally protective. A brief discussion of
the uncertainties in the emissions datasets, dispersion modeling,
inhalation exposure estimates and dose-response relationships follows
below. A more thorough discussion of these uncertainties is included in
the Draft Residual Risk Assessment for the Petroleum Refining Source
Sector, which is available in the docket for this action (Docket ID
Number EPA-HQ-OAR-2010-0682).
a. Uncertainties in the Emission Datasets
Although the development of the RTR datasets involved quality
assurance/quality control processes, the accuracy of emissions values
will vary depending on the source of the data, the degree to which data
are incomplete or missing, the degree to which assumptions made to
complete the datasets are accurate, errors in emission estimates and
other factors. The emission estimates considered in this analysis are
annual totals for 2010, and they do not reflect short-term fluctuations
during the course of a year or variations from year to year. The
estimates of peak hourly emissions rates for the acute effects
screening assessment were based on emission adjustment factors applied
to the average annual hourly emission rates, which are intended to
account for emission fluctuations due to normal facility operations.
As discussed previously, we attempted to provide a consistent
framework for reporting of emissions information by developing the
refinery emissions estimation protocol and requesting that refineries
follow the protocol when reporting emissions inventory data in response
to the ICR. This protocol, called Emission Estimation Protocol for
Petroleum Refineries, is available in the docket for this rulemaking
(Docket Item Number EPA-HQ-OAR-2010-0682-0060). Additionally, we
developed our own estimates of emissions that are based on the factors
provided in the protocol and the REM Model. We developed emission
estimates based on refinery unit capacities, which also provided an
estimate of allowable emissions. We then conducted risk modeling using
REM Model estimates and by locating emissions at the centroid of each
refinery in an attempt to understand the risk associated with emissions
from each refinery. Therefore, even if there were errors in the
emission inventories reported in the ICR, as was the case in many
instances, emissions for those facilities were also modeled using the
protocol emission factors. The risk modeling of allowable emissions
based on emission factors and unit capacities did not result in
significantly different risk results than the actual emissions modeling
runs. Results of the allowable emissions risk estimates are provided in
the Draft Residual Risk Assessment for the Petroleum Refining Source
Sector, which is available in Docket ID Number EPA-HQ-OAR-2010-0682.
b. Uncertainties in Dispersion Modeling
We recognize there is uncertainty in ambient concentration
estimates associated with any model, including the EPA's recommended
regulatory dispersion model, AERMOD. In using a model to estimate
ambient pollutant concentrations, the user chooses certain options to
apply. For RTR assessments, we select some model options that have the
potential to overestimate ambient air concentrations (e.g., not
including plume depletion or pollutant transformation). We select other
model options that have the potential to underestimate ambient impacts
(e.g., not including building downwash). Other options that we select
have the potential to either under- or overestimate ambient levels
(e.g., meteorology and receptor locations). On balance, considering the
directional nature of the uncertainties commonly present in ambient
concentrations estimated by dispersion models, the approach we apply in
the RTR assessments should yield unbiased estimates of ambient HAP
concentrations.
c. Uncertainties in Inhalation Exposure
The EPA did not include the effects of human mobility on exposures
in the assessment. Specifically, short-term mobility and long-term
mobility between census blocks in the modeling domain were not
considered.\16\ The approach of not considering short- or long-term
population mobility does not bias the estimate of the theoretical MIR
(by definition), nor does it affect the estimate of cancer incidence
because the total population number remains the same. It does, however,
affect the shape of the distribution of individual risks across the
affected population, shifting it toward higher estimated individual
risks at the upper end and reducing the number of people estimated to
be at lower risks, thereby increasing the estimated number of people at
specific high-risk levels (e.g., 1-in-10 thousand or 1-in-1 million).
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\16\ Short-term mobility is movement from one micro-environment
to another over the course of hours or days. Long-term mobility is
movement from one residence to another over the course of a
lifetime.
---------------------------------------------------------------------------

In addition, the assessment predicted the chronic exposures at the
centroid of each populated census block as surrogates for the exposure
concentrations for all people living in that block. Using the census
block centroid to predict chronic exposures tends to over-predict
exposures for people in the census block who live further from the
facility and under-predict exposures for people in the census block who
live closer to the facility. Thus, using the census block centroid to
predict chronic exposures may lead to a potential understatement or
overstatement of the true maximum impact, but is an unbiased estimate
of average risk and incidence. We reduce this uncertainty by analyzing
large census blocks near facilities using aerial imagery and adjusting
the location of the block centroid to better represent the population
in the block, as well as adding additional receptor locations where the
block population is not well represented by a single location.
The assessment evaluates the cancer inhalation risks associated
with pollutant exposures over a 70-year period, which is the assumed
lifetime of an individual. In reality, both the length of time that
modeled emission sources at facilities actually operate (i.e., more or
less than 70 years) and the domestic growth or decline of the modeled
industry (i.e., the increase or decrease in the number or size of
domestic facilities) will influence the future risks posed by a given
source or source category. Depending on the characteristics of the
industry, these factors will, in most cases, result in an overestimate
both in individual risk levels and in the total estimated number of
cancer cases. However, in the unlikely scenario where a facility
maintains, or even increases, its emissions levels over a period of
more than 70 years, residents live beyond 70 years at the same
location, and the residents spend most of their days at that location,
then the cancer inhalation risks could potentially be underestimated.
However, annual cancer incidence estimates from exposures to emissions
from these

[[Page 36896]]

sources would not be affected by the length of time an emissions source
operates.
The exposure estimates used in these analyses assume chronic
exposures to ambient (outdoor) levels of pollutants. Because most
people spend the majority of their time indoors, actual exposures may
not be as high, depending on the characteristics of the pollutants
modeled. For many of the HAP, indoor levels are roughly equivalent to
ambient levels, but for very reactive pollutants or larger particles,
indoor levels are typically lower. This factor has the potential to
result in an overestimate of 25 to 30 percent of exposures.\17\
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\17\ U.S. EPA. National-Scale Air Toxics Assessment for 1996.
(EPA 453/R-01-003; January 2001; page 85.)
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In addition to the uncertainties highlighted above, there are
several factors specific to the acute exposure assessment that should
be highlighted. The accuracy of an acute inhalation exposure assessment
depends on the simultaneous occurrence of independent factors that may
vary greatly, such as hourly emissions rates, meteorology and human
activity patterns. In this assessment, we assume that individuals
remain for 1 hour at the point of maximum ambient concentration as
determined by the co-occurrence of peak emissions and worst-case
meteorological conditions. These assumptions would tend to be worst-
case actual exposures as it is unlikely that a person would be located
at the point of maximum exposure during the time when peak emissions
and worst-case meteorological conditions occur simultaneously.
d. Uncertainties in Dose-Response Relationships
There are uncertainties inherent in the development of the dose-
response values used in our risk assessments for cancer effects from
chronic exposures and non-cancer effects from both chronic and acute
exposures. Some uncertainties may be considered quantitatively, and
others generally are expressed in qualitative terms. We note as a
preface to this discussion a point on dose-response uncertainty that is
brought out in the EPA's 2005 Cancer Guidelines; namely, that ``the
primary goal of EPA actions is protection of human health; accordingly,
as an Agency policy, risk assessment procedures, including default
options that are used in the absence of scientific data to the
contrary, should be health protective'' (EPA 2005 Cancer Guidelines,
pages 1-7). This is the approach followed here as summarized in the
next several paragraphs. A complete detailed discussion of
uncertainties and variability in dose-response relationships is given
in the Draft Residual Risk Assessment for the Petroleum Refining Source
Sector, which is available in the docket for this action (Docket ID
Number EPA-HQ-OAR-2010-0682).
Cancer URE values used in our risk assessments are those that have
been developed to generally provide an upper bound estimate of risk.
That is, they represent a ``plausible upper limit to the true value of
a quantity'' (although this is usually not a true statistical
confidence limit).\18\ In some circumstances, the true risk could be as
low as zero; however, in other circumstances, the risk could also be
greater.\19\ When developing an upper-bound estimate of risk and to
provide risk values that do not underestimate risk, health-protective
default approaches are generally used. To err on the side of ensuring
adequate health-protection, the EPA typically uses the upper bound
estimates rather than lower bound or central tendency estimates in our
risk assessments, an approach that may have limitations for other uses
(e.g., priority-setting or expected benefits analysis).
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\18\ IRIS glossary (https://ofmpub.epa.gov/sor_internet/registry/termreg/searchandretrieve/glossariesandkeywordlists/search.do?details=&glossaryName=IRIS%20Glossary).
\19\ An exception to this is the URE for benzene, which is
considered to cover a range of values, each end of which is
considered to be equally plausible, and which is based on maximum
likelihood estimates.
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Chronic non-cancer RfC and reference dose (RfD) values represent
chronic exposure levels that are intended to be health-protective
levels. Specifically, these values provide an estimate (with
uncertainty spanning perhaps an order of magnitude) of a continuous
inhalation exposure (RfC) or a daily oral exposure (RfD) to the human
population (including sensitive subgroups) that is likely to be without
an appreciable risk of deleterious effects during a lifetime. To derive
values that are intended to be ``without appreciable risk,'' the
methodology relies upon an uncertainty factor (UF) approach (U.S. EPA,
1993, 1994) which considers uncertainty, variability and gaps in the
available data. The UF are applied to derive reference values that are
intended to protect against appreciable risk of deleterious effects.
The UF are commonly default values,\20\ e.g., factors of 10 or 3, used
in the absence of compound-specific data; where data are available, UF
may also be developed using compound-specific information. When data
are limited, more assumptions are needed and more UF are used. Thus,
there may be a greater tendency to overestimate risk in the sense that
further study might support development of reference values that are
higher (i.e., less potent) because fewer default assumptions are
needed. However, for some pollutants, it is possible that risks may be
underestimated.
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\20\ According to the NRC report, Science and Judgment in Risk
Assessment (NRC, 1994) ``[Default] options are generic approaches,
based on general scientific knowledge and policy judgment, that are
applied to various elements of the risk assessment process when the
correct scientific model is unknown or uncertain.'' The 1983 NRC
report, Risk Assessment in the Federal Government: Managing the
Process, defined default option as ``the option chosen on the basis
of risk assessment policy that appears to be the best choice in the
absence of data to the contrary'' (NRC, 1983a, p. 63). Therefore,
default options are not rules that bind the Agency; rather, the
Agency may depart from them in evaluating the risks posed by a
specific substance when it believes this to be appropriate. In
keeping with EPA's goal of protecting public health and the
environment, default assumptions are used to ensure that risk to
chemicals is not underestimated (although defaults are not intended
to overtly overestimate risk). See EPA, 2004, An Examination of EPA
Risk Assessment Principles and Practices, EPA/100/B-04/001 available
at: https://www.epa.gov/osa/pdfs/ratf-final.pdf.
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While collectively termed ``UF,'' these factors account for a
number of different quantitative considerations when using observed
animal (usually rodent) or human toxicity data in the development of
the RfC. The UF are intended to account for: (1) Variation in
susceptibility among the members of the human population (i.e., inter-
individual variability); (2) uncertainty in extrapolating from
experimental animal data to humans (i.e., interspecies differences);
(3) uncertainty in extrapolating from data obtained in a study with
less-than-lifetime exposure (i.e., extrapolating from sub-chronic to
chronic exposure); (4) uncertainty in extrapolating the observed data
to obtain an estimate of the exposure associated with no adverse
effects; and (5) uncertainty when the database is incomplete or there
are problems with the applicability of available studies.
Many of the UF used to account for variability and uncertainty in
the development of acute reference values are quite similar to those
developed for chronic durations, but they more often use individual UF
values that may be less than 10. The UF are applied based on chemical-
specific or health effect-specific information (e.g., simple irritation
effects do not vary appreciably between human individuals, hence a
value of 3 is typically used), or based on the purpose for the
reference value (see the following paragraph). The UF

[[Page 36897]]

applied in acute reference value derivation include: (1) Heterogeneity
among humans; (2) uncertainty in extrapolating from animals to humans;
(3) uncertainty in lowest observable adverse effect (exposure) level to
no observed adverse effect (exposure) level adjustments; and (4)
uncertainty in accounting for an incomplete database on toxic effects
of potential concern. Additional adjustments are often applied to
account for uncertainty in extrapolation from observations at one
exposure duration (e.g., 4 hours) to derive an acute reference value at
another exposure duration (e.g., 1 hour).
Not all acute reference values are developed for the same purpose
and care must be taken when interpreting the results of an acute
assessment of human health effects relative to the reference value or
values being exceeded. Where relevant to the estimated exposures, the
lack of short-term dose-response values at different levels of severity
should be factored into the risk characterization as potential
uncertainties.
Although every effort is made to identify appropriate human health
effect dose-response assessment values for all pollutants emitted by
the sources in this risk assessment, some HAP emitted by these source
categories are lacking dose-response assessments. Accordingly, these
pollutants cannot be included in the quantitative risk assessment,
which could result in quantitative estimates understating HAP risk. To
help to alleviate this potential underestimate, where we conclude
similarity with a HAP for which a dose-response assessment value is
available, we use that value as a surrogate for the assessment of the
HAP for which no value is available. To the extent use of surrogates
indicates appreciable risk, we may identify a need to increase priority
for new IRIS assessment of that substance. We additionally note that,
generally speaking, HAP of greatest concern due to environmental
exposures and hazard are those for which dose-response assessments have
been performed, reducing the likelihood of understating risk. Further,
HAP not included in the quantitative assessment are assessed
qualitatively and considered in the risk characterization that informs
the risk management decisions, including with regard to consideration
of HAP reductions achieved by various control options.
For a group of compounds that are unspeciated (e.g., glycol
ethers), we conservatively use the most protective reference value of
an individual compound in that group to estimate risk. Similarly, for
an individual compound in a group (e.g., ethylene glycol diethyl ether)
that does not have a specified reference value, we also apply the most
protective reference value from the other compounds in the group to
estimate risk.
e. Uncertainties in the Multipathway Assessment
For each source category, we generally rely on site-specific levels
of PB-HAP emissions to determine whether a refined assessment of the
impacts from multipathway exposures is necessary. This determination is
based on the results of a two-tiered screening analysis that relies on
the outputs from models that estimate environmental pollutant
concentrations and human exposures for four PB-HAP. Two important types
of uncertainty associated with the use of these models in RTR risk
assessments and inherent to any assessment that relies on environmental
modeling are model uncertainty and input uncertainty.\21\
---------------------------------------------------------------------------

\21\ In the context of this discussion, the term ``uncertainty''
as it pertains to exposure and risk encompasses both variability in
the range of expected inputs and screening results due to existing
spatial, temporal, and other factors, as well as uncertainty in
being able to accurately estimate the true result.
---------------------------------------------------------------------------

Model uncertainty concerns whether the selected models are
appropriate for the assessment being conducted and whether they
adequately represent the actual processes that might occur for that
situation. An example of model uncertainty is the question of whether
the model adequately describes the movement of a pollutant through the
soil. This type of uncertainty is difficult to quantify. However, based
on feedback received from previous EPA SAB reviews and other reviews,
we are confident that the models used in the screen are appropriate and
state-of-the-art for the multipathway risk assessments conducted in
support of RTR.
Input uncertainty is concerned with how accurately the models have
been configured and parameterized for the assessment at hand. For Tier
I of the multipathway screen, we configured the models to avoid
underestimating exposure and risk. This was accomplished by selecting
upper-end values from nationally-representative data sets for the more
influential parameters in the environmental model, including selection
and spatial configuration of the area of interest, lake location and
size, meteorology, surface water and soil characteristics and structure
of the aquatic food web. We also assume an ingestion exposure scenario
and values for human exposure factors that represent reasonable maximum
exposures.
In Tier II of the multipathway assessment, we refine the model
inputs to account for meteorological patterns in the vicinity of the
facility versus using upper-end national values and we identify the
actual location of lakes near the facility rather than the default lake
location that we apply in Tier I. By refining the screening approach in
Tier II to account for local geographical and meteorological data, we
decrease the likelihood that concentrations in environmental media are
overestimated, thereby increasing the usefulness of the screen. The
assumptions and the associated uncertainties regarding the selected
ingestion exposure scenario are the same for Tier I and Tier II.
For both Tiers I and II of the multipathway assessment, our
approach to addressing model input uncertainty is generally cautious.
We choose model inputs from the upper end of the range of possible
values for the influential parameters used in the models, and we assume
that the exposed individual exhibits ingestion behavior that would lead
to a high total exposure. This approach reduces the likelihood of not
identifying high risks for adverse impacts.
Despite the uncertainties, when individual pollutants or facilities
do screen out, we are confident that the potential for adverse
multipathway impacts on human health is very low. On the other hand,
when individual pollutants or facilities do not screen out, it does not
mean that multipathway impacts are significant, only that we cannot
rule out that possibility and that a refined multipathway analysis for
the site might be necessary to obtain a more accurate risk
characterization for the source categories.
For further information on uncertainties and the Tier I and II
screening methods, refer to the risk document Appendix 4, Technical
Support Document for TRIM-Based Multipathway Tiered Screening
Methodology for RTR.
f. Uncertainties in the Environmental Risk Screening Assessment
For each source category, we generally rely on site-specific levels
of environmental HAP emissions to perform an environmental screening
assessment. The environmental screening assessment is based on the
outputs from models that estimate environmental HAP concentrations. The
same models, specifically the TRIM.FaTE multipathway model and the
AERMOD air dispersion model, are used to estimate environmental HAP

[[Page 36898]]

concentrations for both the human multipathway screening analysis and
for the environmental screening analysis. Therefore, both screening
assessments have similar modeling uncertainties.
Two important types of uncertainty associated with the use of these
models in RTR environmental screening assessments--and inherent to any
assessment that relies on environmental modeling--are model uncertainty
and input uncertainty.\22\
---------------------------------------------------------------------------

\22\ In the context of this discussion, the term
``uncertainty,'' as it pertains to exposure and risk assessment,
encompasses both variability in the range of expected inputs and
screening results due to existing spatial, temporal, and other
factors, as well as uncertainty in being able to accurately estimate
the true result.
---------------------------------------------------------------------------

Model uncertainty concerns whether the selected models are
appropriate for the assessment being conducted and whether they
adequately represent the movement and accumulation of environmental HAP
emissions in the environment. For example, does the model adequately
describe the movement of a pollutant through the soil? This type of
uncertainty is difficult to quantify. However, based on feedback
received from previous EPA SAB reviews and other reviews, we are
confident that the models used in the screen are appropriate and state-
of-the-art for the environmental risk assessments conducted in support
of our RTR analyses.
Input uncertainty is concerned with how accurately the models have
been configured and parameterized for the assessment at hand. For Tier
I of the environmental screen for PB-HAP, we configured the models to
avoid underestimating exposure and risk to reduce the likelihood that
the results indicate the risks are lower than they actually are. This
was accomplished by selecting upper-end values from nationally-
representative data sets for the more influential parameters in the
environmental model, including selection and spatial configuration of
the area of interest, the location and size of any bodies of water,
meteorology, surface water and soil characteristics and structure of
the aquatic food web. In Tier I, we used the maximum facility-specific
emissions for cadmium compounds, dioxins/furans, POM, and mercury and
each of the media when comparing to ecological benchmarks. This is
consistent with the conservative design of Tier I of the screen. In
Tier II of the environmental screening analysis for PB-HAP, we refine
the model inputs to account for meteorological patterns in the vicinity
of the facility versus using upper-end national values, and we identify
the locations of water bodies near the facility location. By refining
the screening approach in Tier II to account for local geographical and
meteorological data, we decrease the likelihood that concentrations in
environmental media are overestimated, thereby increasing the
usefulness of the screen. To better represent widespread impacts, the
modeled soil concentrations are averaged in Tier II to obtain one
average soil concentration value for each facility and for each PB-HAP.
For PB-HAP concentrations in water, sediment and fish tissue, the
highest value for each facility for each pollutant is used.
For the environmental screening assessment for acid gases, we
employ a single-tiered approach. We use the modeled air concentrations
and compare those with ecological benchmarks.
For both Tiers I and II of the environmental screening assessment,
our approach to addressing model input uncertainty is generally
cautious. We choose model inputs from the upper end of the range of
possible values for the influential parameters used in the models, and
we assume that the exposed organism (e.g., invertebrate, fish) exhibits
ingestion behavior that would lead to a high total exposure. This
approach reduces the likelihood of not identifying potential risks for
adverse environmental impacts.
Uncertainty also exists in the ecological benchmarks for the
environmental risk screening analysis. We established a hierarchy of
preferred benchmark sources to allow selection of benchmarks for each
environmental HAP at each ecological assessment endpoint. In general,
EPA benchmarks used at a programmatic level (e.g., Office of Water,
Superfund Program) were used if available. If not, we used EPA
benchmarks used in regional programs (e.g., Superfund). If benchmarks
were not available at a programmatic or regional level, we used
benchmarks developed by other agencies (e.g., NOAA) or by state
agencies.
In all cases (except for lead, which was evaluated through a
comparison to the NAAQS), we searched for benchmarks at the following
three effect levels, as described in section III.A.6 of this preamble:
1. A no-effect level (i.e., NOAEL).
2. Threshold-effect level (i.e., LOAEL).
3. Probable effect level (i.e., PEL).
For some ecological assessment endpoint/environmental HAP
combinations, we could identify benchmarks for all three effect levels,
but for most, we could not. In one case, where different agencies
derived significantly different numbers to represent a threshold for
effect, we included both. In several cases, only a single benchmark was
available. In cases where multiple effect levels were available for a
particular PB-HAP and assessment endpoint, we used all of the available
effect levels to help us to determine whether risk exists and if the
risks could be considered significant and widespread.
The EPA evaluated the following seven HAP in the environmental risk
screening assessment: Cadmium, dioxins/furans, POM, mercury (both
inorganic mercury and methyl mercury), lead compounds, HCl and HF.
These seven HAP represent pollutants that can cause adverse impacts for
plants and animals either through direct exposure to HAP in the air or
through exposure to HAP that is deposited from the air onto soils and
surface waters. These seven HAP also represent those HAP for which we
can conduct a meaningful environmental risk screening assessment. For
other HAP not included in our screening assessment, the model has not
been parameterized such that it can be used for that purpose. In some
cases, depending on the HAP, we may not have appropriate multipathway
models that allow us to predict the concentration of that pollutant.
The EPA acknowledges that other HAP beyond the seven HAP that we are
evaluating may have the potential to cause adverse environmental
effects and, therefore, the EPA may evaluate other relevant HAP in the
future, as modeling science and resources allow.
Further information on uncertainties and the Tier I and II
environmental screening methods is provided in Appendix 5 of the
document Technical Support Document for TRIM-Based Multipathway Tiered
Screening Methodology for RTR: Summary of Approach and Evaluation.
Also, see the Draft Residual Risk Assessment for the Petroleum Refining
Source Sector, available in the docket for this action (Docket ID
Number EPA-HQ-OAR-2010-0682).

B. How did we consider the risk results in making decisions for this
proposal?

As discussed in section II.A.1 of this preamble, in evaluating and
developing standards under CAA section 112(f)(2), we apply a two-step
process to address residual risk. In the first step, the EPA determines
whether risks are acceptable. This determination ``considers all health
information, including risk estimation uncertainty, and includes a
presumptive limit on maximum individual lifetime

[[Page 36899]]

[cancer] risk (MIR) \23\ of approximately [1-in-10 thousand] [i.e.,
100-in-1 million].'' 54 FR 38045, September 14, 1989. If risks are
unacceptable, the EPA must determine the emissions standards necessary
to bring risks to an acceptable level without considering costs. In the
second step of the process, the EPA considers whether the emissions
standards provide an ample margin of safety ``in consideration of all
health information, including the number of persons at risk levels
higher than approximately 1-in-1 million, as well as other relevant
factors, including costs and economic impacts, technological
feasibility, and other factors relevant to each particular decision.''
Id. The EPA must promulgate tighter emission standards if necessary to
provide an ample margin of safety.
---------------------------------------------------------------------------

\23\ Although defined as ``maximum individual risk,'' MIR refers
only to cancer risk. MIR, one metric for assessing cancer risk, is
the estimated risk were an individual exposed to the maximum level
of a pollutant for a lifetime.
---------------------------------------------------------------------------

In past residual risk actions, the EPA considered a number of human
health risk metrics associated with emissions from the categories under
review, including the MIR, the number of persons in various risk
ranges, cancer incidence, the maximum non-cancer HI and the maximum
acute non-cancer hazard. See, e.g., 72 FR 25138, May 3, 2007; 71 FR
42724, July 27, 2006. The EPA considered this health information for
both actual and allowable emissions. See, e.g., 75 FR 65068, October
21, 2010, and 75 FR 80220, December 21, 2010). The EPA also discussed
risk estimation uncertainties and considered the uncertainties in the
determination of acceptable risk and ample margin of safety in these
past actions. The EPA considered this same type of information in
support of this action.
The agency is considering these various measures of health
information to inform our determinations of risk acceptability and
ample margin of safety under CAA section 112(f). As explained in the
Benzene NESHAP, ``the first step of judgment on acceptability cannot be
reduced to any single factor,'' and thus ``[t]he Administrator believes
that the acceptability of risk under [previous] section 112 is best
judged on the basis of a broad set of health risk measures and
information.'' 54 FR 38046, September 14, 1989. Similarly, with regard
to making the ample margin of safety determination, ``the Agency again
considers all of the health risk and other health information
considered in the first step. Beyond that information, additional
factors relating to the appropriate level of control will also be
considered, including cost and economic impacts of controls,
technological feasibility, uncertainties, and any other relevant
factors.'' Id.
The Benzene NESHAP approach provides flexibility regarding factors
the EPA may consider in making determinations and how the EPA may weigh
those factors for each source category. In responding to comment on our
policy under the Benzene NESHAP, the EPA explained that:

[t]he policy chosen by the Administrator permits consideration of
multiple measures of health risk. Not only can the MIR figure be
considered, but also incidence, the presence of non-cancer health
effects, and the uncertainties of the risk estimates. In this way,
the effect on the most exposed individuals can be reviewed as well
as the impact on the general public. These factors can then be
weighed in each individual case. This approach complies with the
Vinyl Chloride mandate that the Administrator ascertain an
acceptable level of risk to the public by employing [her] expertise
to assess available data. It also complies with the Congressional
intent behind the CAA, which did not exclude the use of any
particular measure of public health risk from the EPA's
consideration with respect to CAA section 112 regulations, and
thereby implicitly permits consideration of any and all measures of
health risk which the Administrator, in [her] judgment, believes are
appropriate to determining what will `protect the public health.'

See 54 FR at 38057, September 14, 1989. Thus, the level of the MIR is
only one factor to be weighed in determining acceptability of risks.
The Benzene NESHAP explained that ``an MIR of approximately one in 10
thousand should ordinarily be the upper end of the range of
acceptability. As risks increase above this benchmark, they become
presumptively less acceptable under CAA section 112, and would be
weighed with the other health risk measures and information in making
an overall judgment on acceptability. Or, the Agency may find, in a
particular case, that a risk that includes MIR less than the
presumptively acceptable level is unacceptable in the light of other
health risk factors.'' Id. at 38045. Similarly, with regard to the
ample margin of safety analysis, the EPA stated in the Benzene NESHAP
that: ``EPA believes the relative weight of the many factors that can
be considered in selecting an ample margin of safety can only be
determined for each specific source category. This occurs mainly
because technological and economic factors (along with the health-
related factors) vary from source category to source category.'' Id. at
38061. We also consider the uncertainties associated with the various
risk analyses, as discussed earlier in this preamble, in our
determinations of acceptability and ample margin of safety.
The EPA notes that it has not considered certain health information
to date in making residual risk determinations. At this time, we do not
attempt to quantify those HAP risks that may be associated with
emissions from other facilities that do not include the source
categories in question, mobile source emissions, natural source
emissions, persistent environmental pollution or atmospheric
transformation in the vicinity of the sources in these categories.
The agency understands the potential importance of considering an
individual's total exposure to HAP in addition to considering exposure
to HAP emissions from the source category and facility. We recognize
that such consideration may be particularly important when assessing
non-cancer risks, where pollutant-specific health reference levels
(e.g., RfCs) are based on the assumption that thresholds exist for
adverse health effects. For example, the agency recognizes that,
although exposures attributable to emissions from a source category or
facility alone may not indicate the potential for increased risk of
adverse non-cancer health effects in a population, the exposures
resulting from emissions from the facility in combination with
emissions from all of the other sources (e.g., other facilities) to
which an individual is exposed may be sufficient to result in increased
risk of adverse non-cancer health effects. In May 2010, the SAB advised
the EPA ``that RTR assessments will be most useful to decision makers
and communities if results are presented in the broader context of
aggregate and cumulative risks, including background concentrations and
contributions from other sources in the area.'' \24\
---------------------------------------------------------------------------

\24\ EPA's responses to this and all other key recommendations
of the SAB's advisory on RTR risk assessment methodologies (which is
available at: https://yosemite.epa.gov/sab/sabproduct.nsf/
4AB3966E263D943A8525771F00668381/$File/EPA-SAB-10-007-unsigned.pdf)
are outlined in a memo to this rulemaking docket from David Guinnup
entitled, EPA's Actions in Response to the Key Recommendations of
the SAB Review of RTR Risk Assessment Methodologies.
---------------------------------------------------------------------------

In response to the SAB recommendations, the EPA is incorporating
cumulative risk analyses into its RTR risk assessments, including those
reflected in this proposal. The agency is: (1) Conducting facility-wide
assessments, which include source category emission points as well as
other emission points within the facilities; (2) considering sources in
the same category whose emissions result in exposures to the same
individuals; and (3) for some persistent and

[[Page 36900]]

bioaccumulative pollutants, analyzing the ingestion route of exposure.
In addition, the RTR risk assessments have always considered aggregate
cancer risk from all carcinogens and aggregate non-cancer hazard
indices from all non-carcinogens affecting the same target organ
system.
Although we are interested in placing source category and facility-
wide HAP risks in the context of total HAP risks from all sources
combined in the vicinity of each source, we are concerned about the
uncertainties of doing so. Because we have not conducted in-depth
studies of risks due to emissions from sources other those at
refineries subject to this RTR review, such estimates of total HAP
risks would have significantly greater associated uncertainties than
the source category or facility-wide estimates. Such aggregate or
cumulative assessments would compound those uncertainties, making the
assessments too unreliable.

C. How did we perform the technology review?

Our technology review focused on the identification and evaluation
of developments in practices, processes and control technologies that
have occurred since the MACT standards were promulgated. Where we
identified such developments, in order to inform our decision of
whether it is ``necessary'' to revise the emissions standards, we
analyzed the technical feasibility of applying these developments, and
the estimated costs, energy implications, non-air environmental
impacts, as well as considering the emission reductions. We also
considered the appropriateness of applying controls to new sources
versus retrofitting existing sources.
Based on our analyses of the available data and information, we
identified potential developments in practices, processes and control
technologies. For this 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).
We reviewed a variety of data sources in our investigation of
potential practices, processes or controls to consider. Among the
sources we reviewed were the NESHAP for various industries that were
promulgated since the MACT standards being reviewed in this action. We
reviewed the regulatory requirements and/or technical analyses
associated with these regulatory actions to identify any practices,
processes and control technologies considered in these efforts that
could be applied to emission sources subject to Refinery MACT 1 or 2,
as well as the costs, non-air impacts and energy implications
associated with the use of these technologies. Additionally, we
requested information from facilities as described in section II.C of
this preamble. Finally, we reviewed information from other sources,
such as state and/or local permitting agency databases and industry-
supported databases.

IV. Analytical Results and Proposed Decisions

A. What actions are we taking pursuant to CAA sections 112(d)(2) and
112(d)(3)?

In this action, we are proposing the following revisions to the
Refinery MACT 1 and 2 standards pursuant to CAA section 112(d)(2) and
(3) \25\: (1) Adding MACT standards for DCU decoking operations; (2)
revising the CRU purge vent pressure exemption; (3) adding operational
requirements for flares used as air pollution control devices (APCD) in
Refinery MACT 1 and 2; and (4) adding requirements and clarifications
for vent control bypasses in Refinery MACT 1. The results and proposed
decisions based on the analyses performed pursuant to CAA section
112(d)(2) and (3) are presented below.
---------------------------------------------------------------------------

\25\ 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).
---------------------------------------------------------------------------

1. Delayed Coking Units
a. Description of Delayed Coker Process Operations and Emissions
We are proposing to establish MACT standards specific to the DCU
pursuant to CAA section 112(d)(2) and (3). The DCU uses thermal
cracking to upgrade heavy feedstocks and to produce petroleum coke.
Unlike most other refinery operations that are continuous, the DCU
operates in a semi-batch system. Most DCU consist of a large process
heater, two or more coking drums, and a single product distillation
column. The DCU feed is actually fed to the unit's distillation column.
Bottoms from the distillation column are heated to near cracking
temperatures and the resulting heavy oil is fed to one of the coking
drums. As the cracking reactions occur, coke is produced in the drum
and begins to fill the drum with sponge-like solid coke material.
During this process, the DCU is a closed system, with the produced gas
streams piped to the unit's distillation column for product recovery.
When the first coke drum becomes filled with coke, the feed is
diverted to the second coke drum and processing continues via the
second coke drum. The full coke drum, which is no longer receiving oil
feed, is taken through a number of steps, collectively referred to as
decoking operations, to remove the coke from the drum and prepare the
drum for subsequent oil feed processing. The decoking steps include:
purging, cooling/quenching, venting, draining, deheading, and coke
cutting. A description of these steps and the potential emissions from
these activities are provided in the next several paragraphs. Once the
coke is removed, the vessel is re-sealed (i.e., the drain valve is
closed and the ``head'' is re-attached), pressure tested (typically
using steam), purged to remove oxygen, then slowly heated to processing
temperatures so it can go back on-line. When the second coke drum
becomes filled with coke, feed is diverted back to the first coke drum
and the second drum is then decoked. In this manner, the DCU allows for
continuous processing of oil even though the individual coke drums
operate in cyclical batch fashion.
The first step in decoking operations is to purge the coke drum
with steam. This serves to cool the coke bed and to flush oil or
reaction products from the coke bed. The steam purge is initially sent
to the product distillation column and then diverted to the unit's
blowdown system. The blowdown system serves to condense the steam and
other liquids entrained in the

[[Page 36901]]

steam. Nearly all DCU operate a ''closed blowdown'' system, such that
uncondensed gases from the blowdown system are sent to the product
distillation column or the facility's light gas plant, recovered as
fuel gas, or combusted in a flare. In an open blowdown system, these
uncondensed gases would be vented directly to atmosphere. The DCU vent
discharge to the blowdown system is specifically defined in Refinery
MACT 1 as the ``delayed coker vent.''
The next step in the decoking process is cooling/quenching the coke
drum and its contents via the addition of water, commonly referred to
as quench water, at the bottom of the coke drum. The water added to the
vessel quickly turns to steam due to the high temperature of the coke
bed. The water/steam helps to further cool the coke bed and ``quench''
any residual coking reactions that may still occur within the hot coke
bed. As with the steam purge, steam off-gas from the cooling/quenching
cycle is recovered in the unit's blowdown system and this vent
discharge is specifically defined in Refinery MACT 1 as the ``delayed
coker vent.''
After several hours, the coke drum is sufficiently cooled so that
the water level in the drum can be raised to entirely cover the coke
bed. Although water covers the coke bed, the upper portion of the coke
bed may still be well above 212 degrees Fahrenheit ([deg]F) and will
continue to generate steam. In fact, since the coke drum vessel
pressure is greater than atmospheric pressure, the equilibrium boiling
point of water in the vessel is greater than 212[emsp14][deg]F.
Therefore, the water at the top of the coke drum is typically well
above 212[emsp14][deg]F (superheated water). As the coke drum and its
contents continue to cool from the evaporative cooling effect of the
steam generation, the steam generation rate and the pressure within the
vessel will decrease.
Owners or operators of DCU may use different indicators or set
points to determine when the system has cooled sufficiently to move to
the venting step; however, one of the most common indicators monitored
is the pressure of the coke drum vessel (or steam vent line just above
the coke drum, where steam exits the coke drum en route to the blowdown
system). When the vessel has cooled sufficiently (e.g., when the coke
drum vessel pressure reaches the desired set point), valves are opened
to allow the steam generated in the coke drum to vent directly to the
atmosphere rather than the closed blowdown system. This vent is
commonly referred to as the ``coker steam vent'' and is typically the
first direct atmospheric emission release during the decoking
operations when an enclosed blowdown system is used. While this vent
gas contains predominately steam, methane and ethane, a variety of HAP
are also emitted with this steam. These HAP include light aromatics
(e.g., benzene, toluene, and xylene) and light POM (predominately
naphthalene and 2-methyl naphthalene). The level of HAP emitted from
the DCU has been found to be a function of the quantity of steam
generated (see the technical memorandum entitled Impacts Estimates for
Delayed Coking Units in Docket ID Number EPA-HQ-OAR-2010-0682).
In general, the next step in the decoking process is draining the
water from the coke drum by opening a large valve at the bottom of the
coke drum. The drain water typically falls from the coke drum onto a
slanted concrete pad that directs the water to the coke pit area (where
water and coke are collected and separated). Some DCU owners or
operators initiate draining at the same time they initiate venting;
other owners or operators may allow the vessel to vent for 20 or more
minutes prior to initiating draining. While draining immediately may
reduce the amount of steam exiting the unit via the stack, as explained
below, it is not expected to alter the overall emissions from the unit.
During the venting and draining process, the pressure of the system
falls to atmospheric. Steam will be generated until the evaporative
cooling effect of that steam generation cools the coker quench water to
212[emsp14][deg]F. If draining is initiated immediately, some of the
superheated water may drain from the DCU before being cooled. A portion
of that drained water will then convert to steam during the draining
process as that superheated water contacts the open atmosphere.
Therefore, draining quickly is not expected to alter the total amount
of steam generated from the unit nor alter the overall emissions from
the unit. It will, however, alter the relative proportion of the
emissions that are released via the vent versus the quench water drain
area.
The next step in the decoking process is ``deheading'' the coke
drum. At the top of the coke drum is a large 3- to 5-foot diameter
opening, which is sealed with a gasketed lid during normal operations.
When the steam generation rate from the coke drum has sufficiently
subsided, this gasketed lid is removed to allow access for a water
drill that will be used to remove coke from the drum. The process of
removing this lid is referred to as ``deheading'' the coke drum.
Different DCU owners or operators may use different criteria for when
to dehead the coke drum. If the coke drum is deheaded soon after
venting is initiated, some steam and associated HAP emissions may be
released from this opening. As with draining, it is anticipated that
the total volume of steam generated will be a function of the
temperature/pressure of the coke drum. Deheading the coke drum prior to
the coke drum contents reaching 212[emsp14][deg]F will generally mean
that some of the steam will be released from the coke drum head
opening. However, this will not alter the total amount of steam
generated; it merely alters the location of the release (coke drum head
opening versus steam vent). The HAP emissions from the deheading
process are expected to be proportional to the amount of steam released
in the same manner as the emissions from the steam vent.
The final step of the decoking process is coke cutting. A high-
pressure water jet is used to drill or cut the coke out of the vessel.
The drilling water and coke slurry exits the coke drum via the drain
opening and collects in the coke pit. Generally, the coke drum and its
contents are sufficiently cooled so that this process is not expected
to yield significant HAP emissions. However, if the other decoking
steps are performed too quickly, hot spots may exist within the coke
bed and HAP emissions may occur as water contacts these hot spots and
additional steam and emissions are released.
Once the coke is cut out of the drum, the drum is closed and
prepared to go back on-line. This process includes pressurizing with
steam to ensure there are no leaks (i.e., that the head is properly
attached and sealed and the drain valve is fully closed). The vessel is
then purged to remove any oxygen and heated by diverting the produced
gas from the processing coke drum through the empty drum prior to
sending it to the unit's distillation column. A coke drum cycle is
typically 28 to 36 hours from start of feed to start of the next feed.
b. How Delayed Coker Vents Are Addressed in Refinery MACT 1
Delayed coker vents are specifically mentioned as an example within
the first paragraph of the definition of ``miscellaneous process vent''
in 40 CFR 63.641 of Refinery MACT 1. However, the definition of
``miscellaneous process vent'' also excludes coking unit vents
associated with coke drum depressuring (at or below a coke drum outlet
pressure of 15 pounds per square inch gauge [psig]), deheading,
draining, or decoking (coke cutting) or pressure testing after
decoking. Refinery MACT 1 also

[[Page 36902]]

includes a definition of ``delayed coker vent'' in 40 CFR 63.641. This
vent is typically intermittent in nature, and usually occurs only
during the initiation of the depressuring cycle of the decoking
operation when vapor from the coke drums cannot be sent to the
fractionator column for product recovery, but instead is routed to the
atmosphere through a closed blowdown system or directly to the
atmosphere in an open blowdown system. The emissions from the decoking
phases of DCU operations, which include coke drum deheading, draining,
or decoking (coke cutting), are not considered to be delayed coker
vents.
The first paragraph of the definition of ``miscellaneous process
vent'' also includes blowdown condensers/accumulators as an example of
a miscellaneous process vent. Therefore, the DCU blowdown system is a
miscellaneous process vent regardless of whether or not the blowdown
system is associated with a DCU or another process unit. Further, the
inclusion of the ``delayed coker vent'' as an example of a
miscellaneous process vent makes it clear that the DCU's blowdown
system vent (if an open blowdown system is used) is considered a
miscellaneous process vent. It is less clear from the regulatory text
whether the direct venting of the coke drum to the atmosphere via the
steam vent during the final depressurization is considered to be a
``delayed coker vent'' (i.e., whether direct venting to the atmosphere
is equivalent to venting ``directly to the atmosphere in an open
blowdown system'').
The regulatory text is clear that this steam vent is exempt from
the definition of ``miscellaneous process vent'' when the pressure of
the vessel is less than 15 psig. It is also clear that the subsequent
release points from the decoking operations (i.e., deheading, draining,
and coke cutting) are excluded from both the definition of ``delayed
coker vent'' and the definition of ``miscellaneous process vent.''
Further, based on the statements in the background information document
for the August 1995 final Refinery MACT 1 rule,\26\ the 15 psig
pressure limit for the direct venting of the DCU to the atmosphere was
not established as a MACT floor control level; it was established to
accommodate all DCU at whatever pressure they typically switched from
venting to the closed blowdown system to venting directly to the
atmosphere. Based on this information, as well as the data from the
2011 Refinery ICR, refinery enforcement settlements and other
information available, which indicate that all refineries depressurize
the coke drum below 15 psig, we have determined that the direct
atmospheric releases from the DCU decoking operations are currently
unregulated emissions. These unregulated releases include emissions
during atmospheric depressuring (i.e., the steam vent), deheading,
draining, and coke cutting.
---------------------------------------------------------------------------

\26\ National Emission Standards for Hazardous Air Pollutants
Petroleum Refineries--Background Information for Final Standards;
EPA-453/R-95-015b.
---------------------------------------------------------------------------

c. Evaluation of MACT Emission Limitations for Delayed Coking Units
We evaluated emissions and controls during DCU decoking operations
in order to identify appropriate MACT emission limitations pursuant to
CAA section 112(d)(2) and (3). Establishing a lower pressure set point
at which a DCU owner or operator can switch from venting to an enclosed
blowdown system to venting to the atmosphere is the control technique
identified for reducing emissions from delayed coking operations.
Essentially, there is a fixed quantity of steam that will be generated
as the coke drum and its contents cool. The lower pressure set point
will require the DCU to vent to the closed blowdown system longer,
where the organic HAP can be recovered or controlled. This will result
in fewer emissions released during the venting, draining and deheading
process.
We consider this control technique, which is a work practice
standard, appropriate for the DCU for the reasons discussed below for
each of the four possible emission points at the DCU: draining,
deheading, coke cutting and the steam vent. For the first three steps,
the emissions cannot be emitted through a conveyance designed and
constructed to emit or capture such pollutant. For example, during
draining, the drain water typically falls from the coke drum onto a
slanted concrete pad that directs the water to an open coke pit area
(where water and coke are collected and separated). When the coke drum
is deheaded, the coke drum head must be removed to provide an
accessible opening in the drum so the coke cutting equipment can be
lowered into the drum. This opening cannot be sealed during coke
cutting because the drilling shaft will occupy the opening and the
shaft must be free to be lowered or raised during the coke cutting
process.
While the emissions from the fourth point, the DCU steam vent, are
released via a conveyance designed and constructed to emit or capture
such pollutant, as provided in CAA section 112(h)(2)(B), it is not
feasible to prescribe or enforce an emission standard for the DCU steam
vent because the application of a measurement methodology for this
source is not practicable due to technological and economic
limitations.
First, it is not practicable to use a measurement methodology for
the DCU steam vent. The emissions from the vent typically contain 99
percent water, which interferes with common sample collection and
analysis techniques. Also, the flow rate from this vent is not
constant; rather, it decreases during the venting process as the
pressure in the DCU coke drum approaches atmospheric pressure.
Additionally, the venting time can be very short. As part of the ICR,
we requested stack testing of eight DCU. After discussions with stack
testing experts within the agency and with outside contractors used by
industry to perform the tests, we concluded that sources with venting
times less than 20 minutes would not be able to perform an emissions
test that would yield valid results. Therefore, only two of the eight
facilities actually performed the tests. We anticipate all units
complying with the proposed standards for DCU steam vents would vent
for less than 20 minutes.
Second, it is not feasible to enforce an emission standard only on
the steam vent because the timing of drainage and deheading can alter
the portion of the decoking emissions that are released from the actual
steam vent. If draining and deheading are initiated quickly after
venting, this will reduce the emissions discharged from the vent
(although as explained above, it does not reduce the emissions from the
collective set of decoking operations release points).
Consequently, due to the unique nature of DCU emissions, the
difficulties associated with monitoring the DCU steam vent, and the
inability to construct a conveyance to capture emissions from all
decoking release points, we are proposing that it is appropriate to
develop work practice standards in place of emission limits for the
DCU.
To establish the MACT floor, we then reviewed regulations, permits
and consent decrees that require coke controls. Refinery NSPS Ja
establishes a pressure limit of 5 psig prior to allowing the coke drum
to be vented to the atmosphere. Based on a review of permit limits and
consent decrees, we found that coke drum vessel pressure limits have
been established (and achieved) as low as 2 psig. There are 75
operating DCU according to the Refinery ICR responses, so the sixth
percentile is represented by the fifth-best performing DCU. We
identified eight DCU with

[[Page 36903]]

permit requirements or consent decrees specifying a coke drum venting
pressure limit of 2 psig; we did not identify any permit or consent
decree requirements more stringent than 2 psig. Refinery owners and
operators were asked to provide the ``typical coke drum pressure just
prior to venting'' for each DCU in their responses to the Refinery ICR,
and the responses indicate that four DCU operate such that the typical
venting pressure is 1 psig or less. However, this ``typical coke drum
pressure'' does not represent a not-to-be-exceeded pressure limit; it
is expected that these units are operated this way to meet a pressure
limit of 2 psig. We do not have information to indicate whether these
facilities are always depressurized at 1 psig or less. Moreover, there
were only four units for which a typical venting pressure of 1 psig was
identified and the MACT floor for existing sources is represented by
the fifth-best operating DCU, not the best-performing unit. Therefore,
we are proposing that the MACT floor for DCU decoking operations is to
depressure at 2 psig or less prior to venting to the atmosphere for
existing sources. We are also proposing that the MACT floor for new
sources is 2 psig, since the best-performing source is permitted to
depressure at 2 psig or less. For additional details on the MACT floor
analysis, see memorandum entitled MACT Analysis for Delayed Coking Unit
Decoking Operations in Docket ID Number EPA-HQ-OAR-2010-0682.
We then considered control options beyond the floor level of 2 psig
to determine if additional emission reductions could be cost-
effectively achieved. We considered establishing a venting pressure
limit of 1 psig or less, since four facilities reported in the ICR that
the typical coke drum pressure prior to depressurizing was 1 psig.
There are several technical difficulties associated with establishing a
pressure limit at this lower level. First, the lowest pressure at any
point in a closed blowdown system is generally designed to be no lower
than 0.5 psig. Consequently, the DCU compressor system would operate
with an inlet pressure of no less than 0.5 psig. Second, there are
several valves and significant piping (for cooling and condensing
steam) between the DCU drum and the recovery compressor. There is an
inherent pressure drop when a fluid flows through a pipe or valve. Two
valves are used for all DCU lines to make sure that the unit is either
blocked off from the processing fluids or blocked in so there are no
product losses out the steam line during processing. Considering the
need for two valves and piping needed in the cooling system, DCU
designed for a minimal pressure loss will generally still have a 0.5 to
1 psig pressure drop between the DCU drum and the recovery compressor
inlet, even for a new DCU designed to minimize this pressure drop.
Finally, in order to meet a 1 psig pressure limit at all times, the DCU
closed vent system would need to be designed to achieve a vessel
pressure of approximately 0.5 psig. Given the above considerations, it
is not technically feasible for new or existing DCU to routinely
achieve a vessel pressure of 0.5 psig in order to comply with a never-
to-be-exceeded drum vessel pressure of 1 psig. As noted previously,
facilities that ``typically'' achieve vessel pressures of about 1 psig
or less are expected to do so in order to meet a never-to-be-exceeded
drum vessel pressure limit of 2 psig and they are not expected to be
able to comply with a never-to-be-exceeded drum vessel pressure limit
of 1 psig.
We considered setting additional work practice standards regarding
draining, deheading, and coke cutting. The decoking emissions can be
released from a variety of locations, and the 2-psig-or-less limit for
depressurizing the coke drum will effectively reduce the emissions from
all of these emission points, provided that atmospheric venting via the
DCU steam vent is the first step in the decoking process. However, it
is possible to start draining water prior to opening the steam vent. We
are concerned that owners or operators may adopt this practice as a
means to reduce pressure in the coke drum prior to venting the drum to
the atmosphere. Initiating water draining prior to reaching 2 psig
would result in draining water that is hotter than it would be had the
drum been sufficiently cooled (i.e., the pressure limit achieved) prior
to draining the vessel, effectively diverting HAP emissions to the
water drain area rather than capturing these HAP in the enclosed
blowdown system, where they can be either recovered or controlled.
Therefore, we are proposing that the coke drum must reach 2 psig or
less prior to any decoking operations, which includes atmospheric
venting, draining, deheading, and coke cutting.
We could not identify any other emission reduction options that
could lower the emissions from the DCU decoking operations. Since we
could not identify a technically feasible control option beyond the
MACT floor, we determined that the MACT floor pressure limit of 2 psig
is MACT for existing sources. We also determined that the same
technical limitations of going beyond the 2 psig pressure limit for
existing sources exist for new sources; therefore we determined that
the MACT floor pressure limit of 2 psig is MACT for new sources. We
request comment on whether depressurizing to 2 psig prior to venting to
the atmosphere is the appropriate MACT floor and whether it is
appropriate to include restrictions for the other three decoking
operations draining, deheading and coke cutting, in the MACT
requirements. We request comments on whether we have adequately
interpreted the information that indicates that there is currently no
applicable MACT floor for delayed coking. If Refinery MACT 1 currently
provided standards for DCU based on the MACT floor, we would evaluate
whether it is necessary to revise such delayed coking standards under
the risk and technology review requirements of the Act (i.e., CAA
section 112(f) and 112(d)(6)) as discussed later in this preamble.
Finally, we request comment and supporting information on any other
practices that may be used to limit emissions during the decoking
operations.
d. Evaluation of Cost and Environmental Impacts of MACT Emission
Limitations for Delayed Coking Units
DCU that cannot currently meet the 2 psig pressure limit would be
expected to install a device (compressor or steam ejector system) to
lower the DCU vessel pressure. In the Refinery NSPS Ja impact analysis,
facilities not able to meet the pressure threshold were assumed to
purchase and install a larger compressor to lower the blowdown system
pressure. Other approaches to lowering blowdown system (and coke drum)
pressure exist. Specifically, steam ejectors have been identified as a
method to help existing units depressurize more fully in order to
achieve a set vessel pressure or drum bed temperature. Upgrading the
closed vent system to reduce pressure losses or to increase steam
condensing capacity may also allow the DCU to depressurize more quickly
while the emissions are still vented to the closed blowdown system.
This is important because delays in the decoking operations may impact
process feed rates. That is, if the decoking and drum preparation steps
take too long, the feed rate to the other coke unit must be reduced to
prevent overfilling one coke drum prior to being able to switch to the
other coke drum. This issue is less critical for DCU that operate with
3 or 4 drums per distillation column, but a consistent increase in the
decoking times across all

[[Page 36904]]

drums may still limit the capacity of the DCU at some petroleum
refineries.
For existing sources, we assumed all DCU that reported a ``typical
drum pressure prior to venting'' of more than 2 psig would install and
operate a steam ejector system to reduce the coke drum pressure to 2
psig prior to venting to atmosphere or draining.
The operating costs of the steam ejector system are offset, to some
extent, by the additional recovered vapors. Vapors from the additional
gases routed to the blowdown system contain high levels of methane
(approximately 70 percent by volume on a dry basis) based on DCU steam
vent test data. If these vapors are directed to the closed blowdown
system rather than to the atmosphere, generally the dry gas can be
recovered in the refinery fuel gas system or light-ends gas plant. This
recovered methane is expected to off-set natural gas purchases for the
fuel gas system.
For new sources, it is anticipated that the DCU's closed vent
system could be designed to achieve a 2 psig vessel pressure with no
significant increase in capital or operating costs. Designing the
system to vent at a lower pressure would also result in additional
vapor recovery, which is expected to off-set any additional capital
costs associated with the low pressure design closed vent system.
The costs of complying with the 2 psig coke drum threshold prior to
venting or draining are summarized in Table 2 of this preamble. The
costs are approximately $1,000 per ton of VOC reduced and approximately
$5,000 per ton of organic HAP reduced when considering VOC and methane
recovery credits. In addition to VOC and HAP reductions, the proposed
control option will result in a reduction in methane emissions of
18,000 tpy or 343,000 metric tonnes per year of carbon dioxide
equivalents (CO2e), assuming a global warming potential of
21 for methane.

Table 2--Nationwide Emissions Reduction and Cost Impacts of Control Option for Delayed Coking Units at Petroleum Refineries
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total
Annualized annualized Overall cost
costs costs with effectiveness
Capital without Emissions Emissions Cost VOC with VOC
Control option cost recovery reduction, reduction, effectiveness recovery recovery
(million $) credits VOC (tpy) HAP (tpy) ($/ton HAP) credit credit ($/
(million $/ (million $/ ton HAP)
yr) yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
2 psig................................................... 52 10.2 4,250 850 12,000 3.98 4,700
--------------------------------------------------------------------------------------------------------------------------------------------------------

2. CRU Vents
A CRU is designed to reform (i.e., change the chemical structure
of) naphtha into higher-octane aromatics. Over time, coke deposits form
on the reforming catalyst, which reduces the catalyst activity. When
catalyst activity is reduced to a certain point, the catalyst is
regenerated by burning the coke off of the catalyst. Prior to this coke
burn-off process, the catalyst (or reactor vessel containing the
catalyst) must be removed from active service and organics remaining on
the catalyst (or in the reactor) must be purged from the system. This
is generally accomplished by depressurizing the vessel to a certain
vessel pressure, then re-pressurizing the vessel with nitrogen and
depressurizing the vessel again. The re-pressurization and
depressurization process is repeated several times until all organics
have been purged from the system. The organic HAP emissions from this
depressurization/purge cycle vent are typically controlled by directing
the purge gas directly to the CRU process heater or venting the gas to
a flare.
Refinery MACT 2 requires a 98-percent reduction of organic HAP
measured as total organic carbon (TOC) or non-methane TOC or an outlet
concentration of 20 ppmv or less (dry basis, as hexane, corrected to 3-
percent oxygen), whichever is less stringent, for this CRU
depressurization/purge cycle vent (purging prior to coke-burn-off). The
emission limits for organic HAP for the CRU do not apply to emissions
from process vents during depressuring and purging operations when the
reactor vent pressure is 5 psig or less. The Refinery MACT 2
requirements were based on the typical operation of CRU utilizing
sequential pressurization and passive depressurization. The 5 psig
pressure limit exclusion was provided based on state permit conditions,
which recognized that depressurization to an APCD (without other active
motive of flow) is limited by the back pressure of the control system,
which is often a flare or process heater. Source testing information
collected from the 2011 Refinery ICR indicates that facilities have
interpreted the rule to allow the 5 psig pressure limit exclusion to be
used by units using active purging techniques (such as continuous
nitrogen purge or vacuum pump on the CRU reactor at low pressures) to
discharge to the atmosphere without emission controls. The information
collected indicates that HAP emissions from a continuous, active
purging technique could result in emissions of HAP from CRU
depressurization vents much higher than expected to be allowed under
the Refinery MACT 2 requirements, which presumed sequential re-
pressurization and purging cycles. The testing information received
indicated that at one facility, the active purge vent had non-methane
TOC concentrations of 700 to 10,000 ppmv (dry basis, as hexane,
corrected to 3-percent oxygen) compared to less than 10 ppmv for the
typical passive purge vent tested. The annual HAP emissions for the CRU
with the active purge vent were estimated to exceed 10 tpy, while a
comparable unit using the cyclic re-pressurization and passive
depressurization purge technique is projected to have HAP emissions of
less than 0.1 tpy.
Therefore, we are proposing to amend the exclusion in 40 CFR
63.1566(a)(4) to clarify the application of the 5 psig exclusion,
consistent with the MACT floor under CAA section 112(d)(2) and (3).
Specifically, we are limiting the vessel pressure limit exclusion to
apply only to passive vessel depressurization. Units utilizing active
purging techniques have a motive of flow that can be used to direct the
purge gas to a control system, regardless of the CRU vessel pressure.
If a CRU owner or operator uses active purging techniques (e.g., a
continual nitrogen purge) or active vessel depressurization (e.g.,
vacuum pump), then the 98-percent reduction or 20 ppmv TOC emission
limits would apply to these discharges regardless of the vessel
pressure.
3. Refinery Flares
The EPA is proposing under CAA section 112(d)(2) and (3) to amend
the operating and monitoring requirements for petroleum refinery
flares. We have determined that the current requirements for flares are
not adequate to ensure compliance with the Refinery MACT standards. In
the development of Refinery MACT 1, the EPA determined that the average
emission limitation achieved by the best-performing 12

[[Page 36905]]

percent of existing sources was established as the use of combustion
controls for miscellaneous process vents. Further, the EPA stated that
``data analyses conducted in developing previous NSPS and the [National
Emission Standards for Organic Hazardous Air Pollutants (40 CFR part
63, subparts F, G, and H)] HON determined that combustion controls can
achieve 98-percent organic HAP reduction or an outlet organic HAP
concentration of 20 ppmv for all vent streams'' (59 FR 36139, July 15,
1994). The requirements applicable to flares at refineries are set
forth in the General Provisions to 40 CFR part 63 and are cross-
referenced in Refinery MACT 1 and 2. In general, flares used as APCD
were expected to achieve 98-percent HAP destruction efficiencies when
designed and operated according to the requirements in the General
Provisions. Recent studies on flare performance, however, indicate that
these General Provisions requirements are inadequate to ensure proper
performance of refinery flares, particularly when assist steam or
assist air is used. Over the last decade, flare minimization efforts at
petroleum refineries have led to an increasing number of flares
operating at well below their design capacity, and while this effort
has resulted in reduced flaring of gases at refineries, situations of
over-assisting with steam or air have become exacerbated, leading to
the degradation of flare combustion efficiency. Therefore, these
amendments are necessary to ensure that refineries that use flares as
APCD meet the MACT standards at all times when controlling HAP
emissions.
Refinery MACT 1 and 2 require flares used as an APCD to meet the
operational requirements set forth in the General Provisions at 40 CFR
63.11(b). These General Provisions requirements specify that flares
shall be: (1) Steam-assisted, air-assisted, or non-assisted; (2)
operated at all times when emissions may be vented to them; (3)
designed for and operated with no visible emissions (except for periods
not to exceed a total of 5 minutes during any 2 consecutive hours); and
(4) operated with the presence of a pilot flame at all times. The
General Provisions also specify requirements for both the minimum heat
content of gas combusted in the flare and maximum exit velocity at the
flare tip. The General Provisions only specify monitoring requirements
for the presence of the pilot flame and the operation of a flare with
no visible emissions. For all other operating limits, Refinery MACT 1
and 2 require an initial performance evaluation to demonstrate
compliance but there are no specific monitoring requirements to ensure
continuous compliance. As noted previously, flare performance tests
conducted over the past few years suggest that the current regulatory
requirements are insufficient to ensure that refinery flares are
operating consistently with the 98-percent HAP destruction efficiencies
that we determined were the MACT floor.
In 2012, the EPA compiled information and test data collected on
flares and summarized its preliminary findings on operating parameters
that affect flare combustion efficiency (see technical report,
Parameters for Properly Designed and Operated Flares, in Docket ID
Number EPA-HQ-OAR-2010-0682). The EPA submitted the report, along with
a charge statement and a set of charge questions to an external peer
review panel.\27\ The panel concurred with the EPA's assessment that
three primary factors affect flare performance: (1) The flow of the
vent gas to the flare; (2) the amount of assist media (e.g., steam or
air) added to the flare; and (3) the combustibility of the vent gas/
assist media mixture in the combustion zone (i.e., the net heating
value, lower flammability, and/or combustibles concentration) at the
flare tip.
---------------------------------------------------------------------------

\27\ These documents can also be found at https://www.epa.gov/ttn/atw/petref.html.
---------------------------------------------------------------------------

Following is a discussion of requirements we are proposing for
refinery flares, along with impacts and costs associated with these new
requirements. Specifically, this action proposes that refinery flares
operate pilot flame systems continuously and with automatic re-ignition
systems and that refinery flares operate with no visible emissions. In
addition, this action also consolidates requirements related to flare
tip velocity and proposes new operational and monitoring requirements
related to the combustion zone gas. Prior to these proposed amendments,
Refinery MACT 1 and 2 cross-reference the General Provisions
requirements at 40 CFR 63.11(b) for the operational requirements for
flares used as APCD. Rather than revising the General Provisions
requirements for flares, which would impact dozens of different source
categories, this proposal will specify all refinery flare operational
and monitoring requirements specifically in Refinery MACT 1 and cross-
reference these same requirements in Refinery MACT 2. All of the
requirements for flares operating at petroleum refineries in this
proposed rulemaking are intended to ensure compliance with the Refinery
MACT 1 and 2 standards when using a flare as an APCD.
a. Pilot Flames
Refinery MACT 1 and 2 reference the flare requirements in the
General Provisions, which require a flare used as an APCD device to
operate with a pilot flame present at all times. Pilot flames are
proven to improve flare flame stability; even short durations of an
extinguished pilot could cause a significant reduction in flare
destruction efficiency. In this action, we are proposing to remove the
cross-reference to the General Provisions and instead include the
requirement that flares operate with a pilot flame at all times and be
continuously monitored for using a thermocouple or any other equivalent
device in Refinery MACT 1 and 2. We are also proposing to amend
Refinery MACT 1 and 2 to add a new operational requirement to use
automatic relight systems for all flare pilot flames. An automatic
relight system provides a quicker response time to relighting a
snuffed-out flare compared to manual methods and thereby results in
improved flare flame stability. In comparison, manual relighting is
much more likely to result in a longer period where the pilot remains
unlit. Because of safety issues with manual relighting, we anticipate
that nearly all refinery flares are already equipped with an automated
device to relight the pilot flame in the event it is extinguished.
Also, due to the possibility that a delay in relighting the pilot could
result in a flare not meeting the 98-percent destruction efficiency for
the period when the pilot flame is out, we are proposing to amend
Refinery MACT 1 and 2 to add this requirement to ensure that the pilot
operates at all times.
b. Visible Emissions
Refinery MACT 1 and 2 reference the flare requirements in the
General Provisions, which require a flare used as an APCD to operate
with visible emissions for no more than 5 minutes in a 2-hour period.
Owners or operators of these flares are required to conduct an initial
performance demonstration for visible emissions using EPA Method 22 of
40 CFR part 60, Appendix A-7. We are proposing to remove the cross-
reference to the General Provisions and include the limitation on
visible emissions in Refinery MACT 1 and 2. In addition, we are
proposing to amend Refinery MACT 1 and 2 to add a requirement that a
visible emissions test be conducted each day and whenever visible
emissions are observed from the flare. We are proposing that owners or

[[Page 36906]]

operators of flares monitor visible emissions at a minimum of once per
day using an observation period of 5 minutes and EPA Method 22 of 40
CFR part 60, Appendix A-7. Additionally, any time there are visual
emissions from the flare, we are proposing that another 5-minute
visible emissions observation period be performed using EPA Method 22
of 40 CFR part 60, Appendix A-7, even if the minimum required daily
visible emission monitoring has already been performed. For example, if
an employee observes visual emissions or receives notification of such
by the community, the owner or operator of the flare would be required
to perform a 5-minute EPA Method 22 observation in order to check for
compliance upon initial observation or notification of such event. We
are also proposing that if visible emissions are observed for greater
than one continuous minute during any of the required 5-minute
observation periods, the monitoring period shall be extended to 2
hours.
Industry representatives have suggested to the EPA that flare
combustion efficiency is highest at the incipient smoke point (the
point at which black smoke begins to form within the flame). They
stated that the existing limit for visible emissions could be increased
from 5 minutes to 10 minutes in a 2-hour period to encourage operation
near the incipient smoke point (see memorandum, Meeting Minutes for
February 19, 2013, Meeting Between the U.S. EPA and Representatives
from the Petroleum Refining Industry, in Docket ID Number EPA-HQ-OAR-
2010-0682). While we agree that operating near the incipient smoke
point results in good combustion at the flare tip, we disagree that the
allowable period for visible emissions be increased from 5 to 10
minutes for a 2-hour period. Smoking flares can contribute
significantly to emissions of particulate matter 2.5 micrometers in
diameter and smaller (PM2.5) emissions, and we are concerned
that increasing the allowable period of visible emissions from 5
minutes to 10 minutes for every 2-hour period could result in an
increase in the PM2.5 emissions from flares.
As discussed later in this section, we are proposing additional
operational and monitoring requirements for refinery flares which we
expect will result in refineries installing equipment that can be used
to fine-tune and control the amount of assist steam or air introduced
at the flare tip such that combustion efficiency of the flare will be
maximized. These monitoring and control systems will assist refinery
flare owners or operators operating near the incipient smoke point
without exceeding the visible emissions limit. While combustion
efficiency may be highest at the incipient smoke point, it is not
significantly higher than the combustion efficiency achieved by these
proposed operating limits, discussed in section IV.A.3.d of this
preamble. As seen in the performance curves for flares (see technical
memorandum, Petroleum Refinery Sector Rule: Operating Limits for
Flares, in Docket ID Number EPA-HQ-OAR-2010-0682), there is very
limited improvement in flare performance beyond the performance
achieved at these proposed operating limits. We solicit comments and
data on appropriate periods of visible emissions that would encourage
operation at the incipient smoke point while not significantly
increasing PM2.5 emissions.
c. Flare Tip Velocity
The General Provisions at 40 CFR 63.11(b) specify maximum flare tip
velocities based on flare type (non-assisted, steam-assisted, or air-
assisted) and the net heating value of the flare vent gas. These
maximum flare tip velocities are required to ensure that the flame does
not ``lift off'' the flare, which could cause flame instability and/or
potentially result in a portion of the flare gas being released without
proper combustion. We are proposing to remove the cross-reference to
the General Provisions and consolidate the requirements for maximum
flare tip velocity into Refinery MACT 1 and 2 as a single equation,
irrespective of flare type (i.e., steam-assisted, air-assisted or non-
assisted). Based on our analysis of the various studies for air-
assisted flares, we identified air-assisted test runs with high flare
tip velocities that had high combustion efficiencies (see technical
memorandum, Petroleum Refinery Sector Rule: Evaluation of Flare Tip
Velocity Requirements, in Docket ID Number EPA-HQ-OAR-2010-0682). These
test runs exceeded the maximum flare tip velocity limits for air-
assisted flares using the linear equation in 40 CFR 63.11(b)(8). When
these test runs were compared with the test runs for non-assisted and
steam-assisted flares, the air-assisted flares appeared to have the
same operating envelope as the non-assisted and steam-assisted flares.
Therefore, we are proposing that air-assisted flares at refineries use
the same equation that non-assisted and steam-assisted flares currently
use to establish the flare tip velocity operating limit.
In developing these proposed flare tip velocity requirements, we
considered whether any adjustments to these velocity equations were
necessary. The flare tip velocity equations require the input of the
net heating value of the vent gas going to the flare, as opposed to the
net heating value of the gas mixture at the flare tip (i.e., the
combustion zone gas). As discussed later in this section, we found that
the performance of the flare was much more dependent on the net heating
value of the gas mixture in the combustion zone than on the net heating
value of only the vent gas going into the flare (excluding all assist
media). We considered replacing the term in the velocity equation for
the net heating value of the vent gas going into the flare with the net
heating value of the gas mixture in the combustion zone. However, the
steam addition rates were not reported for the tests conducted to
evaluate flame stability as a function of flare tip velocity, so direct
calculation of all the terms needed for calculating the net heating
value in the combustion zone could not be made. At higher flare tip
velocities, we expect that the steam assist rates would be small in
comparison to the total vent gas flow rate, so there would not be a
significant difference between the net heating value of the vent gas
going into the flare and the combustion zone gas net heating value for
the higher velocity flame stability tests. We request comment on the
need and/or scientific reasons to use the flare vent gas net heating
value versus the combustion zone net heating value when determining the
maximum allowable flare tip velocity.
In the 2012 flare peer review, we also discussed the effect of
flame lift off and velocity on flare flame stability (see technical
report, Parameters for Properly Designed and Operated Flares, in Docket
ID Number EPA-HQ-OAR-2010-0682). In looking at ways of trying to
prohibit flame instability, we examined the use of the Shore equation
as a means to limit flare tip velocity. However, after receiving many
comments on use of this equation from the peer reviewers, the
uncertainty with how well the Shore equation models the large range of
flare operation, and the limited dataset with which recent testing used
high velocities (all recent test runs were performed at 10 feet per
second or less), we determined that use of the existing velocity
equation discussed above was still warranted.
We are also proposing for Refinery MACT 1 and 2 to not include the
special flare tip velocity equation in the General Provisions at 40 CFR
63.11(b)(6)(i)(A) for non-assisted flares with hydrogen content greater
than 8 percent. This equation, which was developed based on limited
data from a chemicals manufacturer, has very limited

[[Page 36907]]

applicability for petroleum refinery flares in that it only provides an
alternative for non-assisted flares with large quantities of hydrogen.
Approximately 90 percent of all refinery flares are either steam- or
air-assisted. Furthermore, we are proposing compliance alternatives in
this section that we believe provide a better way for flares at
petroleum refineries with high hydrogen content to comply with the rule
while ensuring proper destruction performance of the flare (see section
IV.A.3.d of this preamble for additional details). Therefore, we are
proposing to not include this special flare tip velocity equation as a
compliance alternative for refinery flares. We request comment on the
need to include this equation. If a commenter supports inclusion of
this equation, we request that the commenter submit supporting
documentation regarding the vent gas composition and flows and, if
available, combustion efficiency determinations that indicate that this
additional equation is needed and is appropriate for refinery flares.
We also request documentation that the maximum allowable flare tip
velocity predicted by this equation adequately ensures proper
combustion efficiency.
The General Provisions require an initial demonstration that a
flare used as an APCD meets the applicable flare tip velocity
requirement in 40 CFR 63.11(b). However, most refinery flares can have
highly variable vent gas flows and a single initial demonstration is
insufficient to demonstrate continuous compliance with the flare tip
velocity requirement. Consequently, we are proposing to amend Refinery
MACT 1 and 2 to require continuous monitoring to determine flare tip
velocity, calculated by monitoring the flare vent gas volumetric flow
rate and dividing by the cross-sectional area of the flare tip. As an
alternative to installing continuous volumetric flow rate monitors, we
are proposing that the owner or operator may elect to install a
pressure- and temperature-monitoring system and use engineering
calculations to determine the flare tip velocity.
d. Refinery Flare Operating and Monitoring Requirements
The current requirements for flares in the General Provisions
specify that the flare vent gas must meet a minimum net heating value
of 200 British thermal units per standard cubic foot (Btu/scf) for non-
assisted flares and 300 Btu/scf for air- and steam-assisted flares.
Refinery MACT 1 and 2 reference these requirements, but neither the
General Provisions nor Refinery MACT 1 and 2 include specific
monitoring requirements to monitor the net heating value of the vent
gas. Moreover, recent flare testing results indicate that this
parameter alone does not adequately address instances when the flare
may be over-assisted since it only considers the gas being combusted in
the flare and nothing else (e.g., no assist media). However, many
industrial flares use steam or air as an assist medium to protect the
design of the flare tip, promote turbulence for the mixing, induce air
into the flame and operate with no visible emissions. Using excessive
steam or air results in dilution and cooling of flared gases and can
lead to operating a flare outside its stable flame envelope, reducing
the destruction efficiency of the flare. In extreme cases, over-
steaming or excess aeration can actually snuff out a flame and allow
regulated material to be released into the atmosphere completely
uncombusted. Since approximately 90 percent of all flares at refineries
are either steam- or air-assisted, it is critical that we ensure the
assist media be accounted for in some form or fashion. Recent flare
test data have shown that the best way to account for situations of
over-assisting is to consider the properties of the mixture of all
gases at the flare tip in the combustion zone when evaluating the
ability to combust efficiently. As discussed in the introduction to
this section, the external peer review panel concurred with our
assessment that the combustion zone properties at the flare tip are
critical parameters to know in determining whether a flare will achieve
good combustion. The General Provisions, however, solely rely on the
net heating value of the flare vent gas.
We are proposing to add definitions of two key terms relevant to
refinery flare performance. First, we are proposing to define ``flare
vent gas'' to include all waste gas, sweep gas, purge gas and
supplemental gas, but not include pilot gas or assist media. We are
proposing this definition because information about ``flare vent gas''
(e.g., flow rate and composition) is one of the necessary inputs needed
to evaluate the make-up of the combustion zone gas. To that end, we are
also proposing to define the ``combustion zone gas'' as flare vent gas
plus the total steam-assist media and premix assist air that is
supplied to the flare.
Based on our review of the recent flare test data, we have
determined that the following combustion zone operational limits can be
used to determine good combustion: Net heating value (Btu/scf), lower
flammability limit (LFL) or a total combustibles fraction (e.g., a
simple carbon count). In this action, we are proposing these new
operational limits, along with methods for determining these limits in
the combustion zone at the flare tip for steam-assisted, air-assisted
and non-assisted flares to ensure that there is enough combustible
material readily available to achieve good combustion.
For air-assisted flares, use of too much perimeter assist air can
lead to poor flare performance. Based on our analysis, we found that
including the flow rate of perimeter assist air in the calculation of
combustion zone operational limits in itself does not identify all
instances of excess aeration. The data suggest that the diameter of the
flare tip, in concert with the amount of perimeter assist air, provides
the inputs necessary to calculate whether or not this type of flare is
over-assisted. Therefore, we are proposing that in addition to
complying with combustion zone operational limits to ensure that there
is enough combustible material available to adequately combust the gas
and pass through the flammability region, air-assisted flares would
also comply with an additional dilution parameter that factors in the
flow rate of the flare vent gas, flow rates of all assist media
(including perimeter assist air), and diameter of flare tip to ensure
that degradation of flare performance from excess aeration does not
occur. This dilution parameter is consistent with the combustion theory
that the more ``time'' the gas spends in the flammability region above
the flare tip, the better it will combust. Also, since both the volume
of the combustion zone (represented by the diameter here) and how
quickly this gas is diluted to a point below the flammability region
(represented by perimeter assist air flow rate) characterize this
``time,'' it makes sense that we propose such a term (see technical
memorandum, Petroleum Refinery Sector Rule: Operating Limits for
Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).
It should be noted that in the 2012 flare peer review report, we
considered a limit for perimeter assist air via the stoichiometric air
ratio. This stoichiometric air ratio is the ratio of the actual mass
flow rate of assist air to the theoretical stoichiometric mass flow
rate of air (based on complete chemical combustion of fuel to carbon
dioxide (CO2) and water) needed to combust the flare vent
gas. However, we are not proposing to include this term as part of the
calculation methodology, as we have determined that the dilution
parameter discussed in this section better assures that air-assisted
flare performance is not degraded due to excess aeration.

[[Page 36908]]

The proposed rule allows the owner or operator flexibility to
select the form of the combustion zone operational limit (i.e., net
heating value, LFL, or total combustibles fraction) with which to
comply in order to provide facilities the option of using monitors they
may already have in place. The monitoring methods we are proposing take
into account the combustible properties of all gas going to the flare
(i.e., flare vent gas, assist gas, and premix air) that affects
combustion efficiency, and they can be used to determine whether a
flare has enough combustible material to achieve the desired level of
control (and whether it is being over-assisted). These methods require
the owner or operator to input the flow of the vent gas to the flare,
the characteristics of the vent gas going to the flare (i.e., either a
heat content (Btu/scf), LFL, or total combustible fuel content,
depending on how the operational limit is expressed), and the flow of
assist media added to the flare.
To estimate the LFL, we are proposing to use a calculation method
based on the Le Chatelier equation. The Le Chatelier calculation uses
the reciprocal of the volume-weighted average over the LFL of the
individual compounds in the gas mixture to estimate the LFL of the gas
mixture. Although Le Chatelier's equation was originally limited to
binary mixtures of combustible gases, we are proposing a method that
was developed by Karim, et al. (1985) and assumes a LFL of infinity for
inert gases. We are also aware of other methods and/or adjustments that
can be made to the Le Chatelier equation in order to calculate a more
accurate estimate of the LFL of a gas mixture (see technical
memorandum, Parameters for Properly Designed and Operated Flares, in
Docket ID Number EPA-HQ-OAR-2010-0682). We are soliciting comment on
the use of this proposed method.
Recent data indicate that one set of operational limits may not be
sufficient for all refinery flares. Flares that receive vent gas
containing significant levels of both hydrogen and olefins often
exhibit lower combustion efficiencies than flares that receive vent gas
with only one (or none) of these compounds. Therefore, we are proposing
more stringent operational limits for flares that simultaneously
receive vent gas containing significant levels of both hydrogen and
olefins (see technical memorandum, Petroleum Refinery Sector Rule:
Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).
Although the minimum net heating value in the combustion zone (i.e.,
Btu/scf) is a good indicator of combustion efficiency, as noted in the
flare peer review report, the LFL and combustibles concentration (or
total combustibles) in the combustion zone are also good indicators of
flare combustion efficiency. For some gas mixtures, such as gases with
high hydrogen content, the LFL or combustibles concentration in the
combustion zone may be better indicators of performance than net
heating value. Consequently, we are proposing operational limits
expressed all three ways, along with associated monitoring requirements
discussed later in this section.
The three operating limits were established in such a way that each
limit is protective on its own. As such, the owner or operator may
elect to comply with any of the three alternative operating limits at
any time, provided they use a monitoring system capable of determining
compliance with each of the proposed alternative operating limits on
which they rely (see technical memorandum, Petroleum Refinery Sector
Rule: Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR-2010-
0682). For example, the owner or operator may elect to install
monitoring for only one of the three alternative operating limits, in
which case the owner or operator must comply with that selected
operating limit at all times. If the owner or operator installs a
system capable of monitoring for all three of the alternative operating
limits, the owner or operator can choose which of the three operating
limits the source will rely on to demonstrate compliance.
A summary of the operating limits specified in this proposed rule
is provided in Table 3 of this preamble. We are proposing that owners
or operators of flares used as APCD would conduct an initial
performance test to determine the values of the parameters to be
monitored (e.g., the flow rate and heat content of the incoming flare
vent gas, the assist media flow rate, and pre-mix air flow rate, if
applicable) in order to demonstrate continuous compliance with the
operational limits in Table 3. We are proposing to require owners or
operators to record and calculate 15-minute block average values for
these parameters. Our rationale for selecting a 15-minute block
averaging period is provided in section IV.A.3.e of this preamble.

Table 3--Operating Limits for Flares in This Proposed Action
------------------------------------------------------------------------
Operating limits: Operating limits:
Flares without Flares with
Operating parameter \a\ hydrogen-olefin hydrogen-olefin
interaction \b\ interaction \b\
------------------------------------------------------------------------
Combustion zone parameters for all flares
------------------------------------------------------------------------
NHVcz....................... >=270 Btu/scf....... >=380 Btu/scf.
LFLcz....................... <=0.15 volume <=0.11 volume
fraction. fraction.
Ccz......................... >=0.18 volume >=0.23 volume
fraction. fraction.
------------------------------------------------------------------------
Dilution parameters for flares using perimeter assist air
------------------------------------------------------------------------
NHVdil...................... >=22 Btu/ft\2\...... >=32 Btu/ft\2\.
LFLdil...................... <=2.2 volume <=1.6 volume
fraction/ft. fraction/ft.
Cdil........................ >=0.012 volume >=0.015 volume
fraction-ft. fraction-ft.
------------------------------------------------------------------------
\a\ The operating parameters are:
NHVcz = combustion zone net heating value.
LFLcz = combustion zone lower flammability limit.
Ccz = combustion zone combustibles concentration.
NHVdil = net heating value dilution parameter.
LFLdil = lower flammability limit dilution parameter.
Cdil = combustibles concentration dilution parameter.
\b\ Hydrogen-Olefin interactions are assumed to be present when the
concentration of hydrogen and olefins in the combustion zone exceed
all three of the following criteria:
(1) The concentration of hydrogen in the combustion zone is greater than
1.2 percent by volume.
(2) The cumulative concentration of olefins in the combustion zone is
greater than 2.5 percent by volume.

[[Page 36909]]

(3) The cumulative concentration of olefins in the combustion zone plus
the concentration of hydrogen in the combustion zone is greater than
7.4 percent by volume.
Btu/ft\2\ = British thermal units per square foot.

We are soliciting comment on the appropriateness of the operating
limits and dilution parameters in Table 3 of this preamble and whether
they ensure that refinery flares operate in a manner that that will
ensure compliance with the MACT requirements for vents to achieve a 98-
percent organic HAP reduction.
Combustion zone gas monitoring alternatives. As discussed
previously in this section, we are proposing to define the combustion
zone gas as the mixture of gas at the flare tip consisting of the flare
vent gas, the total steam-assist media and premix assist air. In order
to demonstrate compliance with the three combustion zone parameter
operating limits of net heating value, LFL and total combustibles
fraction, the owner or operator would need to monitor four things: (1)
Flow rate of the flare vent gas; (2) flow rate of total steam assist
media; (3) flow rate of premix assist air and (4) specific
characteristics associated with the flare vent gas (e.g., heat content,
composition). In order to monitor the flow rates of the flare vent gas,
total steam assist media, and premix assist air, we are proposing that
refinery owners or operators use a continuous volumetric flow rate
monitoring system or a pressure- and temperature-monitoring system with
use of engineering calculations. We are also proposing use of either of
these monitoring methods for purposes of determining the flow rate of
perimeter assist air (for compliance with the dilution parameter).
However, the one component that will determine how many combustion zone
parameter operating limits an owner or operator can comply with is the
specific type of monitor used to characterize the flare vent gas.
Monitoring the individual component concentrations of the flare
vent gas using an on-line gas chromatograph (GC) along with monitoring
vent gas and assist gas flow rates will allow the owner or operator to
determine compliance with any of the three proposed combustion zone
operating limits and any of the three proposed dilution operating
limits (if using air-assisted flares). We considered requiring all
refinery owners or operators of flares to only use a GC to monitor the
flare vent gas composition but since facilities may have other non-GC
monitors already in place (e.g., calorimeters), we are not proposing
such a requirement at this time. However, use of a GC can improve
refinery flare operation and management of resources. For example, use
of a GC to characterize the flare vent gas can lead to product/cost
savings for refiners because they could more readily identify and
correct instances of product being unintentionally sent to a flare,
either through a leaking pressure relief valve or other conveyance that
is ultimately routed to the flare header system. In addition, an owner
or operator that chooses to use a GC (in lieu of one of the other
proposed monitoring alternatives) will be more likely to benefit from
the ability to continuously fine-tune their operations (by reducing
assist gas addition and/or supplemental gas to the flare) in order to
meet any one of the three operating limits. Furthermore, some
facilities are already required to use a GC to demonstrate compliance
with state flare requirements. We are soliciting comment on the
additional benefits that using a GC offers and whether it would be
reasonable to require a GC on all refinery flares.
As an alternative to a continuous compositional monitoring system,
we are proposing to allow the use of grab samples along with
engineering calculations to determine the individual component
concentration. Like the on-line GC, the grab sampling option relies on
compound speciation and is therefore flexible to use with any form of
the operational limits we are proposing. The disadvantage of this
option is that if a grab sample indicates non-compliance with the
operational limits, the permitting authority could presume non-
compliance from the time of the previous grab sample indicating
compliance, which would include all 15-minute periods in that time
period. However, there are a number of situations where the refinery
owner or operator may find this option advantageous. For example, some
flares receive flows only from a specific process with a consistent
composition and high heat content. In this case, the owner or operator
may elect to actively adjust the assist gas flow rates using the
expected vent gas composition and rely on the analysis of the grab
sample to confirm the expected vent gas composition. This alternative
may also be preferred for flares that are used infrequently (non-
routine flow flares) or that have flare gas recovery systems designed
and operated to recover 100 percent of the flare gas under typical
conditions. For these flares, flaring events may be so seldom that the
refinery owner or operator may prefer the uncertainty in proactive
control to the higher cost of continuous monitors that would seldom be
used.
As an alternative to performing a compositional analysis with use
of a GC (through either on-line monitoring or analysis of the grab
sample), we are proposing that owners or operators of flares may elect
to install a device that directly monitors vent gas net heating value
(i.e., a calorimeter). If the owner or operator elects this monitoring
method, we are proposing that they must comply with the operating
limits that are based on the net heating value operating limit.
Similarly, we are also proposing that owners or operators of flares may
elect to install a device that directly monitors the total hydrocarbon
content of the flare vent gas (as a measure of the combustibles
concentration). If the owner or operator elects this monitoring method,
they must comply with the operating limits that are based on the
combustibles concentration.
e. Data Averaging Periods for Flare Gas Operating Limits
We are proposing to use a 15-minute block averaging period for each
proposed flare operating parameter (including flare tip velocity) to
ensure that the flare is operated within the appropriate operating
conditions. As flare vent gas flow rates and composition can change
significantly over short periods of time, a short averaging time was
considered to be the most appropriate for assessing proper flare
performance. Furthermore, since flare destruction efficiencies can fall
precipitously fast below the proposed operating limits, short time
periods where the operating limits are not met could seriously impact
the overall performance of the flare. With longer averaging times,
there may be too much opportunity to mask these short periods of poor
performance (i.e., to achieve the longer-term average operating limit
while not achieving a high destruction efficiency over that time period
because of short periods of poor performance).
Moreover, a 15-minute averaging period is in line with the test
data and the analysis used to establish the operating limits in this
proposed rule. Ninety-three percent of the flare test runs used as a
basis for establishing the proposed operating limits ranged in duration
from 5 to 30 minutes, and 77

[[Page 36910]]

percent of the runs ranged in duration from 5 to 20 minutes. The
failure analysis (discussed in section IV.A.3.f of this preamble)
considered minute-by-minute test run data, but as there are limitations
on how quickly compositional analyses can be conducted, many of the
compositional data still reflect set values over 10- to 15-minute time
intervals. Because the GC compositional analyses generally require 10
to 15 minutes to conduct, shorter averaging times are not practical. To
be consistent with the available test data and to ensure there are no
short periods of significantly poor performance, we are proposing 15-
minute block averaging times.
Given the short averaging times for the operating limits, we are
proposing special calculation methodologies to enable refinery owners
or operators to use ``feed forward'' calculations to ensure compliance
with the operating limits on a 15-minute block average. Specifically,
the results of the compositional analysis determined just prior to a
15-minute block period are to be used for the next 15-minute block
average. Owners or operators of flares will then know the vent gas
properties for the upcoming 15-minute block period and can adjust
assist gas flow rates relative to vent gas flow rates to comply with
the proposed operating limits.
Owners or operators of flares that elect to use grab sampling and
engineering calculations to determine compliance must still assess
compliance on a 15-minute block average. The composition of each grab
sample is to be used for the duration of the episode or until the next
grab sample is taken. We are soliciting comment on whether this
approach is appropriate, and whether grab samples are needed on a more
frequent basis to ensure compliance with the operating limits.
f. Other Peer Review Considerations
In an effort to better inform the proposed new requirements for
refinery flares, in the spring of 2012 the EPA summarized its
preliminary findings on operating parameters that affect flare
combustion efficiency in a technical report and put this report out for
a letter review. Based on the feedback received, the EPA considered
many of the concerns peer reviewers expressed in their comments in the
development of this proposal for refinery flares (see memorandum, Peer
Review of ``Parameters for Properly Designed and Operated Flares'', in
Docket ID Number EPA-HQ-OAR-2010-0682). While the more substantive
issues have been previously discussed in sections IV.A.3.a through e of
this preamble, the following discussion addresses other peer review
considerations that the EPA either discussed in the peer review
technical document or considered from comments received by the peer
review panel that played a role in the development of this proposal.
Test data quality and analysis. For steam-assisted flares, we asked
peer reviewers to comment on our criteria for excluding available flare
test data from our analyses. In general, peer reviewers considered the
EPA's reasons for removing certain test data (prior to performing any
final analysis) to be appropriate; however, one reviewer suggested the
EPA complete an analysis of quality on the data before applying any
criteria, and several reviewers commented on the level of scrutiny of
the 10 data points specifically discussed in the technical report for
not meeting the combustion zone LFL trend. These reviewers stated it
appeared the EPA had scrutinized test data more if it were inconsistent
with the LFL threshold conclusions made in the report. Although we felt
it was appropriate to discuss specific test data not fitting the trend,
we do agree with the reviewers that a more general and standard set of
criteria should be applied to all test data prior to making any
conclusion. In addition, other peer reviewers saw no reason why the EPA
should exclude 0-percent combustion efficiency data points, or data
points where smoking occurs, or single test runs when there was also a
comparable average test run. Therefore, in response to these peer
review comments, the EPA performed a validation and usability analysis
on all available test data. This resulted in a change to the population
of test data used in our final analysis (see technical memorandum,
Flare Performance Data: Summary of Peer Review Comments and Additional
Data Analysis for Steam-Assisted Flares, in Docket ID Number EPA-HQ-
OAR-2010-0682 for a more detailed discussion of the data quality and
analysis).
To help determine appropriate operating limits, several peer
reviewers suggested the EPA perform a false-positive-to-false-negative
comparison (or failure type) analysis between the potential parameters
discussed in the technical report as indicators of flare performance.
The reviewers suggested that the EPA attempt to minimize the standard
error of all false positives (i.e., poor observed combustion efficiency
when the correlation would predict good combustion) and false negatives
(i.e., good observed combustion efficiency when the correlation would
predict poor combustion). In response to these comments, the EPA has
conducted a failure analyses of these parameters which helped form the
basis for the operating limits we are proposing for flares (see
technical memorandum, Petroleum Refinery Sector Rule: Operating Limits
for Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).
Some peer reviewers contended that it is appropriate for the EPA to
round each established operating limit to the nearest whole number,
because using a decimal implies far more accuracy and reliability than
can be determined from the test data. Based on these comments, we have
given more consideration to the number of significant figures used in
the operating limits, and we are proposing to use two significant
figures for the flare operating limits in these proposed amendments.
Multiple peer reviewers performed additional analyses to try and
determine the appropriateness of the limits raised in the technical
report. Some peer reviewers tried to fit the data to a curve, others
performed various failure analyses, while others looked at different
metrics not discussed in the technical report (see memorandum, Peer
Review of ``Parameters for Properly Designed and Operated Flares'', in
Docket ID Number EPA-HQ-OAR-2010-0682). Based on the conclusions drawn
from these various analyses, a range of combustion zone net heating
value targets from 200 Btu/scf to 450 Btu/scf were identified as
metrics that would provide a high level of certainty regarding good
combustion in flares (Note: 450 Btu/scf was the assumed to be
approximately equivalent to a combustion zone LFL of 10 percent). We
solicit comment on this range and the appropriateness for which the
operating limits selected in this proposal will ensure compliance with
the MACT requirements for vents at petroleum refineries.
Effect of supplemental gas use. Most flares normally operate at a
high turndown ratio, which means the actual flare gas flow rate is much
lower than what the flare is designed to handle. In addition, steam-
assisted flares have a manufacturers' minimum steam requirement in
order to protect the flare tip. A combination of high turndown ratio
and minimum steam requirement will likely require some owners or
operators to add supplemental gas to achieve one of the combustion zone
gas operating limits we are proposing here (e.g., combustion zone
combustibles concentration (Ccz) >= 18 volume percent;
combustion zone lower flammability limit (LFLcz) <= 15
volume percent; or combustion zone net heating value (NHVcz)
>= 270 Btu/scf). However, fine-

[[Page 36911]]

tuning the actual steam flow to the flare should significantly reduce
the need for supplemental gas. We considered proposing a steam-to-vent
gas ratio limitation on steam-assisted flares. However, a steam-to-vent
gas ratio alone cannot fully address over-steaming because it would not
account for the variability of chemical properties within the flare
gas. We request that commenters on this issue provide supporting
documentation on their potential to reduce steam as well as their use
of supplemental gas to achieve the proposed operating limit(s), and how
it could affect cost and potential emissions. We emphasize that the
amount and cost of supplemental gas should be reflective of conditions
after any excess steam use has been rectified. It would not be valuable
to consider situations where large amounts of supplemental gas are
added, while steam is simultaneously added far in excess of the amount
recommended by the flare manufacturer or other guidance documents.
In assessing the combustion zone gas and looking at all the gas at
the flare tip, another potential source of added heat content comes
from the gas being used as fuel to maintain a continuously lit pilot
flame. However, since pilot gas is being used as fuel for a continuous
ignition source and is burned to create a flame prior to (or at the
periphery of) the combustion zone, this gas does not directly
contribute to the heat content or flammability of the gas being sent to
the flare to be controlled under Refinery MACT 1 or 2. In addition, in
looking at available test data, the pilot gas flow rate is generally so
small that it does not significantly impact the combustion zone
properties at all. Furthermore, by leaving pilot gas out of the
combustion zone operating limit calculations, the equations become
simplified and a requirement to continuously monitor pilot gas flow
rate can be avoided. Therefore, we are proposing that the owner or
operator not factor in the pilot gas combustible component (or net
heating value) contribution when determining any of the three proposed
combustion zone gas operating limits (Ccz, LFLcz,
or NHVcz).
Effects of wind on flame performance. Several published studies
have investigated the significance of wind on the fluid mechanics of a
flare flame (see technical memorandum, Parameters for Properly Designed
and Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). These
studies were conducted in wind tunnels at crosswind velocities up to
about 60 miles per hour (mph) and have illustrated that increased
crosswind velocity can have a strong effect on flare flame dimensions
and shape, causing the flame to become segmented or discontinuous, and
wake-dominated (i.e., where the flame is bent over on the downwind side
of a flare pipe and is imbedded in the wake of the flare tip), which
may lead to poor flare performance due to fuel stripping. However, the
majority of this research is confined to laboratory studies on flares
with effective diameters less than 3 inches, which have been shown not
to be representative of industrial-sized flares. Research that does
include performance tests conducted on flares scalable to refinery
flares (i.e., 3-inch, 4-inch, and 6-inch pipe flares) was conducted
with flare tip velocities as low as 0.49 feet per second and crosswind
velocities of about 26 mph and less; all tests resulted in good flare
performance. Furthermore, there is no indication that crosswind
velocities negatively impact flare performance in the recent flare
performance tests. These tests were conducted on various sizes of
industrial flares (i.e., effective diameters ranging between 12 and 54
inches) in winds of about 22 mph and less, and at relatively low flare
tip velocities (i.e., 10 feet per second or less). (See Parameters for
Properly Designed and Operated Flares, in Docket ID Number EPA-HQ-OAR-
2010-0682.)
We are aware of flare operating parameters that consider crosswind
velocity; however, using the available flare performance test data, we
were unable to determine a clear correlation that would be appropriate
for all refinery flares. For example, the momentum flux ratio (MFR) is
a measure of momentum strength of the flare exit gas relative to the
crosswind (i.e., the product of flare exit gas density and velocity
squared divided by the product of air density and crosswind velocity
squared). The plume buoyancy factor is the ratio of crosswind velocity
to the flare exit gas velocity, and considers the area of the flare
pipe. The power factor is the ratio of the power of the crosswind to
the power of combustion of the flare gas. Because the available flare
performance test data have relatively low flare tip velocities, and
crosswind velocities were relatively constant during each test run, we
are unable to examine these parameters to the fullest extent.
In light of the data available from performance tests (Gogolek et
al., 2010), we asked peer reviewers whether the MFR could be used in
crosswind velocities greater than 22 mph at the flare tip to indicate
wake-dominated flame situations. We also asked for comment on
observations that in the absence of crosswind greater than 22 mph, a
low MFR does not necessarily indicate poor flare performance. Peer
reviewers suggested that there are no data available from real
industrial flares in winds greater than 22 mph to support that MFR
could be used to identify wake-dominated flame situations. In addition,
we received no further peer review comments that have caused us to
reconsider the observation we made in the April 2012 technical report
that in the absence of crosswind greater than 22 mph, a low MFR does
not necessarily indicate poor flare performance. We request comment
with supporting data and rationale on any of these, or other
parameters, as a measure of wind effects on flare combustion
efficiency.
We considered including observation requirements for detecting
segmented or discontinuous wake-dominated flames, especially for winds
greater than 22 mph (where limited test data is available). However,
owners or operators of flares cannot control the wind speed, and it
would be detrimental to increase the quantity of flared gases in high
crosswind conditions in efforts to improve the MFR and reduce wake-
dominated flow conditions. Furthermore, there is no indication that
crosswind velocities negatively impact flare performance in the recent
flare performance tests. For these reasons, we are not proposing any
flare operating parameter(s) to minimize wind effects on flare
combustion efficiency.
g. Impacts of the Flare Operating and Monitoring Requirements
The EPA expects that the newly proposed requirements for refinery
flares discussed in this section will affect all flares at petroleum
refineries. Based on data received as a result of the Refinery ICR, we
estimate that there are 510 flares operating at petroleum refineries
and that 285 of these receive flare vent gas flow on a regular basis
(i.e., other than during periods of startup, shutdown, and
malfunction). Costs were estimated for each flare for a given refinery,
considering operational type (e.g., receive flare vent gas flow on a
regular basis, use flare gas recovery systems to recover 100 percent of
routine flare flow, handle events during startup, shutdown, or
malfunction only, etc.) and current monitoring systems already
installed on each individual flare. Costs for any additional monitoring
systems needed were estimated based on installed costs received from
petroleum refineries and, if installed costs were unavailable, costs
were estimated based on vendor-purchased equipment. The baseline
emission estimate and the emission

[[Page 36912]]

reductions achieved by the proposed rule were estimated based on
current vent gas and steam flow data submitted by industry
representatives. The results of the impact estimates are summarized in
Table 4 of this preamble. We note that the requirements for refinery
flares we are proposing in this action will ensure compliance with the
Refinery MACT standards when flares are used as an APCD. As such, these
proposed operational and monitoring requirements for flares at
refineries have the potential to reduce excess emissions from flares by
approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 327,000 metric
tonnes per year of CO2e. The VOC compounds are non-methane,
non-ethane total hydrocarbons. According to the Component 2 database
from the Refinery ICR, there are approximately 50 individual HAP
compounds included in the emission inventory for flares, but many of
these are emitted in trace quantities. A little more than half of the
HAP emissions from flares are attributable to hexane, followed next by
benzene, toluene, xylenes, and 1,3-butadiene. For more detail on the
impact estimates, see the technical memorandum Petroleum Refinery
Sector Rule: Flare Impact Estimates in Docket ID Number EPA-HQ-OAR-
2010-0682.

Table 4--Nationwide Cost Impacts of Proposed Amendments To Ensure Proper
Flare Performance
------------------------------------------------------------------------
Total
Total capital annualized
Affected source investment costs (million
(million $) $/yr)
------------------------------------------------------------------------
Flare Monitoring...................... 147 36.3
------------------------------------------------------------------------

4. Vent Control Bypasses
a. Relief Valve Discharges
Refinery MACT 1 recognized relief valve discharges to be the result
of malfunctions. Relief valves are designed to remain closed during
normal operation and only release as the result of unplanned and/or
unpredictable events. A release from a relief valve usually occurs
during an over pressurization of the system. However, emissions vented
directly to the atmosphere by relief valves in organic HAP service
contain HAP that are otherwise regulated under Refinery MACT 1.
Refinery MACT 1 regulated relief valves through equipment leak
provisions that applied only after the pressure relief occurred. In
addition the rule followed the EPA's then-practice of exempting
startup, shutdown and malfunction (SSM) events from otherwise
applicable emission standards. Consequently, with relief valve releases
defined as unplanned and nonroutine and the result of malfunctions,
Refinery MACT 1 did not restrict relief valve releases to the
atmosphere but instead treated them the same as all malfunctions
through the SSM exemption provision.
In Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court
determined that the SSM exemption violates the CAA. See section IV.E of
this preamble for additional discussion. To ensure this standard is
consistent with that decision, these proposed amendments remove the
malfunction exemption in Refinery MACT 1 and 2 and provide that
emissions of HAP may not be discharged to the atmosphere from relief
valves in organic HAP service. To ensure compliance with this
amendment, we are also proposing to require that sources monitor relief
valves 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. Pressure release events from
relief valves to the atmosphere have the potential to emit large
quantities of HAP. Where a pressure release occurs, it is important to
identify and mitigate it as quickly as possible. For purposes of
estimating the costs of this requirement, we assumed that operators
would install electronic monitors on each relief valve that vents to
the atmosphere to identify and record the time and duration of each
pressure release. However, we are proposing to allow owners and
operators to use a range of methods to satisfy these requirements,
including the use of a parameter monitoring system (that may already be
in place) on the process operating pressure that is sufficient to
indicate that a pressure release has occurred as well as record the
time and duration of that pressure release. Based on our cost
assumptions, the nationwide capital cost of installing these electronic
monitors is $9.54 million and the annualized capital cost is $1.36
million per year.
As defined in the Refinery MACT standards, relief valves are valves
used only to release unplanned, nonroutine discharges. A relief valve
discharge results from an operator error, a malfunction such as a power
failure or equipment failure, or other unexpected cause that requires
immediate venting of gas from process equipment in order to avoid
safety hazards or equipment damage. Even so, to the extent that there
are atmospheric HAP emissions from relief valves, we are required to
follow the Sierra Club ruling to address those emissions in our rule,
and we can no longer exempt them as permitted malfunction emissions as
we did under Refinery MACT 1. Our information indicates that there are
approximately 12,000 pressure relief valves that vent to the atmosphere
(based on the ICR responses) and that the majority of relief valves in
the refining industry are not atmospheric, but instead are routed to
flares (see letter from API, Docket Item Number EPA-HQ-OAR-2010-0682-
0012). We request comment on our approach and on alternatives to our
approach to regulating releases from pressure relief valves and also
request commenters to provide information supporting any such comments.
b. Bypass Lines
For a closed vent system containing bypass lines that can divert
the stream away from the APCD to the atmosphere, Refinery MACT 1
requires the owner or operator to either: (1) Install, maintain and
operate a continuous parametric monitoring system (CPMS) for flow on
the bypass line that is capable of detecting whether a vent stream flow
is present at least once every hour, or (2) secure the bypass line
valve in the non-diverting position with a car-seal or a lock-and-key
type configuration. Under option 2, the owner or operator is also
required to inspect the seal or closure mechanism at least once per
month to verify the valve is maintained in the non-diverting position
(see 40 CFR 63.644(c) for more details). We are proposing under CAA
section 112(d)(2) and (3) that the use of a bypass at any time to
divert a Group 1 miscellaneous process vent is a violation of the
emission standard, and to specify that if option 1 is chosen, the owner
or operator would be required to install,

[[Page 36913]]

maintain and operate a CPMS for flow that is capable of recording the
volume of gas that bypasses the APCD. The CMPS must be equipped with an
automatic alarm system that will alert an operator immediately when
flow is detected in the bypass line. We are proposing this revision
because, as noted above, APCD are not to be bypassed because doing so
could result in a release of regulated organic HAP to the atmosphere.
In Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court
determined that standards under CAA section 112(d) must provide for
compliance at all times and a release of uncontrolled HAP to the
atmosphere is inconsistent with that requirement.
c. In Situ Sampling Systems (Onstream Analyzers)
The current Refinery MACT 1 definition of ``miscellaneous process
vent'' states that ``in situ sampling systems (onstream analyzers)''
are not miscellaneous process vents. 40 CFR 63.641. For several
reasons, we are proposing to remove ``in situ sampling systems
(onstream analyzers)'' from the list of vents not considered
miscellaneous process vents. First, the language used in this exclusion
is inconsistent. We generally consider ``in situ sampling systems'' to
be non-extractive samplers or in-line samplers. There are certain in
situ sampling systems where the measurement is determined directly via
a probe placed in the process stream line. Such sampling systems do not
have an atmospheric vent, so excluding these from the definition of
``miscellaneous process vent'' is not meaningful. The parenthetical
term ``onstream analyzers'' generally refers to sampling systems that
feed directly to an analyzer located at the process unit, and has been
interpreted to exclude the ``onstream'' analyzer's vent from the
definition of miscellaneous process vents. As these two terms do not
consistently refer to the same type of analyzer, the provision is not
clear.
Second, we find that there is no technical reason to include
analyzer vents in a list of vents not considered miscellaneous process
vents. For extractive sampling systems and systems with purges, the
equipment leak standards in Refinery MACT 1 require that the material
be returned to the process or controlled. Thus, the only potential
emissions from any sampling system compliant with the Refinery MACT 1
equipment leak provisions would be from the analyzer's ``exhaust gas''
vent. The parenthetical term ``onstream analyzers'' indicates that the
focus of the exemption is primarily on the analyzer (or analyzer vent)
rather than the sampling system. This phrase has been interpreted to
exclude the ``onstream'' analyzer's vent from the definition of
miscellaneous process vents. Analyzer venting is expected to be routine
(continuous or daily intermittent venting).
We are proposing to delete this exclusion from the definition of
``miscellaneous process vent'' and to require these vents to meet the
standards applicable to miscellaneous process vents at all times. We
expect most analyzer vents to be Group 2 miscellaneous process vents
because analyzer vents are not expected to exceed the 72 pounds per day
(lb/day) emissions threshold for Group 1 miscellaneous process vents.
However, if there are larger analyzer vents that exceed the 72 lb/day
emissions threshold for Group 1 miscellaneous process vents, these
emission sources would need to be controlled as a Group 1 miscellaneous
process vent under this proposal. We solicit comment on the existence
of any onstream analyzers that have VOC emissions greater than 72 lb/
day and why such vents are not amenable to control.
d. Refinery Flares and Fuel Gas Systems
The current definition of ``miscellaneous process vent'' in
Refinery MACT 1 states that ``gaseous streams routed to a fuel gas
system'' are not miscellaneous process vents. Furthermore, the affected
source subject to Refinery MACT 1 does not specifically include
``emission points routed to a fuel gas system, as defined in Sec.
63.641 of this subpart.'' The EPA allowed these exemptions for streams
routed to fuel gas systems because according to the 1994 preamble for
Refinery MACT 1, ``these vents are already controlled to the most
stringent levels achievable'' (59 FR 36141, July 15, 1994). Since
gaseous streams routed to a fuel gas system are eventually burned as
fuel, typically in a boiler or process heater, these combustion
controls burning the gaseous streams as fuel effectively achieve this
most stringent level of control (i.e., 98-percent organic HAP reduction
or an outlet organic HAP concentration of 20 ppmv for all vent
streams). However, there can be instances when gaseous streams from the
fuel gas system that would otherwise be combusted in a boiler or
process heater are instead routed to a flare (e.g., overpressure in the
fuel gas system, used as flare sweep gas, used as flare purge gas). In
cases where an emission source is required to be controlled in Refinery
MACT 1 and 2 but is routed to a fuel gas system, we are proposing that
any flare receiving gases from that fuel gas system must comply with
the flare operating and monitoring requirements discussed in section
IV.A.3 of this preamble.

B. What are the results and proposed decisions based on our technology
review?

1. Refinery MACT 1--40 CFR Part 63, Subpart CC
Refinery MACT 1 sources include miscellaneous process vents,
storage vessels, equipment leaks, gasoline loading racks, marine vessel
loading operations, cooling towers/heat exchange systems, and
wastewater.
a. Miscellaneous Process Vents
Many unit operations at petroleum refineries generate gaseous
streams containing HAP. These streams may be routed to other unit
operations for additional processing (e.g., a gas stream from a reactor
that is routed to a distillation unit for separation) or they may be
sent to a blowdown system or vented to the atmosphere. Miscellaneous
process vents emit gases to the atmosphere, either directly or after
passing through recovery and/or APCD. Under 40 CFR 63.643, the owner or
operator must reduce organic HAP emissions from miscellaneous process
vents using a flare that meets the equipment specifications in 40 CFR
63.11 of the General Provisions (subpart A) or use APCD (e.g., thermal
oxidizers, carbon adsorbers) to reduce organic HAP emissions by 98
weight-percent or to a concentration of 20 parts per million by volume
(ppmv) dry basis, corrected to 3-percent oxygen.
In the technology review, we did not identify any practices,
processes or control technologies beyond those already required by
Refinery MACT 1. Therefore, we are proposing that it is not necessary
to revise Refinery MACT 1 requirements for miscellaneous process vents
pursuant to CAA section 112(d)(6).
b. Storage Vessels
Storage vessels (also known as storage tanks) are used to store
liquid and gaseous feedstocks for use in a process, as well as liquid
and gaseous products coming from a process. Most storage vessels are
designed for operation at atmospheric or near atmospheric pressures;
high-pressure vessels are used to store compressed gases and liquefied
gases. Atmospheric storage vessels are typically cylindrical with a
vertical orientation, and they are constructed with either a fixed roof
or a floating roof. Some, generally small,

[[Page 36914]]

atmospheric storage vessels are oriented horizontally. High pressure
vessels are either spherical or horizontal cylinders.
Section 63.646(a) requires certain existing and new storage vessels
to comply with 40 CFR 63.119 through 40 CFR 63.121 of the HON. Under 40
CFR 63.119 through 63.121, storage vessels must be equipped with an
internal floating roof with proper seals, an external floating roof
with proper seals, an external floating roof converted to an internal
floating roof with proper seals or a closed vent system routed to an
APCD that reduces HAP emissions by 95 percent. Storage vessels at
existing sources that use floating roofs are not required under
Refinery MACT 1 to install certain fitting controls included in 40 CFR
63.1119 of the HON (e.g., gaskets for automatic bleeder vents, slit
fabric covers for sample wells, flexible fabric seals or gasketed
sliding covers for guidepoles and gasketed covers for other roof
openings). See 40 CFR 63.646(c).
In 2012, we conducted a general analysis to identify the latest
developments in practices, processes and control technologies for
storage vessels at chemical manufacturing facilities and petroleum
refineries, and we estimated the impacts of applying those practices,
processes and technologies to model storage vessels. (See Survey of
Control Technology for Storage Vessels and Analysis of Impacts for
Storage Vessel Control Options, January 20, 2012, Docket Item Number
EPA-HQ-OAR-2010-0871-0027.) We used this analysis as a starting point
for conducting the technology review for storage vessels at refineries.
In this analysis, we identified fitting controls, particularly controls
for floating roof guidepoles, and monitoring equipment (liquid level
monitors and leak monitors) as developments in practices, processes and
control technologies for storage vessels. In our refinery-specific
review, we also noted that the Group 1 storage vessel size and vapor
pressure thresholds in Refinery MACT 1 were higher than those for
storage vessels in MACT standards for other similar industries.
Therefore, we also evaluated revising the Group 1 storage vessel
thresholds as a development in practices for storage vessels in the
refining industry.
We used data from our 2011 ICR to evaluate the impacts of requiring
the additional controls identified in the technology review for the
petroleum refinery source category. The emission reduction options
identified during the technology review are: (1) Requiring guidepole
controls and other fitting controls for existing external or internal
floating roof tanks as required in the Generic MACT for storage vessels
(40 CFR part 63, subpart WW) in 40 CFR 63.1063; (2) option 1 plus
revising the definition of Group 1 storage vessel to include smaller
capacity storage vessels and/or storage vessels containing materials
with lower vapor pressures and (3) option 2 plus requiring additional
monitoring to prevent roof landings, liquid level overfills and to
identify leaking vents and fittings from tanks. We identified options 1
and 2 as developments in practices, processes and control technologies
because these options are required for similar tanks in some chemical
manufacturing MACT standards and we believe they are technologically
feasible for storage vessels at refineries (e.g., Generic MACT, the
HON). Option 3 is also an improvement in practices because these
monitoring methods have been required for refineries by other
regulatory agencies.
Under option 1, we considered the impacts of requiring improved
deck fittings and controls for guidepoles as is required for other
chemical manufacturing sources in the Generic MACT. Specifically, we
considered these controls for storage vessels with existing internal or
external floating roof tanks. This option also includes the inspection,
recordkeeping, and reporting requirements set forth in the Generic MACT
to account for the additional requirements for fitting controls. We are
aware of recent waiver requests to EPA to allow in-service, top-side
inspections instead of the out-of-service inspections required on a 10-
year basis for internal floating roof tanks for facilities that are
currently subject to 40 CFR part 60, subpart Kb and Refinery MACT 1.
The requirements of Generic MACT allow for this option if there is
visual access to all the deck components. Under option 1, we considered
the Generic MACT provisions for in-service, top-side inspection. We are
requesting comment on whether or not these in-service inspections are
adequate for identifying conditions that are indicative of deck,
fitting, and rim seal failures; we are also requesting comment on
methods to effectively accomplish top-side inspections.
For option 2, we evaluated revising the definition of Group 1
storage vessels to include smaller capacity storage vessels and/or
storage vessels with lower vapor pressure, such that these additional
storage vessels would be subject to the Group 1 control requirements.
For storage vessels at existing sources, Refinery MACT 1 currently
defines Group 1 storage vessels to be those with a capacity of 177
cubic meters (46,760 gallons) or greater, and a true vapor pressure of
10.4 kilopascals (1.5 pounds per square inch absolute (psia)) or
greater. Under option 2, we evaluated the impacts of changing the
definition of Group 1 storage vessels to include storage vessels with a
capacity of 151 cubic meters (40,000 gallons) or greater and a true
vapor pressure of 5.2 kilopascals (0.75 psia) or greater, and also
evaluated including storage vessels with a capacity of 76 cubic meters
(20,000 gallons) or greater (but less than 151 cubic meters), provided
the true vapor pressure of the stored liquid is 13.1 kilopascals (1.9
psia) or greater. These thresholds are consistent with storage vessel
standards already required for the chemical industry (e.g., the HON).
We believe the predominant effect of changing these thresholds will be
fixed roof tanks at existing petroleum refineries shifting from Group 2
storage vessels to Group 1 storage vessels. These fixed roof tanks
would thus need to be retrofitted with floating roofs or vented to an
APCD in order to comply with the provisions for Group 1 storage
vessels. We estimated the impacts of option 2 by assuming all
uncontrolled fixed roof storage vessels that meet or exceed the
proposed new applicability requirements for Group 1 storage vessels
(based on the information collected in the Refinery ICR) would install
an internal floating roof with a single rim seal and deck fittings to
the existing fixed roof tank. The costs of these fixed roof retrofits
were added to the costs determined for option 1 to determine the cost
of option 2.
Under option 3, we considered the impacts of including additional
monitoring requirements for Group 1 storage vessels (in addition to
fitting controls and fixed roof retrofits considered under options 1
and 2). The monitoring requirements evaluated include monitoring of
internal or external floating roof tanks with EPA Method 21 (of 40 CFR
part 60, Appendix A-7) or optical gas imaging for fittings, and
requiring the use of liquid level overfill warning monitors and roof
landing warning monitors. These costs were estimated based on the total
number of Group 1 storage vessels considering the change in the
applicability thresholds included in option 2. For further details on
the assumptions and methodologies used in this analysis, see the
technical memorandum titled Impacts for Control Options for Storage
Vessels at Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-
0682.

[[Page 36915]]

Table 5 of this preamble presents the impacts for the three options
considered. Although the options were considered cumulatively, the
calculation of the incremental cost effectiveness allows us to assess
the impacts of the incremental change between the options. As seen by
the incremental cost effectiveness column in Table 5, both options 1
and 2 result in a net cost savings considering the VOC recovery credit
for product not lost to the atmosphere from the storage vessel.\28\ We
seek comment on the appropriateness of the VOC recovery credit we used.
The incremental cost effectiveness for option 3 exceeds $60,000 per ton
of HAP removed. We consider option 3 not to be cost effective and are
not proposing to require this additional monitoring.
---------------------------------------------------------------------------

\28\ The VOC recovery credit is $560 per ton, based on $1.75/gal
price for generic refinery product (gasoline/diesel fuel). (See the
technical memorandum titled Impacts for Control Options for Storage
Vessels at Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-
2010-0682 for more details.)
---------------------------------------------------------------------------

Based on this analysis, we consider option 2 to be cost effective.
We are, therefore, proposing to revise Refinery MACT 1 to cross-
reference the corresponding storage vessel requirements in the Generic
MACT (including requirements for guidepole controls and other fittings
as well as inspection requirements), and to revise 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 1.9 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.

Table 5--Nationwide Emissions Reduction and Cost Impacts of Control Options for Storage Vessels at Petroleum Refineries
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total
Annualized annualized Overall cost Incremental
costs costs with effectiveness cost
Capital without Emissions Emissions Cost VOC with VOC effectiveness
Control option cost recovery reduction, reduction, effectiveness recovery Rrcovery with VOC
(million $) credits VOC (tpy) HAP (tpy) ($/ton HAP) credit credit ($/ recovery
(million $/ (million $/ ton HAP) credit ($/
yr) yr) ton HAP)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1......................................... 11.9 1.8 11,800 720 2,470 (4.8) (6,690)
2......................................... 18.5 3.1 14,600 910 3,430 (5.0) (5,530) (1,140)
3......................................... 36.4 9.6 16,000 1,000 9,580 0.56 560 61,500
--------------------------------------------------------------------------------------------------------------------------------------------------------

c. Equipment Leaks
Equipment leaks are releases of process fluid or vapor from
processing equipment, including pump and compressor seals, process
valves, relief devices, open-ended valves and lines, flanges and other
connectors, agitators and instrumentation systems. These releases occur
primarily at the interface between connected components of equipment or
in sealing mechanisms.
Refinery MACT 1 requires the owner or operator of an existing
source to comply with the equipment leak provisions in 40 CFR part 60,
subpart VV (Standards of Performance for Equipment Leaks of VOC in the
Synthetic Organic Chemicals Manufacturing Industry) for all equipment
in organic HAP service. The term ``in organic HAP service'' means that
a piece of equipment either contains or contacts a fluid (liquid or
gas) that is at least 5 percent by weight of total organic HAP.
Refinery MACT 1 specifies that the owner or operator of a new source
must comply with the HON, as modified by Refinery MACT 1. The
provisions for both new and existing sources require inspection (either
through instrument monitoring using EPA Method 21 of 40 CFR part 60,
Appendix A-7, or other method such as visible inspection) and repair of
leaking equipment. For existing sources, the leak definition under 40
CFR part 60, subpart VV triggers repair at an instrument reading of
10,000 parts per million (ppm) for all equipment monitored using EPA
Method 21 of 40 CFR part 60, Appendix A-7 (i.e., pumps and valves;
instrument monitoring of equipment in heavy liquid service and
connectors is optional). For new sources, the Refinery MACT 1-modified
version of the HON triggers repair of leaks for pumps at 2,000 ppm and
for valves at 1,000 ppm. Refinery MACT 1 requires new and existing
sources to install a cap, plug or blind flange, as appropriate, on
open-ended valves or lines. Refinery MACT 1 does not require instrument
monitoring of connectors for either new or existing sources.
We conducted a general analysis to identify the latest developments
in practices, processes and control technologies applicable to
equipment leaks at chemical manufacturing facilities and petroleum
refineries, and we estimated the impacts of applying the identified
practices, processes and technologies to several model plants. (See
Analysis of Emissions Reduction Techniques for Equipment Leaks,
December 21, 2011, Docket Item Number EPA-HQ-OAR-2010-0869-0029.) We
used this general analysis as a starting point for conducting the
technology review for equipment leaks at refineries, but did not
identify any developments beyond those in the general analysis. We
estimated the impacts of applying the practices, processes and
technologies identified in the general analysis to equipment leaks in
petroleum refinery processes using the information we collected through
the 2011 Refinery ICR. In general, leak detection and repair (LDAR)
programs have been used by many industries for years to control
emissions from equipment leaks. Over the years, repair methods have
improved and owners and operators have become more proficient at
implementing these programs. The specific developments identified
include: (1) Requiring repair of leaks at a concentration of 500 ppm
for valves and 2,000 ppm for pumps for new and existing sources (rather
than 10,000 ppm for valves and pumps at existing sources and 1,000 for
valves at new sources); (2) requiring monitoring of connectors using
EPA Method 21 (of 40 CFR part 60, Appendix A-7) and repair of leaks for
valves and pumps at a concentration of 500 ppm; and (3) allowing the
use of optical gas imaging devices as an alternative method of
monitoring.
The first option we evaluated was to require repair based on a leak
definition of 500 ppm for valves and a leak definition of 2,000 ppm for
pumps at both new and existing sources. The nationwide costs and
emission reduction impacts of applying those lower leak definitions to
equipment leaks at petroleum refineries are shown in Table 6 of this
preamble. For further details on the assumptions and methodologies used
in this analysis, see the technical memorandum titled Impacts for
Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA-HQ-
OAR-2010-0682.

[[Page 36916]]

The emissions reduction results in product not being lost by a leak;
this additional product can be sold to generate revenue, referred to as
a VOC recovery credit. Table 6 shows costs and cost effectiveness both
with and without the VOC recovery credit. Based on the estimated
organic HAP emission reductions of 24 tpy and the cost effectiveness of
$14,100 per ton of organic HAP (including VOC recovery credit), we
consider lowering the leak definition not to be a cost-effective option
for reducing HAP emissions. We are, therefore, proposing that it is not
necessary to revise Refinery MACT 1 pursuant to CAA section 112(d)(6)
to require repair of leaking valves at 500 ppm or greater and repair of
leaking pumps at 2,000 ppm or greater.

Table 6--Nationwide Emissions Reduction and Cost Impacts of Monitoring and Repair Requirements at Lower Leak Definitions
[500 ppm for valves; 2,000 ppm for pumps]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Overall cost Overall cost
Annualized costs Emissions Emissions Cost Cost Total annualized effectiveness effectiveness
Capital cost (million $) without recovery reduction, VOC reduction, HAP effectiveness ($/ effectiveness ($/ costs with VOC with VOC recovery with VOC recovery
credits (million (tpy) (tpy) ton VOC) ton HAP) recovery credit credit ($/ton credit ($/ton
$/yr) (million $/yr) VOC) HAP)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1.22.................................... 0.53 342 24 1,550 22,100 0.34 987 14,100
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

We note that we are aware that some owners and operators are
required to repair leaking valves as low as 100 ppm and pumps as low as
500 ppm. However, we consider requiring repair of leaking valves at 500
ppm or greater and repair of leaking pumps at 2,000 ppm or greater not
to be cost effective. As documented in Analysis of Emissions Reduction
Techniques for Equipment Leaks (December 21, 2011, in Docket ID Number
EPA-HQ-OAR-2010-0869), the cost effectiveness for this option would be
even higher than the values shown in Table 6 of this preamble.
The second option we considered was connector monitoring and
repair. Several standards applying to chemical manufacturing
facilities, including the HON, include requirements for connector
monitoring using EPA Method 21 (of 40 CFR part 60, Appendix A-7) and
requirements for repair of any connector leaks above 500 ppm VOC.
Neither the Refinery MACT 1 nor the NSPS for equipment leaks from
refineries (40 CFR part 60, subpart GGG and 40 CFR part 60, subpart
GGGa) currently require connector monitoring and repair (provisions are
provided for connector monitoring in Refinery MACT 1, but they are
optional). We evaluated the costs and emissions reduction of requiring
connector monitoring and repair requirements for equipment leaks at
refineries. The nationwide costs and emission reduction impacts, both
with and without VOC recovery credit, are shown in Table 7 of this
preamble. For further details on the assumptions and methodologies used
in this analysis, see the technical memorandum titled Impacts for
Equipment Leaks at Petroleum Refineries, in Docket ID Number EPA-HQ-
OAR-2010-0682. Based on the high annualized cost ($13.9 million per
year) and high cost effectiveness ($153,000 per ton of HAP) of
connector monitoring and repair for equipment leaks at refineries, we
are proposing that it is not necessary to revise Refinery MACT 1
pursuant to CAA section 112(d)(6) to require connector monitoring using
EPA Method 21 (of 40 CFR part 60, Appendix A-7) and repair.

Table 7--Nationwide Emissions Reduction and Cost Impacts of Applying Monitoring and Repair Requirements to Connectors at Petroleum Refineries
[500 ppm]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Overall cost Overall cost
Annualized costs Emissions Emissions Cost Cost Total annualized effectiveness effectiveness
Capital cost (million $) without recovery reduction, VOC reduction, HAP effectiveness ($/ effectiveness ($/ costs with VOC with VOC recovery with VOC recovery
credits (million (tpy) (tpy) ton VOC) ton HAP) recovery credit credit ($/ton credit ($/ton
$/yr) (million $/yr) VOC) HAP)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
52.1.................................... 13.9 1,230 86 11,300 161,000 13.2 10,700 153,000
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Another development identified was to provide optical gas imaging
provisions (including the required instrument specifications,
monitoring frequency, and repair threshold) as an alternative
monitoring option where instrument monitoring using EPA Method 21 of 40
CFR part 60, Appendix A-7, is required in Refinery MACT 1. Since
Refinery MACT 1 was issued, there have been developments in LDAR work
practices using remote sensing technology for detecting leaking
equipment. In this method of detecting leaks, an operator scans
equipment using a device or system specially designed to use one of
several types of remote sensing techniques, including optical gas
imaging of infrared wavelengths, differential absorption light
detection and ranging (DIAL), and solar occultation flux.
The most common remote sensing instrument is a passive system that
creates an image based on the absorption of infrared wavelengths (also
referred to as a ``camera''). A gas cloud containing certain
hydrocarbons (i.e., leaks) will show up as black or white plumes
(depending on the instrument settings and characteristics of the leak)
on the optical gas imaging instrument screen. This type of instrument
is the device on which our evaluation of optical gas imaging
instruments is based, and the instrument to which we are referring when
we use the term ``optical gas imaging instrument.'' These optical gas
imaging instruments can be used to identify specific pieces of
equipment that are leaking. Other optical methods, such as DIAL and
solar occultation flux, are used primarily to assess emissions downwind
of a source. These methods cannot be used to identify specific leaking
equipment; they would only measure the aggregate emissions from all
equipment and any other source up-wind of the measurement location.
While we did review these technologies as discussed further (see the
discussion under fenceline monitoring, section IV.B.1.h of this
preamble), we do not consider DIAL and solar occultation flux methods
to be suitable alternatives to EPA Method 21 for monitoring equipment
leaks and are not considering them further in our technology review for
equipment leaks.

[[Page 36917]]

We expect that all refinery streams ``in organic HAP service'' will
include at least one of the compounds visible with an optical gas
imaging instrument, such as benzene, methane, propane or butane.
Therefore, it is technically feasible to use an optical gas imaging
instrument to detect leaks at petroleum refineries. The optical gas
imaging device can monitor many more pieces of equipment than can be
monitored using instrument monitoring over the same period of time, and
we expect that specific requirements for using an optical gas imaging
device to detect leaks without accompanying instrument monitoring could
be an appropriate alternative to traditional leak detection methods
(EPA Method 21, as specified in 40 CFR part 60, Appendix A-7).
Owners and operators currently have the option to use the
Alternative Work Practice To Detect Leaks From Equipment (AWP) at 40
CFR 63.11(c), (d) and (e). This AWP includes provisions for using
optical gas imaging in combination with annual monitoring using EPA
Method 21 of 40 CFR part 60, Appendix A-7. In this proposal, we are
considering the use of optical gas imaging without an accompanying
requirement to conduct annual monitoring using EPA Method 21, and
developing a protocol for using optical gas imaging techniques. We
anticipate proposing the protocol as Appendix K to 40 CFR part 60.
Rather than specifying the exact instrument that must be used, this
protocol would outline equipment specifications, calibration
techniques, required performance criteria, procedures for conducting
surveys and training requirements for optical gas imaging instrument
operators. This protocol would also contain techniques to verify that
the instrument selected can image the most prevalent chemical in the
monitored process unit. Because field conditions greatly impact
detection of the regulated material using optical gas imaging, the
protocol would describe the impact these field conditions may have on
readings, how to address them and instances when monitoring with this
technique is inappropriate. Finally, the protocol would also address
difficulties with identifying equipment and leaks in dense industrial
areas.
Pursuant to CAA section 112(d)(6), we are proposing to allow
refineries to meet the LDAR requirements in Refinery MACT 1 by
monitoring for leaks via optical gas imaging in place of EPA Method 21
(of 40 CFR part 60, Appendix A-7), using the monitoring requirements to
be specified in Appendix K to 40 CFR part 60. When Appendix K is
proposed, we will request comments on that appendix and how those
requirements would apply for purposes of this proposed action. We will
not take final action adopting use of Appendix K to 40 CFR part 60 for
optical gas imaging for refineries subject to Refinery MACT 1 until
such time as we have considered any comments on that protocol as it
would apply to refineries. We do not yet know the exact requirements of
Appendix K to 40 CFR part 60, and this cannot provide a reliable
estimate of potential costs at this time. However, we have calculated
an initial estimate of the potential costs and emission reduction
impacts, assuming that Appendix K to 40 CFR part 60 is similar to the
AWP without the annual monitoring using EPA Method 21 of 40 CFR part
60, Appendix A-7. For more information on these potential impacts, see
the technical memorandum titled Impacts for Equipment Leaks at
Petroleum Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682.
d. Gasoline Loading Racks
Loading racks are the equipment used to fill gasoline cargo tanks,
including loading arms, pumps, meters, shutoff valves, relief valves
and other piping and valves. Emissions from loading racks may be
released when gasoline loaded into cargo tanks displaces vapors inside
these containers. Refinery MACT 1 specifies that Group 1 gasoline
loading racks at refineries must comply with the requirements of the
National Emission Standards for Gasoline Distribution Facilities (Bulk
Gasoline Terminals and Pipeline Breakout Stations) in 40 CFR part 63,
subpart R. The standard specified in 40 CFR part 63, subpart R is an
emission limit of 10 milligrams of total organic compounds per liter of
gasoline loaded (mg/L). Additionally, 40 CFR part 63, subpart R
requires all tank trucks and railcars that are loaded with gasoline to
undergo annual vapor tightness testing in accordance with EPA Method 27
of 40 CFR part 60, Appendix A-8.
For our technology review of Group 1 gasoline loading racks subject
to Refinery MACT 1, we relied on two separate analyses. First, we
previously conducted a technology review for gasoline distribution
facilities (71 FR 17353, April 6, 2006), in which no new control
systems were identified. Second, more recently, we conducted a general
analysis to identify any developments in practices, processes and
control technologies for transfer operations at chemical manufacturing
facilities and petroleum refineries. (See Survey of Control Technology
for Transfer Operations and Analysis of Impacts for Transfer Operation
Control Options, January 20, 2012, Docket Item Number EPA-HQ-OAR-2010-
0871-0021.) We identified several developments as part of this analysis
and evaluated the impacts of applying the developments to gasoline
loading racks subject to Refinery MACT 1. We have not identified any
developments beyond those in the second analysis. The identified
developments include controlling loading racks above specific
throughput thresholds by submerged loading and by venting displaced
emissions from the transport vehicles through a closed vent system to
an APCD that reduces organic regulated material emissions by at least
95 percent.
We evaluated the emissions projected using this control technique
for a range of different gasoline vapor pressures (to consider the
different seasonal formulations of gasoline). We determined that
submerged loading in combination with 95-percent control of displaced
vapors would allow emissions of 12 to 42 mg/L of gasoline loaded,
depending on the vapor pressure of the gasoline (see Evaluation of the
Stringency of Potential Standards for Gasoline Loading Racks at
Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0682.) The
current Refinery MACT 1 emission limit for gasoline loading is 10 mg/L
of gasoline loaded. We did not identify any developments in practices,
process and control technologies for gasoline loading racks that would
reduce emissions beyond the levels already in Refinery MACT 1.
Therefore, we are proposing that it is not necessary to revise Refinery
MACT 1 requirements for gasoline loading racks pursuant to CAA section
112(d)(6).
e. Marine Vessel Loading Operations
Marine vessel loading operations load and unload liquid commodities
in bulk, such as crude oil, gasoline and other fuels, and naphtha. The
cargo is pumped from the terminal's large, above-ground storage tanks
through a network of pipes and into a storage compartment (tank) on the
vessel. The HAP emissions are the vapors that are displaced during the
filling operation. Refinery MACT 1 specifies that marine tank vessel
loading operations at refineries must comply with the requirements in
40 CFR part 63, subpart Y (National Emission Standards for Marine Tank
Vessel Loading Operations, ``Marine Vessel MACT'').
We previously completed a technology review of the Marine Vessel
MACT (40 CFR part 63, subpart Y) and issued amendments to subpart Y in

[[Page 36918]]

2011 (76 FR 22595, Apr. 21, 2011). The analysis conducted for the
marine vessel loading source category specifically considered loading
of petroleum products such as conventional and reformulated gasoline.
As such, the conclusions drawn from this analysis are directly
applicable to marine vessel loading operations at petroleum refineries.
We have not identified any developments beyond those addressed in that
analysis.
The Marine Vessel MACT required add-on APCD for loading operations
with HAP emissions equal to or greater than 10 tpy of a single
pollutant or 25 tpy of cumulative pollutants (referred to as ``10/25
tpy''). In our technology review of the Marine Vessel MACT standards,
we considered the use of add-on APCD for marine vessel loading
operations with HAP emissions less than 10/25 tpy. We also evaluated
the costs for lean oil absorption systems as add-on APCD under the
Marine Vessel MACT technology review. Depending on the throughput of
the vessel, costs ranged from $77,000 per ton HAP removed for barges to
$510,000 per ton HAP removed for ships ($3,900 per ton VOC removed to
$25,000 per ton VOC removed) (see Cost Effectiveness and Impacts of
Lean Oil Absorption for Control of Hazardous Air Pollutants from
Gasoline Loading--Promulgation in Docket Item Number EPA-HQ-OAR-2010-
0600-0401). We consider requiring add-on APCD for these smaller marine
vessel loading operations not to be cost effective.
As part of the technology review of 40 CFR part 63, subpart Y, we
also considered requiring marine vessel loading operations with
emissions less than 10/25 tpy and offshore operations to use submerged
loading (also referred to as submerged filling). We did include this
requirement in the Marine Vessel MACT. However, when we amended the
Marine Vessel MACT, we specifically excluded marine vessel loading
operations at petroleum refineries from these provisions, deferring the
decisions to include this requirement until we performed the technology
review for Refinery MACT 1. The submerged filling requirement in 40 CFR
part 63, subpart Y cites the cargo filling line requirements developed
by the Coast Guard in 46 CFR 153.282. We project that applying the
submerged filling requirements to marine vessel loading operations at
petroleum refineries will have no costs or actual emission reductions
because marine vessels carrying bulk liquids, liquefied gases or
compressed gas hazardous materials are already required by 46 CFR
153.282 to have compliant ``submerged fill'' cargo lines that also meet
the requirements of the Marine Vessel MACT. While we do not anticipate
that this requirement will affect actual emissions, it will lower the
allowable emissions for these sources under Refinery MACT 1. Therefore,
we are proposing, pursuant to CAA section 112(d)(6), to amend 40 CFR
part 63, subpart Y to delete the exclusion for marine vessel loading
operations at petroleum refineries, which would 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.
f. Cooling Towers/Heat Exchange Systems
Heat exchange systems include equipment necessary to cool heated
non-contact cooling water prior to returning the cooling water to a
heat exchanger or discharging the water to another process unit, waste
management unit or to a receiving water body. Heat exchange systems are
designed as closed-loop recirculation systems with cooling towers or
once-through systems that do not recirculate the cooling water through
a cooling tower. Heat exchangers in heat exchange systems are
constructed with tubes designed to prevent contact between hot process
fluids and cooling water. Heat exchangers occasionally develop leaks
that allow process fluids to enter the cooling water. The volatile HAP
and other volatile compounds in these process fluids are then emitted
to the atmosphere due to stripping in a cooling tower or volatilization
from a cooling water pond or receiving water body.
We established MACT standards for heat exchange systems at
refineries in 2009 (see 74 FR 55686, October 28, 2009, as amended at 75
FR 37731, June 30, 2010). The EPA received a petition for
reconsideration from the American Petroleum Institute (API) and granted
reconsideration on certain issues. On June 20, 2013, we issued a final
rule addressing the petition, clarifying rule provisions, and revising
the monitoring provisions to provide additional flexibility (78 FR
37133). We are not aware of any developments in processes, practices or
control technologies beyond those we recently considered in our
analysis of emission reduction techniques for heat exchange systems,
which can be found in the docket (Docket Item Number EPA-HQ-OAR-2003-
0146-0229). Therefore, we are proposing that it is not necessary to
revise Refinery MACT 1 requirements for heat exchange systems pursuant
to CAA section 112(d)(6).
g. Wastewater Treatment
Wastewater collection includes components such as drains, manholes,
trenches, junction boxes, sumps, lift stations and sewer lines.
Wastewater treatment systems are divided into three categories: primary
treatment operations, which include oil-water separators and
equalization basins; secondary treatment systems, such as biological
treatment units or steam strippers; and tertiary treatment systems,
which further treat or filter wastewater prior to discharge to a
receiving body of water or reuse in a process.
Refinery MACT 1 requires wastewater streams at a new or existing
refinery to comply with 40 CFR 61.340 through 61.355 of the NESHAP for
Benzene Waste Operations (BWON) in 40 CFR part 61, subpart FF. The BWON
requires control of wastewater collection and treatment units for
facilities with a total annual benzene quantity of greater than or
equal to 10 megagrams per year (Mg/yr). Individual waste streams at
refineries with a total annual benzene quantity greater than or equal
to 10 Mg/yr are not required to adopt controls if the flow-weighted
annual average benzene concentration is less than 10 parts per million
by weight (ppmw) or the flow rate is less than 0.02 liters per minute
at the point of generation. The BWON requires affected waste streams to
comply with one of several options for controlling benzene emissions
from waste management units and for treating the wastes containing
benzene (55 FR 8346, March 7, 1990; 58 FR 3095, January 7, 1993).
Although the BWON specifically regulates benzene only, benzene is
considered a surrogate for organic HAP from wastewater treatment
systems at petroleum refineries. Benzene is present in nearly all
refinery process streams. It is an excellent surrogate for wastewater
pollutants because its unique chemical properties cause it to partition
into the wastewater more readily than most other organic chemicals
present at petroleum refineries. We stated our rationale regarding the
use of benzene as a surrogate for refinery HAP emissions from
wastewater in the original preamble to Refinery MACT 1 (59 FR 36133,
July 15, 1994).
We performed a technology review for wastewater treatment systems
to identify different control technologies for reducing emissions from
wastewater treatment systems. We also reviewed the current standards
for wastewater treatment systems in different rules

[[Page 36919]]

including the HON, the proposed NSPS for wastewater systems at
petroleum refineries, and the BWON (See Technology Review for
Industrial Wastewater Collection and Treatment Operations at Petroleum
Refineries, in Docket ID Number EPA-HQ-OAR-2010-0682.) We identified
several developments in processes, practices and control technologies
for wastewater treatment, and evaluated the cost and cost effectiveness
of each of those developments: (1) requiring wastewater drain and tank
controls at refineries with a total annual benzene (TAB) quantity of
less than 10 Mg/yr; (2) requiring specific performance parameters for
an enhanced biological unit (EBU) beyond those required in the BWON;
and (3) requiring wastewater streams with a VOC content of 750 ppmv or
higher to be treated by steam-stripping prior to any other treatment
process for facilities with high organic loading rates (i.e.,
facilities with total annualized benzene quantity of 10 Mg/yr or more).
These options are, for the most part, independent of each other, so the
costs and cost effectiveness of each option are considered separately.
Option 1 was evaluated because refineries with a total annual
benzene quantity of less than 10 Mg/yr are not required to install
additional controls on their wastewater treatment system. Thus, these
refineries are limiting the amount of benzene produced in wastewater
streams to less than 10 Mg/yr, which effectively limits their benzene
emissions from wastewater to less than 10 Mg/yr.
Option 2 is intended to improve the performance of wastewater
treatment systems that use an EBU, and thereby achieve additional
emission reductions. The BWON, as it applies under Refinery MACT 1, has
limited operational requirements for an EBU. Available data suggest
that these systems are generally effective for degrading benzene and
other organic HAP; however, without specific performance or operational
requirements, the effectiveness of the EBU to reduce emissions can be
highly variable. Under option 2, more stringent operating requirements
are considered for the EBU at refineries.
Option 3 considers segregated treatment of wastewater streams with
a volatile organic content of greater than 750 ppmw, or high-strength
wastewater streams, directly in a steam stripper (i.e., not allowing
these streams to be mixed and treated in the EBU). Preliminary
investigations revealed direct treatment of wastewater by steam-
stripping is only cost effective for high-strength wastewater streams
of sufficient quantities. For more detail regarding the impact analysis
for these control options, see Technology Review for Industrial
Wastewater Collection and Treatment Operations at Petroleum Refineries,
in Docket ID Number EPA-HQ-OAR-2010-0682.
Table 8 provides the nationwide impacts for the control options.
Based on the costs and emission reductions for each of the options, we
consider none of the options identified to be cost effective for
reducing emissions from petroleum refinery wastewater treatment
systems. We are proposing that it is not necessary to revise Refinery
MACT 1 to require additional controls for wastewater treatment systems
pursuant to CAA section 112(d)(6).

Table 8--Nationwide Emissions Reduction and Cost Impacts of Control Options Considered for Wastewater Treatment Systems at Petroleum Refineries
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions Emissions Cost Cost
Control option Capital cost Annualized costs reduction, VOC reduction, HAP effectiveness ($/ effectiveness ($/
(million $) (million $/yr) (tpy) (tpy) ton VOC) ton HAP)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1........................................... 19.7 4.2 592 158 7,100 26,600
2........................................... 223 28.6 2,060 549 13,900 52,100
3........................................... 142 50.7 3,480 929 14,500 54,500
--------------------------------------------------------------------------------------------------------------------------------------------------------

h. Fugitive Emissions

The EPA recognizes that, in many cases, it is impractical to
directly measure emissions from fugitive emission sources at
refineries. Direct measurement of fugitive emissions from sources such
as wastewater collection and treatment operations, equipment leaks and
storage vessels can be costly and difficult, especially if required to
be deployed on all sources of fugitives within a refinery and certainly
on a national scale. This is a major reason why fugitive emissions
associated with refinery processes are generally estimated using
factors and correlations rather than by direct measurement. For
example, equipment leak emissions are estimated using factors and
correlations between leak rates and concentrations from EPA Method 21
instrument monitoring. Fugitive emissions from wastewater collection
and treatment are estimated based on process data, material balances
and empirical correlations. Relying on these kinds of approaches
introduces uncertainty into the emissions inventory for fugitive
emission sources.
For each of the individual fugitive emission points, we evaluated
developments in processes, practices and control technologies for
measuring and controlling fugitive emissions from these sources. For
storage vessels, as discussed in section IV.B.1.b of this preamble, we
are proposing to lower the size and vapor pressure threshold and to
require additional fittings on tanks, similar to requirements for tanks
in the chemical industry because we project a cost savings due to
recovered product. However, we considered but are not proposing to
require EPA Method 21 of 40 CFR part 60, Appendix A-7 or optical gas
imaging monitoring to identify fugitive emissions from each individual
storage vessel. For equipment leaks, as discussed in section IV.B.1.c
of this preamble, we considered lowering the leak definition for
equipment at petroleum refineries from the current Refinery MACT 1
level of 10,000 ppm for pumps and valves down to the 500 ppm definition
that is used in all the other MACT standards applying to the chemical
industry, as well as adding a requirement for connectors to be included
in the LDAR program because we consider these more stringent LDAR
requirements to be technically feasible for the petroleum refining
industry. Nevertheless, we rejected these options under the technology
review as not being cost effective, based on costs projected by using
the industry-reported emissions inventories. We are, however, proposing
to adopt the use of optical gas imaging devices following 40 CFR part
60, Appendix K as an alternative to using EPA Method 21, which will be
an alternative available to petroleum refiners that could offer cost
savings, once the monitoring protocol set forth in Appendix K is
promulgated. For wastewater treatment systems, as discussed in section
IV.B.1.g of this

[[Page 36920]]

preamble, we considered both lowering the threshold for refinery
wastewater streams requiring control, as well as requiring refineries
to comply with enhanced monitoring and operating limits for EBU, such
as the requirements contained in most of the chemical sector MACT
standards, because we consider these requirements to be technically
feasible for the refining industry. However, like equipment leaks, we
are rejecting further controls for wastewater because using the
industry-reported emissions inventory, we determined that further
wastewater requirements are not cost effective.
Although we are not proposing to require a number of additional
control options for fugitive emission sources because we determined
them not cost effective, we remain concerned regarding the potential
for high emissions from these fugitive sources due to the difficulties
in monitoring actual emission levels. For example, the regulations
require infrequent monitoring of storage tank floating roof seals
(visual inspections are required annually and direct inspections of
primary seals are required only when the vessel is emptied and
degassed, or no less frequently than once every 5 years for internal
floating roofs or 10 years for external floating roofs with secondary
seals). Given these inspection frequencies, tears or failures in
floating roof seals may exist for years prior to being noticed,
resulting in much higher emissions than expected or estimated for these
sources in the emissions inventory. Similarly, water seals, which are
commonly used to control emissions from wastewater collection drain
systems, may be difficult to monitor (e.g., some are underground so
visible emissions tests cannot be performed) and are subject only to
infrequent inspections. During hot, dry months, these water seals may
dry out, leaving an open pathway of vapors to escape from the
collection system to the atmosphere. Significant emission releases may
occur from these ``dry'' drains, which could persist for long periods
of time prior to the next required inspection.
Because the requirements and decisions that we are proposing in
this action are based upon the emissions inventory reported by
facilities in response to the 2011 Refinery ICR, and considering the
uncertainty with estimating emissions from fugitive emission sources,
we believe that it is appropriate under CAA section 112(d)(6) to
require refiners to monitor, and if necessary, take corrective action
to minimize fugitive emissions, to ensure that facilities appropriately
manage emissions of HAP from fugitive sources. In other words, in this
action, we are proposing a HAP concentration to be monitored in the
ambient air around a refinery, that if exceeded, would trigger
corrective action to minimize fugitive emissions. The fenceline
concentration action level would be set at a level such that no
facility in the category would need to undertake additional corrective
measures if the facility's estimate of emissions from fugitive
emissions is consistent with the level of fugitive emissions actually
emitted. On the other hand, if a facility's estimate of fugitive HAP
emissions was not accurate, the owner or operator may need to take some
corrective action to minimize fugitive emissions. This approach would
provide the owner or operator with the flexibility to determine how
best to reduce HAP emissions to ensure levels remain below the
fenceline concentration action level. The details of this proposed
approach are set forth in more detail in the following discussions in
this preamble section.
In light of the impracticality of directly monitoring many of these
fugitive emission sources on a regular basis, which would help ensure
these fugitive sources are properly functioning to the extent
practical, we evaluated a fenceline monitoring program under CAA
section 112(d)(6). In this section, we evaluate the developments in
processes, practices and control technologies for measuring and
controlling fugitive emissions from the petroleum refinery as a whole
through fenceline monitoring techniques. Fenceline monitoring will
identify a significant increase in emissions in a timely manner (e.g.,
a large equipment leak or a significant tear in a storage vessel seal),
which would allow corrective action measures to occur more rapidly than
it would if a source relied solely on the traditional infrequent
monitoring and inspection methods. Small increases in emissions are not
likely to impact the fenceline concentration, so a fenceline monitoring
approach will generally target larger emission sources that have the
most impact on the ambient pollutant concentration near the refinery.
Historically, improved information through measurement data has
often led to emission reductions. However, without a specific emission
limitation, there may be no incentive for owners or operators to act on
the additional information. Therefore, as part of the fenceline
monitoring approach, we seek to develop a not-to-be exceeded annual
fenceline concentration, above which refinery owners or operators would
be required to implement corrective action to reduce their fenceline
concentration. We sought to develop a maximum fenceline concentration
action level that is consistent with the emissions projected from
fugitive sources compliant with the provisions of the refinery MACT
standards as modified by the additional controls proposed in this
action (e.g., additional fittings on storage vessels).
This section details our technology review to identify developments
in processes, practices and technologies for measuring air toxics at
the fenceline of a facility. Upon selection of a specific fenceline
monitoring method, we provide our rationale for the specific details
regarding the fenceline monitoring approach, including requirements for
siting the monitors, procedures for adjusting for background
interferences, selection of the fenceline action level, and
requirements for corrective action.
Developments in monitoring technology and practices. The EPA
reviewed the available literature and identified several different
methods for measuring fugitive emissions around a petroleum refinery.
These methods include: (1) Passive diffusive tube monitoring networks;
(2) active monitoring station networks; (3) ultraviolet differential
optical absorption spectroscopy (UV-DOAS) fenceline monitoring; (4)
open-path Fourier transform infrared spectroscopy (FTIR); (5) DIAL
monitoring; and (6) solar occultation flux monitoring. We considered
these monitoring methods as developments in practices under CAA section
112(d)(6) for purposes of all fugitive emission sources at petroleum
refineries. Each of these methods has its own strengths and weaknesses,
which are discussed in the following paragraphs.
Fenceline passive diffusive tube monitoring networks employ a
series of diffusive tube samplers at set intervals along the fenceline
to measure a time-integrated ambient air concentration at each sampling
location. A diffusive tube sampler consists of a small tube filled with
an adsorbent, selected based on the pollutant(s) of interest, and
capped with a specially designed cover with small holes that allow
ambient air to diffuse into the tube at a small, fixed rate. Diffusive
tube samplers have been demonstrated to be a cost-effective, accurate
technique for measuring ambient concentrations of pollutants resulting
from fugitive emissions in a number of studies.^{29 30} In
addition,

[[Page 36921]]

diffusive samplers are used in the European Union to monitor and
maintain air quality, as described in European Union directives 2008/
50/EC and Measurement Standard EN 14662-4:2005 for benzene. The
International Organization for Standardization developed a standard
method for diffusive sampling (ISO/FDIS 16017-2).
---------------------------------------------------------------------------

\29\ McKay, J., M. Molyneux, G. Pizzella, V. Radojcic.
Environmental Levels of Benzene at the Boundaries of Three European
Refineries, prepared by the CONCAWE Air Quality Management Group's
Special Task Force on Benzene Monitoring at Refinery Fenceline (AQ/
STF-45), Brussels, June 1999.
\30\ Thoma, E.D., M.C. Miller, K.C. Chung, N.L. Parsons, B.C.
Shine. 2011. Facility Fenceline Monitoring using Passive Sampling,
J. Air & Waste Manage Assoc. 61: 834-842.
---------------------------------------------------------------------------

In 2009, the EPA conducted a year-long fenceline monitoring pilot
project at Flint Hills West Refinery in Corpus Christi, Texas, to
evaluate the viability and performance of passive diffusive sampling
technology. Overall, we found the technology to be capable of providing
cost effective, high spatial-density long-term monitoring. This
approach was found to be relatively robust and implementable by
modestly trained personnel and provided useful information on overall
concentration levels and source identification using simple upwind and
downwind comparisons.\31\ Combined with on-site meteorological
measurements, 2-week time-integrated passive monitoring has been shown
to provide useful facility emission diagnostics.
---------------------------------------------------------------------------

\31\ Thoma, et al., 2011.
---------------------------------------------------------------------------

There are several drawbacks of time-integrated sampling, including
the lack of immediate feedback on the acquired data and the loss of
short-term temporal information. Additionally, time-integrated
monitoring usually requires the collected sample to be transported to
another location for analysis, leading to possible sample integrity
problems (e.g., sample deterioration, loss of analytes, and
contamination from the surrounding environment). However, time-
integrated monitoring systems are generally lower-cost and require less
labor than time-resolved monitoring systems. Furthermore, while passive
diffusive tube monitoring employs time-integrated sampling, these time-
integrated samples still represent much shorter time intervals (2
weeks) than many of the current source-specific monitoring and
inspection requirements (annually or less frequently). Consequently,
passive diffusive tube monitoring still allows earlier detection of
significant fugitive emissions than conventional source-specific
monitoring.
Active monitoring station networks are similar to passive diffusive
tube monitoring networks in that a series of discrete sampling sites
are established; however, each sampling location uses a pump to
actively draw ambient air at a known rate through an adsorption tube.
Because of the higher sampling rate, adsorption tubes can be analyzed
on a daily basis, providing additional time resolution compared to
diffusive tube sampling systems. Alternatively, the active sampling
system can directly feed an analyzer for even more time resolution.
However, this direct analysis of ambient air generally has higher
detection limits than when the organic vapors are collected and
concentrated on an adsorption matrix prior to analysis. Active
monitoring stations have been used for a variety of pollutants in a
variety of settings and the methods are well-established. However,
compared to the passive diffusive tube monitoring stations, the
sampling system is more expensive, more labor-intensive, and generally
requires highly-trained staff to operate.
UV-DOAS fenceline monitoring is an ``open-path'' technology. An
electromagnetic energy source is used to emit a beam of electromagnetic
energy (ultraviolet radiation) into the air towards a detection system
some distance from the energy source (typically 100 to 500 meters). The
electromagnetic energy beam interacts with components in the air in the
open path between the energy source and the detector. The detector
measures the disruptions in the energy beam to determine an average
pollutant concentration across the open path length. Because the UV-
DOAS system can monitor integrated concentrations over a fairly long
path-length, fewer monitoring ``stations'' (energy source/detector
systems) would be needed to measure the ambient concentration around an
entire refinery. However, each UV-DOAS monitoring system is more
expensive than an active or passive monitoring station and generally
requires significant instrumentation shelter to protect the energy
source and analyzer when used for long-term (ongoing) measurements.
Advantages of UV-DOAS systems include providing real-time measurement
data with detection limits in the low parts per billion range for
certain compounds. Fog or other visibility issues (e.g., dust storm,
high pollen, wildfire smoke) will interfere with the measurements. UV-
DOAS systems have been used for fenceline monitoring at several U.S.
petroleum refineries and petrochemical plants. UV-DOAS monitoring
systems are specifically included as one of the measurement techniques
suitable under EPA's Other Test Method 10 (OTM-10).\32\
---------------------------------------------------------------------------

\32\ ``Optical Remote Sensing for Emission Characterization from
Non-Point Sources.'' Final ORS Protocol, June 14, 2006. Available
at: https://www.epa.gov/ttn/emc/prelim/otm10.pdf.
---------------------------------------------------------------------------

Open-path FTIR is similar to UV-DOAS monitoring except that an
infrared light source and detector system are used. Like the UV-DOAS
monitoring approach, the open-path FTIR monitoring system will measure
the average pollutant concentration across the open path length between
the infrared source and detector. Path lengths and equipment costs for
an open-path FTIR system are similar to those for a UV-DOAS system, and
the open-path FTIR system provides real-time measurement data. The
open-path FTIR system has spectral interferences with water vapor, CO
and CO2, which can impact the lower detection limit for
organic vapors. Open-path FTIR fenceline monitoring has also been used
to measure ambient air concentrations around several petroleum
refineries and petrochemical plants. Open-path FTIR is specifically
included as a measurement technique in EPA's OTM-10. Although open-path
FTIR can be used to measure a larger number of compounds than UV-DOAS,
the detection limit of open-path FTIR for benzene is higher than for
UV-DOAS, as noted in OTM-10. In other words, open-path FTIR is not as
sensitive to benzene levels as is UV-DOAS. As benzene is an important
pollutant from fugitive sources at petroleum refineries and can often
be used as a surrogate for other organic HAP emissions, this high
detection limit for benzene is a significant disadvantage. Thus, for
the purposes of measuring organic HAP from fugitive sources at the
fenceline of a petroleum refinery, a UV-DOAS monitoring system is
expected to be more sensitive than an open-path FTIR system. As the
cost and operation of open-path FTIR and UV-DOAS systems are very
comparable, the benzene detection limit issue is a significant
differentiator between these two methods when considering fenceline
monitoring to measure fugitives around a petroleum refinery.
DIAL monitoring systems employ a pulsed laser beam across the
measurement path. Small portions of the light are backscattered due to
particles and aerosols in the measurement path. This backscattered
light is collected through a telescope system adjacent to the laser and
measured via a sensitive light detector. The timing of the received
light provides a measure of the distance of

[[Page 36922]]

the emission plume. Two different wavelengths of light are pulsed in
quick succession: one wavelength that is absorbed strongly by the
pollutant of interest and one that is not absorbed. The difference in
the returned signal strength between these two light pulses provides a
measure of the concentration of the pollutant. Thus, a unique advantage
of the DIAL monitoring system is that it can provide spatially resolved
pollutant concentrations in two dimensions. Measurements can be made in
a relatively short period of time, so the method also provides good
time resolution.
The DIAL monitoring system has been used in a variety of studies to
measure emissions from petroleum refinery and petrochemical sources. It
is typically used for specific, shorter-term studies (one to several
weeks in duration). The equipment is expensive, has limited
availability in the U.S., and requires highly trained professionals to
operate. Although DIAL monitoring is included as an appropriate method
for EPA's OTM-10, there are no known long-term applications of this
technology for the purpose of fenceline monitoring. Given the limited
availability of the equipment and qualified personnel to operate the
equipment, we do not consider DIAL monitoring to be technically
feasible for the purposes of ongoing, long-term fenceline monitoring.
The last fenceline monitoring method evaluated was solar
occultation flux. Solar occultation flux uses the sun as the light
source and uses an FTIR or UV detector to measure the average pollutant
concentration across the measurement path. In this case, the
measurement path is vertical. In order to measure the concentrations
around an industrial source, the measurement device is installed in a
specially equipped van, which is slowly driven along the perimeter of
the facility. Measurement signal strength and a global positioning
system (GPS) enables determination of pollutant concentrations along
the perimeter of the site. This method provides more spatial resolution
of the emissions than the UV-DOAS or open-path FTIR methods and is less
expensive than a DIAL system. It has the advantage that only one
monitoring system is needed per facility, assuming a mobile device is
used. Disadvantages of this method include the need of full-time
personnel to drive the equipment around the perimeter of the facility
(or the need to buy a detector for each measurement location around the
perimeter of the facility, if set locations are used), potential
accessibility issues for some fenceline locations (e.g., no road near
the fenceline), and the measurement method cannot be used at night or
during cloudy periods. It would be possible to purchase numerous
detection devices and establish fixed monitoring stations similar to
the passive or active monitoring approaches described earlier, but this
would be very expensive. Furthermore, any application of solar
occultation flux is dependent on the sun, so this approach would mean
significant periods each calendar day when the monitoring system would
not be able to provide data. Based on our evaluation of this
technology, we determined that this method is not a reasonable approach
for monitoring fenceline concentrations of pollutants around a
petroleum refinery on a long-term, ongoing basis. We are soliciting
comment on the application of alternative monitoring techniques
previously discussed for purposes of fenceline monitoring at
refineries.
Costs associated with fenceline monitoring alternatives. Based on
our review of available monitoring methods, we determined that the
following monitoring methods were technically feasible and appropriate
for monitoring organic HAP from fugitive emission sources at the
fenceline of a petroleum refinery on a long-term basis: (1) Passive
diffusive tube monitoring networks; (2) active monitoring station
networks; (3) UV-DOAS fenceline monitoring; and (4) open-path FTIR.
While DIAL monitoring and solar occultation flux monitoring can be used
for short-term studies, we determined that these methods were not
appropriate for continuous monitoring at petroleum refineries. This
section evaluates the costs of these technically feasible monitoring
methods. As noted previously, the cost identified for the open-path
monitoring methods (UV-DOAS and FTIR) are very similar. Therefore, we
developed costs for only the UV-DOAS system because this method
provides lower detection limits for pollutants of interest
(specifically, benzene).
Costs for the fenceline monitoring methods are dependent on the
sampling frequency (for passive and active monitoring locations) and
the number of monitoring locations needed based on the size and
geometry of the facility. For the open-path methods, we estimated that
four monitoring systems (along the east, west, north and south
fencelines) would be needed, regardless of the size of the refinery.
Some fencelines at larger refineries may be too long for a single open
path length, but we did not vary the number of detectors needed for the
open-path systems based on refinery size in order to provide a
reasonable lower-cost estimate for the open-path monitoring option. For
small petroleum refineries (less than 750 acres), we estimated 12
passive or active monitoring stations would be sufficient. For medium-
sized refineries (750 to 1,500 acres), we estimated 18 monitoring
stations would be required; for large refineries (greater than 1,500
acres), we estimated that 24 monitoring stations would be needed. For
the passive diffusive tube monitoring we assumed a 2-week sampling
interval; for active monitoring stations, we assumed a daily sampling
frequency.
We estimated the first year installation and equipment costs for
the passive tube monitoring system could cost up to $100,000 for larger
refineries (i.e., 24 sampling locations). Annualized costs for ongoing
monitoring are projected to be approximately $40,000 per year, assuming
the ongoing sample analyses are performed in-house. Capital costs for
active sampling systems were estimated to be approximately twice that
of the passive system for the larger refinery. Ongoing costs were more
than 10 times higher, however, due to the daily sampling frequency.
Equipment costs for a single UV-DOAS system were estimated to be about
$100,000, so a complete fenceline monitoring system (four systems plus
shelters) was estimated to cost more than $500,000. A refinery using
this technology for two fenceline locations estimated the annualized
cost of calibrating and maintaining these systems approaches $1-million
per year. (See Fenceline Monitoring Technical Support Document, in
Docket ID Number EPA-HQ-OAR-2010-0682).
Table 9 provides the nationwide costs of the monitoring approaches
as applied to all U.S. petroleum refineries.

[[Page 36923]]

Table 9--Nationwide Cost Impacts of Fenceline Monitoring Options at Petroleum Refineries
----------------------------------------------------------------------------------------------------------------
Annual operating Total annualized
Monitoring option Monitoring option Capital cost costs (million $/ costs (million $/
description (million $) yr) yr)
----------------------------------------------------------------------------------------------------------------
1.................................. Passive diffusive 12.2 3.83 5.58
tube monitoring
network.
2.................................. Active sampling 20.6 30.2 33.1
monitoring network.
3.................................. Open-path monitoring 71.0 35.5 45.6
(UV-DOAS, FTIR).
----------------------------------------------------------------------------------------------------------------

The primary goal of a fenceline monitoring network is to ensure
that owners and operators properly monitor and manage fugitive HAP
emissions. As explained further in this preamble section, we are
proposing a concentration action level that was derived by modeling
fenceline benzene concentrations (as a surrogate for HAP) at each
facility after full compliance with the refinery MACT standards, as
amended by this proposed action. As such, we are proposing a fenceline
benzene concentration that all facilities in the category can meet,
according to the emissions inventories reported in response to the 2011
Refinery ICR. Therefore, we do not project a HAP emission reduction
that the fenceline monitoring network will achieve. However, if an
owner or operator has underestimated the fugitive emissions from one or
more sources, or if a leak develops or a tank seal or fitting fails, a
fenceline monitoring system would provide for identification of such
leaks much earlier than current monitoring requirements and, where
emissions are beyond those projected from implementation of the MACT
standards, would help ensure that such emissions are quickly addressed.
We note that any costs for a fugitive monitoring system would be
offset, to some extent, by product recovery since addressing these
leaks more quickly than would otherwise occur based on the more
infrequent monitoring required would reduce product losses.
Based on the low cost and relative benefits of passive monitoring,
which include the ability to generate time-integrated concentration
measurements at low detection limits, coupled with relative ease of
deployment and analysis, the EPA is proposing to require refineries to
deploy passive time-integrated samplers at the fenceline. These
samplers would monitor the level of fugitive emissions that reach the
fenceline from all fugitive emission sources at the facility. The EPA
is proposing to require fugitive emission reductions if fenceline
concentrations exceed a specified concentration action level, as
described further below. These proposed fenceline monitoring
requirements complement the EPA's proposal to allow the use of the
optical gas imaging camera as described in Appendix K of 40 CFR part 60
as an alternative work practice for measuring emissions from equipment
leaks, in lieu of monitoring with EPA Method 21 of 40 CFR part 60,
Appendix A-7 (see section IV.B.1.c of this preamble for further
discussion). Both approaches utilize low-cost methods to help ensure
that total fugitives from a facility are adequately controlled.
Because there is no current EPA test method for passive diffusive
tube monitoring, as part of this action we are proposing specific
monitor citing and sample collection requirements as EPA Method 325A of
40 CFR part 63, Appendix A, and specific methods for analyzing the
sorbent tube samples as EPA Method 325B of 40 CFR part 63, Appendix A.
We are proposing to establish an ambient concentration of benzene at
the fenceline that would trigger required corrective action. A brief
summary of the proposed fenceline sampling requirements and our
rationale for selecting the corrective action concentration levels are
provided below.
Siting, design and sampling requirements for fenceline monitors.
The EPA is proposing that passive fenceline monitors collecting 2-week
time-integrated samples be deployed to measure fenceline concentrations
at refineries. We are proposing that refineries deploy passive samplers
at 12 to 24 points circling the refinery perimeter. A primary
requirement for a fenceline monitoring system is that it provides
adequate spatial coverage for determination of representative pollutant
concentrations at the boundary of the facility or operation. In an
ideal scenario, fenceline monitors would be placed so that any fugitive
plume originating within the facility would have a high probability of
intersecting one or more monitors, regardless of wind direction. This
proposed monitoring program would require that monitors be placed at 15
to 30 degree intervals along the perimeter of the refinery, depending
on the size of the facility. For small refineries (less than 750
acres), monitors should be placed at 30 degree intervals, for a total
of 12 locations; for facilities that are larger than 750 acres and less
than 1,500 acres, monitors should be placed at 20 degree intervals, at
18 locations; and for facilities greater than 1,500 acres, monitors
should be placed at 15 degree intervals, accounting for 24 locations.
We have also established an alternative siting procedure where monitors
can be placed every 2,000 feet along the fenceline of the refinery,
which may be easier to implement, especially for irregularly-shaped
facilities. In proposing these requirements for the number and location
of required monitors, the EPA assumes that all portions of the facility
are contiguous such that it is possible to define a single facility
boundary or perimeter, although this perimeter may be irregular in
shape. We request comment on how these monitoring requirements should
be adapted for instances where one or more portions of the facility are
not contiguous, and on the number and location of facilities for which
special fenceline monitoring requirements to accommodate non-contiguous
operations might apply.
We are proposing that the highest concentration of benzene, as an
annual rolling average measured at any individual monitor and adjusted
for background (see below), would be compared against the concentration
action level in order to determine if there are significant excess
emissions of fugitive emissions that need to be addressed. Existing
sources would be required to deploy samplers no later than 3 years
after the effective date of the final rule; new sources would be
required to deploy samplers by the effective date of the final rule or
startup, whichever is later. Because the proposed concentration action
level is composed of 1 year's worth of data, we are proposing that
refinery owners and operators would be required to demonstrate
compliance with the concentration action level for the first time 1
year following the compliance date, and thereafter on a 1-year rolling
annual average basis (i.e., considering results from the most recent 26
consecutive 2-week sampling intervals and recalculating the average
every 2 weeks).

[[Page 36924]]

Benzene as an appropriate target analyte. Passive diffusive tube
monitors can be used to determine the ambient concentration of a large
number of compounds. However, different sorbent materials are typically
needed to collect compounds with significantly different properties.
Rather than require multiple tubes per monitoring location and require
a full analytical array of compounds to be determined, which would
significantly increase the cost of the proposed fenceline monitoring
program, we are proposing that the fenceline monitors be analyzed
specifically for benzene. Refinery owners or operators may elect to do
more detailed speciation of the emissions, which could help identify
the process unit that may be contributing to a high fenceline
concentration, but we are only establishing monitoring requirements and
action level requirements for benzene. We consider benzene to be an
excellent surrogate for organic HAP from fugitive sources for multiple
reasons. First, benzene is ubiquitous at refineries, and is present in
nearly all refinery process streams such that leaking components
generally will leak benzene at some level (in addition to other
compounds). Benzene is also present in crude oil and gasoline, so most
storage tank emissions include benzene. As described previously in our
discussion of wastewater treatment systems, benzene is also a very good
surrogate for organic HAP emissions from wastewater and is already
considered a surrogate for organic HAP emissions in the wastewater
treatment system control requirements in Refinery MACT 1. Second, the
primary releases of benzene occur at ground level as fugitive emissions
from process equipment, storage vessels and wastewater collection and
treatment systems, and the highest ambient benzene concentrations
outside the facility will likely occur near the property boundary near
ground level, so fugitive releases of benzene will be effectively
detected at the ground-level monitoring sites. According to the
emissions inventory we have relied on for this proposed action, 85
percent of benzene emissions from refineries result from ground-level
fugitive emissions from equipment and wastewater collection and
treatment (see the Component 2 database contained in Docket ID Number
EPA-HQ-OAR-2010-0682). Finally, benzene is present in nearly all
process streams. Therefore, the presence of benzene at the fenceline is
also an indicator of other air toxics emitted from fugitive sources at
refineries.
For the reasons discussed above, we believe that benzene is the
most appropriate pollutant to monitor. We believe that other compounds,
such as PAH or naphthalene, would be less suitable indicators of total
fugitive HAP for a couple of reasons. First, they are prevalent in
stack emissions as well as fugitive emissions, so there is more
potential for fenceline monitors to pick up contributions from non-
fugitive sources. In contrast, almost all benzene comes from fugitive
sources, so monitoring for benzene increases our confidence that the
concentration detected at the fenceline is from fugitives. Second, as
compared to benzene, these other compounds are expected to be present
at lower concentrations and, therefore, would be more difficult to
measure accurately using fenceline monitoring. We request comments on
the suitability of selecting benzene or other HAP, including PAH or
naphthalene, as the indicator to be monitored by fenceline samplers. We
also request comment on whether it would be appropriate to require
multiple HAP to be monitored at the fenceline considering the capital
and annual cost for additional monitors, and if so, which pollutants
should be monitored.
Adjusting for background benzene concentrations. Under this
proposed approach, absolute measurements along a facility fenceline
cannot completely characterize which emissions are associated with the
refinery and which are associated with other background sources. The
EPA recognizes that sources outside the refinery boundaries may
influence benzene levels monitored at the fenceline. Furthermore,
background levels driven by local upwind sources are spatially
variable. Both of these factors could result in inaccurate estimates of
the actual contribution of fugitive emissions from the facility itself
to the concentration measured at the fenceline. Many refineries and
petrochemical industries are found side-by-side along waterways or
transport corridors. With this spatial positioning, there is a
possibility that the local upwind neighbors of a facility could cause
different background levels on different sides of the facility. To
account for background concentrations (i.e., to remove the influence of
benzene emissions from sources outside the refinery on monitored
fenceline values), we are proposing to adjust monitored fenceline
values to account for background concentrations as described below. We
solicit comments on alternative approaches for making these adjustments
for background benzene.
Fenceline-deployed passive samplers measure concentrations that
originate from both the observed facility and from off-site sources.
The relative contribution of the facility versus off-site source(s) to
the measured concentration depends on the emission levels of the
observed facility and off-site sources (including both near-field and
remote sources), transporting wind direction and atmospheric
dispersion. The ability to identify facility and off-site source
contributions is reliant on the measurement scheme selected. The most
basic (and lowest cost) approach involves different calculations using
2-week deployed samplers located only at the facility fenceline.
Greater discrimination capability is found by adding passive samplers
to specific areas of the facility, reducing the time duration of the
passive samplers, and coupling measured meteorology information to the
passive sampler analysis. Selective use of time-resolved monitoring or
wind sector sampling approaches provides the highest source and
background discrimination capability. The approach we are proposing
seeks to remove off-site source contributions to the measured fenceline
concentrations to the greatest extent possible using the most cost-
effective measurement solutions.
The highest fenceline concentration (HFC) for each 2-week sampling
period can be expressed as:

HFC = Maximum x (MFC-OSCi)

Where:

HFC = highest fenceline concentration, corrected for background.
MFCi = measured fenceline concentration for the sampling
period at monitoring location i.
OSCi = estimated off-site source contribution for the
sampling period at monitoring location i.

The off-site source contribution (OSC) consists of two primary
components: (1) A slowly varying, spatially uniform background (UB)
concentration and, in some cases, (2) potential near-field interfering
sources.

OSCi = UB + NFSi

Where:

UB = uniform background concentration.
NFSi = near-field interfering source concentration
contribution at monitoring location i.

In some deployment scenarios (such as spatially isolated
facilities), the major off-site source component can be identified as
background concentrations that are uniform across the facility
fenceline and neighboring area. In this

[[Page 36925]]

scenario, a UB concentration level can be determined and subtracted
from the measured fenceline concentrations for each sampling period.
This can be accomplished through use of facility-measured or otherwise
available, quality assured time-resolved (or wind sector-resolved)
background monitoring data, or from placement of additional passive
samplers at upwind locations away from the facility fenceline and other
sources.
In other scenarios, such as where other industrial sources or a
highway are located nearby, background concentrations are likely not
uniform. These outside sources would influence some, but not perhaps
not all, fenceline monitors and, therefore, the true ``background''
concentration would vary, depending where on the fenceline the
measurement was taken. In this case, background is not uniform, and
monitoring location-specific near-field interfering source (NFS) values
would need to be determined.
Due to the difficulties associated with determining location-
specific NFS values, we are proposing to approximate OSC by using the
lowest measured concentration (LMC) at the facility fenceline for that
period. In this case, the HFC for the monitoring period, corrected for
background, would be calculated as:

HFC [ap] [Delta]C = HMC-LMC

Where:

[Delta]C = concentration difference between the highest and lowest
measured concentrations for the sampling period.
HMC = highest measured fenceline concentration for the sampling
period.
LMC = lowest measured fenceline concentration for the sampling
period.

This alternative is directly applicable for all refinery locations
and requires no additional, off-site, upwind monitors, the placement of
which is impossible to prescribe a priori. Use of LMC provides a
reasonable proxy for OSC in most cases, but can over- or underestimate
OSC in some cases. In locations where there are few upwind source
contributions and where wind direction is relatively consistent, upwind
passive samples on the fenceline can provide a realistic approximation
of the actual off-site background levels. As the meteorology becomes
more complicated (e.g., mixed wind directions, higher percentage of
calm winds), the LMC will reflect a progressively larger amount of
emissions from the facility itself, so differential calculations may
underestimate the true HFC for some monitoring periods (by
inadvertently allowing some facility emissions to be subtracted as part
of ``background''). On the other hand, if a near-field source impacts
the highest measured concentration monitoring location significantly,
but contributes little to the monitoring location with the LMC, the LMC
differential calculation (i.e., [Delta]C) could lead to an artificially
elevated assessment of the highest fenceline concentration, corrected
for background.
Based on our examination of previous fenceline monitoring results,
we expect that the use of the LMC differential will provide an accurate
method by which to determine HFC. Therefore, we are not proposing to
limit the use of the LMC differential calculation in cases where there
are no near-field sources and where mixed wind direction (or calm wind)
is common. In these special cases, use of the UB concentration alone
(no NFS term) may be more accurate than using LMC. We are seeking
comment on how to identify conditions under which the LMC differential
may underestimate the highest fenceline concentration, corrected for
background, and the need to require facilities to determine and use UB
rather than LMC in these cases.
We also recognize that under different site-specific conditions,
the NFS contribution may affect certain fenceline monitoring stations
more than others, causing the LMC differential calculation to
overestimate the facility's contribution to the highest fenceline
concentration. Therefore, we are also proposing to allow owners or
operators of petroleum refineries to develop site-specific monitoring
plans to determine UB and NFSi.
If standard 2-week passive fenceline data and site analysis
indicate potential near-field off-site source interferences at a
section of the refinery, the proposal allows the owner or operator to
conduct additional sampling strategies to determine a local background
(OSC term) for use in the HFC calculation. The owner or operator would
be required to report the basis for this correction, including analyses
used to identify the sources and contribution of benzene concentration
to the passive sampler concentration, within 45 days of the date the
owner or operator first measures an exceedance of the concentration
action level.
We envision that facilities would implement these additional
strategies to refine fenceline concentration estimates only if
appropriate given site-specific characteristics and only if HFC
determined by the LMC approach is likely to exceed the concentration
action level (see discussion below regarding this action level).
Facilities with HFC below the concentration action level based on the
simple LMC differential calculation would not be required to make any
further demonstration of the influence of background sources on
concentrations measured at the fenceline. For facilities where
additional background adjustment is appropriate, optional strategies
could include deployment of additional passive samplers at distances
from the fenceline (toward and away from suspected NFS) and reducing
the time intervals of passive deployments to increase time resolution
and wind direction-comparison capability. In complex cases, such as two
refineries sharing a common fenceline, wind-sector sampling or various
forms of time-resolved monitoring may be required to ascertain the
fenceline concentrations.
We are proposing that owners or operators of petroleum refineries
electing to determine monitoring location-specific NFS concentrations
must prepare and submit a site-specific monitoring plan. The monitoring
plan is required to identify specific near-field sources, identify the
location and type of monitors used to determine UB and NFS
concentrations, identify the monitoring location(s) for which the NFS
concentrations would apply, and delineate the calculations to be used
to determine monitoring location specific NFS concentrations (for those
monitoring locations impacted by the near-field source). We are
proposing that the site-specific monitoring plan must be submitted to
the Administrator for approval and receive approval prior to its use
for determining HFC values.
The EPA requests comment on the most appropriate approach(es) for
adjusting measured fenceline concentrations for background
contributions, including (in complex cases) where meteorology is highly
variable or where one or more near-field off-site sources affect the
measured fenceline concentration (MFC) at a refinery. We are also
seeking comment on the adequacy of the proposed requirements for
developing and approving site-specific monitoring plans.
Concentration action level. As mentioned above, the EPA is
proposing to require refineries to take corrective action to reduce
fugitive emissions if monitored fenceline concentrations exceed a
specific concentration action level on a rolling annual average basis
(recalculated every two weeks). We selected this proposed fenceline
action level by modeling fenceline benzene concentrations using the
emissions inventories reported in response to the 2011 Refinery ICR,
assuming that those reported emissions represented full compliance with
all refinery MACT requirements, adjusted for additional control
requirements we are proposing

[[Page 36926]]

in today's action. Thus, if the reported inventories are accurate, all
facilities should be able to meet the fenceline concentration action
level. We estimated the long-term ambient post-control benzene
concentrations at each petroleum refinery using the post-control
emission inventory and EPA's American Meteorological Society/EPA
Regulatory Model dispersion modeling system (AERMOD). Concentrations
were estimated by the model at a set of polar grid receptors centered
on each facility, as well as surrounding census block centroid
receptors extending from the facility outward to 50 km. For purposes of
this modeling analysis, we assumed that the nearest off-site polar grid
receptor was the best representation of each facility's fenceline
concentration in the post-control case, unless there was a census block
centroid nearer to the fenceline than the nearest off-site polar grid
receptor or an actual receptor was identified from review of the site
map. In those instances, we estimated the fenceline concentration as
the concentration at the census block centroid. Only receptors (either
the polar or census block) that were estimated to be outside the
facility fenceline were considered in determining the maximum benzene
level for each facility. We note that this analysis does not correlate
to any particular metric related to risk. The maximum post-control
benzene concentration modeled at the fenceline for any facility is 9
micrograms per cubic meter ([micro]g/m\3\) (annual average). (For
further details of the analysis, see memo entitled Fenceline Ambient
Benzene Concentrations Surrounding Petroleum Refineries in Docket ID
Number EPA-HQ-OAR-2010-0682.)
The facility inventories generally project emissions with the
required fugitive controls working as designed (e.g., no tears in seals
for storage vessel floating roofs and water in all water drain seals).
If facility inventories are correct, annual average benzene
concentrations would not exceed 9 [micro]g/m\3\ at the fenceline of any
facility. Because the modeling approach considers only the emissions
from the refinery, with no contribution from background or near-field
sources, this concentration is comparable to the highest modeled
fenceline concentration after correcting for background concentrations,
as described previously. The EPA is proposing to set the standard at
this concentration action level. We also note that this modeling effort
evaluated the annual average benzene concentration at the fenceline, so
that this action level applies to the annual average fenceline
concentration measured at the facility.
The EPA recognizes that, because it is difficult to directly
measure emissions from fugitive sources, there is significant
uncertainty in current emissions inventories for fugitives. Thus, there
is the potential for benzene concentrations monitored at the fenceline
to exceed modeled concentrations. However, given the absence of
fenceline monitors at most facilities, there is very limited
information available at present about fenceline concentrations and the
extent to which they may exceed concentrations modeled from
inventories. In the absence of additional data regarding the
concentration of fugitive emissions of benzene at the fenceline, the
EPA believes it is reasonable to rely on the maximum modeled fenceline
value as the concentration action level. We are soliciting comment on
alternative concentration action levels and other approaches for
establishing the concentration action level.
Due to differences in short-term meteorological conditions, short-
term (i.e., two-week average) concentrations at the fenceline can vary
greatly. Given the high variability in short-term fenceline
concentrations and the difficulties and uncertainties associated with
estimating a maximum 2-week fenceline concentration given a limited
number of years of meteorological data used in the modeling exercise,
we determined that it would be inappropriate and ineffective to propose
a short-term concentration action level that would trigger corrective
action based on a single 2-week sampling event.
One objective for this monitoring program is to identify fugitive
emission releases more quickly, so that corrective action can be
implemented in a more timely fashion than might otherwise occur without
the fenceline monitoring requirement. We believe the proposed fenceline
monitoring approach and a rolling annual average concentration action
limit (i.e., using results from the most recent 26 consecutive 2-week
samples and recalculating the average every 2 weeks) will achieve this
objective. The proposed fenceline monitoring will provide the refinery
owner or operator with fenceline concentration information once every 2
weeks. Therefore, the refinery owner or operator will be able to timely
identify emissions leading to elevated fenceline concentrations. We
anticipate that the refinery owners or operators will elect to identify
and correct these sources early, in efforts to avoid exceeding the
annual benzene concentration action level.
An ``exceedance'' of the benzene concentration action level would
occur when the rolling annual average highest fenceline concentration,
corrected for background (determined as described previously), exceeds
9 [micro]g/m\3\. Upon exceeding the concentration action level, we
propose that refinery owners or operators would be required to conduct
analyses to identify sources contributing to fenceline concentrations
and take corrective action to reduce fugitive emissions to ensure
fenceline benzene concentrations remain at or below 9 [micro]g/m\3\
(rolling annual average).
Corrective action requirements. As described previously, the EPA is
proposing that the owner or operator analyze the samples and compare
the rolling annual average fenceline concentration, corrected for
background, to the concentration action level. This section summarizes
the corrective action requirements in this proposed rule. First, we are
proposing that the calculation of the rolling annual average fenceline
concentration must be completed within 30 days after the completion of
each sampling episode. If the rolling annual average fenceline benzene
concentration, corrected for background, exceeds the proposed
concentration action level (i.e., 9 [mu]g/m\3\), the facility must,
within 5 days of comparing the rolling annual average concentration to
the concentration action level, initiate a root cause analysis to
determine the primary cause, and any other contributing cause(s), of
the exceedance. The facility must complete the root cause analysis and
implement corrective action within 45 days of initiating the root cause
analysis. We are not proposing specific controls or corrections that
would be required when the concentration action level is exceeded
because the cause of an exceedance could vary greatly from facility to
facility and episode to episode, since many different sources emit
fugitive emissions. Rather, we are proposing to allow facilities to
determine, based on their own analysis of their operations, the action
that must be taken to reduce air concentrations at the fenceline to
levels at or below the concentration action level, representing full
compliance with all refinery MACT requirements, adjusted for additional
control requirements we are proposing in today's action.
If, upon completion of the corrective action described above, the
owner or operator exceeds the action level for the next two-week
sampling episode following the completion of a first set of corrective
actions, the owner or operator

[[Page 36927]]

would be required to develop and submit to EPA a corrective action plan
that would describe the corrective actions completed to date. This plan
would include a schedule for implementation of emission reduction
measures that the owner or operator can demonstrate is as soon as
practical. This plan would be submitted to the Administrator for
approval within 30 days of an exceedance occurring during the next two-
week sampling episode following the completion of the initial round of
corrective action. The EPA would evaluate this plan based on the
ambient concentrations measured, the sources identified as contributing
to the high fenceline concentration, the potential emission reduction
measures identified, and the emission reduction measures proposed to be
implemented in light of the costs of the options considered and the
reductions needed to reduce the ambient concentration below the action
level threshold. To minimize burden on the state implementing agencies
and provide additional resources for identifying potential emission
sources, we are proposing not to delegate approval of this plan. The
refinery owner or operator is not deemed out of compliance with the
proposed concentration action level, provided that the appropriate
corrective action measures are taken according to the time-frame
detailed in an approved corrective action plan.
The EPA requests comment on whether it is appropriate to establish
a standard time frame for compliance with actions listed in a
corrective action plan. We also request comment on whether the approval
of the corrective action plan should be delegated to state, local and
tribal governments.
The EPA's post-control dispersion modeling (described in section
III.A of this preamble), which relies on reported emissions inventories
from the 2011 Refinery ICR, adjusted to reflect compliance with the
existing refinery MACT standards as modified by the additional controls
proposed in this rulemaking, indicates that fugitive emissions at all
refineries are low enough to ensure that fenceline concentrations of
benzene do not exceed the proposed concentration action level. Assuming
the reported inventories and associated modeling are accurate, we
expect that few, if any, facilities will need to engage in required
corrective action. We do, however, expect that facilities may identify
``poor-performing'' sources (e.g., unusual leaks) from the fenceline
monitoring data and, based on this additional information, will take
action to reduce HAP emissions before they would have otherwise been
aware of the issue through existing inspection and enforcement
measures.
By selecting a fenceline monitoring approach and by selecting
benzene as the surrogate for organic HAP emissions, we believe that the
proposed monitoring approach will effectively target refinery MACT-
regulated fugitive emission sources. However, there may be instances
where the fenceline concentration is impacted by a low-level
miscellaneous process vent, heat exchange system or other similar
source. As these sources are regulated under Refinery MACT 1 and the
emissions from these sources were included in our post-control modeling
file (from which the 9 [mu]g/m\3\ fenceline concentration action level
was developed), sources would not be able to avoid taking corrective
action by claiming the exceedance of the fenceline concentration was
from one of these emission points rather than from fugitive emission
sources.
There may be instances in which the high fenceline concentration is
impacted by a non-refinery emission source. The most likely instance of
this would be leaks from HON equipment or HON storage vessels co-
located at the refinery. However, we consider the fenceline monitoring
requirement to be specific to refinery emission sources. Therefore, we
are proposing to allow refinery owners or operators to develop site-
specific monitoring plans to determine the impact of these non-Refinery
emission sources on the ambient benzene concentration measured at the
fenceline. This monitoring plan would be identical to those used by
refinery owners or operators that elect to determine monitoring
location-specific NFS values for nearby off-site sources. In this case,
however, the NFS is actually within the refinery fenceline. Upon
approval and implementation of the monitoring plan, the refinery owner
or operator would determine the highest fenceline concentration
corrected for background; the background correction in this case
includes a correction for the co-located non-Refinery emission
source(s).
The EPA requests comment on whether the corrective action
requirements should be limited to exceedances of the fenceline
concentration solely from refinery emission sources and whether a
refinery owner or operator should be allowed to exceed the annual
average fenceline concentration action level if they can demonstrate
the exceedance of the action level is due to a non-refinery emissions
source. We also request comment on the requirements proposed for
refinery owners or operators to demonstrate that the exceedance is
caused by a non-refinery emissions source. Specifically, we request
comment on whether the ``near-field source'' correction is appropriate
for on-site sources and whether there are other methods by which
refinery owners or operators with co-located, non-refinery emission
sources can demonstrate that their benzene concentrations do not exceed
the proposed fenceline concentration action level.
Additional requirements of the fenceline monitoring program. We are
proposing that fenceline data at each monitor location be reported
electronically for each semiannual period's worth of sampling periods
(i.e., 13 to 14 2-week sampling periods per semiannual period). These
data would be reported within 45 days of the end of each semiannual
period, and will be made available to the public through the EPA's
electronic reporting and data retrieval portal, in keeping with the
EPA's efforts to streamline and reduce reporting burden and to move
away from hard copy submittals of data where feasible.
We are proposing to require the reporting of raw fenceline
monitoring data, and not just the HFC, on a semiannual basis;
considering the fact that the fenceline monitoring standard is a new
approach for fugitive emissions control, and it involves the use of new
methods, both analytical and siting methods, this information is
necessary for the EPA to evaluate whether this standard has been
implemented correctly. Further, the information provided by the raw
data, such as the need for additional or less monitoring sites, the
range of measured concentrations, the influence of background sources,
and the ability to collect and compare data from all refineries, will
inform us of further improvements we can make to the fenceline
standard, monitoring and analytical methods, approaches for estimating
refinery fugitive emissions, and guidance that may be helpful to
improve implementation of the fenceline monitoring approach. We seek
comment on suggestions for other ways we can monitor and improve the
fenceline monitoring requirement.
We are proposing that facilities be required to conduct fenceline
monitoring on a continuous basis, in accordance with the specific
methods described above, even if benzene concentrations, as measured at
the fenceline, routinely are substantially lower than the concentration
action level. In light of the low annual

[[Page 36928]]

monitoring and reporting costs associated with the fenceline monitors
(as described in the next section), and the importance of the fenceline
monitors as a means of ensuring the control of fugitives achieves the
expected emission levels, we believe it is appropriate to require
collection of fenceline monitoring data on a continuous basis. However,
the EPA recognizes that fugitive benzene emissions from some facilities
may be so low as to make it improbable that exceedances of the
concentration action level would ever occur.
In the interest of reducing the cost burden on facilities to comply
with this rule, the EPA solicits comment on approaches for reducing or
eliminating fenceline monitoring requirements for facilities that
consistently measure fenceline concentrations below the concentration
action level, and the measurement level that should be used to provide
such relief. Such an approach would be consistent with graduated
requirements for valve leak monitoring in Refinery MACT 1 and other
equipment leak standards, where the frequency of required monitoring
varies depending on the percent of leaking valves identified during the
previous monitoring period (see, for example, 40 CFR 63.648(c) and 40
CFR 63.168(d)). The EPA requests comment on the minimum time period
facilities should be required to conduct fenceline monitoring; the
level of performance, in terms of monitored fenceline concentrations,
that would enable a facility to discontinue use of fenceline monitors
or reduce the frequency of data collection and reporting; and any
adjustments to the optical gas imaging camera requirements that would
be necessary in conjunction with such changes to the fenceline
monitoring requirements.
i. Delayed Coking Units
As noted in section IV.A of this preamble, we are soliciting
comments on the need to establish MACT standards for DCU under CAA
section 112(d)(2) and (3). Even if we were to assume that there is
already an applicable MACT standard for DCU, a technology review of
this emission source, as prescribed under CAA section 112(d)(6), would
lead us to propose a depressurization limit of 2 psig because of
technology advancements since the MACT standards were originally issued
and because it is cost effective. Industry representatives have pointed
out that Refinery NSPS Ja requires DCU at new and modified sources to
depressure to 5 psig, and they have indicated that EPA should not
require a lower depressurization limit under a CAA section 112(d)(6)
technology review. Further, industry representatives also provided
summary-level information (available in Docket ID Number EPA-HQ-OAR-
2010-0682 as correspondence from API entitled Coker Vent Potential
Release Limit Preliminary Emission, Cost and Cost Effectiveness
Estimates) on costs to depressure to 5 psig versus 2 psig. While the
cost information does not show large differences for any particular
facility to depressure at 5 psig versus 2 psig, the information does
show a large range in potential costs between refineries. At this time,
we do not have the detailed, refinery-specific cost breakdowns to
compare against our cost assumptions, which were derived from data
obtained for a facility that did install the necessary equipment to
meet a 2 psig limit. We also do not have detailed information on the
design and operation of the DCU in industry's cost study to evaluate
whether there are any differences that would warrant subcategories. We
solicit information on designs, operational factors, detailed costs and
emissions data for DCU, and we specifically solicit comments on what
should be the appropriate DCU depressurization limit if we were to
adopt such a requirement pursuant to CAA section 112(d)(6) rather than
pursuant to CAA section 112(d)(2) and (3).
2. Refinery MACT 2--40 CFR Part 63, Subpart UUU
The Refinery MACT 2 source category regulates HAP emissions from
FCCU, CRU and SRU process vents. Criteria pollutant emissions from FCCU
and SRU are regulated under 40 CFR part 60, subparts J and Ja (Refinery
NSPS J and Refinery NSPS Ja, respectively). We conducted a technology
review of Refinery NSPS J emission limits from 2005 to 2008 and
promulgated new standards for FCCU and SRU (among other sources) in
Refinery NSPS Ja on June 24, 2008 (73 FR 35838). Our current technology
review of Refinery MACT 2 relies upon, but is not limited to,
consideration of this recent technology review of Refinery NSPS J for
FCCU and SRU.
a. FCCU Process Vent
The FCCU has one large atmospheric vent, the coke burn-off exhaust
stream for the unit's catalyst regenerator. HAP emissions from this
FCCU process vent include metal HAP associated with entrained catalyst
particles and organic HAP, mostly by-products of incomplete combustion
from the coke burn-off process. As the control technologies associated
with each of these classes of pollutants are very different, the
controls associated with each of these classes of pollutants are
considered separately.
Metal HAP emission controls. The current Refinery MACT 2 includes
several different compliance options, some based on PM as a surrogate
for total metal HAP and some based on nickel (Ni) as a surrogate for
total metal HAP. Refinery NSPS J was the basis of the PM emission
limits and the metal HAP MACT floor in Refinery MACT 2. Refinery NSPS J
limits PM from FCCU catalyst regeneration vents to 1.0 gram particulate
matter per kilogram (g PM/kg) of coke burn-off, with an additional
incremental PM allowance for liquid or solid fuel burned in an
incinerator, waste heat boiler, or similar device. Refinery MACT 2
states that FCCU subject to Refinery NSPS J PM emission limits are
required to demonstrate compliance with Refinery NSPS J PM emission
limits as specified in Refinery NSPS J. As provided in Refinery NSPS J,
ongoing compliance with the PM emission limits is determined by
compliance with a 30-percent opacity limit, except for one 6-minute
average per hour not to exceed 60-percent opacity. FCCU not subject to
Refinery NSPS J may elect to comply with the FCCU PM provisions in
Refinery NSPS J. Alternatively, they may comply with a 1.0 g PM/kg of
coke burn-off emission limit in Refinery MACT 2 (with no provision for
an additional incremental PM allowance for liquid or solid fuel burned
in an incinerator, waste heat boiler, or similar device). Compliance
with this limit in Refinery MACT 2 is demonstrated by either a 1-hour
average site-specific opacity limit using a continuous opacity
monitoring system (COMS) or APCD-specific daily average operating
limits using CPMS.
Refinery MACT 2 also includes two emission limit alternatives that
use Ni, rather than PM, as the surrogate for metal HAP. The first of
these Ni alternatives is a mass emission limit of 13 grams Ni per hour;
the second nickel alternative is an emission limit of 1.0 milligrams Ni
per kilogram of coke burn-off. Compliance with the Ni emission limits
in Refinery MACT 2 is demonstrated by either a daily average site-
specific Ni operating limit (using a COMS and weekly determination of
Ni concentration on equilibrium FCCU catalyst), or APCD-specific daily
average operating limits using CPMS and monthly average Ni
concentration operating limit for the equilibrium FCCU catalyst.
Under Refinery MACT 2, an initial performance demonstration (source
test) is required to show that FCCU is

[[Page 36929]]

compliant with the emission limits selected by the refinery owner or
operator. No additional performance test is required for facilities
already complying with Refinery NSPS J. The performance test is a one-
time requirement; additional performance tests are only required if the
owner or operator elects to establish new operating limits, or to
modify the FCCU or control system in such a manner that could affect
the control system's performance.
Under the review for Refinery NSPS J, we conducted a literature
review as well as a review of the EPA's refinery settlements and state
and local regulations affecting refineries to identify developments in
practices, processes and control technologies to reduce PM emissions
from refinery sources (see Summary of Data Gathering Efforts: Emission
Control and Emission Reduction Activities, August 19, 2005, and Review
of PM Emission Sources at Refineries, December 20, 2005, Docket Item
Number EPA-HQ-OAR-2007-0011-0042). At that time, we identified
regulations for PM from FCCU that were more stringent than the Refinery
NSPS J requirements for PM, and we promulgated more stringent PM limits
in Refinery NSPS Ja. Refinery NSPS Ja limits PM from FCCU catalyst
regeneration vents to 1.0 g PM/kg of coke burn-off for modified or
reconstructed FCCU, with no incremental allowance for PM-associated
liquid or solid fuels burned in a post-combustion device. Furthermore,
an emission limit of 0.5 g PM/kg of coke burn-off was established for
FCCU constructed after May 14, 2007.
In addition, the Refinery NSPS J review identified improvements in
APCD monitoring practices, which were included in the Refinery NSPS Ja
standards. Refinery NSPS J includes a 30-percent opacity limit as the
only ongoing monitoring requirements for PM from the FCCU. This 30-
percent opacity limit has shown to be lenient and high in comparison to
recent federal rules that have included more stringent opacity limits
(e.g., 40 CFR part 60, subpart Db with 20-percent opacity), and recent
state and local agency rules that omit opacity limits altogether in
favor of operating limits for the emission control systems. Based on
the Refinery NSPS J review, Refinery NSPS Ja does not include an
opacity limit, but includes updated and more appropriate monitoring
approaches, such as requiring bag leak detectors (BLD) for fabric
filter control systems, and requiring CPMS for electrostatic
precipitators (ESP) and wet scrubbers. Additionally, Refinery NSPS Ja
includes an option to measure PM emissions directly using a PM CEMS.
For this monitoring alternative, a direct PM concentration limit
(equivalent to the conventional FCCU PM emission limit in terms of g
PM/kg of coke burn-off) is included in the rule. Finally, in our review
for Refinery NSPS J, we noted that, even with improved monitoring
methods, periodic source testing is needed to verify the performance of
the control system as it ages. In Refinery NSPS Ja, annual performance
demonstrations are required for affected FCCU. The Refinery NSPS Ja
standards for PM from FCCU reflect the latest developments in
practices, processes and control technologies. In our current review of
Refinery MACT 2, we did not identify any other developments in
practices, processes or control technologies since we promulgated
Refinery NSPS Ja in 2008.
The conclusions of the technology review conducted for the Refinery
NSPS J PM emission limits are directly applicable to Refinery MACT 2;
the initial Refinery MACT 2 rule recognized this by providing that
compliance with Refinery NSPS J would also be compliance with Refinery
MACT 2. We considered the impacts of proposing to revise Refinery MACT
2 to incorporate the developments in monitoring practices and control
technologies reflected in the Refinery NSPS Ja limits and monitoring
provisions.
As noted above, Refinery NSPS Ja includes a limit of 0.5 g PM/kg of
coke burn-off for newly constructed sources. There would be no costs
associated with requiring the lower emission limit of 0.5 g PM/kg of
coke burn-off for Refinery MACT 2 new sources under CAA section
112(d)(6) because these sources would already be required to comply
with that limit under Refinery NSPS Ja. Therefore, we are proposing
that it is necessary pursuant to CAA section 112(d)(6) to revise
Refinery MACT 2 to incorporate the Refinery NSPS Ja PM limit for new
sources.
We are also proposing to establish emission limits and monitoring
requirements in Refinery MACT 2 that are consistent with those in
Refinery NSPS Ja. This option would not impose any additional cost on
sources already subject to Refinery NSPS Ja. We note that for
facilities subject to Refinery NSPS J, this would not lead to
duplicative or conflicting monitoring requirements because Refinery
NSPS J already includes a provision that allows affected facilities
subject to Refinery NSPS J to instead comply with the provisions in
Refinery NSPS Ja (see 40 CFR 60.100(e)).
In addition, in conjunction with our proposal to revise Refinery
MACT 2 to include the more stringent requirements in Refinery NSPS Ja,
we are proposing to remove the less stringent compliance option of
meeting the requirements of Refinery NSPS J. As described previously,
Refinery NSPS J includes an incremental PM emissions allowance for
post-combustion devices and relies on a 30-percent opacity limit that
is outdated and has been demonstrated to be ineffective at identifying
exceedances of the 1.0 g PM/kg coke burn-off emissions limit.
We also reviewed the compliance monitoring requirements for the
Refinery MACT 2 PM and Ni-based emission limits. As described
previously, Refinery MACT 2 includes operating limits based on APCD
operating parameters or site-specific opacity limits. There are
differences between the monitoring approaches in Refinery MACT 2 for
these limits and Refinery NSPS Ja monitoring approaches for the NSPS PM
limit, so we evaluated whether it is necessary, pursuant to CAA section
112(d)(6), to revise the monitoring provisions in Refinery MACT 2
consistent with the requirements in Refinery NSPS Ja.
The first significant difference is in the averaging times used for
the different operating limits. Refinery NSPS Ja requires a 3-hour
rolling average for the operating limits for parametric monitoring
systems; Refinery MACT 2 includes daily averaging of the operating
limits. Typically, the averaging time for operating limits is based on
the duration of the performance test used to establish those operating
limits. As the performance test duration is 3 hours (three 1-hour test
runs) and compliance with the PM (or Ni) emission limit is based on the
average emissions during this 3-hour period, the most appropriate
averaging period for these operating limits is 3 hours. Using a daily
average could allow poor performance (i.e., control equipment for
shorter periods (e.g., 3-hour averages that are higher than the PM
emissions limit in Refinery NSPS Ja). For example, assume an operating
limit developed from a performance test has a value of 1 and that
values exceeding this level would suggest that the control system is
not operating as well as during the performance test (i.e., potentially
exceeding the PM emission limit). If the control system is run for 18
hours operating at a level of 0.9 and 6 hours at a level of 1.2, the
unit would be in compliance with the daily operating limit even though
the unit may have 6 consecutive hours during which the operating limit
was exceeded.

[[Page 36930]]

Reducing the averaging time does not impact the types of monitors
required; it merely requires the owner or operator of the unit to pay
more careful attention to the APCD operating parameters. We are
proposing that it is necessary, pursuant to CAA section 112(d)(6), to
incorporate the use of 3-hour averages rather than daily averages for
parameter operating limits in Refinery MACT 2 for both the PM and Ni
limits, because this is a cost-effective development in monitoring
practice.
The site-specific opacity operating limit for PM in Refinery MACT 2
(for units not electing to comply with Refinery NSPS J) has a 1-hour
averaging period, but the Ni operating limits (which use opacity
monitoring) have a 24-hour averaging period. These averaging periods
are inconsistent with the duration of the performance test, which is
over a 3-hour period. We are proposing, pursuant to CAA section
112(d)(6), to incorporate the use of 3-hour averages for the site-
specific opacity operating limit and the Ni operating limits rather
than daily averages because this is a cost-effective development in
monitoring practice.
We also compared the APCD-specific operating parameters used in
Refinery MACT 2 to those that we promulgated for Refinery NSPS Ja. The
Refinery NSPS Ja rule includes monitoring approaches that are not
included in Refinery MACT 2. These include the option of using PM CEMS
and requiring BLD for fabric filter control systems. Adding a PM CEMS
as an option for demonstrating compliance with the Refinery MACT 2 PM
limit (similar to what is provided in Refinery NSPS Ja) would not
impact the costs of complying with Refinery MACT 2 because sources can
choose whether or not to adopt this monitoring method. With respect to
BLD, there is only one refinery that currently uses a baghouse (fabric
filter) to control emissions from its FCCU (although one additional
unit has indicated that it has plans to install a fabric filter control
within the next few years). Under the existing requirements in Refinery
MACT 2 (assuming that the FCCU currently operating with a fabric filter
has not elected to comply with the Refinery NSPS J PM emission limit
option), it is required to comply with a site-specific opacity
operating limit. For new, reconstructed, or modified FCCU, Refinery
NSPS Ja requires use of BLD. While we generally consider the BLD to be
superior to opacity monitors for ensuring fabric filter control systems
are operating efficiently, it is difficult to determine what, if any,
increment in assurance that the unit is properly controlled would be
achieved by requiring the one facility currently operating a fabric
filter control system and complying with a site-specific opacity
operating limit to switch from a COMS to BLD. Therefore, we are
proposing that it is not necessary to require the one existing FCCU
with a fabric filter control system to switch from COMS to a BLD system
because this would require additional monitoring equipment (with
additional costs) and little to no associated increase in assurance
that the unit is properly controlled. Although we are not proposing to
require existing sources using a fabric filter to use BLD, we are
proposing to include BLD as an option to COMS; owners or operators of
FCCU using fabric filter-type control systems at existing sources can
elect (but are not required) to use BLD in lieu of COMS and the site-
specific opacity operating limit.
The Refinery NSPS Ja monitoring requirements for ESP include CPMS
for monitoring and recording the total power and the secondary current
to the entire system. The current MACT requires monitoring voltage and
secondary current or monitoring only the total power to the APCD. While
these monitoring requirements are similar, we consider that the
Refinery NSPS Ja requirements will provide improved operation of the
ESP. As the monitors required to measure these parameters are a routine
part of ESP installations, we project no additional costs for
monitoring equipment. We expect that a new performance test would be
needed to ensure that both total power and secondary current are
recorded during the source test. As discussed later in this section, we
are proposing to require ongoing performance tests regardless of the
monitoring option, so we are not projecting any additional costs
specific to revising the monitoring requirements for ESP. Because the
Refinery NSPS Ja monitoring and operating requirements for ESP are
expected to provide improved performance of the APCD with no
incremental costs, we propose that it is necessary, pursuant to CAA
section 112(d)(6), to incorporate the total power and the secondary
current operating limits into Refinery MACT 2.
Refinery NSPS Ja provides a specific monitoring alternative to
pressure drop for jet ejector-type wet scrubbers or any other type of
wet scrubbers equipped with atomizing spray nozzles. Owners or
operators of FCCU controlled by these types of wet scrubbers can elect
to perform daily checks of the air or water pressure to the spray
nozzle rather than monitor pressure. Refinery MACT 2 currently excludes
these types of control systems from monitoring pressure drop but
includes no specific monitoring to ensure the jet ejectors or atomizing
spray nozzle systems are properly operating. Since proper functioning
of the jet ejectors or atomizing spray nozzles is critical to ensuring
these control systems operate at the level contemplated by the MACT,
some monitoring/inspection requirement of these components is necessary
to ensure compliance with the FCCU PM or Ni emission limit. The owner
or operator of a jet ejector-type wet scrubber or other type of wet
scrubber equipped with atomizing spray nozzles should be performing
routine checks of these systems, such as the daily checks of the air or
water pressure to the spray nozzles, as required in Refinery NSPS Ja.
These daily checks are consistent with good operational practices for
wet scrubbers and should not add significant burden to the FCCU wet
scrubber owner or operator. For these reasons, we propose it is
necessary to require owners or operators of a jet ejector-type wet
scrubber or other type of wet scrubber equipped with atomizing spray
nozzles to perform daily checks of the air or water pressure to the
spray nozzles pursuant to CAA section 112(d)(6).
Finally, in our action promulgating Refinery NSPS Ja, we noted
that, even with improved monitoring methods, periodic source testing is
needed to verify the performance of the control system as it ages. In
Refinery NSPS Ja, annual performance demonstrations are required for
new sources. FCCU subject to Refinery MACT 2 as new sources would also
be subject to Refinery NSPS Ja and would have to comply with the annual
testing requirements in Refinery NSPS Ja. However, Refinery MACT 2 does
not include periodic performance tests for any FCCU. We considered
adding an annual testing requirement for FCCU subject to Refinery MACT
2. The annual nationwide cost burden exceeds $1 million per year and we
project only modest improvement in control performance resulting from
the performance demonstrations. We considered requiring FCCU
performance tests once every 5 years (i.e., once per title V permit
period). The nationwide annual cost of this additional testing
requirement for FCCU is projected to be, on average, $213,000 per year.
We consider this to be a reasonable minimum frequency for which
affected sources should demonstrate direct compliance with the FCCU
emission limits and that this cost is reasonable. Therefore, we propose
that it is

[[Page 36931]]

necessary, pursuant to CAA section 112(d)(6), to require a performance
test once every 5 years for all FCCU under to Refinery MACT 2.
Organic HAP. Refinery MACT 2 uses CO as a surrogate for organic HAP
and establishes an emission limit of 500 ppmv CO (dry basis). Some
FCCU, referred to as complete-combustion FCCU, employ excess oxygen in
the FCCU regenerator and are able to meet this emission limit without
the need for a post-combustion device. Other FCCU, referred to as
partial-combustion FCCU, do not supply enough air/oxygen for complete
combustion of the coke to CO2 and, therefore, produce a
significant quantity of CO in the regenerator exhaust. Partial-
combustion FCCU are typically followed by a post-combustion unit,
commonly referred to as a CO boiler, to burn the CO in the regenerator
exhaust in order to meet the 500 ppmv CO limit (and to recover useful
heat from the exhaust stream).
In our review of Refinery NSPS J, we conducted a review of state
and local regulations affecting refineries to identify control
strategies to reduce CO emissions or VOC emissions from refinery
sources (see Review of VOC Emission Sources at Refineries, December 14,
2005, Docket Item Number EPA-HQ-OAR-2007-0011-0043). We also conducted
a review of federal, state and local regulations affecting refineries
to identify control strategies to reduce CO emissions from refinery
sources (see Review of CO Emission Sources at Refineries, December 22,
2005, Docket Item Number EPA-HQ-OAR-2007-0011-0044). We did not
identify any developments in practices, processes and control
technologies to reduce CO or VOC emissions from FCCU as part of the
review of Refinery NSPS J, and we have not identified any developments
in practices, processes and control technologies for FCCU that would
reduce organic HAP since promulgation of Refinery MACT 2. We are
proposing that it is not necessary to revise the regulatory provisions
for organic HAP in the current MACT standards for FCCU, pursuant to CAA
section 112(d)(6).
Inorganic HAP. As mentioned previously, Refinery MACT 2 includes a
CO emission limit of 500 ppmv. Although this limit is expressly
provided as a limit addressing organic HAP emissions, this emission
limit is also expected to limit the emissions of oxidizable inorganic
HAP, such as HCN. That is, the CO concentration limit was developed as
an indicator of complete combustion for all oxidizable pollutants
typically found in exhaust gas from the FCCU regenerator operated in
partial burn mode. We note that HCN concentrations in FCCU regenerator
exhaust with high CO levels also have high HCN concentrations and that
HCN concentrations in the regenerator exhaust from complete-combustion
FCCU (those meeting the 500 ppmv CO limit without the need for a post-
combustion device) are much lower than those from partial burn FCCU
prior to a post-combustion device. Thus, we consider that the CO
emission limit also acts as a surrogate for the control of oxidizable
inorganic HAP, such as HCN.
The source test data from the ICR effort revealed that HCN
emissions from FCCU are greater than previous tests indicated,
particularly for complete-combustion FCCU. The increase in HCN
emissions was observed at units meeting lower NOX emission
limits, which have recently been required by consent decrees, state and
local requirements and Refinery NSPS Ja. The higher HCN emissions from
complete-combustion FCCU appear to be directly related to operational
changes made in efforts to meet these lower NOX emission
limits (e.g., reduced excess oxygen levels in the regenerator and
reduced regenerator bed temperatures). These higher HCN emissions were
only observed in complete-combustion FCCU; FCCU that operated in
partial burn mode followed by a CO boiler or similar post-combustion
device had significantly lower HCN emissions subsequent to the post-
combustion device.
Based on our review of the available ICR data and the technologies
used in practice, we considered establishing specific emission limits
for HCN. In order to comply with emission limits for HCN, owners or
operators of complete-combustion FCCU would either have to operate
their FCCU regenerator at slightly higher temperatures and excess
oxygen concentrations (to limit the formation of HCN in the
regenerator) or employ a post-combustion device or thermal oxidizer to
destroy HCN exhausted from the FCCU regenerator. However, each of these
options comes with significant secondary energy and environmental
impacts. First, both of these control strategies would yield a
significant increase in NOX emissions. We anticipate that
most FCCU owners or operators would have to install a selective
catalytic reduction (SCR) system to meet their NOX emission
limits, if applicable. Operation of the SCR would have energy impacts
and may have additional secondary PM2.5 impacts (associated
with ammonia slip from the SCR). We expect that modifying the
regenerator operating characteristics is the most cost-effective
option, although installing and using a thermal oxidizer may be
necessary, depending on the operational characteristics of the
regenerator and the HCN control requirement. Using a thermal oxidizer
to treat FCCU regenerator exhaust, a gas stream that has limited
heating value (due to the already low CO concentrations) would be much
more expensive and would have additional energy and secondary impacts
associated with the auxiliary fuel needed for the device, as compared
to modifying regenerator operating conditions.
We first performed a screening analysis of the impacts of making
only operational changes to the FCCU with the highest HCN
concentrations. If this control option is not cost effective for these
FCCU, it would not be cost effective for units that have lower HCN
concentrations and lower HCN emissions. Similarly, if operating changes
in the FCCU regenerator alone are not cost effective, then we can
assume that installing a thermal oxidizer to achieve this same level of
HCN emission reductions would also not be cost effective. We calculated
the cost of changing the regenerator parameters and adding an SCR for
the FCCU with the highest HCN emissions rate reported in the ICR, which
is an annual emissions rate of 460 tpy. This is also the largest FCCU
in operation in the United States and its territories. Based on the
size of this unit, we project that an SCR would be expected to cost
approximately $13-million and have annualized costs of approximately
$4.0-million/yr. Thus, if the HCN emissions can be reduced by 95
percent, the cost effectiveness would be approximately $9,000 per ton
of HCN. A smaller FCCU had similar HCN concentrations and annual HCN
emissions of 141 tpy. Based on the size of this unit, we project an SCR
would be expected to cost approximately $7-million and have annualized
costs of approximately $1.5-million/yr. Assuming a 95-percent reduction
in HCN emissions, the cost effectiveness would be approximately $11,000
per ton of HCN. The second-highest emitting FCCU was larger than this
unit, but had lower HCN concentrations. This third unit had emissions
of 184 tpy. Based on the size of this unit, we expect that an SCR would
cost approximately $9-million and have annualized costs of
approximately $2.2-million/yr. Assuming a 95-percent reduction in HCN
emissions, the cost effectiveness would be approximately $12,600 per
ton of HCN.
These costs are for the FCCU with the largest HCN emissions and the
lowest control cost (assuming operational

[[Page 36932]]

changes alone are insufficient to significantly reduce HCN emissions),
and the average cost effectiveness for these units exceeds $10,000 per
ton HCN emissions reduced. Based on the economies of scale and
considering lower HCN concentrations for all other units, the costs per
ton of HCN removed for a nationwide standard would be higher. If a
post-combustion device is needed to achieve a specific HCN emissions
limit, the costs would be even higher.
Based on the cost, secondary energy and secondary environmental
impacts of an HCN emission limit beyond that achieved by the CO
emission limit as a surrogate for HCN, we are proposing, at this time,
that it is not necessary, pursuant to CAA section 112(d)(6), to revise
the MACT standard to establish a separate HCN standard. As our
understanding of the mechanisms of HCN and NOX formation
improves and as catalyst additives evolve, it may be possible to
achieve both low NOX and low HCN emissions without the use
of an SCR and/or post-combustion controls. However, at this time our
test data indicate an inverse correlation between these two pollutants.
The three facilities with the highest HCN concentrations were the
facilities with the lowest NOX concentrations, all of which
were below 20 ppmv (dry basis, 0-percent excess air) during the
performance tests. While a 20 ppmv NOX limit may be
achievable, we anticipate that further reducing the NOX new
source performance limits for FCCU would either increase
PM2.5 secondary emissions (via the use of an SCR and its
associated ammonia slip) or further increase HCN emissions (if
combustion controls are used).
b. CRU Process Vents
A CRU is designed to reform (i.e., change the chemical structure
of) naphtha into higher-octane aromatics. The reforming process uses a
platinum or bimetal (e.g., platinum and rhenium) catalyst material.
Small amounts of coke deposit on the catalyst during the catalytic
reaction and this coke is burned off the catalyst to regenerate
catalyst activity. There are three types of CRU classified by
differences in how the units are designed and operated to effect
reforming catalyst regeneration. Semi-regenerative reforming is
characterized by shutting down the reforming unit at specified
intervals, or at the operator's convenience, for in situ catalyst
regeneration. Semi-regenerative CRU typically regenerate catalyst once
every 8 to 18 months, with the regeneration cycle lasting approximately
2 weeks. Cyclic-regeneration reforming is characterized by continuous
or continual reforming operation with periodic (but frequent)
regeneration of catalyst in situ by isolating one of the reactors in
the series, regenerating the catalyst, then returning the reactor to
the reforming operation. The regeneration of the catalyst in a single
reactor may occur numerous times per year (e.g., once a month), and the
regeneration of each reactor may take 3 to 5 days to complete.
Continuous-regeneration reforming units use moving catalyst bed
reactors situated vertically (which is why they are often referred to
as platforming units). Catalyst flows down the series of reactors. At
the bottom of the last reactor, catalyst is continually isolated and
sent to a special regenerator. After regeneration, the regenerated
catalyst is continually fed to the first (top) reactor. Thus,
continuous-regeneration reforming units are characterized by
continuous-reforming operation along with continuous-regeneration
operation.
The catalytic reforming reaction is performed in a closed reactor
system; there are no emissions associated with the processing portion
of the CRU. There is a series of emission points associated with the
CRU catalyst regenerator. Regardless of the type of CRU used, there is
a series of steps conducted to effect catalyst regeneration. These
steps are: (1) Initial depressurization/purge; (2) coke burn-off; (3)
catalyst rejuvenation; and (4) reduction/final purge. The primary
emissions during the depressurization/purge cycle are organic HAP.
Inorganic HAP, predominately HCl and chlorine, are emitted during the
coke burn-off and rejuvenation cycles. The reduction purge is mostly
inert materials (nitrogen and/or hydrogen). Refinery MACT 2 contains
organic HAP emission limits for the depressurization/purge cycle
(purging prior to coke-burn-off) and inorganic HAP emission limits for
the coke burn-off and catalyst rejuvenation cycles. Our technology
review, summarized below, considers each of these emission limits
separately. For additional details on the technology review for CRU,
see Technology Review Memorandum for Catalytic Reforming Units at
Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0682.
Organic HAP. Refinery MACT 2 requires the owner or operator to
comply with either a 98-percent reduction of TOC or non-methane TOC, or
an outlet concentration of 20 ppmv or less (dry basis, as hexane,
corrected to 3-percent oxygen). The emission limits for organic HAP for
the CRU do not apply to emissions from process vents during
depressuring and purging operations when the reactor vent pressure is 5
psig or less. Control technologies used include directing the purge gas
directly to the CRU process heater to be burned, recovering the gas to
the facility's fuel gas system, or venting to a flare or other APCD.
The pressure limit exclusion was provided to allow atmospheric venting
of the emissions when the pressure of the vessel fell below that needed
to passively direct the purge gas to the APCD (most commonly the CRU
process heater or flare).
We did not identify any developments in practices, processes and
control technologies for reducing organic HAP emissions from CRU.
However, as noted in section IV.A.2 of this preamble, we are proposing
to amend the pressure limit exclusion pursuant to CAA sections
112(d)(2) and (3) to clarify that this limit only applies during
passive vessel depressuring. Also, as described in section IV.A.3 of
this preamble, we are proposing revisions to Refinery MACT 1 and 2,
pursuant to CAA sections 112(d)(2) and (3), to ensure flares used as
APCD meet the required destruction efficiency, which includes flares
used to control the organic HAP emissions from the CRU
depressurization/purge vent streams.
Inorganic HAP. Refinery MACT 2 uses HCl as a surrogate for
inorganic HAP during the coke burn-off and rejuvenation cycles.
Refinery MACT 2 requires owners or operators of existing semi-
regenerative CRU to reduce uncontrolled emissions of HCl by 92-percent
by weight or to a concentration of 30 ppmv (dry basis, corrected to 3-
percent oxygen) during the coke burn-off and rejuvenation cycles.
Owners or operators of new semi-regenerative CRU, new or existing
cyclic CRU, or new or existing continuous CRU are required to reduce
uncontrolled emissions of HCl by 97-percent by weight or to a
concentration of 10 ppmv (dry basis, corrected to 3-percent oxygen)
during the coke burn-off and rejuvenation cycles. Technologies used to
achieve these limits include caustic spray injection, wet scrubbers,
and solid adsorption systems. We conducted a technology review for CRU
by reviewing the ICR responses and scientific literature. We did not
identify any developments in practices, processes and control
technologies for reducing inorganic HAP emissions from CRU. We are
proposing that it is not necessary to revise the current inorganic HAP
MACT standards for CRU, pursuant to CAA section 112(d)(6).

[[Page 36933]]

c. SRU Process Vents
Most sulfur recovery plants at petroleum refineries use the Claus
reaction to produce elemental sulfur. In the Claus reaction, two moles
of hydrogen sulfide (H2S) react with one mole of
SO2 in a catalytic reactor to form elemental sulfur and
water vapor. Prior to the Claus reactors, one-third of the
H2S in the sour gas feed to the sulfur plant must be
oxidized to SO2 to have the correct proportion of
H2S and SO2 for the Claus reaction. This
oxidation step is performed in the ``Claus burner.'' The remaining gas
stream, after the elemental sulfur is condensed, is referred to as
``tail gas.'' HAP emissions in tail gas from sulfur recovery plants are
predominately COS and CS2, which are primarily formed as
side reactions of the Claus process.
Refinery MACT 2 contains HAP standards for SRU that were based on
the Refinery NSPS J SO2 and reduced sulfur compounds
emission limits. Refinery NSPS J includes an emission limit of 300 ppmv
reduced sulfur compounds for a reduction control system not followed by
an incinerator, and an emission limit of 250 ppmv SO2 (dry
basis, 0-percent excess air) for oxidative control systems or reductive
control systems followed by incineration. These Refinery NSPS J limits
apply only to Claus sulfur recovery plants with a sulfur recovery
capacity greater than 20 long tons per day (LTD). These emission limits
effectively required sulfur recovery plants to achieve 99.9-percent
sulfur recovery.
Refinery MACT 2 defines SRU as a process unit that recovers
elemental sulfur from gases that contain reduced sulfur compounds and
other pollutants, usually by a vapor-phase catalytic reaction of sulfur
dioxide and hydrogen sulfide (see 40 CFR 63.1579). This definition
specifically excludes sulfur recovery processes that do not recover
elemental sulfur, such as the LO-CAT II process, but does not
necessarily limit applicability to Claus SRU. Refinery MACT 2 requires
owners or operators of an SRU that is subject to Refinery NSPS J to
meet the Refinery NSPS J limits. Owners or operators of an SRU that is
not subject to Refinery NSPS J can elect to meet the emission limits in
Refinery NSPS J or meet a reduced sulfur compound limit of 300 ppmv
(dry basis, 0-percent excess air) regardless of the type of control
system or the presence of an incinerator. Unlike Refinery NSPS J,
Refinery MACT 2 does not have a capacity applicability limit, so this
300 ppmv reduced sulfur compound limit is applicable to all SRU (as
that term is defined), regardless of size.
Upon completion of our technology review for Refinery NSPS J, we
promulgated Refinery NSPS Ja, which includes new provisions for the
sulfur recovery plant. First, Refinery NSPS Ja limits are now
applicable to all sulfur recovery plants, not just Claus sulfur
recovery plants. Second, emission limits were added for sulfur recovery
plants with a capacity of 20 LTD or less, to require new, small sulfur
recovery plants to achieve a target sulfur recovery efficiency of 99-
percent. These limits are a factor of 10 higher than the emission
limits for larger sulfur recovery plants (i.e., 3,000 ppmv reduced
sulfur compounds for a reduction control system not followed by an
incinerator and 2,500 ppmv SO2 for oxidative control systems
or reductive control systems followed by incineration). Refinery NSPS J
did not include emission limits for these smaller sulfur recovery
plants. Third, new correlations were introduced to provide equivalent
emission limits for systems that use oxygen-enriched air in their Claus
burner.
The technology review conducted for Refinery NSPS J focused on
SO2 emissions. Under our current technology review for
Refinery MACT 2, we considered the developments in practices, processes
or control technologies identified in the Refinery NSPS J technology
review as they pertain to HAP emissions and the existing Refinery MACT
2 requirements.
We considered the new Refinery NSPS Ja limits for small sulfur
recovery plants. While Refinery NSPS Ja establishes criteria pollutant
emission limits for these smaller sulfur recovery plants that were
previously unregulated for such emissions, these sources are already
covered under Refinery MACT 2. Refinery MACT 2 requires these SRU to
meet a 300 ppmv reduced sulfur compound limit, which is more stringent
than the 3,000 ppmv limit established in Refinery NSPS Ja.
We also considered the new correlations in Refinery NSPS Ja for SRU
that use oxygen-enriched air in their Claus burner. In the technology
review under Refinery NSPS J, we identified a change in practice in the
operation of certain Claus SRU. At the time we promulgated Refinery
MACT 2, we assumed that all units were using ambient air in the Claus
burner, and we established the same emission limits as in Refinery NSPS
J. Now, however, we understand that some facilities are using oxygen-
enriched air. This practice lowers the amount of inert gases introduced
into the SRU and improves operational performance and reliability of
the sulfur recovery plant. Air is approximately 20.9 percent by volume
oxygen and 79.1-percent inert gases (predominately nitrogen with 1-
percent argon and other inert gases). The inert gases introduced in the
Claus burner become a significant portion of the overall tail gas flow.
When oxygen enrichment is used in the Claus burner, there are fewer
inert gases in the tail gas and a lower overall tail gas flow rate. The
same molar flow rate of reduced sulfur compounds will be present in the
tail gas, but without the additional flow of inerts from the ambient
air, the concentration of the reduced sulfur compounds (or
SO2) in the tail gas is higher.
In developing Refinery NSPS Ja, we included a correlation equation
that facilities can use to adjust the concentration limit based on the
enriched-oxygen concentration used in the Claus burner. This equation
is designed to allow the same mass of emissions for these units as is
allowed for units using only ambient air. That is, the emission
equation establishes a concentration limit for units using oxygen
enrichment so that the mass emissions from the unit do not exceed the
mass emissions allowed under the 250 ppmv SO2 (or 300 ppmv
reduced sulfur compounds) emissions limits in Refinery NSPS J and in
Refinery MACT 2. The new equation in Refinery NSPS Ja for large sulfur
recovery plants (those with sulfur recovery greater than 20 LTD)
provides an equivalent mass emissions rate of reduced sulfur HAP from
the SRU as is currently required in Refinery MACT 2 while allowing a
practice that improves the operational reliability of the unit. There
are no costs to providing this option for units using oxygen-enriched
air because: (1) It is an option that the owner or operator can elect
to meet instead of the xisting 250 ppmv SO2 emissions limit
and (2) owners or operators of SRU that use oxygen-enriched air are
expected to already routinely monitor the inlet air oxygen
concentration for operational purposes. Therefore, we are proposing
that it is necessary, pursuant to CAA section 112(d)(6), to amend
Refinery MACT 2 sulfur recovery requirements to include this equation
that addresses the use of oxygen-enriched air as a development in
practice in SRU process operations.
The emission limits for large sulfur recovery plants (those with
sulfur recovery greater than 20 LTD) in Refinery NSPS Ja are equivalent
to those in Refinery MACT 2. We are proposing to allow owners or
operators subject to Refinery NSPS Ja limits for sulfur

[[Page 36934]]

recovery plants with a capacity greater than 20 LTD to comply with
Refinery NSPS Ja as a means of complying with Refinery MACT 2.
We have not identified any additional developments in practices,
processes or control technologies for HAP from SRU since development of
Refinery NSPS Ja.

C. What are the results of the risk assessment and analyses?

1. Inhalation Risk Assessment Results
Table 10 of this preamble provides an overall summary of the
results of the inhalation risk assessment.

Table 10--Petroleum Refining Source Sector Inhalation Risk Assessment Results
----------------------------------------------------------------------------------------------------------------
Estimated population Estimated annual Maximum chronic Maximum screening
Maximum individual cancer risk (- at increased risk cancer incidence non-cancer TOSHI acute non-cancer HQ
in-1 million) \a\ levels of cancer (cases per year) \b\ \c\
----------------------------------------------------------------------------------------------------------------
Actual Emissions
----------------------------------------------------------------------------------------------------------------
60............................... >= 1-in-1 million: 0.3 0.9 HQREL = 5
5,000,000. (Nickel Compounds).
>= 10-in-1 million:
100,000.
>= 100-in-1 million:
0.
----------------------------------------------------------------------------------------------------------------
Allowable Emissions \d\
----------------------------------------------------------------------------------------------------------------
100.............................. >= 1-in-1 million: 0.6 1 --
7,000,000 \e\.
>= 10-in-1 million:
Greater than 90,000
\e\.
>= 100-in-1 million:
0.
----------------------------------------------------------------------------------------------------------------
\a\ Estimated maximum individual excess lifetime cancer risk due to HAP emissions from the source category.
\b\ Maximum TOSHI. The target organ with the highest TOSHI for the Petroleum Refining source sector is the
thyroid system for actual emissions and the neurological system for allowable emissions.
\c\ The maximum off-site HQ acute value of 5 is driven by emissions of nickel from CCU. See section III.A.3 of
this preamble for explanation of acute dose-response values. Acute assessments are not performed on allowable
emissions because of a lack of detailed hourly emissions data. However, because of the conservative nature of
the actual annual to actual hourly emissions rate multiplier, allowable acute risk estimates will be
comparable to actual acute estimates.
\d\ The development of allowable emission estimates can be found in the memo entitled Refinery Risk Estimates
for Modeled ``Allowable'' Emissions, which can be found in Docket ID Number EPA-HQ-OAR-2010-0682.
\e\ Population risks from allowable emissions were only calculated for the model plant emissions (REM) approach.
For the 138 facilities modeled using the modeled plant approach the population risks greater than 10-in-1
million was estimated to be 90,000. If we consider the second approach to determining allowable emissions
(combined the results of the actual and REM emissions estimates) we estimate that the allowable population
risks greater than 10-in-1 million would be greater than 90,000 people. Further, the number of people above 1-
in-1 million would also be higher than the 7,000,000 estimated using the REM model.

The inhalation risk modeling performed to estimate risks based on
actual emissions relied primarily on emissions data from the ICR,
updated based on our quality assurance review as described in section
III.A.1 of this preamble.
The results of the chronic baseline inhalation cancer risk
assessment indicate that, based on estimates of current actual
emissions, the maximum individual lifetime cancer risk (MIR) posed by
the refinery source category is 60-in-1 million, with benzene and
naphthalene emissions from equipment leaks and storage tanks accounting
for 98 percent of the MIR risk. The total estimated cancer incidence
from refinery emission sources based on actual emission levels is 0.3
excess cancer cases per year or one case in every 3.3 years, with
emissions of naphthalene, benzene, and 2-methylnaphthalene contributing
22 percent, 21 percent and 13 percent, respectively, to this cancer
incidence. In addition, we note that approximately 100,000 people are
estimated to have cancer risks greater than 10-in-1 million, and
approximately 5,000,000 people are estimated to have risks greater than
1-in-1 million as a result of actual emissions from these source
categories. When considering the MACT-allowable emissions, the maximum
individual lifetime cancer risk is estimated to be up to 100-in-1
million, driven by emissions of benzene and naphthalene from refinery
fugitives (e.g., storage tanks, equipment leaks and wastewater) and the
estimated cancer incidence is estimated to be 0.6 excess cancer cases
per year or one excess case in every 1.5 years. Greater than 90,000
people were estimated to have cancer risks above 10-in-1 million and
approximately 7,000,000 people were estimated to have cancer risks
above 1-in-1 million considering allowable emissions from all petroleum
refineries.
The maximum modeled chronic non-cancer HI (TOSHI) value for the
source sector based on actual emissions was estimated to be less than
1. When considering MACT-allowable emissions, the maximum chronic non-
cancer TOSHI value was estimated to be about 1.
2. Acute Risk Results
Our screening analysis for worst-case acute impacts based on actual
emissions indicates the potential for five pollutants--acetaldehyde,
acrolein, arsenic, benzene and nickel--to exceed an HQ value of 1, with
an estimated worst-case maximum HQ of 5 for nickel based on the REL
values. This REL occurred at a facility reporting nickel emissions from
the FCCU vent. One hundred thirty-six of the 142 petroleum refineries
had an estimated worst-case HQ less than or equal to 1 for all HAP;
except for the one facility that had an estimated REL of 5, the
remaining 5 refineries with an REL above 1 had an estimated worst-case
HQ less than or equal to 3.
To better characterize the potential health risks associated with
estimated worst-case acute exposures to HAP, and in response to a key
recommendation from the SAB's peer review of EPA's RTR risk assessment
methodologies, we examine a wider range of available acute health
metrics than we do for our chronic risk assessments. This is in
acknowledgement that there are generally more data gaps and
inconsistencies in acute reference values than there are in chronic
reference values. By definition, the acute CalEPA REL represents a
health-

[[Page 36935]]

protective level of exposure, with no risk anticipated below those
levels, even for repeated exposures; however, the health risk from
higher-level exposures is unknown. Therefore, when a CalEPA REL is
exceeded and an AEGL-1 or ERPG-1 level is available (i.e., levels at
which mild effects are anticipated in the general public for a single
exposure), we have used them as a second comparative measure.
Historically, comparisons of the estimated maximum off-site 1-hour
exposure levels have not been typically made to occupational levels for
the purpose of characterizing public health risks in RTR assessments.
This is because occupational ceiling values are not generally
considered protective for the general public since they are designed to
protect the worker population (presumed healthy adults) for short-
duration increases in exposure (less than 15 minutes). As a result, for
most chemicals, the 15-minute occupational ceiling values are set at
levels higher than a 1-hour AEGL-1, making comparisons to them
irrelevant unless the AEGL-1 or ERPG-1 levels are also exceeded. Such
is not the case when comparing the available acute inhalation health
effect reference values for some of the pollutants considered in this
analysis.
The worst-case maximum estimated 1-hour exposure to acetaldehyde
outside the facility fence line for the source categories is 1 mg/m\3\.
This estimated worst-case exposure exceeds the 1-hour REL by a factor
of 2 (HQREL=2) and is well below the 1-hour AEGL-1
(HQAEGL-1=0.01) and the ERPG-1 (HQERPG-1=0.05).
The worst-case maximum estimated 1-hour exposure to acrolein
outside the facility fence line for the source categories is 0.005 mg/
m\3\. This estimated worst-case exposure exceeds the 1-hour REL by a
factor of 2 (HQREL=2) and is below the 1-hour AEGL-1
(HQAEGL-1=0.1) and the ERPG-1 (HQERPG-1=0.04).
The worst-case maximum estimated 1-hour exposure to nickel
compounds outside the facility fence line for the source categories is
0.001 mg/m\3\. This estimated worst-case exposure exceeds the 1-hour
REL by a factor of 5 (HQREL=5). There are no AEGL, ERPG or
short-term occupational values for nickel to use as comparison to the
acute 1-hour REL value.
The worst-case maximum estimated 1-hour exposure to arsenic
compounds outside the facility fence line for the source categories is
0.0004 mg/m\3\. This estimated worst-case exposure exceeds the 1-hour
REL by a factor of 2 (HQREL=2). There are no AEGL, ERPG or
short-term occupational values for arsenic to use as comparison to the
acute 1-hour REL value.
The maximum estimated 1-hour exposure to benzene outside the
facility fence line is 2.7 mg/m\3\. This estimated exposure exceeds the
REL by a factor of 2 (HQREL=2), but is significantly below
both the 1-hour ERPG-1 and AEGL-1 value (HQ ERPG-1 (or AEGL-1) = 0.02).
This exposure estimate neither exceeds the AEGL-1/ERPG-1 values, nor
does it exceed workplace ceiling level guidelines designed to protect
the worker population for short-duration exposure (less than 15
minutes) to benzene, as discussed below. The occupational short-term
exposure limit (STEL) standard for benzene developed by the
Occupational Safety and Health Administration is 16 mg/m\3\, ``as
averaged over any 15-minute period.'' \33\ Occupational guideline STEL
for exposures to benzene have also been developed by the American
Conference of Governmental Industrial Hygienists (ACGIH) \34\ for less
than 15 minutes \35\ (ACGIH threshold limit value (TLV)-STEL value of
8.0 mg/m\3\), and by the National Institute for Occupational Safety and
Health (NIOSH) \36\ ``for any 15 minute period in a work day'' (NIOSH
REL-STEL of 3.2 mg/m\3\). These shorter duration occupational values
indicate potential concerns regarding health effects at exposure levels
below the 1-hour AEGL-1 value.
---------------------------------------------------------------------------

\33\ 29 CFR 1910.1028, Benzene.
\34\ ACGIH (2001) Benzene. In Documentation of the TLVs[supreg]
and BEIs[supreg] with Other Worldwide Occupational Exposure Values.
ACGIH, 1300 Kemper Meadow Drive, Cincinnati, OH 45240 (ISBN: 978-1-
882417-74-1) and available online at https://www.acgih.org.
\35\ The ACGIH definition of a TLV-STEL states that ``Exposures
above the TLV-TWA up to the TLV-STEL should be less than 15 minutes,
should occur no more than four times per day, and there should be at
least 60 minutes between successive exposures in this range.''
\36\ NIOSH. Occupational Safety and Health Guideline for
Benzene; https://www.cdc.gov/niosh/docs/81-123/pdfs/0049.pdf.
---------------------------------------------------------------------------

All other HAP and facilities modeled had worst-case acute HQ values
less than 1, indicating that the HAP emissions are believed to be
without appreciable risk of acute health effects. In characterizing the
potential for acute non-cancer risks of concern, it is important to
remember the upward bias of these exposure estimates (e.g., worst-case
meteorology coinciding with a person located at the point of maximum
concentration during the hour) and to consider the results along with
the conservative estimates used to develop hourly emissions as
described earlier, as well as the screening methodology. Refer to the
memo in the docket for this rulemaking (Docket ID Number EPA-HQ-OAR-
2010-0682, Derivation of hourly emission rates for petroleum refinery
emission sources used in the acute risk analysis) for a detailed
description of how the hourly emissions were developed for this source
sector.
3. Multipathway Risk Screening Results
Results of the worst-case Tier I screening analysis indicate that
PB-HAP emissions (based on estimates of actual emissions) from several
facilities in this source sector exceed the screening emission rates
for POM (PAH), CDDF, mercury compounds, and cadmium compounds. For the
compounds and facilities that did not screen out at Tier I, we
conducted a Tier II screen. The Tier II screen replaces some of the
assumptions used in Tier I with site-specific data, including the land
use around the facilities, the location of fishable lakes, and local
wind direction and speed. The Tier II screen continues to rely on high-
end assumptions about consumption of local fish and locally grown or
raised foods (adult female angler at 99th consumption for fish \37\ and
90th percentile for consumption of locally grown or raised foods \38\)
and uses an assumption that the same individual consumes each of these
foods in high end quantities (i.e., that an individual has high end
ingestion rates for each food). The result of this analysis was the
development of site-specific emission screening levels for POM, CDDF,
mercury compounds, and cadmium compounds. It is important to note that,
even with the inclusion of some site-specific information in the Tier
II analysis, the multi-pathway screening analysis is a still a very
conservative, health-protective assessment (e.g., upper-bound
consumption of local fish, locally grown, and/or raised foods) and in
all likelihood will yield results that serve as an upper-bound multi-
pathway risk associated with a facility.
---------------------------------------------------------------------------

\37\ Burger, J. 2002. Daily consumption of wild fish and game:
Exposures of high end recreationists. International Journal of
Environmental Health Research 12:343-354.
\38\ U.S. EPA. Exposure Factors Handbook 2011 Edition (Final).
U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-09/
052F, 2011.
---------------------------------------------------------------------------

While the screening analysis is not designed to produce a
quantitative risk result, the factor by which the emissions exceed the
screening value serves as a rough gauge of the ``upper-limit'' risks we
would expect from a facility. Thus, for example, if a facility emitted
a PB-HAP carcinogen at a level 2 times the screening value, we can say
with a high degree of confidence that the actual maximum cancer risks
will be less than

[[Page 36936]]

2-in-1 million. Likewise, if a facility emitted a noncancer PB-HAP at a
level 2 times the screening level, the maximum noncancer risks would
represent a HQ less than 2. The high degree of confidence comes from
the fact that the screens are developed using the very conservative
(health-protective) assumptions that we describe above.
Based on the Tier II screening analysis, one facility emits cadmium
compounds above the Tier II screening level and exceeds that level by
about a factor of 2. Twenty-three facilities emit CDDF as 2,3,7,8-
tetrachlorodibenzo-p-dioxin toxicity equivalent (TEQ) above the Tier II
screening level, and the facility with the highest emissions of dioxins
exceeds the Tier II screening level by about a factor of 40. No
facilities emit mercury compounds above the Tier II screening levels.
Forty-four facilities emit POM as benzo(a)pyrene TEQ above the Tier II
screening level, and the facility with the highest emissions of POM as
benzo(a)pyrene TEQ exceeds its screening level by a factor of 30.
Polychlorinated biphenyls (PCB) are PB-HAP that do not currently
have multi-pathway screening values and so are not evaluated for
potential non-inhalation risks. These HAP, however, are not emitted in
appreciable quantities (0.001 tpy) from refinery operations, and we do
not believe they contribute to multi-pathway risks for this source
category.
Results of the analysis for lead indicate that the maximum annual
off-site ambient lead concentration was only 2 percent of the NAAQS for
lead, and even if the total annual emissions occurred during a 3-month
period, the maximum 3-month rolling average concentrations would still
be less than 8 percent of the NAAQS, indicating that there is no
concern for multi-pathway risks due to lead emissions.
4. Refined Multipathway Case Study
To gain a better understanding of the uncertainty associated with
the multipathway Tier I and II screening analysis, a refined
multipathway case study using the TRIM.Fate model was conducted for a
single petroleum refinery. The site, a refinery in St. John the Baptist
Parish, Louisiana, was selected based upon its close proximity to
nearby lakes and farms as well as having one of the highest potential
multipathway risks for PAH based on the Tier II analysis. The refined
analysis for this facility showed that the Tier II screen for each
pollutant over-predicted the potential risk when compared to the
refined analysis results. For this site, the Tier II screen for mercury
indicated that mercury emissions were 3 times lower than the screening
value, indicating a potential maximum HQ for mercury of 0.3. In the
refined analysis, the potential HQ was 0.04 or about 7 times lower than
that predicted by the Tier II screen. For cadmium emissions, the Tier
II screen for this facility indicated that cadmium emissions were about
20 times lower than the screening value, indicating a potential maximum
HQ for mercury of 0.05. The results of the refined analysis for the
selected site in Louisiana show a maximum cadmium HQ of 0.02 or about 3
times lower than that predicted by the Tier II screen. For PAH
emissions, the site selected for the refined analysis had PAH emissions
20 times the PAH Tier II screening value, indicating a potential cancer
risk of 20-in-1 million. When the more refined analysis was conducted
for this site, the potential cancer risks were estimated to be 2-in-1
million or about 14 times lower than predicted by the Tier II analysis.
Finally, for the facility selected for the refined assessment, the
emissions of CDDF as 2,3,7,8-tetrachlorodibenzo-p-dioxin TEQ are 5
times higher than the dioxin Tier II screening value, indicating a
potential maximum cancer risk of 5-in-1 million. In the refined
assessment, the cancer risk from dioxins was estimated to be 2-in-1
million, about one-third of the estimate from the Tier II screen.
Overall, the refined analysis predicts a potential lifetime cancer
risk of 4-in-1 million to the maximum most exposed individual (MIR).
The non-cancer HQ is predicted to be well below 1 for all target
organs. The chronic inhalation cancer risk assessment estimated
inhalation cancer risk around this same facility to be approximately
10-in-1 million, due in large part to emissions of naphthalene and 2-
methylnaphthalene (both non-persistent, bioaccumulative, and toxic
(PBT) HAP). Thus, although highly unlikely, if around this facility the
person with the highest chronic inhalation cancer risk is also the same
person with the highest individual multipathway cancer risk, then the
combined, worst-case MIR for that facility could theoretically be 10-
in-1 million (risk estimates are expressed as 1 significant figure).
While this refined assessment was performed on only a single
facility, the results of this single refined analysis indicate that if
refined analyses were performed for other sites, the risk estimates
would consistently be lower than those estimated by the Tier II
analysis. In addition, the risks predicted by the multipathway analyses
at most facilities are considerably lower than the risk estimates
predicted by the inhalation assessment, indicating that the inhalation
risk results are in all likelihood the primary factor in our residual
risk determination for this source category.
Further details on the site-specific case study can be found in
Appendix 10 of the Draft Residual Risk Assessment for the Petroleum
Refining Source Sector, which is available in Docket ID Number EPA-HQ-
OAR-2010-0682.
5. Environmental Risk Screening Results
As described in the Draft Residual Risk Assessment for the
Petroleum Refining Source Sector, which is available in Docket ID
Number EPA-HQ-OAR-2010-0682, we conducted an environmental risk
screening assessment for the petroleum refineries source category. In
the Tier I screening analysis for PB-HAP (other than lead, which was
evaluated differently, as noted in section III.A.6 of this preamble),
the individual modeled Tier I concentrations for one facility in the
source category exceeded some of the ecological benchmarks for mercury.
In addition, Tier I modeled concentrations for four facilities exceeded
sediment and soil ecological benchmarks for PAH. Therefore, we
conducted a Tier II assessment.
In the Tier II screening analysis for PB-HAP, none of the
individual modeled concentrations for any facility in the source
category exceeded any of the ecological benchmarks (either the LOAEL or
NOAEL).
For lead compounds, we did not estimate any exceedances of the
secondary lead NAAQS. Therefore, we did not conduct further assessment
for lead compounds.
For acid gases, the average modeled concentration around each
facility (i.e., the average concentration of all off-site data points
in the modeling domain) did not exceed any ecological benchmark. In
addition, for both HCL and HF, each individual concentration (i.e.,
each off-site data point in the modeling domain) was below the
ecological benchmarks for all facilities.
6. Facility-Wide Risk Results
Table 11 of this preamble displays the results of the facility-wide
risk assessment.

[[Page 36937]]

Table 11--Petroleum Refining Facility-Wide Risk Assessment Results
------------------------------------------------------------------------

------------------------------------------------------------------------
Number of facilities analyzed......................... 142
Cancer Risk:
Estimated maximum facility-wide individual cancer 70
risk ([dash]in-1 million)........................
Number of facilities with estimated facility-wide 54
individual cancer risk of 10-in-1 million or more
Number of petroleum refining operations 50
contributing 50 percent or more to facility-wide
individual cancer risk of 10-in-1 million or more
Number of facilities with facility-wide individual 115
cancer risk of 1-in-1 million or more............
Number of petroleum refining operations 107
contributing 50 percent or more to facility-wide
individual cancer risk of 1-in-1 million or more.
Chronic Non-cancer Risk:
Maximum facility-wide chronic non-cancer TOSHI........ 4
Number of facilities with facility-wide maximum 5
non-cancer TOSHI greater than 1..................
Number of petroleum refining operations 0
contributing 50 percent or more to facility-wide
maximum non-cancer TOSHI of 1 or more............
------------------------------------------------------------------------

The maximum individual cancer whole-facility risk from all HAP
emissions at any petroleum refinery is estimated to be 70-in-1 million,
based on actual emissions. Of the 142 facilities included in this
analysis, 54 have facility-wide maximum individual cancer risks of 10-
in-1 million or greater. At the majority of these facilities (50 of
54), the petroleum refinery operations account for over 50 percent of
the risk.
There are 115 facilities with facility-wide maximum individual
cancer risks of 1-in-1 million or greater. At the majority of these
facilities (107 of 115), the petroleum refinery operations account for
over 50 percent of the risk. The facility-wide maximum individual
chronic non-cancer TOSHI is estimated to be 4, based on actual
emissions. Of the 142 refineries included in this analysis, five have a
TOSHI value greater than 1. The highest non-cancer TOSHI results from
emissions of chlorine from cooling towers. In each case, the petroleum
refinery operations account for less than 20 percent of the TOSHI
values greater than 1.
Additional detail regarding the methodology and the results of the
facility-wide analyses are included in the risk assessment
documentation (Draft Residual Risk Assessment for the Petroleum
Refining Source Sector), which is available in the docket for this
rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682).
7. What demographic groups might benefit from this regulation?
To examine the potential for any environmental justice issues that
might be associated with the source categories, we performed a
demographic analysis of the population close to the facilities. In this
analysis, we evaluated the distribution of HAP-related cancer and non-
cancer risks from petroleum refineries across different social,
demographic, and economic groups within the populations living near
facilities identified as having the highest risks. The methodology and
the results of the demographic analyses are included in a technical
report, Draft Risk and Technology Review--Analysis of Socio-Economic
Factors for Populations Living Near Petroleum Refineries, available in
the docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682).
The results of the demographic analysis are summarized in Table 12
of this preamble. These results, for various demographic groups, are
based on the estimated risks from actual emissions levels for the
population living within 50 km of the facilities.

Table 12--Petroleum Refining Demographic Risk Analysis Results
----------------------------------------------------------------------------------------------------------------
Population with
cancer risk at or Population with
Nationwide above 1-in-1 chronic hazard
million index above 1
----------------------------------------------------------------------------------------------------------------
Total Population....................................... 312,861,265 5,204,234 0
----------------------------------------------------------------------------------------------------------------
Race by Percent
----------------------------------------------------------------------------------------------------------------
White.................................................. 72 50 0
All Other Races........................................ 28 50 0
----------------------------------------------------------------------------------------------------------------
Race by Percent
----------------------------------------------------------------------------------------------------------------
White.................................................. 72 50 0
African American....................................... 13 28 0
Native American........................................ 1 1 0
Other and Multiracial.................................. 14 21 0
----------------------------------------------------------------------------------------------------------------
Ethnicity by Percent
----------------------------------------------------------------------------------------------------------------
Hispanic............................................... 17 29 0
Non-Hispanic........................................... 83 71 0
----------------------------------------------------------------------------------------------------------------
Income by Percent
----------------------------------------------------------------------------------------------------------------
Below Poverty Level.................................... 14 21 0
Above Poverty Level.................................... 86 79 0
----------------------------------------------------------------------------------------------------------------

[[Page 36938]]

Education by Percent
----------------------------------------------------------------------------------------------------------------
Over 25 and without High School Diploma................ 15 23 0
Over 25 and with a High School Diploma................. 85 77 0
----------------------------------------------------------------------------------------------------------------

The results of the demographic analysis indicate that emissions
from petroleum refineries expose approximately 5,000,000 people to a
cancer risk at or above 1-in-1 million. Implementation of the
provisions included in this proposal is expected to reduce the number
of people estimated to have a cancer risk greater than 1-in-1 million
due to HAP emissions from these sources from 5,000,000 people to about
4,000,000. Our analysis of the demographics of the population within 50
km of the facilities indicates potential disparities in certain
demographic groups, including the African American, Other and
Multiracial, Hispanic, Below the Poverty Level, and Over 25 without a
High School Diploma. The population living within 50 km of the 142
petroleum refineries has a higher percentage of minority, lower income
and lower education persons when compared to the nationwide percentages
of those groups. For example, 50 percent are in one or more minority
demographic group, compared to 28 percent nationwide. As noted above,
approximately 5,000,000 people currently living within 50 km of a
petroleum refinery have a cancer risk greater than 1-in-1 million. We
would expect that half of those people are in one or more minority
demographic groups.
Because minority groups make up a large portion of the population
living near refineries, as compared with their representation
nationwide, those groups would similarly see a greater benefit from the
implementation of the controls proposed in this rule, if finalized. For
example, we estimate that after implementation of the controls proposed
in this action (i.e., post-controls), about 1,000,000 fewer people will
be exposed to cancer risks greater than 1-in-1 million (i.e., 4,000,000
people). Further, we estimate that approximately 500,000 people no
longer exposed to a cancer risk greater than 1-in-1 million would be in
a minority demographic group. The post-control risk estimates are
discussed further in section III.A.5 of this preamble.
Although the EPA's proposed fenceline monitoring requirement is
intended to ensure that owners and operators monitor, manage and, if
necessary, reduce fugitive emissions of HAP, we also expect the
collected fenceline data to help the EPA understand and identify
emissions of benzene and other fugitive emissions that are impacting
communities in close proximity to the facility. While currently-
available emissions and monitoring data do not indicate that risks to
nearby populations are unacceptable (see section IV.D.1 of this
preamble), we recognize that the collection of additional data through
routine fenceline monitoring can provide important information to
communities concerned with potential risks associated with emissions
from fugitive sources. We note that the data we are proposing to
collect on a semiannual basis may include exceedances of the fenceline
action level that a facility could have addressed or could still be
actively addressing at the time of the report. As noted in section
IV.B.1.h of this preamble, directly monitoring fugitive emissions from
each potential emissions source at the facility is impractical.
Fenceline monitoring offers a cost-effective alternative for monitoring
fugitive emissions from the entire facility. The EPA's proposal to
require the electronic reporting of fenceline monitoring data on a
semiannual basis will ensure that communities have access to data on
benzene levels near the facility, which is directly relevant to the
potential health risks posed by the facility. The proposed requirements
for fenceline monitoring and corrective action when fugitive emissions
from a facility exceed the specified corrective action level will serve
as an important backstop to protect the health of the populations
surrounding the facility, including minority and low-income
populations.

D. What are our proposed decisions regarding risk acceptability, ample
margin of safety and adverse environmental effects?

1. Risk Acceptability
As noted in section II.A.1 of this preamble, the EPA sets standards
under CAA section 112(f)(2) using ``a two-step standard-setting
approach, with an analytical first step to determine an `acceptable
risk' that considers all health information, including risk estimation
uncertainty, and includes a presumptive limit on maximum individual
lifetime risk (MIR) of approximately 1 in 10 thousand.\[39]\ '' (54 FR
38045, September 14, 1989).
---------------------------------------------------------------------------

\39\ 1-in-10 thousand is equivalent to 100-in-1 million. The EPA
currently describes cancer risks as `n-in-1 million'.
---------------------------------------------------------------------------

In this proposal, we estimate risks based on actual emissions from
petroleum refineries. We also estimate risks from allowable emissions;
as discussed earlier, we consider our analysis of risk from allowable
emissions to be conservative and as such to represent an upper bound
estimate on risk from emissions allowed under the current MACT
standards for the source categories.
a. Estimated Risks From Actual Emissions
The baseline inhalation cancer risk to the individual most exposed
to emissions from sources regulated by Refinery MACT 1 and 2 is 60-in-1
million based on actual emissions. The estimated incidence of cancer
due to inhalation exposures is 0.3 excess cancer cases per year, or 1
case every 3.3 years. Approximately 5,000,000 people face an increased
cancer risk greater than 1-in-1 million due to inhalation exposure to
actual HAP emissions from these source categories, and approximately
100,000 people face an increased risk greater than 10-in-1 million and
up to 60-in-1 million. The agency estimates that the maximum chronic
non-cancer TOSHI from inhalation exposure is 0.9 due to actual
emissions of HCN from FCCU.

[[Page 36939]]

The screening assessment of worst-case acute inhalation impacts
from actual emissions indicates the potential for five pollutants--
nickel, arsenic, acrolein, benzene and acetaldehyde--to exceed an HQ
value of 1, with an estimated worst-case maximum HQ of 5 for nickel
based on the REL values. One hundred thirty-six of the 142 petroleum
refineries had an estimated worst-case HQ less than or equal to 1 for
all HAP. One facility had an estimated worst-case maximum HQ of 5 and
the remaining five refineries with an HQ above 1 had an estimated
worst-case HQ less than or equal to 3. Considering the conservative,
health-protective nature of the approach that is used to develop these
acute estimates, it is highly unlikely that an individual would have an
acute exposure above the REL. Specifically, the analysis is based on
the assumption that worst-case emissions and meteorology would coincide
with a person being at this exact location for a period of time long
enough to have an exposure level above the conservative REL value.
The Tier II multipathway screening analysis of actual emissions
indicated the potential for PAH emissions that are about 30 times the
screening level for cancer, dioxin and furans emissions that are about
40 times the cancer screening level and cadmium emissions that are
about 2 times the screening level for non-cancer health effects. No
facility's emissions were above the screening level for mercury. As we
note above, the Tier II multipathway screen is conservative in that it
incorporates many health-protective assumptions. For example, we choose
inputs from the upper end of the range of possible values for the
influential parameters used in the Tier II screen and we assume that
the exposed individual exhibits ingestion behavior that would lead to a
high total exposure. A Tier II exceedance cannot be equated with a risk
value or a HQ or HI. Rather, it represents a high-end estimate of what
the risk or hazard may be. For example, an exceedance of 2 for a non-
carcinogen can be interpreted to mean that we have high confidence that
the HI would be lower than 2. Similarly, an exceedance of 30 for a
carcinogen means that we have high confidence that the risk is lower
than 30-in-1-million. Our confidence comes from the conservative, or
health-protective, assumptions that are used in the Tier II screen.
The refined analysis that we conducted for a specific facility
showed that the Tier II screen for each pollutant over-predicted the
potential risk when compared to the refined analysis results. That
refined multipathway assessment showed that the Tier II screen resulted
in estimated risks that are higher than the risks estimated by the
refined analysis by 14 times for PAH, 3 times for dioxins and furans,
and 3 times for cadmium. The refined assessment results indicate that
the multipathway risks are considerably lower than the estimated
inhalation risks, and our refined multipathway analysis indicates that
multipathway risks are low enough that, while they are considered in
our proposed decisions, they do not weigh heavily into those decisions
because risks for the source category are driven by inhalation.
b. Estimated Risks From Allowable Emissions
We estimate that the baseline inhalation cancer risk to the
individual most exposed to emissions from sources regulated by Refinery
MACT 1 and 2 is as high as 100-in-1 million based on allowable
emissions. The EPA estimates that the incidence of cancer due to
inhalation exposures could be as high as 0.6 excess cancer cases per
year, or 1 case approximately every 1.5 years. About 7,000,000 people
face an increased cancer risk greater than 1-in-1 million due to
inhalation exposure to allowable HAP emissions from these source
categories, and greater than 90,000 people face an increased risk
greater than 10-in-1 million, and as high as 100-in-1 million. Further,
we estimate that the maximum chronic non-cancer TOSHI from inhalation
exposure values at all refineries is less than 1 based on allowable
emissions.
The baseline risks summarized above do not account for additional
risk reductions that we anticipate due to the MACT standards or the
technology review requirements we are proposing in this action.
c. Acceptability Determination
In determining whether risk is acceptable, the EPA considered all
available health information and risk estimation uncertainty as
described above. As noted above, the agency estimated risk from actual
and allowable emissions. While there are uncertainties associated with
both the actual and allowable emissions, we consider the allowable
emissions to be an upper bound, based on the conservative methods we
used to calculate allowable emissions.
The results indicate that both the actual and 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. The MIR based on actual emissions is 60-in-1 million,
approximately 60 percent of the presumptive limit. Based on the results
of the refined site-specific multipathway analysis summarized above and
described in section IV.C.3 of this preamble, we also conclude that the
ingestion cancer risk to the individual most exposed is significantly
less than 100-in-1 million. In addition, the maximum chronic non-cancer
TOSHI due to inhalation exposures is less than 1, and our refined
multipathway analysis indicates that non-cancer ingestion risks are
estimated to be less than non-cancer risk from inhalation. Finally, the
evaluation of acute non-cancer risks was very conservative, and showed
acute risks below a level of concern.
In determining risk acceptability, we also evaluated population
impacts because of the large number of people living near facilities in
the source category. The analysis indicates that there are
approximately 5 million people exposed to actual emissions resulting in
a cancer risk greater than 1-in-1 million, and a substantially smaller
number of people (100,000) are exposed to a cancer risk of greater than
10-in-1 million but less than 100-in-1 million (with a maximum risk of
60-in-1 million). The inhalation cancer incidence is approximately one
case in every 3 years based on actual emissions. More detail on this
risk analysis is presented in section IV.C and summarized in Tables 10
and 11 of this preamble. The results of the demographic analysis for
petroleum refineries indicate that a greater proportion of certain
minority groups and low-income populations live near refineries than
the national demographic profile. More detail on these population
impacts is presented in section IV.C.7 of this preamble. We did not
identify any sensitivity to pollutants emitted from these source
categories particular to minority and low income populations.
Considering the above information, we propose that the risks remaining
after implementation of the existing NESHAP for the Refinery MACT 1 and
2 source categories is acceptable.
We also note that the estimated baseline risks for the refineries
source categories include risks from emissions from DCU, which are a
previously unregulated emission source. As discussed in section IV.A.
of this preamble, we are proposing new MACT standards for these sources
that would reduce emissions of HAP by 850 tpy. We estimate that these
new standards would not affect the MIR, but would

[[Page 36940]]

reduce the source category cancer incidence by 15 percent.
We solicit comment on all aspects of our proposed acceptability
determination. We note that while we are proposing that the risks
estimated from actual and allowable emissions are acceptable, the risks
based on allowable emissions are at the presumptive limit of acceptable
risk. Furthermore, a significant number of people live in relative
proximity to refineries across the country, and therefore a large
population is exposed to risks greater than 1-in-1 million. In
particular, we solicit comment on the methodology used to estimate
allowable emissions. As noted above, we consider the allowable
emissions to be an upper bound estimate based on the conservative
methods used to calculate such emissions. We recognize, however, that
some of the health information concerning allowable emissions arguably
borders on the edge of acceptability. Specifically, the analysis of
allowable emissions resulted in a MIR of 100-in-1 million, which is the
presumptive limit of acceptability, a large number of people
(7,000,000) estimated to be exposed at a cancer risk above 1-in-1
million, and an estimated high cancer incidence (one case approximately
every 1.5 years). Although we believe that our allowable emissions
represent an upper end estimate, we nonetheless solicit comment on
whether the health information currently before the Agency should be
deemed unacceptable. We also solicit comment on whether our allowable
emissions analysis reflects a reasonable estimate of emissions allowed
under the current MACT standards. Lastly, we solicit comment on the
acceptability of risk considering individuals' potential cumulative
inhalation and ingestion pathway exposure. Please provide comments and
data supporting your position. Such information will aid the Agency to
make an informed decision on risk acceptability as it moves forward
with this rulemaking.
2. Ample Margin of Safety
We next considered whether the existing MACT standards provide an
ample margin of safety to protect public health. In addition to
considering all of the health risks and other health information
considered in the risk acceptability determination, in the ample margin
of safety analysis we evaluated the cost and feasibility of available
control technologies and other measures that could be applied in these
source categories to further reduce the risks due to emissions of HAP.
For purposes of the ample margin of safety analysis, we evaluated the
changes in risk that would occur through adoption of a specific
technology by looking at the changes to the risk due to actual
emissions. Due to the nature of the allowable risk analysis, which is
based on model plants and post processing to combine risk results,\40\
we did not evaluate the risk reductions resulting from reducing
allowable emissions at individual emission sources. Such an approach
would require an unnecessarily complex analysis that would not provide
any more useful information than the analysis we undertook using actual
emissions. We note that while we did not conduct a specific analysis
for allowable emissions, it is reasonable to expect reductions in risk
similar to those for actual emissions.
---------------------------------------------------------------------------

\40\ As described in the memorandum entitled Refinery Emissions
and Risk Estimates for Modeled ``Allowable'' Emissions, available in
Docket EPA-HQ-OAR-2010-0682, the use of model plants and post-
processing was for the purpose of ensuring that our analysis would
provide a conservative estimate of actual emissions and thus a
conservative estimate of risk.
---------------------------------------------------------------------------

As noted in our discussion of the technology review in section IV.B
of this preamble, we identified a number of developments in practices,
processes or control technologies for reducing HAP emissions from
petroleum refinery processes. As part of the risk review, we evaluated
these developments to determine if any of them could reduce risks and
whether it is necessary to require any of these developments to provide
an ample margin of safety to protect public health.
We evaluated the health information and control options for all of
the emission sources located at refineries, including: Storage vessels,
equipment leaks, gasoline loading racks, marine vessel loading
operations, cooling towers/heat exchange systems, wastewater collection
and treatment, FCCU, flares, miscellaneous process vents, CRU and SRU.
For each of these sources, we considered chronic cancer and non-cancer
risk metrics as well as acute risk. Regarding our ample margin of
safety analyses for chronic non-cancer risk for the various emission
sources, we note that the baseline TOSHIs are less than 1 for the
entire source category and considerably less than 1 for all of the
emission sources except for the FCCU (which had an TOSHI of 0.9).
Therefore, we did not quantitatively evaluate reductions in the chronic
non-cancer TOSHI for sources other than FCCU in the ample margin of
safety analysis. Regarding our ample margin of safety analyses for
acute risk for all of the various emission sources, we note that our
analyses did not identify acute risks at a level of concern and,
therefore, we did not quantitatively evaluate reductions in the acute
HQ values for each individual emission source in the ample margin of
safety analysis. Accordingly, the following paragraphs focus on cancer
risk in the determination of whether the standards provide an ample
margin of safety to protect public health.
For storage vessels, as discussed in section IV.B of this preamble,
we identified and evaluated three control options. Under the technology
review, we determined that two of the options, which we call options 1
and 2, are cost effective. We are proposing option 2, which includes
all of the requirements of option 1, as part of the technology review.
The option 2 controls that we are proposing under the technology review
would result in approximately 910 tpy reduction in HAP (a 40-percent
reduction from this emission source). As described in section IV.B of
this preamble, not only are these controls cost effective, but we
estimate a net cost savings because the emission reductions translate
into reduced product loss. These controls would reduce the cancer risk
to the individual most exposed from 60-in-1 million to 50-in-1 million
based on actual emissions at the facility where storage tank emissions
were driving the risk. However, the MIR remains unchanged for the
refinery source categories, at 60-in 1-million, because the facility
with the next highest cancer risk is 60-in-1 million and this risk is
driven by another emission source. The option 2 controls also would
reduce cancer incidence by approximately 2 percent. Finally, we
estimate that the option 2 controls reduce the number of people with a
cancer risk greater than 10-in-1 million storage tanks from 3,000 to 60
and reduce the number of people with a cancer risk greater than 1-in-1
million from storage tanks from 140,000 to 72,000. Since these controls
reduce cancer incidence, and reduce the number of people exposed to
cancer risks greater than 1-in-10 million and 1-in-1 million from
storage tank emissions, and are cost effective, we propose that these
controls are necessary to provide an ample margin of safety to protect
public health. We also evaluated one additional control option for
storage vessels, option 3, which incorporated both options 1 and 2
along with additional monitoring requirements. We estimate incremental
HAP emission reductions (beyond those provided by option 2) of 90 tpy.
The

[[Page 36941]]

incremental cost effectiveness for option 3 exceeds $60,000 per ton,
which we do not consider cost effective. In addition, the option 3
controls do not result in quantifiable reductions in the cancer risk to
the individual most exposed or the cancer incidence beyond the
reductions estimated for the option 2 controls. For these reasons, we
propose that it is not necessary to require the option 3 controls in
order to provide an ample margin of safety to protect public health.
For equipment leaks, we identified and evaluated three control
options discussed previously in the technology review section of this
preamble (section IV.B). These options are:
Option 1--monitoring and repair at lower leak definitions;
Option 2--applying monitoring and repair requirements to
connectors; and
Option 3--optical gas imaging and repair.
We estimate that these three independent control options reduce
industry-wide emissions of organic HAP by 24 tpy, 86 tpy, and 24 tpy,
respectively. We estimate that none of the control options would reduce
the risk to the individual most exposed. We also estimate that the
cancer incidence would not change perceptively if these controls were
required. Finally, we estimate that the control options do not reduce
the number of people with a cancer risk greater than 10-in-1 million or
the number of people with a cancer risk greater than 1-in-1 million. As
discussed above, the available control options for equipment leaks do
not provide quantifiable risk reductions and, therefore, we propose
that these controls are not necessary to provide an ample margin of
safety.
For gasoline loading racks, we identified and evaluated one control
option discussed previously in the technology review section of this
preamble (section IV.B). As discussed earlier, this option is a new
development that results in emissions that are higher than the current
level required under Refinery MACT 1. Since we estimate that no
emission reductions would result from this new technology and thus no
reduction in risk, we propose that this control option is not necessary
to provide an ample margin of safety.
For marine vessel loading operations, we identified and evaluated
two control options discussed previously in the technology review
section of this preamble (section IV.B). The first option would be to
require submerged fill for small and offshore marine vessel loading
operations. Based on actual emissions, we project no HAP emission
reductions for this option, as all marine vessels that are used to
transport bulk refinery liquids are expected to already have the
required submerged fill pipes. Accordingly, we do not project any
changes in risk. While we are proposing this option under the
technology review, because the option is not projected to reduce
emissions or risk, we propose that a submerged loading requirement is
not necessary to provide an ample margin of safety. We also identified
and evaluated the use of add-on controls for gasoline loading at small
marine vessel loading operations. In the technology review, we rejected
this control option because the cost effectiveness exceeded $70,000 ton
of HAP reduced. We estimate that this option would not result in
quantifiable changes to any of the risk metrics. Because add-on
controls would not result in quantifiable risk reductions and we do not
consider the controls to be cost effective, we are proposing that add-
on controls for gasoline loading at small marine vessel loading
operations are not necessary to provide an ample margin of safety.
For cooling towers and heat exchangers, we did not identify as part
of our technology review any developments in processes, practices or
controls beyond those that we considered in our beyond-the-floor
analysis at the time we set the MACT standards. We note that we issued
MACT standards for heat exchange systems in a final rule on October 28,
2009 (74 FR 55686), but existing sources were not required to comply
until October 29, 2012. As a result, the reductions were not reflected
in the inventories submitted in response to the ICR for refineries and
therefore were not included in our risk analysis based on actual
emissions. We estimate that these MACT standards will result in an
industry-wide reduction of over 600 tons HAP per year (or 85 percent).
The projected contribution to risk associated with cooling tower
emissions after implementation of these MACT standards for heat
exchange systems is approximately 1 percent. Because we did not
identify any control options beyond those required by the current
standards for cooling towers and heat exchange systems, we are
proposing that additional controls for these systems are not necessary
to provide an ample margin of safety.
For wastewater collection and treatment systems, we identified and
evaluated three options for reducing emissions. We estimate
implementing these independent control options would result in emission
reductions of 158 tpy (4 percent), 549 tpy (15 percent), and 929 tpy
(25 percent), respectively. None of the control options would reduce
the cancer risk to the individual most exposed from 60-in-1 million.
Option 1 would reduce the cancer incidence by less than 1 percent, and
we expect any reduction in cancer incidence that would result from
options 2 or 3 to be small because this source accounts for about 10
percent of the cancer incidence from refineries as a whole and the most
stringent control option would reduce emissions from these source by
only 25 percent. Finally, we estimate that control option 1 would not
reduce the number of people with a cancer risk greater than 10-in-1
million or the number of people with a cancer risk greater than 1-in-1
million. We expect any changes to the number of people with a cancer
risk greater than 1-in-1 million from implementation of options 2 or 3
to be small for the same reasons mentioned above for cancer incidence.
We estimate the cost effectiveness of these options to be $26,600 per
ton, $52,100 per ton, and $54,500 per ton of organic HAP reduced, and
we do not consider any of these options to be cost effective. Because
of the very small reductions in risk and the lack of cost-effective
control options, we propose that these controls are not necessary to
provide an ample margin of safety.
For FCCU, we did not identify any developments in processes,
practices or control technologies for organic HAP. For inorganic HAP
from FCCU, in the technology review, we identified and evaluated one
control option for an HCN emissions limit and one control option for a
PM emissions limit. The PM limit was adopted for new sources in
Refinery NSPS Ja as part of our review of Refinery NSPS J. We
considered the costs and emission reductions associated with requiring
existing sources to meet the new source level for PM under Refinery
NSPS Ja (i.e., 0.5 g PM/kg of coke burn-off rather than 1.0 g PM/kg).
As indicated in our promulgation of Refinery NSPS Ja, the cost
effectiveness of lowering the PM limit for existing sources to the
level we are requiring for new sources was projected to be $21,000 per
ton of PM reduced (see 73 FR 35845, June 24, 2008). Based on the
typical metal HAP concentration in PM from FCCU, the cost effectiveness
of this option for HAP metals is approximately $1 million per ton of
HAP reduced. We estimate that this control option would not reduce the
cancer risk to the individual most exposed, would not change the cancer
incidence, and would not change the number of people with estimated
cancer

[[Page 36942]]

risk greater than 1-in-1 million or 10-in-1 million. For the HCN
emissions limit, we evaluated the costs of controlling HCN using
combustion controls in combination with SCR. The cost effectiveness of
this option was approximately $9,000 per ton of HCN. This control
option would reduce the non-cancer HI from 0.9 to 0.8 and would not
change any of the cancer risk metrics. Based on the cost effectiveness
of these options and the limited reduction in cancer and non-cancer
risk (the non-cancer risk is below a level of concern based on the
existing standards), we propose that additional controls for FCCU are
not necessary to provide an ample margin of safety.
Flares are used as APCD to control emissions from several emission
sources covered by Refinery MACT 1 and 2. In this proposed rule, under
CAA sections 112(d)(2) and (3), we are proposing operating and
monitoring requirements to ensure flares achieve the 98-percent HAP
destruction efficiency identified as the MACT Floor in the initial MACT
rulemaking in 1995. Flares are critical safety devices that effectively
reduce emissions during startup, shutdown, and process upsets or
malfunctions. In most cases, flares are the only means by which
emissions from pressure relief devices can be controlled. Thus, we find
that properly-functioning flares act to reduce HAP emissions, and
thereby risk, from petroleum refinery operations. The changes to the
flare requirements that we are proposing under CAA sections 112(d)(2)
and (3) will result in sources meeting the level required by the
original standards, and we did not identify any control options that
would further reduce the HAP emissions from flares. Therefore, we are
proposing that additional controls for flares are not necessary to
provide an ample margin of safety.
For the remaining emission sources within the Refinery MACT 1 and
Refinery MACT 2 source categories, including miscellaneous process
vents, CRU, and SRU, we did not identify any developments in processes
practices and control technologies. Therefore, we are proposing that
additional controls for these three Refinery MACT 1 and 2 emission
sources are not necessary to provide an ample margin of safety.
In summary, we propose that the original Refinery MACT 1 and 2 MACT
standards, along with the proposed requirements for storage vessels
described above, provide an ample margin of safety to protect public
health. We are specifically requesting comment on whether there are
additional control measures for emission sources subject to Refinery
MACT 1 and Refinery MACT 2 that are necessary to provide an ample
margin of safety to protect public health. In particular, we are
requesting that states identify any controls they have already required
for these facilities, controls they are currently considering, or other
controls of which they may be aware.
While not part of our decisions regarding residual risk, we note
that DCU are an important emission source with respect to risk from
refineries. As described in section IV.A of this preamble, we are
proposing new MACT standards under CAA sections 112(d)(2) and (3) for
DCU. For informational purposes, we also looked at the risk reductions
that would result from implementation of those standards. We estimate
no reduction in the cancer risk to the individual most exposed and a
decrease in cancer incidence of 0.05 cases per year, or approximately
15 percent. While our decisions on risk acceptability and ample margin
of safety are supported even in the absence of these reductions, if we
finalize the proposed requirements for DCU, they would further
strengthen our conclusions that the standards provide an ample margin
of safety to protect public health.
3. Adverse Environmental Effects
We conducted an environmental risk screening assessment for the
petroleum refineries source category for lead, mercury, cadmium, PAH,
dioxins and furans, HF, and HCl. For mercury, cadmium, PAH, and dioxins
and furans, none of the individual modeled concentrations for any
facility in the source category exceeded any of the Tier II ecological
benchmarks (either the LOAEL or NOAEL). For lead, we did not estimate
any exceedances of the secondary lead NAAQS. For HF and HCl, the
average modeled concentration around each facility (i.e., the average
concentration of all off-site data points in the modeling domain) did
not exceed any ecological benchmark. Based on these results, EPA
proposes 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.

E. What other actions are we proposing?

We are proposing the following changes to Refinery MACT 1 and 2 as
described below: (1) Revising the SSM provisions in order to ensure
that the subparts are consistent with the court decision in Sierra Club
v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), which vacated two provisions
that exempted sources from the requirement to comply with otherwise
applicable section 112(d) emission standards during periods of SSM; (2)
proposing to clarify requirements related to open-ended valves or
lines; (3) adding electronic reporting requirements in Refinery MACT 1
and 2; and (4) updating the General Provisions cross-reference tables.
1. SSM
In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C.
Cir. 2008), the United States Court of Appeals for the District of
Columbia Circuit vacated portions of two provisions in the EPA's CAA
section 112 regulations governing the emissions of HAP during periods
of SSM. Specifically, the Court vacated the SSM exemption contained in
40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that under section
302(k) of the CAA, emissions standards or limitations must be
continuous in nature and that the SSM exemption violates the CAA's
requirement that some section 112 standards apply continuously.
We are proposing the elimination of the SSM exemption in 40 CFR
part 63, subparts CC and UUU. Consistent with Sierra Club v. EPA, we
are proposing standards in these rules that apply at all times. We are
also proposing 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) as explained in more
detail below. For example, we are proposing to eliminate the
incorporation of the General Provisions' requirement that the source
develop an SSM plan. We also are proposing to eliminate and revise
certain recordkeeping and reporting requirements related to the SSM
exemption as further described below.
The EPA has attempted to ensure that the provisions we are
proposing to eliminate are inappropriate, unnecessary, or redundant in
the absence of the SSM exemption. We are specifically seeking comment
on whether we have successfully done so.
In proposing the standards in this rule, the EPA has taken into
account startup and shutdown periods and, for the reasons explained
below, we are proposing alternate standards for those periods for a few
select emission sources. We expect facilities can meet nearly all of
the emission standards in Refinery MACT 1 and 2 during startup and
shutdown, including the amendments we are proposing in this action. For
most of the emission sources, APCD are operating prior to process
startup and continue to operate through process shutdown.

[[Page 36943]]

For Refinery MACT 1 and 2, we identified three emission sources for
which specific startup and shutdown provisions may be needed. First, as
noted above, most APCD used to control metal HAP emissions from FCCU
under Refinery MACT 2 (e.g., wet scrubber, fabric filter, cyclone)
would be operating before emissions are routed to them and would be
operating during startup and shutdown events in a manner consistent
with normal operating periods, such that the monitoring parameter
operating limits set during the performance test are maintained and
met. However, we recognize that there are safety concerns associated
with operating an ESP during startup of the FCCU, as described in the
following paragraphs. Therefore, we are proposing specific PM standards
for startup of FCCU controlled with an ESP under Refinery MACT 2.
During startup of the FCCU, ``torch oil'' (heavy oil typically used
as feed to the unit via the riser) is injected directly into the
regenerator and burned to raise the temperature of the regenerator and
catalyst to levels needed for normal operation. Given the poor mixing
of fuel and air in the regenerator during this initial startup, it is
difficult to maintain optimal combustion characteristics, and high CO
concentrations are common. Elevated CO levels pose an explosion threat
due to the high electric current and potential for sparks within the
ESP. Consequently, it is common practice to bypass the ESP during
startup of the FCCU. Once torch oil is shut off and the regenerator is
fueled by catalyst coke burn-off, the CO levels in the FCCU regenerator
off-gas will stabilize and the gas can be sent to the ESP safely.
When the ESP is offline, the operating limits for the ESP are
meaningless. During much of the startup process, either catalyst is not
circulating between the FCCU regenerator and reactor or the catalyst
circulation rate is much lower than during normal operations. While the
catalyst is not circulating or is circulating at reduced rates, the PM
and metal HAP emissions are expected to be much lower than during
normal operations. Therefore, the cyclone separators that are internal
to the FCCU regenerator should provide reasonable PM control during
this initial startup. To ensure the internal cyclones are operating
efficiently, we are proposing that FCCU using an ESP as the APCD meet a
30-percent opacity limit (on a 6-minute rolling average basis) during
the period that torch oil is used during FCCU startup. This opacity
limit was selected because it has been used historically to assess
compliance with the PM emission limit for FCCU in Refinery NSPS J and
because the emission limit can be assessed using manual opacity
readings, eliminating the need to install a COMS. We note that Refinery
NSPS J includes the exception for one 6-minute average of up to 60-
percent opacity in a 1-hour period primarily to accommodate soot
blowing events. As no soot blowing should be performed prior to the ESP
coming on-line, we are not including this exception to the proposed 30-
percent opacity limit during startup for FCCU that are controlled by an
ESP.
Second, for emissions of organic HAP from FCCU under Refinery MACT
2, we also expect that APCD would be operating before emissions are
routed to them, and would be operating during startup and shutdown
events in a manner consistent with normal operating periods, such that
the monitoring parameter operating limits set during the performance
test are maintained and met. However, many FCCU operate in ``complete
combustion'' mode without a post-combustion device. In other words, for
FCCU without a post-combustion device, organic HAP are controlled by
the FCCU itself, so there is no separate APCD that could be operating
during startup and demonstrating continuous compliance with the
monitoring parameter operating limits. Therefore, we are proposing
specific CO standards for startup of FCCU without a post-combustion
device under Refinery MACT 2.
As mentioned previously, ``torch oil'' is injected directly into
the regenerator and burned during FCCU startup to raise the temperature
of the regenerator and catalyst to levels needed for normal operation.
During this period, CO concentrations often will exceed the 500 ppm
emissions limit due to the poor mixing of fuel and air in the
regenerator. The emissions limit is based on CO emissions, as a
surrogate for organic HAP emissions, and the emission limit is
evaluated using a 1-hour averaging period. This 1-hour averaging period
does not provide adequate time for short-term excursions that occur
during startup to be offset by lower emissions during normal
operational periods.
Based on available data during normal operations, ensuring adequate
combustion (indicated by CO concentration levels below 500 ppmv)
minimizes organic HAP emissions. Low levels of CO in the exhaust gas
are consistently achieved during normal operations when oxygen
concentrations in the exhaust gas exceed 1-percent by volume (dry
basis). Thus, maintaining an adequate level of excess oxygen for the
combustion of fuel in the FCCU is expected to minimize organic HAP
emissions. Emissions of CO during startup result from a series of
reactions with the fuel source and are dependent on mixing, local
oxygen concentrations, and temperature. While the refinery owner or
operator has direct control over air blast rates, CO emissions may not
always directly correlate with the air blast rate. Exhaust oxygen
concentrations are expected to be more directly linked with air blast
rates and are, therefore, more directly under control of the refinery
owner or operator. We are proposing an excess oxygen concentration of 1
volume percent (dry basis) based on a 1-hour average during startup. We
consider the 1-hour averaging period for the oxygen concentration in
the exhaust gas from the FCCU to be appropriate during periods of FCCU
startup because air blast rates can be directly controlled to ensure
adequate oxygen supply on a short-term basis.
Third, we note that the SRU is unique in that it essentially is the
APCD for the fuel gas system at the facility. The SRU would be
operating if the refinery is operating, including during startup and
shutdown events. There are typically multiple SRU trains at a facility.
Different trains can be taken off-line as sour gas production decreases
to maintain optimal operating characteristics of the operating SRU
during startup or shutdown of a set of process units. Thus, the sulfur
recovery plant is expected to run continuously and would only shut down
its operation during a complete turnaround or shutdown of the facility.
For these limited situations, the 12-hour averaging time provided for
the SRU emissions limitation under Refinery MACT 2 may not be adequate
time in which to shut down the unit without exceeding the emissions
limitation. Therefore, we are proposing specific standards for SRU
during periods of shutdown.
We note also that, for SRU subject to Refinery NSPS J or electing
to comply with Refinery NSPS J as provided in Refinery MACT 2, the
emissions limit is in terms of SO2 concentration for SRU
with oxidative control systems or reductive control systems followed by
an incinerator. While the SO2 concentration limit provides a
reasonable proxy of the reduced sulfur HAP emissions during normal
operations, it does not necessarily provide a good indication of
reduced sulfur HAP emissions during periods of shutdown. During periods
of shutdown, the sulfur remaining in the unit is purged and combusted
generally in a thermal oxidizer or a flare. Although the sulfur loading
to the thermal oxidizer

[[Page 36944]]

during shutdown may be higher than during normal operations (thereby
causing an increase in the SO2 concentration and exceedance
of the SO2 emissions limitation), appropriate operation of
the thermal oxidizer will adequately control emissions of reduced
sulfur HAP. Thus, during periods of shutdown, the 300 ppmv reduced
sulfur compound emission limit alternative (provided for SRU not
subject to Refinery NSPS J) is a better indicator of reduced sulfur HAP
emissions. In Refinery MACT 2, SRU that elect to comply with the 300
ppmv reduced sulfur compound emission limit (i.e., those not subject to
Refinery NSPS J or electing to comply with Refinery NSPS J) and that
use a thermal incinerator for sulfur HAP control are required to
maintain a minimum temperature and excess oxygen level (as determined
through a source test of the unit) to demonstrate compliance with the
reduced sulfur compound emission limitation.
In Refinery MACT 2, SRU subject to Refinery NSPS J (or that elect
to comply with Refinery NSPS J) that use an incinerator to control
sulfur HAP emissions are required to install an SO2 CEMS to
demonstrate compliance with the SO2 emission limitation. For
these units, it is impractical to require installation of a reduced
sulfur compound monitor or to require a source test to establish
operating parameters during shutdown of the SRU because of the few
hours per year that the entire series of SRU trains are shutdown.
Although the autoignition temperature of COS is unknown, based on the
autoignition temperature of CS2 (between 200 and 250 [deg]F)
and the typical operating characteristics of thermal oxidizers used to
control emissions from SRU, we are proposing that, for periods of SRU
shutdown, diverting the 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 1200 [deg]F and a minimum outlet oxygen
concentration of 2 volume percent (dry basis). We believe that this
provides adequate assurance of compliance with the 300 ppmv reduced
sulfur compound emission limitation for SRU because incineration at
these temperatures was determined to be the MACT floor in cases where
no tail gas treatment units were used (i.e., units not subject to
Refinery NSPS J).
For all other emission sources, we believe that the requirements
that apply during normal operations should apply during startup and
shutdown. For Refinery MACT 1, these emission sources include process
vents, transfer operations, storage tanks, equipment leaks, heat
exchange systems, and wastewater. Emission reductions for process vents
and transfer operations, such as gasoline loading racks and marine tank
vessel loading, are typically achieved by routing vapors to thermal
oxidizers, carbon adsorbers, absorbers and flares. It is common
practice to start an APCD prior to startup of the emissions source it
is controlling, so the APCD would be operating before emissions are
routed to it. We expect APCD would be operating during startup and
shutdown events in a manner consistent with normal operating periods,
and that these APCD will be operated to maintain and meet the
monitoring parameter operating limits set during the performance test.
We do not expect startup and shutdown events to affect emissions from
equipment leaks, heat exchange systems, wastewater, or storage tanks.
Leak detection programs associated with equipment leaks and heat
exchange systems are in place to detect leaks, and, therefore, it is
inconsequential whether the process is operating under normal operating
conditions or is in startup or shutdown. Wastewater emissions are also
not expected to be significantly affected by startup or shutdown events
because the control systems used can operate while the wastewater
treatment system is in startup or shutdown. Working and breathing
losses from storage tanks are the same regardless of whether the
process is operating under normal operating conditions or if it is in a
startup or shutdown event. Degassing of a storage tank is common for
shutdown of a process; the residual emissions in a storage tank are
vented as part of the cleaning of the storage tank. We evaluated
degassing controls as a control alternative for storage vessels and do
not consider these controls to be cost effective (see memorandum Survey
of Control Technology for Storage Vessels and Analysis of Impacts for
Storage Vessel Control Options, Docket Item Number EPA-HQ-OAR-2010-
0871-0027). Based on this review, we are not proposing specific
standards for storage vessels during startup or shutdown.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. However, by
contrast, malfunction is defined as a sudden, infrequent, and not
reasonably preventable failure of air pollution control and monitoring
equipment, process equipment or a process to operate in a normal or
usual manner (see 40 CFR 63.2). The EPA has determined that CAA section
112 does not require that emissions that occur during periods of
malfunction be factored into development of section 112 standards.
Under section 112, emissions standards for new sources must be no less
stringent than the level ``achieved'' by the best-controlled similar
source and for existing sources generally must be no less stringent
than the average emission limitation ``achieved'' by the best-
performing 12 percent of sources in the category. There is nothing in
section 112 that directs the EPA to consider malfunctions in
determining the level ``achieved'' by the best-performing sources when
setting emission standards. As the D.C. Circuit has recognized, the
phrase ``average emissions limitation achieved by the best performing
12 percent of'' sources ``says nothing about how the performance of the
best units is to be calculated.'' Nat'l Ass'n of Clean Water Agencies
v. EPA, 734 F.3d 1115, 1141 (D.C. Cir. 2013). While the EPA accounts
for variability in setting emissions standards, nothing in section 112
requires the EPA to consider malfunctions as part of that analysis. A
malfunction should not be treated in the same manner as the type of
variation in performance that occurs during routine operations of a
source. A malfunction is a failure of the source to perform in a
``normal or usual manner'' and no statutory language compels EPA to
consider such events in setting standards based on ``best performers.''
Further, accounting for malfunctions in setting emissions standards
would be difficult, if not impossible, given the myriad different types
of malfunctions that can occur across all sources in the category, and
given the difficulties associated with predicting or accounting for the
frequency, degree, and duration of various malfunctions that might
occur. As such, the performance of units that are malfunctioning is not
``reasonably'' foreseeable. See, e.g., Sierra Club v. EPA, 167 F. 3d
658, 662 (D.C. Cir. 1999) (the EPA typically has wide latitude in
determining the extent of data-gathering necessary to solve a problem.
We generally defer to an agency's decision to proceed on the basis of
imperfect scientific information, rather than to ``invest the resources
to conduct the perfect study.''). See also, Weyerhaeuser v. Costle, 590
F.2d 1011, 1058 (D.C. Cir. 1978) (``In the nature of things, no general
limit, individual permit, or even any upset provision can anticipate
all upset situations. After a certain point, the transgression of
regulatory limits caused by

[[Page 36945]]

`uncontrollable acts of third parties,' such as strikes, sabotage,
operator intoxication or insanity, and a variety of other
eventualities, must be a matter for the administrative exercise of
case-by-case enforcement discretion, not for specification in advance
by regulation.''). In addition, emissions during a malfunction event
can be significantly higher than emissions at any other time of source
operation, and thus, accounting for malfunctions in setting standards
could lead to standards that are significantly less stringent than
levels that are achieved by a well-performing non-malfunctioning
source. It is reasonable to interpret section 112 to avoid such a
result. The EPA's approach to malfunctions is consistent with CAA
section 112 and is a reasonable interpretation of the statute.
In the event that a source fails to comply with the applicable CAA
section 112(d) standards as a result of a malfunction event, the EPA
would determine an appropriate response based on, among other things,
the good-faith efforts of the source to minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as root cause analyses to ascertain and rectify excess emissions.
The EPA would also consider whether the source's failure to comply with
the CAA section 112(d) standard was, in fact, sudden, infrequent, not
reasonably preventable and was not instead caused in part by poor
maintenance or careless operation, as described in the definition of
malfunction (see 40 CFR 63.2). Further, to the extent the EPA files an
enforcement action against a source for violation of an emission
standard, the source can raise any and all defenses in that enforcement
action and the federal district court will determine what, if any,
relief is appropriate. The same is true for citizen enforcement
actions. Similarly, the presiding officer in an administrative
proceeding can consider any defense raised and determine whether
administrative penalties are appropriate.
In several prior rules, the EPA had included an affirmative defense
to civil penalties for violations caused by malfunctions in an effort
to create a system that incorporates some flexibility, recognizing that
there is a tension, inherent in many types of air regulation, to ensure
adequate compliance while simultaneously recognizing that despite the
most diligent of efforts, emission standards may be violated under
circumstances entirely beyond the control of the source. Although the
EPA recognized that its case-by-case enforcement discretion provides
sufficient flexibility in these circumstances, it included the
affirmative defense to provide a more formalized approach and more
regulatory clarity. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011,
1057-58 (D.C. Cir. 1978) (holding that an informal case-by-case
enforcement discretion approach is adequate); but see Marathon Oil Co.
v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977) (requiring a more
formalized approach to consideration of ``upsets beyond the control of
the permit holder.''). Under the EPA's regulatory affirmative defense
provisions, if a source could demonstrate in a judicial or
administrative proceeding that it had met the requirements of the
affirmative defense in the regulation, civil penalties would not be
assessed. Recently, the United States Court of Appeals for the District
of Columbia Circuit vacated such an affirmative defense in one of the
EPA's section 112(d) regulations. NRDC v. EPA, No. 10-1371 (D.C. Cir.
April 18, 2014) 2014 U.S. App. LEXIS 7281 (vacating affirmative defense
provisions in section 112(d) rule establishing emission standards for
Portland cement kilns). The court found that the EPA lacked authority
to establish an affirmative defense for private civil suits and held
that under the CAA, the authority to determine civil penalty amounts
lies exclusively with the courts, not the EPA. Specifically, the Court
found: ``As the language of the statute makes clear, the courts
determine, on a case-by-case basis, whether civil penalties are
`appropriate.' '' See NRDC, 2014 U.S. App. LEXIS 7281 at *21 (``[U]nder
this statute, deciding whether penalties are `appropriate' in a given
private civil suit is a job for the courts, not EPA.'').\41\ In light
of NRDC, the EPA is not including a regulatory affirmative defense
provision in this rulemaking. As explained above, if a source is unable
to comply with emissions standards as a result of a malfunction, the
EPA may use its case-by-case enforcement discretion to provide
flexibility, as appropriate. Further, as the D.C. Circuit recognized,
in an EPA or citizen enforcement action, the court has the discretion
to consider any defense raised and determine whether penalties are
appropriate. Cf. NRDC, 2014 U.S. App. LEXIS 7281 at *24. (arguments
that violation were caused by unavoidable technology failure can be
made to the courts in future civil cases when the issue arises). The
same logic applies to EPA administrative enforcement actions.
---------------------------------------------------------------------------

\41\ The court's reasoning in NRDC focuses on civil judicial
actions. The Court noted that ``EPA's ability to determine whether
penalties should be assessed for Clean Air Act violations extends
only to administrative penalties, not to civil penalties imposed by
a court.'' Id.
---------------------------------------------------------------------------

a. General Duty
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.6(e)(1)(i) by changing the
``Yes'' in the second column to a ``No.'' Similarly, we are proposing
to revise the 40 CFR part 63, subpart UUU General Provisions table
(Table 44) entry for Sec. 63.6(e)(1)(i) by changing the ``Yes'' in the
third column to a ``No.'' We are making this change because section
63.6(e)(1)(i) describes the general duty to minimize emissions and the
current characterizes what the general duty entails during periods of
SSM and that language is no longer necessary or appropriate in light of
the elimination of the SSM exemption. We are proposing instead to add
general duty regulatory text at 40 CFR 63.642(n) and 40 CFR 63.1570(c)
that reflects the general duty to minimize emissions while eliminating
the reference to periods covered by an SSM exemption. With the
elimination of the SSM exemption, there is no need to differentiate
between normal operations, startup and shutdown, and malfunction events
in describing the general duty. Therefore the language the EPA is
proposing does not include that language from 40 CFR 63.6(e)(1).
We are also proposing to revise the 40 CFR part 63, subpart CC
General Provisions table (Table 6) entry for 63.6(e)(1)(ii) by changing
the ``Yes'' in the second column to a ``No.'' Similarly, we are also
proposing to revise the 40 CFR part 63, subpart UUU General Provisions
table (Table 44) entry for Sec. 63.6(e)(1)(ii) by changing the ``Yes''
in the third column to a ``No.'' Section 63.6(e)(1)(ii) imposes
requirements that are not necessary with the elimination of the SSM
exemption or are redundant of the general duty requirement being added
at 40 CFR 63.642(n) and 40 CFR 63.1570(c).
b. SSM Plan
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entries for 63.6(e)(3)(i) and
63.6(e)(3)(iii)-63.6(e)(3)(ix) by changing the ``Yes'' in the second
column to a ``No.'' Similarly, we are proposing to revise the 40 CFR
part 63, subpart UUU General Provisions table (Table 44) entries for
Sec. 63.6(e)(3)(i)-(iii), Sec. 63.6(e)(3)(iv), Sec. 63.6(e)(3)(v)-
(viii), Sec. 63.6(e)(3)(ix) to be entries for 63.6(e)(3)(i) and
63.6(e)(3)(iii)-63.6(e)(3)(ix) with ``No'' in the third column and
Sec. 63.6(e)(3)(ii) with ``Not

[[Page 36946]]

Applicable'' in the third column (that section is reserved). Generally,
these paragraphs require development of an SSM plan and specify SSM
recordkeeping and reporting requirements related to the SSM plan. As
noted, the EPA is proposing to remove the SSM exemptions. Therefore,
affected units will be subject to an emission standard during such
events. The applicability of a standard during such events will ensure
that sources have ample incentive to plan for and achieve compliance
and thus the SSM plan requirements are no longer necessary.
c. Compliance With Standards
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.6(f)(1) by changing the ``Yes''
in the second column to a ``No.'' Similarly, we are proposing to revise
the 40 CFR part 63, subpart UUU General Provisions table (Table 44)
entry for Sec. 63.6(f)(1) by changing the ``Yes'' in the third column
to a ``No.'' The current language of 40 CFR 63.6(f)(1) exempts sources
from non-opacity standards during periods of SSM. As discussed above,
the court in Sierra Club vacated the exemptions contained in this
provision and held that the CAA requires that some section 112 standard
apply continuously. Consistent with Sierra Club, the EPA is proposing
to revise standards in this rule to apply at all times.
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.6(h)(1) by changing the ``Yes''
in the second column to a ``No.'' Similarly, we are proposing to revise
the 40 CFR part 63, subpart UUU General Provisions table (Table 44)
entry for Sec. 63.6(h)(1) by changing the ``Yes'' in the third column
to a ``No.'' The current language of 40 CFR 63.6(h)(1) exempts sources
from opacity standards during periods of SSM. As discussed above, the
court in Sierra Club vacated the exemptions contained in this provision
and held that the CAA requires that some section 112 standard apply
continuously. Consistent with Sierra Club, the EPA is proposing to
revise standards in this rule to apply at all times.
d. Performance Testing
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.7(e)(1) by changing the ``Yes''
in the second column to a ``No.'' Similarly, we are proposing to revise
the 40 CFR part 63, subpart UUU General Provisions table (Table 44)
entry for Sec. 63.7(e)(1) by changing the ``Yes'' in the third column
to a ``No.'' Section 63.7(e)(1) describes performance testing
requirements. The EPA is instead proposing to add performance testing
requirements at 40 CFR 63.642(d)(3) and 40 CFR 63.1571(b)(1). The
performance testing requirements we are proposing differ from the
General Provisions performance testing provisions in several respects.
The regulatory text does not include the language in 40 CFR 63.7(e)(1)
that restated the SSM exemption. The regulatory text also does not
preclude startup and shutdown periods from being considered
``representative'' for purposes of performance testing, however, the
testing. However, the specific testing provisions proposed at 40 CFR
63.642(d)(3) and 40 CFR 63.1571(b)(1) do not allow performance testing
during startup or shutdown. As in 40 CFR 63.7(e)(1), performance tests
conducted under this subpart may not be conducted during malfunctions
because conditions during malfunctions are often not representative of
normal operating conditions. The EPA is proposing to add language that
requires the owner or operator to record the process information that
is necessary to document operating conditions during the test and
include in such record an explanation to support that such conditions
represent normal operation. Section 63.7(e) requires that the owner or
operator make available to the Administrator such records ``as may be
necessary to determine the condition of the performance test''
available to the Administrator upon request, but does not specifically
require the information to be recorded. The regulatory text EPA is
proposing to add to Refinery MACT 1 and 2 builds on that requirement
and makes explicit the requirement to record the information.
e. Monitoring
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entries for 63.8(c)(1)(i) and
63.8(c)(1)(iii) by changing the ``Yes'' in the second column to a
``No.'' Similarly, we are proposing to revise the 40 CFR part 63,
subpart UUU General Provisions table (Table 44) entry for Sec.
63.8(c)(1)(i) and Sec. 63.8(c)(1)(iii) by changing the ``Yes'' in the
third column to a ``No.'' The cross-references to the general duty and
SSM plan requirements in those subparagraphs are not necessary in light
of other requirements of 40 CFR 63.8 that require good air pollution
control practices (40 CFR 63.8(c)(1)) and that set out the requirements
of a quality control program for monitoring equipment (40 CFR 63.8(d)).
We are proposing to revise the 40 CFR part 63, subpart UUU General
Provisions table (Table 44) entry for Sec. 63.8(d) to include separate
entries for specific paragraphs of 40 CFR 63.8(d), including an entry
for Sec. 63.10(d)(3) with ``No'' in the third column. The final
sentence in 40 CFR 63.8(d)(3) refers to the General Provisions' SSM
plan requirement which is no longer applicable. The EPA is proposing to
add to the rule at 40 CFR 63.1576(b)(3) text that is identical to 40
CFR 63.8(d)(3) except that the final sentence is replaced with the
following sentence: ``The program of corrective action should be
included in the plan required under Sec. 63.8(d)(2).''
f. Recordkeeping
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.10(b)(2)(i) by changing the
``Yes'' in the second column to a ``No.'' Section 63.10(b)(2)(i)
describes the recordkeeping requirements during startup and shutdown.
These recording provisions are no longer necessary because the EPA is
proposing that recordkeeping and reporting applicable to normal
operations will apply to startup and shutdown. In the absence of
special provisions applicable to startup and shutdown, such as a
startup and shutdown plan, there is no reason to retain additional
recordkeeping for startup and shutdown periods.
We are proposing to revise the 40 CFR part 63, subpart UUU General
Provisions table (Table 44) entry for Sec. 63.10(b) to include
separate entries for specific paragraphs of 40 CFR 63.10(b), including
an entry for Sec. 63.10(b)(2)(i) with ``No'' in the third column.
Section 63.10(b)(2)(i) describes the recordkeeping requirements during
startup and shutdown. We are instead proposing to add recordkeeping
requirements to 40 CFR 63.1576(a)(2). When a source is subject to a
different standard during startup and shutdown, it will be important to
know when such startup and shutdown periods begin and end in order to
determine compliance with the appropriate standard. Thus, the EPA is
proposing to add language to 40 CFR 63.1576(a)(2) requiring that
sources subject to an emission standard during startup or shutdown that
differs from the emission standard that applies at all other times must
record the date, time, and duration of such periods.
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.10(b)(2)(ii) by changing the
``Yes'' in the second column to a ``No.'' Similarly, we are proposing
to revise the 40 CFR part 63,

[[Page 36947]]

subpart UUU General Provisions table (Table 44) entry for Sec.
63.10(b) to include separate entries for specific paragraphs of 40 CFR
63.10(b), including an entry for Sec. 63.10(b)(2)(ii) with ``No'' in
the third column. Section 63.10(b)(2)(ii) describes the recordkeeping
requirements during a malfunction. The EPA is proposing to add such
requirements to 40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2). The
regulatory text we are proposing to add differs from the General
Provisions language that was cross-referenced, which provides the
creation and retention of a record of the occurrence and duration of
each malfunction of process, air pollution control, and monitoring
equipment. The proposed text would apply to any failure to meet an
applicable standard and would require the source to record the date,
time, and duration of the failure. The EPA is also proposing to add to
40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2) a requirement that
sources keep records that include a list of the affected source or
equipment and actions taken to minimize emissions, an estimate of the
quantity of each regulated pollutant emitted over the standard for
which the source failed to meet a standard, and a description of the
method used to estimate the emissions. Examples of such methods would
include product-loss calculations, mass balance calculations,
measurements when available, or engineering judgment based on known
process parameters. The EPA is proposing to require that sources keep
records of this information to ensure that there is adequate
information to allow the EPA to determine the severity of any failure
to meet a standard, and to provide data that may document how the
source met the general duty to minimize emissions when the source has
failed to meet an applicable standard.
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.10(b)(2)(iv) by changing the
``Yes'' in the second column to a ``No.'' Similarly, we are proposing
to revise the 40 CFR part 63, subpart UUU General Provisions table
(Table 44) entry for Sec. 63.10(b) to include separate entries for
specific paragraphs of 40 CFR 63.10(b), including an entry for Sec.
63.10(b)(2)(iv)-(v) with ``No'' in the third column. When applicable,
40 CFR 63.10(b)(2)(iv) requires sources to record actions taken during
SSM events when actions were inconsistent with their SSM plan. The
requirement is no longer appropriate because SSM plans will no longer
be required. The requirement previously applicable under 40 CFR
63.10(b)(2)(iv)(B) to record actions to minimize emissions and record
corrective actions is now applicable by reference to 40 CFR
63.655(i)(11)(iii) and 40 CFR 63.1576(a)(2)(iii).
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.10(b)(2)(v) by changing the
``Yes'' in the second column to a ``No.'' Similarly, we are proposing
to revise the 40 CFR part 63, subpart UUU General Provisions table
(Table 44) entry for Sec. 63.10(b) to include separate entries for
specific paragraphs of 40 CFR 63.10(b), including an entry for Sec.
63.10(b)(2)(iv)-(v) with ``No'' in the third column. When applicable,
40 CFR 63.10(b)(2)(v) requires sources to record actions taken during
SSM events to show that actions taken were consistent with their SSM
plan. The requirement is no longer appropriate because SSM plans would
no longer be required.
We are proposing to revise the 40 CFR part 63, subpart UUU General
Provisions table (Table 44) entry for Sec. 63.10(c)(9)-(15) to include
separate entries for specific paragraphs of 40 CFR 63.10(c), including
an entry for Sec. 63.10(c)(15) with ``No'' in the third column. The
EPA is proposing that 40 CFR 63.10(c)(15) no longer apply. When
applicable, the provision allows an owner or operator to use the
affected source's SSM plan or records kept to satisfy the recordkeeping
requirements of the SSM plan, specified in 40 CFR 63.6(e), to also
satisfy the requirements of 40 CFR 63.10(c)(10) through (12). The EPA
is proposing to eliminate this requirement because SSM plans would no
longer be required, and therefore 40 CFR 63.10(c)(15) no longer serves
any useful purpose for affected units.
g. Reporting
We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entries for 63.10(d)(5)(i) and
63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a
``No'' in the second column. Similarly, we are proposing to revise the
40 CFR part 63, subpart UUU General Provisions table (Table 44) entries
for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry
for 63.10(d)(5) with a ``No'' in the third column. Section 63.10(d)(5)
describes the reporting requirements for startups, shutdowns, and
malfunctions. To replace the General Provisions reporting requirement,
the EPA is proposing to add reporting requirements to 40 CFR
63.655(g)(12), 40 CFR 63.1575(c)(4), 40 CFR 63.1575(d), and 40 CFR
63.1575(e). The General Provisions requirement that was cross-
referenced requires periodic SSM reports as a stand-alone report. In
its place, we are proposing language that requires sources that fail to
meet an applicable standard at any time to report the information
concerning such events in the periodic report already required under
each of these rules. We are proposing that the report must contain the
number, date, time, duration, and the cause of such events (including
unknown cause, if applicable), a list of the affected source or
equipment, an estimate of the quantity of each regulated pollutant
emitted over any emission limit, and a description of the method used
to estimate the emissions.
Examples of methods that can be used to estimate emissions would
include product-loss calculations, mass balance calculations,
measurements when available, or engineering judgment based on known
process parameters. The EPA is proposing this requirement to ensure
that there is adequate information to determine compliance, to allow
the EPA to determine the severity of the failure to meet an applicable
standard, and to provide data that may document how the source met the
general duty to minimize emissions during a failure to meet an
applicable standard.
We will no longer require owners or operators to determine whether
actions taken to correct a malfunction are consistent with an SSM plan,
because SSM plans would no longer be required. The proposed rule
eliminates the cross-reference to 40 CFR 63.10(d)(5)(i) that contains
the description of the previously required SSM report format and
submittal schedule from this section. These specifications are no
longer necessary because the events will be reported in otherwise
required reports with similar format and submittal requirements.
As noted above, we are proposing to revise the 40 CFR part 63,
subpart CC General Provisions table (Table 6) entries for
63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for
63.10(d)(5) with a ``No'' in the second column. Similarly, we are
proposing to revise the 40 CFR part 63, subpart UUU General Provisions
table (Table 44) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by
combining them into one entry for 63.10(d)(5) with a ``No'' in the
third column. Section 63.10(d)(5)(ii) describes an immediate report for
startups, shutdown, and malfunctions when a source fails to meet an
applicable standard but does not follow the SSM plan. We are proposing
to no longer require owners and operators to report when actions taken
during a startup, shutdown, or malfunction were not consistent with an
SSM plan,

[[Page 36948]]

because such plans would no longer be required.
2. Electronic Reporting
In this proposal, the EPA is describing a process to increase the
ease and efficiency of performance test data submittal while improving
data accessibility. Specifically, the EPA is proposing that owners and
operators of petroleum refineries submit electronic copies of required
performance test and performance evaluation reports by direct computer-
to-computer electronic transfer using EPA-provided software. The direct
computer-to-computer electronic transfer is accomplished through the
EPA's Central Data Exchange (CDX) using the Compliance and Emissions
Data Reporting Interface (CEDRI). The CDX is EPA's portal for submittal
of electronic data. The EPA-provided software is called the Electronic
Reporting Tool (ERT) which is used to generate electronic reports of
performance tests and evaluations. The ERT generates an electronic
report package which will be submitted using the CEDRI. The submitted
report package will be stored in the CDX archive (the official copy of
record) and the EPA's public database called WebFIRE. All stakeholders
will have access to all reports and data in WebFIRE and accessing these
reports and data will be very straightforward and easy (see the WebFIRE
Report Search and Retrieval link at https://cfpub.epa.gov/webfire/index.cfm?action=fire.searchERTSubmission). A description and
instructions for use of the ERT can be found at https://www.epa.gov/ttn/chief/ert/ and CEDRI can be accessed through the CDX Web site
(www.epa.gov/cdx). A description of the WebFIRE database is available
at: https://cfpub.epa.gov/oarweb/index.cfm?action=fire.main.
The proposal to submit performance test data electronically to the
EPA applies only to those performance tests (and/or performance
evaluations) conducted using test methods that are supported by the
ERT. The ERT supports most of the commonly used EPA reference methods.
A listing of the pollutants and test methods supported by the ERT is
available at: https://www.epa.gov/ttn/chief/ert/.
We believe that industry would benefit from this proposed approach
to electronic data submittal. Specifically, by using this approach,
industry will save time in the performance test submittal process.
Additionally, the standardized format that the ERT uses allows sources
to create a more complete test report resulting in less time spent on
data backfilling if a source failed to include all data elements
required to be submitted. Also through this proposal industry may only
need to submit a report once to meet the requirements of the applicable
subpart because stakeholders can readily access these reports from the
WebFIRE database. This also benefits industry by cutting back on
recordkeeping costs as the performance test reports that are submitted
to the EPA using CEDRI are no longer required to be retained in hard
copy, thereby reducing staff time needed to coordinate these records.
Since the EPA will already have performance test data in hand,
another benefit to industry is that fewer or less substantial data
collection requests in conjunction with prospective required residual
risk assessments or technology reviews will be needed. This would
result in a decrease in staff time needed to respond to data collection
requests.
State, local and tribal air pollution control agencies (S/L/Ts) may
also benefit from having electronic versions of the reports they are
now receiving. For example, S/L/Ts may be able to conduct a more
streamlined and accurate review of electronic data submitted to them.
For example, the ERT would allow for an electronic review process,
rather than a manual data assessment, therefore, making review and
evaluation of the source provided data and calculations easier and more
efficient. In addition, the public stands to benefit from electronic
reporting of emissions data because the electronic data will be easier
for the public to access. How the air emissions data are collected,
accessed and reviewed will be more transparent for all stakeholders.
One major advantage of the proposed submittal of performance test
data through the ERT is a standardized method to compile and store much
of the documentation required to be reported by this rule. The ERT
clearly states what testing information would be required by the test
method and has the ability to house additional data elements that might
be required by a delegated authority.
In addition the EPA must have performance test data to conduct
effective reviews of CAA sections 111 and 112 standards, as well as for
many other purposes including compliance determinations, emission
factor development and annual emission rate determinations. In
conducting these required reviews, the EPA has found it ineffective and
time consuming, not only for us, but also for regulatory agencies and
source owners and operators, to locate, collect and submit performance
test data. In recent years, stack testing firms have typically
collected performance test data in electronic format, making it
possible to move to an electronic data submittal system that would
increase the ease and efficiency of data submittal and improve data
accessibility.
A common complaint heard from industry and regulators is that
emission factors are outdated or not representative of a particular
source category. With timely receipt and incorporation of data from
most performance tests, the EPA would be able to ensure that emission
factors, when updated, represent the most current range of operational
practices. Finally, another benefit of the proposed data submittal to
WebFIRE electronically is that these data would greatly improve the
overall quality of existing and new emissions factors by supplementing
the pool of emissions test data for establishing emissions factors.
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 would save industry, state, local and tribal agencies and the
EPA significant time, money and effort while also improving the quality
of emission inventories and air quality regulations.
In addition, we are proposing that the fenceline data at each
monitor location (as proposed above) would be reported electronically
on a semiannual basis. All data reported electronically would be
submitted to CDX through CEDRI and made available to the public.
3. Technical Amendments to Refinery MACT 1 and 2
a. Open-Ended Valves and Lines
Refinery MACT 1 requires an owner or operator to control emissions
from equipment leaks according to the requirements of either 40 CFR
part 60, subpart VV or 40 CFR part 63, subpart H. For open-ended valves
and lines, both subparts require that the open end be equipped with a
cap, blind flange, plug or second valve that ``shall seal the open end
at all times.'' However, neither subpart defines ``seal'' or explains
in practical and enforceable terms what constitutes a sealed open-ended
valve or line. This has led to uncertainty on the part of the owner or
operator as to whether compliance is being achieved. Inspections under
the EPA's Air Toxics LDAR initiative have provided evidence that while
certain open-ended lines may be equipped with a cap, blind flange, plug
or second valve, they are not

[[Page 36949]]

operating in a ``sealed'' manner as the EPA interprets that term.
In response to this uncertainty, we are proposing to amend 40 CFR
63.648 to clarify what is meant by ``seal.'' This proposed amendment
clarifies that, for the purpose of complying with the requirements of
40 CFR 63.648, open-ended valves and lines are ``sealed'' by the cap,
blind flange, plug, or second valve when there are no detectable
emissions from the open-ended valve or line at or above an instrument
reading of 500 ppm. We solicit comment on this approach to reducing the
compliance uncertainty associated with open-ended valves and lines and
our proposed amendment.
b. General Provisions Cross-Referencing
We have reviewed the application of 40 CFR part 63, subpart A
(General Provisions) to Refinery MACT 2. The applicable requirements of
40 CFR part 63, subpart A are contained in Table 44 of 40 CFR part 63,
subpart UUU. As a result of our review, we are proposing several
amendments to Table 44 of 40 CFR part 63, subpart UUU (in addition to
those discussed in section IV.E.1 of this preamble that address SSM) to
bring the table up-to-date with requirements of the General Provisions
that have been amended since this table was created, to correct cross-
references, and to incorporate additional sections of the General
Provisions that are necessary to implement other subparts that are
cross-referenced by this rule.
Although we reviewed the application of the General Provisions to
Refinery MACT 1 and amended Table 6 of 40 CFR part 63, subpart CC in
2009, we are proposing a few additional technical corrections to this
table (in addition to those discussed in section IV.E.1 of this
preamble that address SSM). We are not discussing the details of these
proposed technical corrections in this preamble but the rationale for
each change to Table 6 of 40 CFR part 63, subpart CC and Table 44 of 40
CFR part 63, subpart UUU (including the proposed amendments to address
SSM discussed above), is included in Docket ID Number EPA-HQ-OAR-2010-
0682.
4. Amendments to Refinery NSPS J and Ja
As discussed in section II.B.2 of this preamble, we are addressing
a number of technical corrections and clarifications for Refinery NSPS
J and Ja to address some of the issues raised in the petition for
reconsideration and to improve consistency and clarity of the rule
requirements. These issues are addressed in detail in API's amended
petition, dated August 21, 2008 (see Docket Item Number EPA-HQ-OAR-
2007-0011-0246) and the meeting minutes for a September 11, 2008
meeting between EPA and API (see Docket Item Number EPA-HQ-OAR-2007-
0011-0266).
a. The Depressurization Work Practice Standard for Delayed Coking Units
HOVENSA and the Industry Petitioners raised several issues with the
analysis conducted to support the DCU work practice standard in
Refinery NSPS Ja. With the promulgation and implementation of the
standards we are proposing for the DCU under Refinery MACT 1, the DCU
work practice standards in Refinery NSPS Ja are not expected to result
in any further decreases in emissions from the DCU. Any DCU that
becomes subject to Refinery NSPS Ja would already be in compliance with
Refinery MACT 1, which is a more stringent standard than the DCU work
practice standards in Refinery NSPS Ja. As such, we are contemplating
various ideas for harmonizing the requirements for the DCU in these two
regulations. One option is to amend Refinery NSPS Ja to incorporate the
same requirements being proposed for Refinery MACT 1 (the DCU work
practice standard in Refinery NSPS Ja is less stringent than the
proposed requirements for Refinery MACT 1). Another option we are
contemplating is deleting the DCU work practice standard within
Refinery NSPS Ja once the DCU standards in Refinery MACT 1 are
promulgated and fully implemented. We believe deletion of this work
practice standard is consistent with the objectives of Executive Order
13563, ``Improving Regulation and Regulatory Review.'' We solicit
comment on these options as well as any other comments regarding the
interaction between the DCU requirements in these two rules (i.e., the
need to keep the DCU work practice standard in Refinery NSPS Ja after
promulgation of these revisions to Refinery MACT 1.)
b. Technical Corrections and Clarifications
In addition to their primary issues, the Industry Petitioners
enumerated several points of clarification and recommended amendments
to Refinery NSPS J and Ja. These issues are addressed in detail in
API's amended petition for reconsideration, dated August 21, 2008 (see
Docket Item Number EPA-HQ-OAR-2007-0011-0246) and the meeting minutes
for a September 11, 2008 meeting between EPA and API (see Docket Item
Number EPA-HQ-OAR-2007-0011-0266). We are including several proposed
amendments in this rulemaking to specifically address these issues.
These amendments are discussed in the remainder of this section. We are
addressing these issues now while we are proposing amendments for
Refinery MACT 2 in an effort to improve consistency and clarity for
sources regulated under both the NSPS and Refinery MACT 2.
We are proposing a series of amendments to the requirements for
sulfur recovery plants in 40 CFR 60.102a, to clarify the applicable
emission limits for different types of sulfur recovery plants based on
whether oxygen enrichment is used. These amendments also clarify that
emissions averaging across a group of emission points within a given
sulfur recovery plant is allowed from each of the different types of
sulfur recovery plants, and that emissions averaging is specific to the
SO2 or reduced sulfur standards (and not to the
H2S limit). The 10 ppmv H2S limit for reduction
control systems not followed by incineration must be met on a release
point-specific basis. These amendments are being made to clarify the
original intent of the Refinery NSPS Ja requirements for sulfur
recovery plants.
We are proposing a series of corresponding amendments in 40 CFR
60.106a to clarify the monitoring requirements, particularly when
oxygen enrichment or emissions averaging is used. The monitoring
requirements in Refinery NSPS Ja were incomplete for these provisions
and did not specify all of the types of monitoring devices needed for
implementation. We are also proposing in 40 CFR 60.106a to 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. The term ``reduced sulfur
compounds'' is a defined term in Refinery NSPS Ja, and the emissions
limit for sulfur recovery plants with reduction control systems not
followed by incineration is specific to ``reduced sulfur compounds.''
Therefore, the proposed amendments to the monitoring provisions provide
clarification of the requirements by using a consistent, defined term.
We are proposing amendments to 40 CFR 60.102a(g)(1) to clarify that
CO boilers, while part of the FCCU affected facility, can also be fuel
gas combustion devices (FGCD). Industry Petitioners suggested that the
CO boiler should only be subject to the FCCU NOX and
SO2

[[Page 36950]]

limits and should not be considered a FGCD. While Refinery NSPS Ja
clearly states that the coke burn-off exhaust from the FCCU catalyst
regenerator is not considered to be fuel gas, other fuels combusted in
the CO boiler must meet the H2S concentration requirements
for fuel gas like any other FGCD. This amendment is provided to clarify
our original intent with respect to fuel gas. Industry Petitioners also
noted that some CO boiler ``furnaces'' may be used as process heaters
rather than steam-generating boilers. While we did not originally
contemplate that CO furnaces would be used as process heaters,
available data from the detailed ICR suggests that there are a few CO
furnaces used as process heaters. These CO furnaces are all forced-
draft process heaters, and the newly amended NOX emissions
limit in Refinery NSPS Ja for forced-draft process heaters is 60 ppmv,
averaged over a 30-day period. Given the longer averaging time of the
process heater NOX limits, these two emission limits (for
FCCU NOX and for process heater NOX) are
reasonably comparable and are not expected to result in a significant
difference in the control systems selected for compliance. As such, we
are not amending or clarifying the NOX standards for the
FCCU or process heaters at this time. We are, however, clarifying
(through this response) that if an emission source meets the definition
of more than one affected facility, that source would need to comply
with all requirements applicable to the emissions source.
We are proposing to revise the annual testing requirement in 40 CFR
60.104a(b) to clarify our original intent. Instead of requiring a PM
performance test at least once every 12 months, the rule would require
a PM performance test annually and specify that annually means once per
calendar year, with an interval of at least 8 months but no more than
16 months between annual tests. This provision will ensure that testing
is conducted at a reasonable interval while giving owners and operators
flexibility in scheduling the testing. We are also proposing 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 per coke burn-off emissions limit (rather than just
the PM limit) in 40 CFR 60.102a(b)(1), to clarify that facilities
electing to comply with the concentration limit using a PM CEMS would
not also be required to install a COMS. We are also proposing to amend
40 CFR 60.104a(j) to delete the requirements to measure flow for the
H2S concentration limit for fuel gas, as these are not
needed in the performance evaluation.
We are proposing 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 are also
proposing amendments to 40 CFR 60.105a(i) to include 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. These proposed amendments
are necessary so that periods when the APCD operation is compromised
are properly managed and/or reported.
We are proposing amendments to 40 CFR 60.105(b)(1)(iv) and
60.107a(b)(1)(iv) to allow using tubes with a maximum span between 10
and 40 ppmv, inclusive, when 1<=N<=10, where N = number of pump strokes
rather than requiring use of tubes with ranges 0-10/0-100 ppm (N = 10/
1) because different length-of-stain tube manufacturers have different
span ranges, and none of the commercially-available tubes have a
specific span of 0-10/0-100 ppm (N = 10/1). We are also proposing to
amend 40 CFR 60.105(b)(3)(iii) and 40 CFR 60.107a(b)(3)(iii) to specify
that the temporary daily stain sampling must be made 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. This proposed amendment
clarifies this monitoring requirement, ensures the proper tube range is
used, and provides some flexibility in span range to accommodate
different manufacturers of the length-of-stain tubes. We also propose
to delete the last sentence in 40 CFR 60.105(b)(3)(iii), as there is no
long-term H2S concentration limit in Refinery NSPS J.
We are proposing to clarify that flares are subject to the
performance test requirements. We are also proposing to clarify those
performance test requirements in 40 CFR 60.107a(e)(1)(ii) and 40 CFR
60.107a(e)(2)(ii) to remove the distinction between flares with or
without routine flow. The term ``routine flow'' is not defined and it
is difficult to make this distinction in practice.

F. What compliance dates are we proposing?

Amendments to Refinery MACT 1 and 2 proposed in this rulemaking for
adoption under CAA section 112(d)(2) and (3) and CAA section 112(d)(6)
are subject to the compliance deadlines outlined in the CAA under
section 112(i). For all of the requirements we are proposing under CAA
section 112(d)(2) and (3) or CAA section 112(d)(6) except for storage
vessels, which we are also requiring under 112 (f)(2), we are proposing
the following compliance dates. As provided in CAA section 112(i), new
sources would be required to comply with these requirements by the
effective date of the final amendments to Refinery MACT 1 and 2 or
startup, whichever is later.
For existing sources, CAA section 112(i) provides that the
compliance date shall be as expeditiously as practicable, but no later
than 3 years after the effective date of the standard. In determining
what compliance period is as expeditious as practicable, we consider
the amount of time needed to plan and construct projects and change
operating procedures. Under CAA section 112(d)(2) and (3), we are
proposing new operating requirements for DCU. In order to comply with
these new requirements, we project that most DCU owners or operators
would need to install additional controls (e.g., steam ejector
systems). Similarly, the proposed revision in the CRU pressure limit
exclusions would require operational changes and, in some cases,
additional controls. The addition of new control equipment would
require engineering design, solicitation and review of vendor quotes,
contracting and installation of the equipment, which would need to be
timed with process unit outage and operator training. Therefore, we are
proposing that it is necessary to provide 3 years after the effective
date of the final rule for these sources to comply with the DCU and CRU
requirements.
We are proposing new operating and monitoring requirements for
flares under CAA section 112(d)(2) and (3). We anticipate that these
requirements would require the installation of new flare monitoring
equipment and we project most refineries would install new control
systems to monitor and adjust assist gas (air or steam) addition rates.
Similar to the addition of new control equipment, these new monitoring
requirements for flares would require engineering evaluations,
solicitation and review of vendor quotes, contracting and installation
of the equipment, and operator training.

[[Page 36951]]

Installation of new monitoring and control equipment on flares will
require the flare to be taken out of service. Depending on the
configuration of the flares and flare header system, taking the flare
out of service may also require a significant portion of the refinery
operations to be shut down. Therefore, we are proposing that it is
necessary to provide 3 years after the effective date of the final rule
for owners or operators to comply with the new operating and monitoring
requirements for flares.
Under CAA section 112(d)(2) and (3), we are proposing new vent
control requirements for bypasses. These requirements would typically
require the addition of piping and potentially new control
requirements. As these vent controls would most likely be routed to the
flare, we are proposing to provide 3 years after the effective date of
the final rule for owners or operators to afford coordination of these
bypass modifications with the installation of the new monitoring
equipment for the flares.
Under our technology review, we are proposing to require fenceline
monitoring pursuant to CAA section 112(d)(6). These proposed provisions
would require refinery owners or operators to install a number of
monitoring stations around the facility fenceline. While the diffusive
tube sampling system is relatively low-tech and is easy to install,
site-specific factors must be considered in the placement of the
monitoring systems. We also assume all refinery owners or operators
would invest in the analytical equipment needed to perform automated
sample analysis on-site and time is needed to select an appropriate
vendor for this equipment. Furthermore, additional monitoring systems
may be needed to account for near-field contributing sources, for which
the development and approval of a site-specific monitoring plan.
Considering all of the requirements needed to implement the fenceline
monitoring system, we are proposing to provide 3 years from the
effective date of the final rule for refinery owners or operators to
install and begin collecting ambient air samples around the fenceline
of their facility following an approved (if necessary) site-specific
monitoring plan.
As a result of our technology review for equipment leaks, we are
proposing to allow the use of optical gas imaging devices in lieu of
using EPA Method 21 of 40 CFR part 60, Appendix A-7 without the annual
compliance demonstration with EPA Method 21 as required in the AWP (see
73 FR 73202, December 22, 2008), provided that the owner and operator
follows the provisions of Appendix K to 40 CFR part 60. Facilities
could begin to comply with the optical gas imaging alternative as soon
as Appendix K to 40 CFR part 60 is promulgated. Alternatively, as is
currently provided in the AWP, the refinery owner or operator can elect
to use the optical gas imaging monitoring option prior to installation
and use of the fenceline monitoring system, provided they conduct an
annual compliance demonstration using EPA Method 21 as required in the
AWP.
Under our technology review for marine vessel loading operations,
we are proposing to add a requirement for submerged filling for small
and for offshore marine vessel loading operations. We anticipate that
the submerged fill pipes are already in place on all marine vessels
used to transport petroleum refinery liquids, so we are proposing that
existing sources comply with this requirement on the effective date of
the final rule. We request comment regarding the need to provide
additional time to comply with the submerged filling requirement;
please provide in your comment a description of the vessels loaded that
do not already have a submerged fill pipe, how these vessels comply
with (or are exempt from) the Coast Guard requirements at 46 CFR
153.282, and an estimate of the time needed to add the required
submerged fill pipes to these vessels.
We are also proposing to require FCCU owners and operators
currently subject to Refinery NSPS J (or electing that compliance
option in Refinery MACT 2) to transition from the Refinery NSPS J
option to one of the alternatives included in the proposed rule. We are
also proposing altering the averaging times for some of the operating
limits. A PM performance test is needed in order to establish these new
operating limits prior to transitioning to the proposed requirements.
Additionally, we are proposing that a PM performance test be conducted
for each FCCU once every 5 years. We do not project any new control or
monitoring equipment will be needed in order to comply with the
proposed provisions; however, compliance with the proposed provisions
is dependent on conducting a performance test. Establishing an early
compliance date for the first performance test can cause scheduling
issues as refinery owners or operators compete for limited number of
testing contractors. Considering these scheduling issues, we propose to
require the first performance test for PM and compliance with the new
operating limits be completed no later than 18 months after the
effective date of the final rule.
In this action, we are proposing revisions to the SSM provisions of
Refinery MACT 1 and 2, including specific startup or shutdown standards
for certain emission sources, and we are proposing electronic reporting
requirements in Refinery MACT 1 and 2. The proposed monitoring
requirements associated with the new startup and shutdown standards are
expected to be present on the affected source, so we do not expect that
owners or operators will need additional time to transition to these
requirements. Similarly, the electronic reporting requirements are not
expected to require a significant change in operation or equipment, so
these requirements should be able to be implemented more quickly than
those that require installation of new control or monitoring equipment.
Based on our review of these requirements, we propose that these
requirements become effective upon the effective date of the final
rule.
Finally, we are proposing additional requirements for storage
vessels under CAA sections 112(d)(6) and (f)(2). The compliance
deadlines for standards developed under CAA section 112(f)(2) are
delineated in CAA sections 112(f)(3) and (4). As provided in CAA
section 112(f)(4), risk standards shall not apply to existing sources
until 90 days after the effective date of the rule, but the
Administrator may grant a waiver for a particular source for a period
of up to 2 years after the effective date. While additional controls
will be necessary to comply with the proposed new control and fitting
requirements for storage vessels, the timing for installation of these
controls is specified within the Generic MACT (40 CFR part 63, subpart
WW). Therefore, we propose that these new requirements for storage
vessels become effective 90 days following the effective date of the
final rule.

V. Summary of Cost, Environmental and Economic Impacts

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

The sources affected by significant amendments to the petroleum
refinery standards include storage vessels, equipment leaks, fugitive
emissions and DCU subject to Refinery MACT 1. The proposed 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 proposed amendments and
standards is estimated at $239 million, $82.8 million from proposed
amendments and $156 million from

[[Page 36952]]

standards to ensure compliance. We estimate annualized costs to be
approximately $4.53 million, which includes an estimated $14.4 million
credit for recovery of lost product and the annualized cost of capital.
We also estimate annualized costs of the proposed standards to ensure
compliance to be approximately $37.9 million. The proposed amendments
would achieve a nationwide HAP emission reduction of 1,760 tpy, with a
concurrent reduction in VOC emissions of 18,800 tpy. Table 13 of this
preamble summarizes the cost and emission reduction impacts of the
proposed amendments, and Table 14 of this preamble summarizes the costs
of the proposed standards to ensure compliance.

Table 13--Nationwide Impacts of Proposed Amendments
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total annualized
Total capital cost without Product recovery Total annualized VOC emission Cost HAP emission Cost
Affected source investment credit (million $/ credit (million costs (million $/ reductions (tpy) effectiveness ($/ reductions (tpy) effectiveness ($/
(million $) yr) $/yr) yr) ton VOC) ton HAP)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Storage Vessels................................ 18.5 3.13 (8.16) (5.03) 14,600 (345) 910 (5,530)
Delayed Coking Units........................... 52.0 10.2 (6.20) 3.98 4,250 937 850 4,680
Fugitive Emissions (Fenceline Monitoring)...... 12.2 5.58 ................ 5.58 ................ ................ ................ ................
------------------------------------------------------------------------------------------------------------------------------------------------
Total...................................... 82.8 18.9 (14.4) 4.53 18,800 241 1,760 2,570
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Table 14--Nationwide Costs of Proposed Amendments to Ensure Compliance
----------------------------------------------------------------------------------------------------------------
Total
Total capital annualized Product Total
Affected source investment cost without recovery annualized
(million $) credit credit costs (million
(million $/yr) (million $/yr) $/yr)
----------------------------------------------------------------------------------------------------------------
Relief Valve Monitoring......................... 9.54 1.36 .............. 1.36
Flare Monitoring................................ 147 36.3 .............. 36.3
FCCU Testing.................................... -- 0.21 .............. 0.21
---------------------------------------------------------------
Total....................................... 156 37.9 -- 37.9
----------------------------------------------------------------------------------------------------------------

Note that any corrective actions taken in response to the fenceline
monitoring program are not included in the impacts shown in Table 13.
Any corrective actions associated with fenceline monitoring will result
in additional emission reductions and additional costs.
The impacts shown in Table 14 do not consider emission reductions
associated with relief valve or flare monitoring provisions or emission
reductions that may occur as a result of the additional FCCU testing
requirements. The proposed operational and monitoring requirements for
flares at refineries have the potential to reduce excess emissions from
flares by approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and
327,000 metric tonnes per year of CO2e. When added to the
reductions in CO2e achieved from proposed controls on DCU,
these proposed amendments are projected to result in reductions of
670,000 metric tonnes of CO2e due to reductions of methane
emissions.\42\
---------------------------------------------------------------------------

\42\ The flare operational and monitoring requirements are
projected to reduce methane emissions by 29,500 tpy while increasing
CO2 emissions by 260,000 tpy, resulting in a net GHG
reduction of 327,000 metric tonnes per year of CO2e,
assuming a global warming potential of 21 for methane. Combined with
methane emissions reduction of 18,000 tpy from the proposed controls
on DCU, the overall GHG reductions of the proposed amendments is
670,000 metric tonnes per year of CO2e assuming a global
warming potential of 21 for methane.
---------------------------------------------------------------------------

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 much 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 are 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 proposed rule
(Docket ID Number EPA-HQ-OAR-2010-0682).

C. What are the benefits?

The proposed rule is anticipated to result in a reduction of 1,760
tons of HAP (based on allowable emissions under the MACT standards) and
18,800 tons of VOC emissions per year, not including potential emission
reductions that may occur as a result of the proposed provisions for
flares or 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.

VI. Request for Comments

We solicit comments on all aspects of this proposed action. In
addition to general comments on this proposed action, we are also
interested in additional data that may improve the risk assessments and
other analyses. We are specifically interested in receiving any
improvements to the data used in the site-specific emissions profiles
used for risk modeling. Such data should include supporting
documentation in sufficient detail to allow characterization of the
quality and representativeness of the data or information. Section VII
of this preamble provides more information on submitting data.

[[Page 36953]]

VII. Submitting Data Corrections

The site-specific emissions profiles used in the source category
risk and demographic analyses and instructions are available on the RTR
Web page at: https://www.epa.gov/ttn/atw/rrisk/rtrpg.html. The data
files include detailed information for each HAP emissions release point
for the facilities in the source categories.
If you believe that the data are not representative or are
inaccurate, please identify the data in question, provide your reason
for concern and provide any ``improved'' data that you have, if
available. When you submit data, we request that you provide
documentation of the basis for the revised values to support your
suggested changes. To submit comments on the data downloaded from the
RTR page, complete the following steps:
1. Within this downloaded file, enter suggested revisions to the
data fields appropriate for that information.
2. Fill in the commenter information fields for each suggested
revision (i.e., commenter name, commenter organization, commenter email
address, commenter phone number and revision comments).
3. Gather documentation for any suggested emissions revisions
(e.g., performance test reports, material balance calculations).
4. Send the entire downloaded file with suggested revisions in
Microsoft[supreg] Access format and all accompanying documentation to
Docket ID Number EPA-HQ-OAR-2010-0682 (through one of the methods
described in the ADDRESSES section of this preamble).
5. If you are providing comments on a single facility or multiple
facilities, you need only submit one file for all facilities. The file
should contain all suggested changes for all sources at that facility.
We request that all data revision comments be submitted in the form of
updated Microsoft[supreg] Excel files that are generated by the
Microsoft[supreg] Access file. These files are provided on the RTR Web
page at: https://www.epa.gov/ttn/atw/rrisk/rtrpg.html.

VIII. Statutory and Executive Order Reviews

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

Under Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is a ``significant regulatory action'' because it raises novel
legal and policy issues. Accordingly, the EPA submitted this action to
the Office of Management and Budget (OMB) for review under Executive
Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes
made in response to OMB recommendations have been documented in the
docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682).

B. Paperwork Reduction Act

The information collection requirements in this rule have been
submitted for approval to OMB under the Paperwork Reduction Act, 44
U.S.C. 3501, et seq.
Revisions and burden associated with amendments to 40 CFR part 63,
subparts CC and UUU are discussed in the following paragraphs. OMB has
previously approved the information collection requirements contained
in the existing regulations in 40 CFR part 63, subparts CC and UUU
under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501, et
seq., OMB control numbers for the EPA's regulations in 40 CFR are
listed in 40 CFR part 9. Burden is defined at 5 CFR 1320.3(b).
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 53,619 hours; the frequency
of response is semiannual for all 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 $17
million, which includes monitoring equipment for bypass valves,
fenceline monitoring, relief valves, and flares), a total operation and
maintenance component (about $16 million per year for fenceline and
flare monitoring), and a labor cost component (about $4.5 million per
year, the cost of the additional 53,619 labor hours). 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 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 1844.07. Burden changes associated
with these amendments would result from new testing, recordkeeping and
reporting requirements being proposed with this action. The estimated
average burden per response is 26 hours; the frequency of response is
both once and 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 $356,000 per year
over the first 3 years for the initial performance test and $213,000
per year starting in the fourth year), and a labor cost component
(approximately $238,000 per year for 2,860 additional labor hours). 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.
To comment on the agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes the ICR, under Docket ID Number EPA-HQ-
OAR-2010-0682. Submit any comments related to the ICR to the EPA and
OMB. See the ADDRESSES section at the beginning of this preamble for
where to submit comments to the EPA. Send comments to OMB at the Office
of Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street NW., Washington, DC 20503, Attention: Desk Office for
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after June 30, 2014, a comment to OMB is best
assured of having its full effect if OMB receives it by July 30, 2014.
The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute, unless the agency certifies that
the rule will not have a significant economic impact on a substantial
number of small entities (SISNOSE). Small entities include small
businesses, small organizations and small governmental jurisdictions.
For purposes of assessing the impacts of this proposed rule on small
entities, a small entity is defined as: (1) A small business in the
petroleum refining industry

[[Page 36954]]

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.
After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The small
entities subject to the requirements of this proposed rule are small
refiners. We have determined that 36 companies (59 percent of the 61
total) employ fewer than 1,500 workers and are considered to be small
businesses. For small businesses, the average cost-to-sales ratio is
about 0.05 percent, the median cost-to-sales ratio is 0.02 percent and
the maximum cost-to-sales ratio is 0.55 percent. The potential costs do
not have a more significant impact on small refiners and because no
small firms are expected to have cost-to-sales ratios greater than 1
percent, we determined that the cost impacts for this rulemaking will
not have a SISNOSE.
Although not required by the RFA to convene a Small Business
Advocacy Review (SBAR) Panel; because the EPA has determined that this
proposal would not have a significant economic impact on a substantial
number of small entities, the EPA originally convened a panel to obtain
advice and recommendations from small entity representatives
potentially subject to this rule's requirements. The panel was not
formally concluded; however, a summary of the outreach conducted and
the written comments submitted by the small entity representatives can
be found in the docket for this proposed rule (Docket ID Number EPA-HQ-
OAR-2010-0682).
We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.

D. Unfunded Mandates Reform Act

This proposed rule does not contain a federal mandate under the
provisions of Title II of the Unfunded Mandates Reform Act of 1995
(UMRA), 2 U.S.C. 1531-1538 that may result in expenditures of $100
million or more for state, local and tribal governments, in the
aggregate, or the private sector in any one year. As discussed earlier
in this preamble, these amendments result in nationwide costs of $42.4
million per year for the private sector. Thus, this proposed rule is
not subject to the requirements of sections 202 or 205 of the UMRA.
This proposed rule is also not subject to the requirements of
section 203 of UMRA because it contains no regulatory requirements that
might significantly or uniquely affect small governments because it
contains no requirements that apply to such governments and does not
impose obligations upon them.

E. Executive Order 13132: Federalism

This rule does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. None of the facilities subject to
this action are owned or operated by state governments, and, because no
new requirements are being promulgated, nothing in this proposal will
supersede state regulations. Thus, Executive Order 13132 does not apply
to this rule.
In the spirit of Executive Order 13132, and consistent with the EPA
policy to promote communications between the EPA and state and local
governments, the EPA specifically solicits comment on this proposed
rule from state and local officials.

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

This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have
substantial direct effects on tribal governments, on the relationship
between the federal government and Indian tribes, or on the
distribution of power and responsibilities between the federal
government and Indian tribes as specified in Executive Order 13175.
Thus, Executive Order 13175 does not apply to this action.
Although Executive Order 13175 does not apply to this action, the
EPA consulted with tribal officials in developing this action. The EPA
sent out letters to tribes nationwide to invite them to participate in
a tribal consultation meeting and solicit their input on this
rulemaking. The EPA conducted the tribal consultation meeting on
December 14, 2011. Participants from eight tribes attended the meeting,
but they were interested only in outreach, and none of the tribes had
delegation for consultation. The EPA presented all the information
prepared for the consultation and conducted a question and answer
session where participants asked clarifying questions about the
information that was presented and generally expressed their support of
the rulemaking requirements.
The EPA specifically solicits additional comment on this proposed
action from tribal officials.

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

This action is not subject to Executive Order 13045 (62 FR 19885,
April 23, 1997) because it is not economically significant as defined
in Executive Order 12866, and because the agency 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 sections III.A and B and sections IV.C and
D of this preamble.
The public is invited to submit comments or identify peer-reviewed
studies and data that assess effects of early life exposure to
emissions from petroleum refineries.

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

This action is not a ``significant energy action'' as defined under
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not
likely to have significant adverse effect on the supply, distribution
or use of energy. The overall economic impact of this proposed rule
should be minimal for the refining industry and its consumers.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note)
directs the EPA to use voluntary consensus standards (VCS) in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. VCS are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by VCS bodies. The
NTTAA directs the EPA to provide Congress, through OMB, explanations
when the agency decides not to use available and applicable VCS.
This proposed rulemaking involves technical standards. The EPA
proposes to use ISO 16017-2, ``Air quality Sampling and analysis of
volatile organic compounds in ambient air,

[[Page 36955]]

indoor air and workplace air by sorbent tube/thermal desorption/
capillary gas chromatography Part 2: Diffusive sampling'' as an
acceptable alternative to EPA Method 325A. This method is available at
https://www.iso.org. This method was chosen because it meets the
requirements of EPA Method 301 for equivalency, documentation and
validation data for diffusive tube sampling.
The EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this
regulation.

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 United States.
The EPA has determined that this proposed 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 the provisions of this rule
will provide an ample margin of safety to protect public health of all
demographic groups.
To examine the potential for any environmental justice issues that
might be associated with the refinery source categories associated with
today's proposed rule, we evaluated the percentages of various social,
demographic and economic groups within the at-risk populations living
near the facilities where these source categories 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 groups. In
addition, the population living within 50 km of the 142 petroleum
refineries has a higher percentage of minority, lower income and lower
education persons when compared to the nationwide percentages of those
groups. These groups stand to benefit the most from the emission
reductions achieved by this proposed rulemaking, and this proposed
rulemaking is projected to result in 1 million fewer people exposed to
risks greater than 1-in-1 million.
The EPA defines ``Environmental Justice'' to include 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. To promote meaningful
involvement, the EPA conducted numerous outreach activities and
discussions, including targeted outreach (such as conference calls and
Webinars) to communities and environmental justice organizations. In
addition, after the rule is proposed, the EPA will be conducting a
webinar to inform the public about the proposed rule and to outline how
to submit written comments to the docket. Further stakeholder and
public input is expected through public comment and follow-up meetings
with interested stakeholders.

List of Subjects

40 CFR Part 60

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

40 CFR Part 63

Environmental protection, Air pollution control, Hazardous
substances, Incorporation by reference, Reporting and recordkeeping
requirements, Volatile organic compounds.

Dated: May 15, 2014.
Gina McCarthy,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is proposed to be amended as follows:

PART 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--[AMENDED]

0
2. Section 60.105 is amended by:
0
a. Revising paragraph (b)(1)(iv) and
0
b. Revising paragraph (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, Test for Hydrogen Sulfide and
Carbon Dioxide in Natural Gas Using Length of Stain Tubes,'' 1986
Revision (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.
The owner or operator must begin monitoring according to the
requirements in paragraphs (a)(1) or (a)(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

[[Page 36956]]

exceedance of the 3-hour H2S concentration limit.
* * * * *

Subpart Ja--[AMENDED]

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, 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'' to
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:
0
a. Revising paragraphs (b)(1)(i) and (iii);
0
b. Revising paragraph (f); and
0
c. Revising paragraph (g)(1).
The revisions 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), each owner or operator
of an affected sulfur recovery plant shall comply with the applicable
emission limits in paragraphs (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 paragraphs (f)(1)(i) or
(f)(1)(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 paragraphs (f)(1)(i) or (f)(1)(ii) of this section 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 paragraphs (f)(1)(i) or (f)(1)(ii) of this section
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] TP30JN14.058

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 36957]]

section 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 paragraphs (f)(2)(i) or (f)(2)(ii) of this
section 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] TP30JN14.059

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) 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) of this section 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);
0
b. Revising paragraph (b);
0
c. Revising paragraph (f) introductory text;
0
d. Revising paragraph (h) introductory text;
0
e. Adding paragraph (h)(6); and
0
f. 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. Sec. 60.102a(f)(1)(i) and 60.102a(f)(2)(i) and the reduced sulfur
compounds and H2S emissions limits for sulfur recovery
plants in Sec. Sec. 60.102a(f)(1)(ii), 60.102a(f)(1)(iii),
60.102a(f)(2)(ii) and 60.102a(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 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 paragraph (b)(1)(i);
0
b. Revising paragraph (b)(1)(ii)(A);

[[Page 36958]]

0
c. Revising paragraph (b)(2);
0
d. Revising paragraph (h)(1);
0
e. Revising paragraph (h)(3)(i);
0
f. Revising paragraph (i)(1);
0
g. Redesignating paragraphs (i)(2) through (6) as (i)(3) through (7);
0
h. Adding paragraph (i)(2); and
0
i. 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 Sec. 60.105a(h)(3).
(i) The owner or operator shall install, operate, and maintain each
CO2 and O2 monitor according to Performance
Specification 3 of Appendix B to part 60.
(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 part 60. The owner or operator shall use Method 3 of
Appendix A-3 to part 60 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 part 60. 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 part 60. The owner or operator shall use Method 10, 10A,
or 10B of Appendix A-3 to part 60 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 part 60, 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 part 60. 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 part 60. 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 part 60 and employ the sample conditioning
system of Method 10A of appendix A-4 to part 60, the alternative
relative accuracy test procedure in section 10.1 of Performance
Specification 2 of appendix B to part 60 may be used in place of the
relative accuracy test.
* * * * *
(i) * * *
(1) If a CPMS is used according to Sec. 60.105a(b)(1), all 3-hour
periods during which the average PM control device operating
characteristics, as measured by the continuous monitoring systems under
Sec. 60.105a(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 Sec.
60.105a(c), each day in which the cause of an alarm is not alleviated
within the time period specified in Sec. 60.105a(c)(3).
* * * * *
(7) All 1-hour periods during which the average CO concentration as
measured by the CO continuous monitoring system under Sec. 60.105a(h)
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 Sec. 60.105a(h)(4) 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 paragraph (a)(2) introductory text;
0
d. Revising paragraphs (a)(2)(i) and (ii);
0
e. Revising the first sentence of paragraph (a)(2)(iii);
0
f. Removing paragraphs (a)(2)(iv) and (v);
0
g. Redesignating (a)(2)(vi) through (ix) as (a)(2)(iv) through (vii);
0
h. Revising the first sentence of paragraph (a)(3) introductory text;
0
i. Revising paragraph (a)(3)(i);
0
j. Adding paragraphs (a)(4) through (7); and
0
k. 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 part 60.
(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

[[Page 36959]]

O2 monitor according to the requirements of Sec. 60.13(c)
and Performance Specification 3 of Appendix B to part 60. The owner or
operator shall use Methods 3, 3A, or 3B of Appendix A-2 to part 60 for
conducting the relative accuracy evaluations. The method ANSI/ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec. 60.17) is an acceptable alternative to EPA Method
3B of Appendix A-2 to part 60.
(vii) The owner or operator shall comply with the applicable
quality assurance procedures of Appendix F to part 60 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 Sec.
60.102a(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 part 60.
(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 part
60. * * *
* * * * *
(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 Sec.
60.102a(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 part 60.
(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 part 60. The
owner or operator shall use Methods 11 or 15 of appendix A-5 to part 60
or Method 16 of appendix A-6 to part 60 for conducting the relative
accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, ``Flue and
Exhaust Gas Analyses,'' (incorporated by reference--see Sec. 60.17) is
an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.
(iv) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
appendix B to part 60.
(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 part 60. The
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 3B of appendix A-2 to part 60.
(vii) The owner or operator shall comply with the applicable
quality assurance procedures of appendix F to part 60 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 part 60.
(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 part 60. The
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 3B of appendix A-2 to part 60.
(iv) The owner or operator shall comply with the applicable quality
assurance procedures of appendix F to part 60 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) The owner or operator shall install locate the monitor in a
position that

[[Page 36960]]

provides a representative measurement of the total gas flow rate.
(B) Use a flow sensor with a measurement sensitivity of no more
than 5 percent of the flow rate 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] TP30JN14.001

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 this section
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 Sec. 60.102a(f)(2)(i) or the reduced sulfur compounds emission
limit in Sec. 60.102a(f)(1)(ii) or Sec. 60.102a(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) The owner or operator shall install locate the monitor in a
position that provides a representative measurement of the total gas
flow rate.
(B) Use a flow sensor with a measurement sensitivity of no more
than 5 percent of the flow rate 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] TP30JN14.002

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] TP30JN14.003

[[Page 36961]]

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 Sec. 60.102a(f)(2)(i)]
or reduced sulfur compounds [if complying with the reduced sulfur
compounds emission limit in Sec. 60.102a(f)(1)(ii) or Sec.
60.102a(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).

(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 paragraphs
(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:
0
a. Revising paragraphs (a)(1)(i) and (ii);
0
b. Revising paragraph (b)(1)(iv);
0
c. Revising the first sentence of paragraph (b)(3)(iii);
0
d. Revising paragraph (d)(3);
0
e. Revising paragraph (e)(1) introductory text;
0
f. Revising paragraph (e)(1)(ii);
0
g. Revising paragraph (e)(2) introductory text;
0
h. Revising paragraph (e)(2)(ii);
0
i. Revising paragraph (e)(2)(vi)(C);
0
j. Revising paragraph (e)(3); and
0
k. Revising paragraph (h)(5).
The revisions 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 part 60. 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 part 60. The
owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 6 or 6A of appendix A-4 to part 60. Samples
taken by Method 6 of appendix A-4 to part 60 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, Test for
Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of
Stain Tubes,'' 1986 Revision (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] TP30JN14.004

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

[[Page 36962]]

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 part
60. The owner or operator of each total reduced sulfur monitor shall
use EPA Method 15A of Appendix A-5 to part 60 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 part 60. The
alternative relative accuracy procedures described in section 16.0 of
Performance Specification 2 of Appendix B to part 60 (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 part 60. The
owner or operator shall use EPA Method 11, 15 or 15A of Appendix A-5 to
part 60 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 part
60. The alternative relative accuracy procedures described in section
16.0 of Performance Specification 2 of Appendix B to part 60 (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] TP30JN14.060

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.

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.
* * * * *
(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 seq.

Subpart A--[Amended]

0
11. Section 63.14 is amended by:
0
a. Revising paragraph (g)(14);
0
b. Adding paragraphs (g)(95) and (96);
0
c. Adding paragraph (i)(2);
0
d. Adding paragraphs (l)(21) through (23); and
0
e. Adding paragraphs (m)(3) and (s).
The revisions and additions read as follows:

Sec. 63.14 Incorporation by reference.

* * * * *
(g) * * *
(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).
* * * * *
(95) ASTM D6196-03 (Reapproved 2009), Standard Practice for
Selection of Sorbents, Sampling, and Thermal Desorption Analysis
Procedures for Volatile Organic Compounds in Air, IBR approved for
appendix A to part 63: Method 325A, Sections 1.2 and 6.1, and Method
325B, Sections 1.3, 7.1.2, 7.1.3, and A.1.1.
(96) ASTM UOP539-12, Refinery Gas Analysis by Gas Chromatography,
IBR approved for Sec. 63.670(j).
* * * * *
(i) * * *
(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, IBR approved for
appendix A to part 63: Method 325A, Section 1.2, and Method 325B,
Sections 1.3, 7.1.3, and A.1.1.
* * * * *
(l) * * *
(21) EPA-454/R-99-005, Office of Air Quality Planning and Standards
(OAQPS), Meteorological Monitoring

[[Page 36963]]

Guidance for Regulatory Modeling Applications, February 2000, IBR
approved for appendix A to part 63: Method 325A, Section 8.3.
(22) 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 2008, IBR approved for Sec. 63.658(d) and appendix A to part 63:
Method 325A, Sections 8.1.4 and 10.0.
(23) EPA-454/B-13-003, Office of Air Quality Planning and Standards
(OAQPS), Quality Assurance Handbook for Air Pollution Measurement
Systems, Volume II: Ambient Air Quality Monitoring Program, May 2013,
IBR approved for Sec. 63.658(c) and appendix A to part 63: Method
325A, Section 4.1.
(m) * * *
(3) ISO 16017-2:2003, Indoor, Ambient and Workplace Air--Sampling
and Analysis of Volatile Organic Compounds by Sorbent Tube/Thermal
Desorption/Capillary Gas Chromatography--Part 2: Diffusive Sampling,
First edition, June 11, 2003, IBR approved for appendix A to part 63:
Method 325A, Sections 1.2, 6.1, and 6.5, and Method 325B, Sections 1.3,
7.1.2, 7.1.3, and A.1.1.
* * * * *
(s) U.S. Department of the Interior, 1849 C Street NW., Washington,
DC 20240, (202) 208-3100, www.doi.gov.
(1) Bulletin 627, Bureau of Mines, Flammability Characteristics of
Combustible Gases and Vapors, 1965, IBR approved for Sec. 63.670(l).
(2) [Reserved]

Subpart Y--[Amended]

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--[Amended]

0
13. Section 63.640 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (c) introductory text;
0
c. Adding paragraph (c)(9);
0
d. Revising paragraph (d)(5);
0
e. Revising paragraph (h);
0
f. Revising paragraph (k)(1);
0
g. Revising paragraph (l) introductory text;
0
h. Revising paragraph (l)(2) introductory text;
0
i. Revising paragraph (l)(2)(i);
0
j. Revising paragraph (l)(3) introductory text;
0
k. Revising paragraph (m) introductory text;
0
l. Revising paragraph (n) introductory text;
0
m. Revising paragraphs (n)(1) through (5);
0
n. Revising paragraph (n)(8) introductory text;
0
o. Revising paragraph (n)(8)(ii);
0
p. Adding paragraphs (n)(8)(vii) and (viii);
0
q. Revising paragraph (n)(9)(i);
0
r. Adding paragraph (n)(10);
0
s. Revising paragraph (o)(2)(i) introductory text;
0
t. Adding paragraph (o)(2)(i)(D);
0
u. Revising paragraph (o)(2)(ii) introductory text;
0
v. Adding paragraph (o)(2)(ii)(C); and
0
w. Revising paragraph (p)(2).
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 (c)(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 of this subpart, provided that on and after [THE DATE 3
YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE
FEDERAL REGISTER], any flares receiving gas from that fuel gas system
are in compliance with 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 63.661, 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.
(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 (h)(3)(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 paragraphs (i) or (j) of this
section, the requirements in paragraphs (l)(1) through (4) of this

[[Page 36964]]

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 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 paragraphs (l)(2)(i) or
(l)(2)(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
(l)(3)(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 subpart CC with other regulations for storage
vessels. As applicable, paragraphs (n)(1), (n)(3), (n)(4), (n)(6), and
(n)(7) of this section apply for Group 2 storage vessels and paragraphs
(n)(2) and (n)(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 CFR part 61, subpart Y is required to
comply only with the requirements of 40 CFR part 60, 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, subparts 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 (n)(8)(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 (n)(8)(vii) 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
subpart Kb or to inspect the vessel to determine compliance with Sec.
60.113b(a) of subpart Kb 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 Sec. 63.120(b)(7)(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 Sec. 63.1063(c)(2)(iv)(B) of subpart WW.
* * * * *
(vii) To be in compliance with Sec. 60.112b(a)(2)(ii) of this
chapter, floating roof storage vessels must be equipped with guidepole
controls as described in Appendix I: Acceptable Controls for Slotted
Guidepoles Under the Storage Tank Emissions Reduction Partnership
Program (available at https://www.epa.gov/ttn/atw/petrefine/petrefpg.html).
(viii) If a flare is used as a control device for a storage vessel,
on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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
subpart Ka 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 Sec. 63.120(b)(7)(ii) of subpart G (only up to the
compliance date specified in paragraph (h) of this section for

[[Page 36965]]

compliance with Sec. 63.660, as applicable) or either Sec.
63.1063(c)(2)(iv)(A) or Sec. 63.1063(c)(2)(iv)(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 (n)(8)(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 (n)(10)(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 Sec. 63.120(b)(7)(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 Sec. 63.1063(c)(2)(iv)(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 Sec. 61.272(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(b)(3) of this chapter,
floating roof storage vessels must be equipped with guidepole controls
as described in Appendix I: Acceptable Controls for Slotted Guidepoles
Under the Storage Tank Emissions Reduction Partnership Program
(available at https://www.epa.gov/ttn/atw/petrefine/petrefpg.html).
(viii) If a flare is used as a control device for a storage vessel,
on and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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.
(p) * * *
(2) Equipment leaks that are also subject to the provisions of 40
CFR part 60, subpart GGGa, are required to comply only with the
provisions specified in 40 CFR part 60, subpart GGGa. Owners and
operators of equipment leaks that are subject to the provisions of 40
CFR part 60, subpart GGGa and subject to this subpart may elect to
monitor equipment leaks following the provisions in Sec. 63.661,
provided that the equipment is in compliance with all other provisions
of 40 CFR part 60, subpart GGGa.
* * * * *
0
14. Section 63.641 is amended by:
0
a. Adding, in alphabetical order, new 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,''
``Halogenated vent stream or halogenated stream,'' ``Halogens and
hydrogen halides,'' ``Lower steam,'' ``Net heating value,'' ``Perimeter
assist air,'' ``Pilot gas,'' ``Premix assist air,'' ``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 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.

[[Page 36966]]

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 delayed coker vent
to 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 vent that is typically intermittent in
nature, and usually occurs only 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, but instead is routed to
the atmosphere through the delayed coking unit's blowdown system. 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 minimum amount of gas necessary 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 minimum amount
of gas necessary 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), flare sweep gas, flare purge gas and flare supplemental gas,
but does not include pilot gas, total steam or assist air.
* * * * *
Group 1 storage vessel means:
(1) Prior to [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS
IN THE FEDERAL REGISTER]:
(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-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 [THE DATE OF PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL REGISTER]:
(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

[[Page 36967]]

greater than 2 percent by weight total organic HAP.
* * * * *
Halogenated vent stream or halogenated stream means a stream
determined to have a mass rate of halogen atoms of 0.45 kilograms per
hour or greater, determined by the procedures presented in Sec.
63.115(d)(2)(v). The following procedures may be used as alternatives
to the procedures in Sec. 63.115(d)(2)(v)(A):
(1) Process knowledge that halogen or hydrogen halides are present
in a vent stream and that the vent stream is halogenated, or
(2) Concentration of compounds containing halogen and hydrogen
halides measured by Method 26 or 26A of part 60, Appendix A-8 of this
chapter, or
(3) Concentration of compounds containing hydrogen halides measured
by Method 320 of Appendix A of this part.
Halogens and hydrogen halides means hydrogen chloride (HCl),
chlorine (Cl2), hydrogen bromide (HBr), bromine
(Br2), and hydrogen fluoride (HF).
* * * * *
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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL
RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas from
the fuel gas system are in compliance with Sec. 63.670;
(2) Relief valve discharges regulated under Sec. 63.648;
(3) Leaks from equipment regulated under Sec. 63.648;
(4) [Reserved];
(5) In situ sampling systems (onstream analyzers) until [THE DATE 3
YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE
FEDERAL REGISTER]. 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 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 meeting the specifications of
Sec. 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);
(iii) An external floating roof converted to an internal floating
roof meeting the specifications of Sec. 63.1063(a)(1)(i) and (b); 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 (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 (b)(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.
* * * * *
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 paragraph (d)(3);

[[Page 36968]]

0
c. Revising paragraph (e);
0
d. Revising paragraph (i);
0
e. Revising paragraph (k) introductory text;
0
f. Revising paragraph (k)(1);
0
g. Revising paragraph (l) introductory text;
0
h. Revising paragraph (l)(2); and
0
i. 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 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 or
63.661, 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
or 63.661, 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 paragraph (a)(1) to read as
follows:

Sec. 63.643 Miscellaneous process vent provisions.

(a) * * *
(1) Reduce emissions of organic HAP's using a flare. On and after
[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet the
requirements of Sec. 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER],
the flare shall meet the requirements of Sec. 63.11(b) of subpart A or
the requirements of Sec. 63.670.
* * * * *
0
17. Section 63.644 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(2); and
0
c. Revising paragraph (c).
The revisions 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),
(a)(2), (a)(3), or (a)(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 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 [THE DATE 3 YEARS AFTER THE DATE
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 [THE DATE 3
YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE
FEDERAL REGISTER], 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 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 is an emissions standards violation.
Equipment such as low leg drains and equipment subject to Sec. 63.648
are not subject to this paragraph.

[[Page 36969]]

(1) Install, operate, calibrate, and maintain a continuous
parameter monitoring system for flow, as specified in paragraphs
(c)(1)(i) through (iii) of this section.
(i) Install a continuous parameter monitoring system for flow at
the entrance to any bypass line. The continuous parameter monitoring
system must record the volume of the gas stream that bypassed the
control device and must meet the applicable minimum accuracy,
calibration and quality control requirements specified in table 13 of
this subpart.
(ii) Equip the continuous parameter monitoring system for flow with
an alarm system that will alert an operator immediately and
automatically when flow is detected in the bypass line. Locate the
alarm such that an operator can easily detect and recognize the alert.
(iii) Reports and records shall be generated as specified in Sec.
63.655(g) and (i).
(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:
0
a. Adding introductory text to Sec. 63.646; and
0
b. Revising paragraph (b)(2).
The revisions and additions 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).
* * * * *
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 [THE DATE
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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. Revising paragraph (a) introductory text;
0
b. Adding paragraphs (a)(3) and (4);
0
c. Revising paragraph (c) introductory text;
0
d. Revising paragraph (c)(2)(ii);
0
e. Adding paragraphs (c)(11) and (12); and
0
f. Adding paragraph (j).
The revisions and additions read as follows:

Sec. 63.648 Equipment leak standards.

(a) Each owner or operator of an existing source subject to the
provisions of this subpart shall comply with the provisions of part 60,
subpart VV of this chapter and paragraph (b) of this section except as
provided in paragraphs (a)(1), (a)(2), and (c) through (i) of this
section. Each owner or operator of a new source subject to the
provisions of this subpart shall comply with subpart H of this part
except as provided in paragraphs (c) through (i) of this section. As an
alternative to the monitoring requirements of part 60, subpart VV of
this chapter or subpart H of this part, as applicable, the owner or
operator may elect to monitor equipment leaks following the provisions
in Sec. 63.661.
* * * * *
(3) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of complying with
the requirements of Sec. 60.482-6(a)(2) of this chapter, the term
``seal'' or ``sealed'' means that instrument monitoring of the open-
ended valve or line conducted according to the method specified in
Sec. 60.485(b) and, as applicable, Sec. 60.485(c) of this chapter
indicates no readings of 500 parts per million or greater.
(4) If a flare is used as a control device, on and after [THE DATE
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet
the applicable requirements of part 60, subpart VV of this chapter, or
the requirements of Sec. 63.670.
* * * * *

[[Page 36970]]

(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 of this
part except as provided in paragraphs (c)(1) through (c)(12) and (e)
through (i) of this section.
* * * * *
(2) * * *
(ii) If an owner or operator elects to monitor connectors according
to the provisions of Sec. 63.649, paragraphs (b), (c), or (d), then
the owner or operator shall monitor valves at the frequencies specified
in table 9 of this subpart. If an owner or operator elects to comply
with Sec. 63.649, the owner or operator cannot also elect to comply
with Sec. 63.661.
* * * * *
(11) On and after [THE DATE OF PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL REGISTER], for the purpose of complying with
the requirements of Sec. 63.167(a)(2), the term ``seal'' or ``sealed''
means that instrument monitoring of the open-ended valve or line
conducted according to the method specified in Sec. 63.180(b) and, as
applicable, Sec. 63.180(c) of this chapter indicates no readings of
500 parts per million or greater.
(12) If a flare is used as a control device, on and after [THE DATE
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 relief valves 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 paragraph (j)(4) of this section, the owner or operator
must also comply with the requirements specified in paragraph (j)(3) of
this section for all relief valves in organic HAP service.
(1) Operating requirements. Except during a pressure release,
operate each relief valve 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 relief valves in organic HAP
gas or vapor service, the owner or operator must comply with either
paragraph (j)(2)(i) or (ii) of this section following a pressure
release.
(i) If the relief valve 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
relief valve returns to organic HAP gas or vapor service following a
pressure release to verify that the relief valve is operating with an
instrument reading of less than 500 ppm.
(ii) If the relief valve consists of or includes 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 must also 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 relief valve returns to organic
HAP gas or vapor service following a pressure release to verify that
the relief valve is operating with an instrument reading of less than
500 ppm.
(3) Pressure release management. Except as specified in paragraph
(j)(4) of this section, emissions of organic HAP may not be discharged
to the atmosphere from relief valves in organic HAP service, and on or
before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL
RULE AMENDMENTS IN THE FEDERAL REGISTER], the owner or operator shall
comply with the requirements specified in paragraphs (j)(3)(i) and (ii)
of this section for all relief valves in organic HAP service.
(i) The owner or operator must equip each relief valve in organic
HAP service with a device(s) or use a monitoring system that is capable
of: (1) Identifying the pressure release; (2) recording the time and
duration of each pressure release; and (3) 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) If any relief valve in organic HAP service vents or releases
to atmosphere as a result of a pressure release event, the owner or
operator must calculate the quantity of organic HAP released during
each pressure release event and report this quantity as required in
Sec. 63.655(g)(10)(iii). Calculations may be based on data from the
relief valve monitoring alone or in combination with process parameter
monitoring data and process knowledge.
(4) Relief valves routed to a control device. If all releases and
potential leaks from a relief valve in organic HAP service are routed
through a closed vent system to a control device, the owner or operator
is not required to comply with paragraphs (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, all references to ``Group 1
miscellaneous process vent'' in 63.644 mean ``relief valve.''
0
22. 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, Sec. Sec. 63.421, 63.422(a)
through (c) and (e), 63.425(a) through (c) and (i), 63.425(e) through
(h), 63.427(a) and (b), and 63.428(b), (c), (g)(1), (h)(1) through (3),
and (k).
* * * * *
(d) If a flare is used as a control device, on and after [THE DATE
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet
the applicable requirements of subpart R of this part, or the
requirements of Sec. 63.670.
0
23. Section 63.651 is amended by revising paragraph (a) 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

[[Page 36971]]

the requirements of Sec. Sec. 63.560 through 63.568.
* * * * *
(e) If a flare is used as a control device, on and after [THE DATE
3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN
THE FEDERAL REGISTER], the flare shall meet the requirements of Sec.
63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare shall meet
the applicable requirements of subpart Y of this part, or the
requirements of Sec. 63.670.
0
24. Section 63.652 is amended by:
0
a. Revising paragraph (a);
0
b. Removing and reserving paragraph (f)(2);
0
c. Revising paragraph (g)(2)(iii)(B)(1);
0
d. Revising paragraph (h)(3);
0
e. Revising paragraph (k) introductory text; and
0
f. Revising paragraph (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 of this subpart, as applicable, or a boiler or
process heater meeting the criteria in Sec. 63.645(d) of this subpart
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 (b)(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) Sections 63.1063(a)(1)(i), (a)(2), and (b) or Sec. 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) Sections 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) Sections 63.1063(a)(1)(i), (a)(2), and (b) or Sec. 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
25. Section 63.653 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraphs (a)(3)(i) and (ii); and
0
c. Revising paragraph (a)(7).
The revisions 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
26. Section 63.655 is amended by:
0
a. Revising paragraph (f) introductory text;
0
b. Revising paragraph (f)(1) introductory text;
0
c. Revising paragraph (f)(1)(i)(A) introductory text;
0
d. Revising paragraphs (f)(1)(i)(A)(2) and (3);
0
e. Revising paragraph (f)(1)(i)(B) introductory text;
0
f. Revising paragraph (f)(1)(i)(B)(2);
0
g. Revising paragraph (f)(1)(i)(D)(2);
0
h. Revising paragraph (f)(1)(iv) introductory text;
0
i. Revising paragraph (f)(1)(iv)(A);
0
j. Adding paragraph (f)(1)(vii);
0
k. Revising paragraph (f)(2) introductory text;
0
l. Revising paragraph (f)(3) introductory text;
0
m. Revising paragraph (f)(6);
0
n. Revising paragraph (g) introductory text;

[[Page 36972]]

0
o. Revising paragraphs (g)(1) through (5);
0
p. Revising paragraph (g)(6)(iii);
0
q. Revising paragraph (g)(7)(i);
0
r. Adding paragraphs (g)(10) through (13);
0
s. Removing and reserving paragraph (h)(1);
0
t. Revising paragraph (h)(2) introductory text;
0
u. Revising paragraph (h)(2)(i)(B);
0
v. Revising paragraph (h)(2)(ii);
0
w. Adding paragraphs (h)(8) and (9);
0
x. Adding paragraph (i) introductory text;
0
y. Revising paragraph (i)(1) introductory text;
0
z. Revising paragraph (i)(1)(ii);
0
aa. Adding paragraphs (i)(1)(v) and (vi);
0
bb. Redesignating paragraph (i)(4) and (5) as (i)(5) and (6)
respectively;
0
cc. Adding paragraph (i)(4);
0
dd. Revising newly redesignated paragraph (i)(5) introductory text; and
0
ee. Adding paragraphs (i)(7) through (11).
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 (f)(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) of this subpart.
(1) The Notification of Compliance Status report shall include the
information specified in paragraphs (f)(1)(i) through (f)(1)(vii) 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
(f)(1)(i)(A)(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. 63.645 of this subpart
and Sec. 63.116(a) of subpart G of this part or Sec. 63.670(h) of
this subpart, as applicable, and
* * * * *
(vii) For relief valves in organic HAP service, a description of
the monitoring system to be implemented, including the relief valves
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.
(2) If initial performance tests are required by Sec. Sec. 63.643
through 63.653 of this subpart, the Notification of Compliance Status
report shall include one complete test report for each test method used
for a particular source. On and after [THE DATE 3 YEARS AFTER THE DATE
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER],
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 (f)(3)(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. Six-month periods shall be the same
6-month periods specified in paragraph (g) of this section. The
Notification of Compliance Status report shall include the information
specified in paragraphs (f)(1) through (f)(5) 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,
as part of the periodic report, or in any combination of these four. If
the required information has been submitted before the date 60 days
after the end of the 6-month period in which the addition of the Group
1 emission

[[Page 36973]]

point took place, a separate Notification of Compliance Status report
is not required within 60 days after the end of the 6-month period. If
an owner or operator submits the information specified in paragraphs
(f)(1) through (f)(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.
(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 (12) 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 paragraph (g)(1) through (7) of this section or
paragraphs (g)(9) through (12) 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 if the reports contain
the information required by paragraphs (g)(1) through (12) of this
section.
(1) For storage vessels, Periodic Reports shall include the
information specified for Periodic Reports in paragraph (g)(2) through
(g)(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)(C) 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 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 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 (g)(2)(ii)(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) and (B) 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), (b)(4), (b)(5), or (b)(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 (b)(4) of subpart G.
(3) A description of any seal condition specified in Sec.
63.120(b)(5) or (b)(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

[[Page 36974]]

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).
(B) An owner or operator who elects to use an extension in
accordance with Sec. 63.1063(e)(2) or Sec. 63.1063(c)(2)(iv)(B) of
subpart WW shall, in the next Periodic Report, submit the documentation
required by those paragraphs.
(4) An owner or operator who elects to comply with Sec. 63.646 or
Sec. 63.660 by using an external floating roof converted to an
internal floating roof shall comply with the periodic reporting
requirements of paragraph (g)(2)(i) of this section.
(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 (g)(5)(iii) 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 (e)(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 [THE DATE 3 YEARS AFTER THE DATE
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER]
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 of this part and shall include: Identification of
the flare that does not meet the general requirements specified in
Sec. 63.11(b) of subpart A of this part, and reasons the flare did not
meet the general requirements specified in Sec. 63.11(b) of subpart A
of this part.
(iv) If a flare is used on and after compliance with the
requirements in Sec. 63.670 is elected, which can be no later than
[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL REGISTER], 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) * * *
(iii) For closed vent systems, include the records of periods when
vent stream flow was detected in the bypass line or diverted from the
control device, a flow indicator was not operating or a bypass of the
system was indicated, as specified in paragraph (i)(4) of this section.
(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 relief valves, Periodic Reports must include the
information specified in paragraphs (g)(10)(i) through (iii) of this
section.
(i) For relief valves in organic HAP gas or vapor service, pursuant
to Sec. 63.648(j), report any instrument reading of 500 ppm or
greater, more than 5 days after the relief valve returns to service
after a pressure release.
(ii) For relief valves in organic HAP gas or vapor service subject
to Sec. 63.648(j)(2), report confirmation that all monitoring to show
compliance was conducted within the reporting period.
(iii) For relief valves in organic HAP service, report each
pressure release to the atmosphere, including duration of the pressure
release and estimate of quantity of substances released.
(11) For flares subject to Sec. 63.670, Periodic Reports must
include the information specified in paragraphs (g)(11)(i) through
(iii) of this section.
(i) Records as specified in paragraph (i)(9)(i) of this section for
each period when regulated material is routed to a flare and a pilot
flame is not present.
(ii) Visible emission records as specified in paragraph (i)(9)(ii)
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 15-minute block average
operating parameters determined following the methods in Sec.
63.670(k) through (o) as applicable, and an indication of whether the
three criteria in Sec. 63.670(e)(vi) were all met for that 15-minute
block period.
(iv) Records as specified in paragraph (i)(9)(x) of this section
for each period when a halogenated vent stream as defined in Sec.
63.641 is discharged to the flare.
(12) If a source fails to meet an applicable standard, report such
events in the Periodic Report. Report the number of failures to meet an
applicable standard. For each instance, report the date, time and
duration of each failure. For each failure the report must include a
list of the affected sources or equipment, an estimate of the quantity
of each regulated pollutant emitted over any emission limit, and a
description of the method used to estimate the emissions.
(13) Any changes in the information provided in a previous
Notification of Compliance Status report.

[[Page 36975]]

(h) * * *
(2) For storage vessels, notifications of inspections as specified
in paragraphs (h)(2)(i) and (h)(2)(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), Sec.
63.120(a)(3), or Sec. 63.120(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 (b)(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.
* * * * *
(8) For fenceline monitoring systems subject to Sec. 63.658,
within 45 calendar days after the end of each semiannual reporting
period, each owner or operator shall submit the following information
to the EPA's Compliance and Emissions Data Reporting Interface (CEDRI)
that is accessed through the EPA's Central Data Exchange (CDX)
(www.epa.gov/cdx). 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
episode during the semiannual 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 12-month rolling average concentration difference
([Delta]c) values for benzene for the semiannual 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 [THE DATE OF PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL REGISTER], if required to submit the results
of a performance test or CEMS performance evaluation, the owner or
operator shall submit the results using EPA's Electronic Reporting Tool
(ERT) 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 according to the method specified
by either paragraph (h)(9)(i)(A) or (h)(9)(i)(B) of this section.
(A) For data collected using test methods supported by the EPA's
ERT as listed on the EPA's ERT Web site (https://www.epa.gov/ttn/chief/ert/), the owner or operator must submit the results of the
performance test to the CEDRI accessed through the EPA's CDX (https://cdx.epa.gov/epa_home.asp), unless the Administrator approves another
approach. Performance test data must be submitted in a file format
generated through the use of the EPA's ERT. 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,
including information claimed to be CBI, on a compact disc or other
commonly used electronic storage media (including, but not limited to,
flash drives) by registered letter to the EPA. The electronic media
must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI
Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page
Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be
submitted to the EPA via CDX as described earlier in this paragraph.
(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, 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
according to the method specified by either paragraph (h)(9)(ii)(A) or
(h)(9)(ii)(B) of this section.
(A) For data collection of relative accuracy test audit (RATA)
pollutants that are supported by the EPA's ERT as listed on the ERT Web
site, the owner or operator must submit the results of the performance
evaluation to the CEDRI that is accessed through the EPA's CDX, unless
the Administrator approves another approach. Performance evaluation
data must be submitted in a file format generated through the use of
the EPA's ERT. 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, including information claimed to be CBI, on a compact disc
or other commonly used electronic storage media (including, but not
limited to, flash drives) by registered letter to the EPA. The
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02,
4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI
omitted must be submitted to the EPA via CDX as described earlier in
this paragraph.
(B) For any performance evaluation data with RATA pollutants that
are not supported by the EPA's ERT as listed on the EPA's ERT Web site,
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 (11) 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 of this part except as specified in paragraphs (i)(1)(i)

[[Page 36976]]

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 of
this part 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.
(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 to the
atmosphere, or cause air intrusion into the control device, 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 any alarms
triggered because flow was detected in the bypass line, including the
date and time the alarm was triggered and the duration of the flow in
the bypass line. The owner or operator shall also maintain records of
all periods when the vent stream is diverted from the control device or
air intrudes into the control device. 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.
(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 emissions
of organic HAP that bypassed the control device.
(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 of
the average pressure 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.
(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 (ix) of this section on an ongoing basis.
(i) Coordinates of all passive monitors, including replicate
samplers and field blanks, and 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) Daily unit vector wind direction, calculated daily sigma
theta, daily average temperature and daily average 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 episode and the two samples used to determine it,
whether background correction was used, and the 12-month rolling
average [Delta]c calculated after each sampling episode.
(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.
(9) For each flare subject to Sec. 63.670, each owner or operator
shall keep the records specified in paragraphs (i)(9)(i) through (vii)
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 periods during which the pilot
flame is not present when regulated material is routed to a flare for a
minimum of 5 years.
(ii) Daily visible emissions observations, as required in Sec.
63.670(c), as well as any observations required in Sec. 63.670(h). 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.
(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 or total hydrocarbon 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 (m), as
applicable.
(vi) The 15-minute block average olefins, hydrogen, and olefins
plus

[[Page 36977]]

hydrogen concentration in the combustion zone used to determine if the
criteria in Sec. 63.670(e)(4) are met. If process knowledge and
engineering calculations are used, retain records of the information
used in the assessment and records of all compositional analyses
required in Sec. 63.670(o)(ii). Identify all 15-minute block averages
for which all three criteria in Sec. 63.670(e)(4) are met or are
assumed to be met.
(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) All periods during which a halogenated vent stream, as defined
in Sec. 63.641, is discharged to the flare. Records shall include the
start time and date of the event, the end time and date of the event,
and an estimate of the cumulative flow of the halogenated vent stream
over the duration of the event.
(10) If the owner or operator elects to comply with Sec. 63.661,
the owner or operator shall keep the records described in paragraphs
(i)(10)(i) through (v) of this section.
(i) The equipment and process units for which the owner or operator
chooses to use the optical gas imaging instrument.
(ii) All records required by part 60, Appendix K of this chapter,
as applicable.
(iii) A video record to document the leak survey results. The video
record must include a time and date stamp for each monitoring event.
(iv) Identification of the equipment screened and the time and date
of the screening.
(v) Documentation of repairs attempted and repairs delayed. If
repair of a leak is confirmed using the optical gas imaging instrument,
then instead of the maximum instrument reading measured by Method 21 of
part 60, Appendix A-7 of this chapter, the owner or operator shall keep
a video record following repair to confirm the equipment is repaired.
(11) Other records must be kept as specified in paragraphs
(i)(11)(i) through (iii) of this section.
(i) 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.
(ii) 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.
(iii) Record actions taken to minimize emissions in accordance with
Sec. 63.642(n), and any corrective actions taken to return the
affected unit to its normal or usual manner of operation.
0
27. Section 63.656 is amended by:
0
a. Revising paragraph (c) introductory text;
0
b. Revising paragraph (c)(1); and
0
c. Adding paragraph (c)(5).
The revisions and additions read as follows:

Sec. 63.656 Implementation and enforcement.

* * * * *
(c) The authorities that cannot be delegated to state, local, or
Tribal agencies are as specified in paragraphs (c)(1) through (5) of
this section.
(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 63.661, 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.
* * * * *
(5) Approval of the corrective action plan under Sec. 63.658(h).
0
28. Section 63.657 is added to read as follows:

Sec. 63.657 Delayed coking unit decoking operation standards.

(a) 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 is 2 pounds per square inch gauge (psig) or less
prior to venting to the atmosphere, draining or deheading the coke drum
at the end of the cooling cycle.
(b) Each owner or operator of a delayed coking unit shall install,
operate, calibrate, and maintain a continuous parameter monitoring
system to determine the coke drum vessel pressure. The pressure
monitoring system must be capable of measuring a pressure of 2 psig
within 0.5 psig.
(c) The owner or operator of a delayed coking unit shall determine
the coke drum vessel pressure on a 5-minute rolling average basis while
the coke drum is vented to the closed blowdown system to demonstrate
compliance the requirement in paragraph (a) of this section. Pressure
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 for the purpose of compliance with the
requirement in paragraph (a) of this section.
0
29. 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.
(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. General guidance for siting passive monitors can be found in EPA-
454/R-98-004, Quality Assurance Handbook for Air Pollution Measurement
Systems, Volume II: Part 1: Ambient Air Quality Monitoring Program
Quality System Development, August 1998 (incorporated by reference--see
Sec. 63.14). Alternatively, the owner or operator may elect to place
monitors at 2 kilometers intervals as measured along the property
boundary, provided additional monitors are located, if necessary, as
required in Section 8.2.2.5 in Method 325A of Appendix A of this part.
(1) As it pertains to this subpart, known emission source, as used
in Section 8.2.2.5 in Method 325A of Appendix A of this part for siting
passive monitors means a wastewater treatment unit or a Group 1 storage
vessel.
(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 plant, the background sampler(s) should be

[[Page 36978]]

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 episode and at
least two field blanks per sampling episode, 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 use a dedicated meteorological
station in accordance with Section 8.3 of Method 325A of Appendix A of
this part.
(1) The owner or operator shall collect and record hourly average
meteorological data, including wind speed, wind direction and
temperature.
(2) The owner or operator shall follow the calibration and
standardization procedures for meteorological measurements in EPA-454/
B-08-002, Quality Assurance Handbook for Air Pollution Measurement
Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final),
March 2008 (incorporated by reference--see Sec. 63.14).
(e) The length of the sampling episode must be fourteen days,
unless a shorter sampling episode is determined to be necessary under
paragraph (g) or (i) of this section. A sampling episode is defined as
the period during which the owner or operator collects the sample and
does not include the time required to analyze the sample.
(f) Within 30 days of completion of each sampling episode, the
owner or operator shall determine whether the results are above or
below the action level as follows:
(1) For each sampling episode, the owner or operator shall
determine the highest and lowest sample results for benzene from the
sample pool and calculate the difference in concentration ([Delta]c).
(i) The owner or operator shall adhere to the following procedures
when one or more samples for the sampling episode 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) If the owner or operator identifies an offsite upwind source
or an onsite source excluded under Sec. 63.640(g) that contributes to
the benzene concentration at any passive monitor and collects
background samples according to an approved site-specific monitoring
plan, 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 average the [Delta]c values
collected over the twelve months prior to and including the most recent
sampling episode. The owner or operator shall update this value after
receiving the results of each sampling episode.
(3) The action level for benzene is 9 micrograms per cubic meter
([mu]g/m\3\). If the 12-month rolling average [Delta]c value for
benzene is less than 9 [mu]g/m\3\, the concentration is below the
action level. If the 12-month rolling average [Delta]c value for
benzene is equal to or 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 12-month rolling average and no longer than 35 days
after completion of the sampling episode, the owner or operator shall
initiate a root cause analysis to determine the cause of such
exceedance and to determine appropriate corrective action, as described
in paragraphs (g)(1) through (4) of this section. The root cause
analysis and corrective action analysis shall be completed 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 as specified in Sec.
63.661 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 episodes for Methods 325A and
325B of Appendix A of this part, or using active sampling techniques),
or employing additional monitors to determine contributing offsite
sources.
(h) If, upon completion of the corrective actions described in
paragraph (g) of this section, the action level is exceeded for the
next sampling episode following the completion of the corrective
action, 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 Administrator within 60 days after
determining the action level was exceeded during the sampling episode
following the completion of the initial corrective action. 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.
(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.
(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 for each monitoring location, the near field source
or sources that are expected to contribute to fenceline 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

[[Page 36979]]

concentration contribution for each monitoring location.
(v) If more frequent monitoring is proposed or if a monitoring
station other than a passive diffusive tub monitoring station is
proposed, provide a detailed description of the measurement methods,
measurement frequency, and recording frequency proposed 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
(2)(i) through (iii) of this section.
(i) For each monitoring location, calculate [Delta]ci
using the following equation.

[Delta]ci = MCFi - 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 specified included in the site-specific
monitoring plan, [mu]g/m\3\. If no additional measurement location
is 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 episode 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 detection, 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
detection, 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 process for a site-specific monitoring plan. Factors that
the EPA 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 or if a monitoring
station other than a passive diffusive tub monitoring station is
proposed, the adequacy of the description of the measurement methods,
measurement frequency, and recording frequency proposed and the
adequacy of the rationale for using the alternative monitoring
frequency or method.
(j) The owner or operator shall comply with the applicable
recordkeeping and reporting requirements in Sec. 63.655(h) and (i).
0
30. 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 subpart 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, subpart WW, or subpart
SS of this part. The definitions of ``Group 1 storage vessel'' (item 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,

[[Page 36980]]

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) In addition to the options presented in Sec. Sec.
63.1063(a)(2)(vii)(A), 63.1063(a)(2)(vii)(B), and 63.1064, an external
floating roof storage vessel may comply with Sec. 63.1063(a)(2)(vii)
using a flexible enclosure system as described in item 6 of Appendix I:
Acceptable Controls for Slotted Guidepoles Under the Storage Tank
Emissions Reduction Partnership Program (available at https://www.epa.gov/ttn/atw/petrefine/petrefpg.html).
(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 [THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS
IN THE FEDERAL REGISTER].
(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 [THE DATE OF PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL REGISTER].
(4) All references to ``the proposal date of the relevant standard
established pursuant to CAA section 112(f)'' in 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 existing storage vessel fixed roof that meets the
definition of Group 1 storage vessel (item 2) in Sec. 63.641 but not
the definition of Group 1 storage vessel (item 1) in Sec. 63.641, the
requirements of Sec. 63.1062 do not apply until the next time the
storage vessel is completely emptied and degassed, or [THE DATE 10
YEARS AFTER PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL
REGISTER], 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 (c)(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.
63.985(a)(3)(i) or (ii) for each closed vent system that contains
bypass lines that could divert a vent stream to the atmosphere. Use of
the bypass at any time to divert a Group 1 storage vessel to the
atmosphere is an emissions standards violation. Equipment such as low
leg drains and equipment subject to Sec. 63.648 are not subject to
this paragraph.
(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 paragraph
Sec. 63.984(a)(1) does not apply.
0
31. Section 63.661 is added to read as follows:

Sec. 63.661 Alternative means of emission limitation: Monitoring
equipment leaks using optical gas imaging.

(a) Applicability. The owner or operator may only use an optical
gas imaging instrument to screen for leaking equipment, as required by
Sec. 63.648, if the requirements in paragraphs (a)(1) through (3) of
this section are met.
(1) The owner or operator may only use the optical gas imaging
instrument as an alternative to provisions in Sec. 63.648 that would
otherwise require monitoring according to Sec. 60.485(b) or Sec.
63.180(b)(1) through (5), as applicable. The owner or operator shall
continue to comply with all other requirements in Sec. 63.648 (e.g.,
weekly inspections of pumps; for relief valves, installation of a
device that is capable of identifying and recording the time and
duration of each pressure release, if applicable; sampling connection
system requirements).
(2) The owner or operator must be in compliance with the fenceline
monitoring provisions of Sec. 63.658.
(3) The optical gas imaging instrument must be able to meet all of
the criteria and requirements specified in part 60, Appendix K of this
chapter, and the owner or operator shall conduct monitoring according
to part 60, Appendix K of this chapter.
(b) Compliance requirements. The owner or operator shall meet the
requirements of paragraphs (b)(1) through (3) of this section.
(1) The owner or operator shall identify the equipment and process
units for which the optical gas imaging instrument will be used to
identify leaks.
(2) The owner or operator shall repair leaking equipment as
required in the applicable section of part 60, subpart VV of this
chapter or subpart H of this part.
(3) Monitoring to confirm repair of leaking equipment must be
conducted using the procedures referenced in paragraph (a)(2) of this
section.
(c) Recordkeeping. The owner or operator shall comply with the
applicable requirements in Sec. 63.655(i).
0
32. Section 63.670 is added to read as follows:

Sec. 63.670 Requirements for flare control devices.

On or before [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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) Halogenated vent streams. The owner or operator shall not use a
flare

[[Page 36981]]

to control halogenated vent streams as defined in Sec. 63.641.
(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. The pilot system must be equipped with an
automated device to relight the pilot if extinguished. The owner or
operator shall monitor for the presence of a pilot flame as specified
in paragraph (g) of this section.
(c) Visible emissions. Each flare must be designed for and operated
with no visible emissions, except for periods not to exceed a total of
5 minutes during any 2 consecutive hours. The owner or operator shall
monitor for visible emissions from the flare as specified in paragraph
(b) of this section.
(d) Flare tip velocity. For each flare, the owner or operator shall
comply with either paragraph (d)(1) or (d)(2) of this section, provided
the appropriate monitoring systems are in-place. If a total hydrocarbon
analyzer is used for compositional analysis as allowed under section
(j)(4) of this section, then the owner or operator must comply with
paragraph (d)(1) of this section.
(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 when regulated material is being routed to the flare. The
owner or operator shall monitor Vtip using the procedures
specified in paragraph (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 at all times regulated
material is being routed to the flare. The owner or operator shall
monitor Vtip using the procedures specified in paragraph (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] TP30JN14.005

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) Target combustion zone gas properties. For each flare, the
owner or operator shall comply with the applicable requirements in
either paragraph (e)(1), (2), or (3) of this section. The owner or
operator may elect to comply with any of these applicable requirements
at any time (e.g., may elect to comply with the requirements in
paragraph (e)(1) during certain flow conditions and comply with the
requirements in paragraph (e)(2) or (e)(3) under different flow
conditions) provided that the owner or operator has the appropriate
monitoring equipment to determine compliance with the specified
requirement.
(1) The net heating value of flare combustion zone gas
(NHVcz) must be greater than or equal to the target values
in paragraphs (e)(1)(i) or (ii), as applicable, when regulated material
is being routed to the flare. The owner or operator shall monitor and
calculate NHVcz as specified in paragraph (m) of this
section.
(i) For flares meeting all three requirements in paragraph (e)(4)
of this section, the target NHVcz value is 380 British
thermal units per standard cubic feet (Btu/scf).
(ii) For all flares other than those meeting all three requirements
in paragraph (e)(4) of this section, the target NHVcz value
is 270 Btu/scf.
(2) The lower flammability limit of the combustion zone gas
(LFLcz) must be less than or equal to the target values in
paragraphs (e)(2)(i) or (ii), as applicable, when regulated material is
being routed to the flare. The owner or operator shall monitor and
calculate LFLcz as specified in paragraph (m) of this
section.
(i) For flares meeting all three requirements in paragraph (e)(4)
of this section, the target LFLcz value is 0.11 volume
fraction.
(ii) For all flares other than those meeting all three requirements
in paragraph (e)(4) of this section, the target LFLcz value
is 0.15 volume fraction.
(3) The total volumetric fraction of hydrogen and combustible
organic components present in the combustion zone gas (Ccz),
as propane, must be greater than or equal to the target values in
paragraphs (e)(3)(i) or (ii), as applicable, when regulated material is
being routed to the flare. The owner or operator shall monitor and
calculate Ccz as specified in paragraph (m) of this section.
(i) For flares meeting all three requirements in paragraph (e)(4)
of this section, the target Ccz value is 0.23 volume
fraction as propane.
(ii) For all flares other than those meeting all three requirements
in paragraph (e)(4) of this section, the target Ccz value is
0.18 volume fraction as propane.
(4) More stringent combustion zone gas target properties apply only
during those flare flow periods when all three conditions in paragraphs
(e)(4)(i) through (iii) simultaneously exist. The owner or operator
shall monitor and calculate hydrogen and cumulative olefin combustion
zone concentrations as specified in paragraph (o) of this section:
(i) The concentration of hydrogen in the combustion zone is greater
than 1.2 percent by volume.
(ii) The cumulative concentration of olefins in the combustion zone
is greater than 2.5 percent by volume.
(iii) The cumulative concentration of olefins in the combustion
zone plus the concentration of hydrogen in the combustion zone is
greater than 7.4 percent by volume.
(f) Target dilution parameters for flares with perimeter assist
air. For each flare actively receiving perimeter assist air, the owner
or operator shall comply with the applicable requirements in either
paragraph (f)(1), (2), or (3) of this section in addition to complying
with the target combustion zone gas properties as specified in
paragraph (e) of this section. The owner or operator may elect to
comply with any of these applicable requirements at any time (e.g., may
elect to comply with the requirements in paragraph (f)(1) during
certain flow conditions and comply with the requirements in paragraph
(f)(2) or (f)(3) under different flow conditions) provided that the
owner or operator has the appropriate monitoring equipment to determine
compliance with the specified requirement.
(1) The net heating value dilution parameter (NHVdil)
must be greater than or equal to the target values in paragraphs
(f)(1)(i) or (ii), as applicable, when regulated material is being
routed to the flare. The owner or operator shall monitor and calculate
NHVdil as specified in paragraph (n) of this section.
(i) For flares meeting all three requirements in paragraph (e)(4)
of this section, the target NHVdil value is 31

[[Page 36982]]

British thermal units per square foot (Btu/ft\2\).
(ii) For all flares other than those meeting all three requirements
in paragraph (e)(4) of this section, the target NHVdil value
is 22 Btu/ft\2\.
(2) The lower flammability limit dilution parameter
(LFLdil) must be less than or equal to the target values in
paragraphs (f)(2)(i) or (ii), as applicable, when regulated material is
being routed to the flare. The owner or operator shall monitor and
calculate LFLdil as specified in paragraph (n) of this
section.
(i) For flares meeting all three requirements in paragraph (e)(4)
of this section, the target LFLdil value is 1.6 volume
fraction per foot (volume fraction/ft).
(ii) For all flares other than those meeting all three requirements
in paragraph (e)(4) of this section, the target LFLdil value
is 2.2 volume fraction/ft.
(3) The combustibles concentration dilution parameter
(Cdil) must be greater than or equal to the target values in
paragraphs (f)(3)(i) or (ii), as applicable, when regulated material is
being routed to the flare. The owner or operator shall monitor and
calculate Cdil as specified in paragraph (n) of this
section.
(i) For flares meeting all three requirements in paragraph (e)(4)
of this section, the target Cdil value is 0.015 volume
fraction-ft.
(ii) For all flares other than those meeting all three requirements
in paragraph (e)(4) of this section, the target Ccz value is
0.012 volume fraction-ft.
(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 at a minimum of once per day 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.
(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. 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.
(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 [deg]F] and a
pressure of 1 atm). The flare vent gas flow rate monitoring system(s)
must also be able to output flow in actual conditions for use in the
flare tip velocity calculation.
(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] TP30JN14.006

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 paragraphs (j)(1) or
(j)(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 or the
combustibles concentration following the methods provided in paragraphs
(j)(4) of this section.. The owner or operator electing to directly
monitor the net heating value of the flare vent gas must comply with
the net heating value operating limits in paragraph (e) and, if
applicable, paragraph (f) of this section. The owner or operator
electing to directly monitor the combustibles concentration in the
flare vent gas must comply with the combustibles concentration
operating limits in paragraph (e) and, if applicable, paragraph (f) of
this section, and must comply with the maximum velocity requirements in
paragraph (d)(1) of this section.
(1) Except as provided in paragraph (j)(5) 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 paragraph (j)(5) 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

[[Page 36983]]

60, Appendix A-6, ASTM D1945-03 (Reapproved 2010) (incorporated by
reference--see Sec. 63.14), or ASTM UOP539-12 (incorporated by
reference--see Sec. 63.14).
(3) The owner or operator shall install, operate, calibrate, and
maintain a monitoring system capable of continuously measuring,
calculating, and recording NHVvg. at standard conditions.
(4) The owner or operator shall install, operate, calibrate, and
maintain a monitoring system capable of continuously measuring,
calculating, and recording total hydrocarbon content (as propane) as a
surrogate for combustibles concentration.
(5) Direct compositional monitoring is not required for pipeline
quality natural gas streams. In lieu of monitoring the composition of a
pipeline quality natural gas stream, the following composition can be
used for any pipeline quality natural gas stream.
(i) 93.2 volume percent (vol %) methane.
(ii) 3.2 vol % ethane.
(iii) 0.6 vol % propane.
(iv) 0.3 vol % butane.
(v) 2.0 vol % hydrogen.
(vi) 0.7 vol % nitrogen.
(k) Calculation methods for 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 vent gas does not exit through them.
(2) The owner or operator shall determine the cumulative volumetric
flow of 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.
(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 of 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 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] TP30JN14.007

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
paragraph (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 parameters.
The owner or operator shall determine the net heating value, lower
flammability limit, and/or combustibles concentration vent gas of the
flare (NHVvg, LFLvg, and/or Cvg,
respectively) based on the composition monitoring data on a 15-minute
block average basis according to the following requirements.
(1) 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.
(2) When a continuous monitoring system is used to determine flare
vent gas composition, net heating value, or total hydrocarbon content:
(i) Use the results from the first sample collected during an
event, (for periodic flare vent gas flow events) for the first and
second 15-minute block associated with that event.
(ii) For all other 15-minute block periods, 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 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.
(3) 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 the
purpose of this requirement, use the time the sample was collected
rather than the time the analytical results become available.
(4) The owner or operator shall determine NHVvg from
compositional analysis data by using the following equation. If the
owner or operator uses a monitoring system(s) capable of continuously
measuring, calculating, and recording NHVvg, as provided in
paragraph (j)(3) of this section, the owner or operator shall use the
NHVvg as determined by the continuous NHVvg
monitor.
[GRAPHIC] [TIFF OMITTED] TP30JN14.008

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.

[[Page 36984]]

(5) The owner or operator shall calculate LFLvg using
the following equation:
[GRAPHIC] [TIFF OMITTED] TP30JN14.009

Where:

LFLvg = Lower flammability limit of flare vent gas,
volume fraction.
n = Number of components in the vent gas.
i = Individual component in the vent gas.
[chi]i = Concentration of component i in the vent gas,
volume percent (vol %).
LFLi = Lower flammability limit of component i according
to table 12 of this subpart, vol %. If the component is not
specified in table 12 of this subpart, the owner or operator shall
use the LFL value as published in Appendix A of Flammability
Characteristics of Combustible Gases and Vapors, U.S. Bureau of
Mines, Bulletin 627, 1965 (incorporated by reference--see Sec.
63.14). All inerts, including nitrogen, shall be assumed to have an
infinite lower flammability limit (e.g., LFLN2 = [infin],
so that [chi]N2/LFLN2 = 0).

(6) The owner or operator shall calculate Cvg using the
following equation. If the owner or operator uses a total hydrocarbon
analyzer, the owner or operator may substitute the
``[sum][chi]i'' term in the following equation with the
total volumetric hydrocarbon concentration present in the flare vent
gas (vol % as propane), and the owner or operator may choose to ignore
the concentration of hydrogen in the flare vent gas.
[GRAPHIC] [TIFF OMITTED] TP30JN14.010

Where:

Cvg = Total volumetric fraction of hydrogen and
combustible organic components present in the flare vent gas, volume
fraction. For the purposes of Cvg, carbon dioxide is not
considered to be a combustible organic component, but carbon
monoxide may be included in Cvg.
n = Number of individual combustible organic components in flare
vent gas.
i = Individual combustible organic component in flare vent gas.
[chi]i = Concentration of combustible organic component i
in flare vent gas, vol %.
CMNi = Carbon mole number of combustible organic
component i in flare vent gas, mole carbon atoms per mole of
compound. E.g., CMN for ethane (C2H6) is 2;
CMN for propane (C3H8) is 3.
[chi]h = Concentration of hydrogen in flare vent gas, vol
%.
100% = Constant, used to convert volume percent to volume fraction.

(m) Calculation methods for determining combustion zone parameters.
The owner or operator shall determine the net heating value, lower
flammability limit and combustibles concentration of the combustion
zone gas (NHVcz, LFLcz, and Ccz,
respectively) based on the vent gas and assist gas flow rates on a 15-
minute block average basis according to the following requirements. For
periods when there is no assist steam flow or premix assist air flow,
the combustion zone parameters are equal to the vent gas parameters.
(1) The owner or operator shall calculate NHVcz using
the following equation:
[GRAPHIC] [TIFF OMITTED] TP30JN14.011

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.

(2) The owner or operator shall calculate LFLcz using
the following equation:
[GRAPHIC] [TIFF OMITTED] TP30JN14.012

Where:

LFLcz = Lower flammability limit of combustion zone gas,
volume fraction.
LFLvg = Lower flammability limit of flare vent gas
determined for the 15-minute block period, volume fraction.
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.

(3) The owner or operator shall calculate Ccz using the
following equation:
[GRAPHIC] [TIFF OMITTED] TP30JN14.013

Where:

Ccz = Combustibles concentration in the combustion zone
gas, volume fraction.
Cvg = Combustibles concentration of flare vent gas
determined for the 15-minute block period, volume fraction.
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.

(n) Calculation methods for determining dilution parameters. The
owner or operator shall determine the net heating value, lower
flammability limit and combustibles concentration dilution parameters
(NHVdil, LFLdil, and Cdil,
respectively) based on the vent gas and perimeter assist air flow rates
on a 15-minute block average basis according to the following
requirements 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 dilution parameters do not need to be
calculated.

[[Page 36985]]

[GRAPHIC] [TIFF OMITTED] TP30JN14.014

[[Page 36986]]

[GRAPHIC] [TIFF OMITTED] TP30JN14.015

(o) Special provisions for assessing olefins and hydrogen
combustion zone concentrations. The owner or operator shall determine
the olefins and hydrogen content of the flare vent gas and calculate
the combustion zone

[[Page 36987]]

concentrations for the purposes of assessing the criteria in paragraph
(e)(4) of this section on a 15-minute block average according to the
following requirements.
(1) The olefins concentration shall be determined as the cumulative
sum of the following flare gas constituents: ethylene, acetylene,
propylene, propadiene, all isomers of n- or iso-butene, and all isomers
of butadiene.
(2) If individual component concentrations are determined following
the methods specified in paragraphs (j)(1) or (j)(2) of this section,
the measured vent gas concentrations shall be used to determine the
hydrogen, olefins, and hydrogen plus olefins concentration in the
combustion zone using the following general equation. The methods
specified in paragraphs (l)(1) through (3) of this section, as
applicable, shall be used to assign the vent gas concentration results
to a specific 15-minute block period.
[GRAPHIC] [TIFF OMITTED] TP30JN14.017

Where:

Acz = Concentration of target compound(s) ``A''
(representing either the olefins concentration, the hydrogen
concentration, or the sum of the olefins and hydrogen concentration)
in the combustion zone gas, volume fraction.
Avg = Concentration of target compound(s) ``A''
(representing either the olefins concentration, the hydrogen
concentration, or the sum of the olefins and hydrogen concentration)
in the flare vent gas determined for the 15-minute block period,
volume fraction.
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.

(3) If NHVvg or total hydrocarbon monitoring systems are
used as provided in paragraphs (j)(3) or (j)(4) of this section, the
owner or operator may elect to determine the hydrogen and olefins
concentrations using any of the following methods.
(i) The owner or operator may elect to assume the hydrogen
concentration, the olefins concentration, and the olefins plus hydrogen
concentration in the combustion zone gas exceed all three criteria in
(e)(4) at all times without making specific measurements of olefins or
hydrogen concentrations.
(ii) The owner or operator may elect to use process knowledge and
engineering calculations to determine the highest flare vent gas
concentrations of olefins and hydrogen that can reasonably be expected
to be discharged to the flare and the highest concentration of olefins
plus hydrogen that can reasonably be expected to be discharged to the
flare while the flare vent gas concentrations exceed the target
combustion zone concentrations in paragraphs (e)(4)(i) and (ii) of this
section at the same time. The owner or operator shall take daily flare
vent gas samples for fourteen days or for 7 flaring events, whichever
results in the greatest number of grab samples to verify that the
calculated values are representative of the highest concentrations that
reasonably be expected to be discharged to the flare.
(A) If the highest flare vent gas concentrations of olefins,
hydrogen, and olefins plus hydrogen that can reasonably be expected to
be discharged to the flare do not exceed all three combustion zone
concentration criteria in paragraph (e)(4) of this section, for
example, if the flare does not service any process units that contain
olefins, then the engineering assessment is sufficient to document that
all three criteria in paragraph (e)(4) of this section are not met and
that the more stringent operating limits do not apply at any time.
(B) If the highest flare vent gas concentrations of olefins,
hydrogen, and olefins plus hydrogen that can reasonably be expected to
be discharged to the flare exceed all three combustion zone
concentration criteria in paragraph (e)(4), then the owner or operator
will use the concentrations determined from the engineering analysis as
the vent gas concentrations that exist in the vent gas at all times and
use the equation in paragraph (o)(2) of this section to determine the
combustion zone concentrations of olefins.
(C) If the operation of process units connected to the flares
change or new connections are made to the flare and these changes can
reasonably be expected to alter the highest vent gas concentrations of
olefins, hydrogen, and/or olefins plus hydrogen received by the flare,
a new engineering assessment and sampling period for verification will
be conducted following the requirements of paragraph (o)(3)(ii) of this
section.
(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 test 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 test plan prior to
conducting any flare performance test intended for use in developing
site-specific operating limits. The site-specific test 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 test
plan, the owner or operator shall conduct a performance test for the
flare following the procedures described in the site-specific test
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 test. 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

[[Page 36988]]

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 test. A
sufficient number of test runs shall be conducted to identify the point
at which the combustion/destruction efficiency of the flare
deteriorates.
(viii) If the flare can receive vent gases containing olefins and
hydrogen above the levels specified for the combustion zone gas in
paragraph (e)(4) of this section, a sufficient number of tests must be
conducted while exceeding these limits to assess whether more stringent
operating limits are required under these conditions.
(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 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 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 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 test
conducted following the methods in an approved site-specific test 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 40 CFR 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 test 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 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:

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

[[Page 36989]]

specified in paragraphs (a)(1) through (8) of this section.
(1) All monitoring equipment must meet the 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 maintenance periods, instrument adjustments or
checks to maintain precision and accuracy, calibration checks, and zero
and span adjustments, the owner or operator shall operate all CPMS and
collect data continuously 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, the owner or operator shall comply with the out-
of-control procedures described in paragraphs (c) of this section. The
CPMS monitoring plan must be submitted to the Administrator for
approval upon request.
(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. 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 (c)(3)(i) through (viii) of this section.
(i) Manufacturer and model number for all monitoring equipment
components.
(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.
(v) Span of the analyzer. The span must encompass all expected
concentrations and meet the requirements of paragraph (b)(10) of this
section.
(vi) How data outside of the analyzer's span 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 (c)(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 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, 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

[[Page 36990]]

CPMS 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 the compounds that exist in the flare gas
stream. 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.
(ii) The owner or operator must use a surrogate calibration gas
consisting of C1 through C7 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 the following paragraphs.
(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) Unknown compounds that elute after n-heptane must either be
identified and quantified using an identical compound standard, or the
owner or operator must extend the calibration range to include the
additional normal hydrocarbons necessary to perform the unknown
hydrocarbon quantitation procedure.
0
34. Table 6 to Subpart CC is amended by:
0
a. Revising the entry ``63.5(d)(1)(ii)'';
0
b. Revising the entry ``63.5(f)'';
0
c. Removing the entry ``63.6(e)'';
0
d. Adding, in numerical order, the entries ``63.6(e)(1)(i) and (ii)''
and ``63.6(e)(1)(iii)'';
0
e. Revising the entries ``63.6(e)(3)(i)'' and ``63.6(e)(3)(iii)-
63.6(e)(3)(ix)'';
0
f. Revising the entry ``63.6(f)(1)'';
0
g. Removing the entry ``63.6(f)(2) and (3)'';
0
h. Adding, in numerical order, the entries ``63.6(f)(2)'' and
``63.6(f)(3)'';
0
i. Removing the entry ``63.6(h)(1) and 63.6(h)(2)'';
0
j. Adding, in numerical order, the entries ``63.6(h)(1)'' and
``63.6(h)(2)'';
0
k. Revising the entry ``63.7(b)'';
0
l. Revising the entry ``63.7(e)(1)'';
0
m. Removing the entry ``63.8(a)'';
0
n. Adding, in numerical order, the entries ``63.8(a)(1) and (2),''
``63.8(a)(3)'' and ``63.8(a)(4)'';
0
o. Revising the entry ``63.8(c)(1)'';
0
p. Adding, in numerical order, the entries ``63.8(c)(1)(i)'' and
``63.8(c)(1)(iii)'';
0
q. Revising the entries ``63.8(c)(4)'' and ``63.8(c)(5)-63.8(c)(8)'';
0
r. Revising the entries ``63.8(d)'' and ``63.8(e)'';
0
s. Revising the entry ``63.8(g)'';
0
t. Revising the entries ``63.10(b)(2)(i)'' and ``63.10(b)(2)(ii)'';
0
u. Revising the entries ``63.10(b)(2)(iv)'' and ``63.10(b)(2)(v)'';
0
v. Revising the entry ``63.10(b)(2)(vii)'';
0
w. Removing the entry ``63.10(c)(9)-63.10(c)(15)'';
0
x. 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
y. Removing the entries ``63.10(d)(5)(i)'' and ``63.10(d)(5)(ii)'';
0
z. Adding, in numerical order, the entry ``63.10(d)(5)'';
0
aa. Removing the entry ``63.11-63.16'';
0
bb. Adding, in numerical order, the entries ``63.11'' and ``63.12-
63.16'';
0
cc. Removing footnote b.
The revisions and additions read as follows:

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 subpart CC,
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)(ix)... No..................
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
subpart CC does not require a site-specific test plan.
63.6(f)(3)....................... Yes................. Except the cross-references to Sec. 63.6(f)(1) and
Sec. 63.6(e)(1)(i) are changed to Sec. 63.642(n).

* * * * * * *
63.6(h)(1)....................... No..................

[[Page 36991]]

63.6(h)(2)....................... Yes................. Except Sec. 63.6(h)(2)(ii), which is reserved.

* * * * * * *
63.7(b).......................... Yes................. Except subpart CC 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 Sec. 63.8(c)(iii).
63.8(c)(1)(i).................... No.................. See Sec. 63.642(n).
63.8(c)(1)(iii).................. No..................

* * * * * * *
63.8(c)(4)....................... Yes................. Except that for sources other than flares, subpart CC
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.................. Subpart CC specifies continuous monitoring system
requirements.
63.8(d).......................... No.................. Subpart CC specifies quality control procedures for
continuous monitoring systems.
63.8(e).......................... Yes.................

* * * * * * *
63.8(g).......................... No.................. Subpart CC 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.................. See Sec. 63.655(i)(11) 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 to minimize emissions and correct the failure.

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

* * * * * * *
63.10(b)(2)(vii)................. No.................. Sec. 63.655(i) of subpart CC 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.................. See Sec. 63.655(i)(11) for malfunctions recordkeeping
requirements.
63.10(c)(12)-63.10(c)(15)........ No..................

* * * * * * *
63.10(d)(5)...................... No.................. See Sec. 63.655(g)(12) for malfunctions 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 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. Table 10 to Subpart CC is amended by:
0
a. Redesignating the entry ``Flare'' as ``Flare (if meeting the
requirements of 63.643 and 63.644)'';
0
b. Adding the entry ``Flare (if meeting the requirements of 63.670 and
63.671)'' after the newly redesignated entry ``Flare (if meeting the
requirements of 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:

[[Page 36992]]

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 reporting requirements
Control device Parameters to be monitored \a\ for monitored parameters
----------------------------------------------------------------------------------------------------------------

* * * * * * *
Flare (if meeting the requirements of The parameters specified in 1. Records as specified in 63.655(i)(9).
63.670 and 63.671). 63.670.
2. Report information as specified in
63.655(g)(11)--PR \g\.
All control devices................... Volume of the gas stream 1. Continuous records \c\.
diverted to the atmosphere
from the control device
(63.644(c)(1)) or
2. 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\.
Monthly inspections of sealed 1. Records that monthly inspections were
valves (63.644(c)(2)). 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.
\c\ ``Continuous records'' is defined in Sec. 63.641.
\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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL
REGISTER], 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. Table 11 is added to Subpart CC to read as follows:

Table 11--Compliance Dates and Requirements
----------------------------------------------------------------------------------------------------------------
If the construction/ And the owner or operator
reconstruction date \a\ is . . Then the owner or operator must achieve compliance . . Except as provided in
. must comply with . . . . . . .
----------------------------------------------------------------------------------------------------------------
(1) After June 30, 2014....... (i) Requirements for new (a) Upon initial startup or (1) Sec. 63.640(k),
sources in Sec. Sec. [THE DATE OF PUBLICATION (l) and (m).
63.640 through 63.642, OF THE FINAL RULE
Sec. 63.647, Sec. Sec. AMENDMENTS IN THE FEDERAL
63.650 through 63.653, REGISTER], whichever is
and Sec. Sec. 63.656 later.
through 63.660.
(ii) The new source (a) Upon initial startup or (1) Sec. 63.640(k),
requirements in Sec. October 28, 2009, (l) and (m).
63.654 for heat exchange whichever is later.
systems.
(2) After September 4, 2007 (i) Requirements for new (a) Upon initial startup... (1) Sec. 63.640(k),
but on or before June 30, sources in Sec. Sec. (l) and (m).
2014. 63.640 through 63.653 and
63.656 b c.
(ii) Requirements for new (a) On or before [THE DATE (1) Sec. 63.640(k),
sources in Sec. Sec. 3 YEARS AFTER THE DATE OF (l) and (m).
63.640 through 63.645, PUBLICATION OF THE FINAL
Sec. Sec. 63.647 RULE AMENDMENTS IN THE
through 63.653, and Sec. FEDERAL REGISTER].
Sec. 63.656, through
63.658 \b\.
(iii) Requirements for new (a) On or before [THE DATE (1) Sec. 63.640(k),
sources in Sec. 63.660 90 DAYS AFTER THE DATE OF (l) and (m).
\c\. PUBLICATION OF THE FINAL
RULE AMENDMENTS IN THE
FEDERAL REGISTER].
(iv) The new source (a) Upon initial startup or (1) Sec. 63.640(k),
requirements in Sec. October 28, 2009, (l) and (m).
63.654 for heat exchange whichever is later.
systems.
(3) After July 14, 1994 but on (i) Requirements for new (a) Upon initial startup or (1) Sec. 63.640(k),
or before September 4, 2007. sources in Sec. Sec. August 18, 1995, whichever (l) and (m).
63.640 through 63.653 and is later.
63.656 d e.
(ii) Requirements for new (a) On or before [THE DATE (1) Sec. 63.640(k),
sources in Sec. Sec. 3 YEARS AFTER THE DATE OF (l) and (m).
63.640 through 63.645, PUBLICATION OF THE FINAL
Sec. Sec. 63.647 RULE AMENDMENTS IN THE
through 63.653, and Sec. FEDERAL REGISTER].
Sec. 63.656, through
63.658 \d\.
(iii) Requirements for new (a) On or before [THE DATE (1) Sec. 63.640(k),
sources in Sec. 63.660 90 DAYS AFTER THE DATE OF (l) and (m).
\e\. PUBLICATION OF THE FINAL
RULE AMENDMENTS IN THE
FEDERAL REGISTER].

[[Page 36993]]

(iv) The existing source (a) On or before October (1) Sec. 63.640(k),
requirements in Sec. 29, 2012. (l) and (m).
63.654 for heat exchange
systems.
(4) On or before July 14, 1994 (i) Requirements for (a) On or before August 18, (1) Sec. 63.640(k),
existing sources in Sec. 1998. (l) and (m)
Sec. 63.640 through
63.653 and 63.656 f g.
(2) Sec. 63.6(c)(5)
of subpart A of this
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 (a) On or before [THE DATE (1) Sec. 63.640(k),
existing sources in Sec. 3 YEARS AFTER THE DATE OF (l) and (m).
Sec. 63.640 through PUBLICATION OF THE FINAL
63.645, Sec. Sec. RULE AMENDMENTS IN THE
63.647 through 63.653, and FEDERAL REGISTER].
Sec. Sec. 63.656
through 63.658 \f\.
(iii) Requirements for (a) On or before [THE DATE (1) Sec. 63.640(k),
existing sources in Sec. 90 DAYS AFTER THE DATE OF (l) and (m).
63.660 \g\. PUBLICATION OF THE FINAL
RULE AMENDMENTS IN THE
FEDERAL REGISTER].
(iii) The existing source (a) On or before October (1) Sec. 63.640(k),
requirements in Sec. 29, 2012. (l) and (m).
63.654 for heat exchange
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)(a) and (2)(ii)(a) 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)(a) and (2)(iii)(a) of this table, the owner or operator may
elect to comply with either the requirements in item (2)(i) or item (2)(iii) of this table. The requirements
in item (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item
(2)(iii) of this table.
\d\ Between the compliance dates in items (3)(i)(a) and (3)(ii)(a) 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)(a) and (3)(iii)(a) of this table, the owner or operator may
elect to comply with either the requirements in item (3)(i) or item (3)(iii) of this table. The requirements
in item (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item
(3)(iii) of this table.
\f\ Between the compliance dates in items (4)(i)(a) and (4)(ii)(a) 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)(a) and (4)(iii)(a) of this table, the owner or operator may
elect to comply with either the requirements in item (4)(i) or item (4)(iii) of this table. The requirements
in item (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item
(4)(iii) of this table.

0
37. Table 12 is added to Subpart CC to read as follows:

Table 12--Individual Component Properties
--------------------------------------------------------------------------------------------------------------------------------------------------------
NHVi (British
MWi (pounds per CMNi (mole per thermal units
Component Molecular formula pound-mole) mole) per standard LFLi (volume %)
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 0 274 4.0
Methane................................... CH4................................. 16.04 1 896 5.0

[[Page 36994]]

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]
--------------------------------------------------------------------------------------------------------------------------------------------------------

0
38. Table 13 is added to Subpart CC to read as follows:

Table 13--Calibration and Quality Control Requirements for CPMS
----------------------------------------------------------------------------------------------------------------
Parameter Accuracy requirements Calibration requirements
----------------------------------------------------------------------------------------------------------------
Temperature................... 1 percent over Performance evaluation annually and following any
the normal range of period of more than 24 hours throughout which the
temperature measured or temperature exceeded the maximum rated temperature
2.8 degrees Celsius (5 of the sensor, or the data recorder was off scale.
degrees Fahrenheit), Visual inspections and checks of CPMS operation
whichever is greater, for every 3 months, unless the CPMS has a redundant
non-cryogenic temperature temperature sensor.
ranges.
2.5 percent Select a representative measurement location.
over the normal range of
temperature measured or
2.8 degrees Celsius (5
degrees Fahrenheit),
whichever is greater, for
cryogenic temperature
ranges.
Flow Rate..................... 5 percent over Performance evaluation annually and following any
the normal range of flow period of more than 24 hours throughout which the
measured or 1.9 liters per flow rate exceeded the maximum rated flow rate of
minute (0.5 gallons per the sensor, or the data recorder was off scale.
minute), whichever is Checks of all mechanical connections for leakage
greater, for liquid flow monthly. Visual inspections and checks of CPMS
rate. operation every 3 months, unless the CPMS has a
redundant flow sensor.
5 percent over Select a representative measurement location where
the normal range of flow swirling flow or abnormal velocity distributions
measured or 280 liters per due to upstream and downstream disturbances at the
minute (10 cubic feet per point of measurement are minimized.
minute), whichever is
greater, for gas flow rate.
5 percent over
the normal range measured
for mass flow rate.
Pressure...................... 5 percent over Checks for obstructions at least once each process
the normal range measured operating day (e.g., pressure tap pluggage).
or 0.12 kilopascals (0.5 Performance evaluation annually and following any
inches of water column), period of more than 24 hours throughout which the
whichever is greater. pressure exceeded the maximum rated pressure of
the sensor, or the data recorder was off scale.
Checks of all mechanical connections for leakage
monthly. Visual inspection of all components for
integrity, oxidation and galvanic corrosion every
3 months, unless the CPMS has a redundant pressure
sensor.
Select a representative measurement location that
minimizes or eliminates pulsating pressure,
vibration, and internal and external corrosion.
Net Heating Value by 2 percent of Specify calibration requirements in your site
Calorimeter. span. 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.
Net Heating Value by Gas As specified in Performance Follow the procedure in Performance Specification 9
Chromatograph. Specification 9 of 40 CFR of 40 CFR part 60, Appendix B
part 60, Appendix B.

[[Page 36995]]

Net Heating Value by Total Calibration drift <=3% of Calibration drift check daily. Follow the procedure
Hydrocarbon Monitor. instrument span at each in Sections 4.1 and 4.2 of Procedure 1 in 40 CFR
level. part 60, Appendix F.
Cylinder Gas Audit Accuracy Cylinder gas audit quarterly. Follow the procedure
<=5% of instrument span at in Section 5.1.2 of Procedure 1 in 40 CFR part 60,
each level. Appendix F, except the audit shall be performed
every quarter.
For both the calibration drift and error tests, the
calibration gases should be injected into the
sampling system as close to the sampling probe
outlet as practical and must pass through all
filters, scrubbers, conditioners, and other
monitor components used during normal sampling.
Select a measurement location that meets the
requirements of Section 3.1 of Performance
Specification 8A of Appendix B to 40 CFR part 60.
----------------------------------------------------------------------------------------------------------------

Subpart UUU--[Amended]

0
39. Section 63.1562 is amended by:
0
(a) Revising paragraph (b)(3) and
0
(b) Revising paragraph (f)(5).
The revisions 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL
RULE AMENDMENTS IN THE FEDERAL REGISTER], any flares receiving gas from
the fuel gas system are in compliance with Sec. 63.670.
0
40. Section 63.1564 is amended by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(i);
0
c. Revising paragraph (a)(1)(ii);
0
d. Revising paragraph (a)(1)(iv);
0
e. Adding paragraph (a)(5);
0
f. Revising paragraph (b)(4)(i);
0
g. Revising paragraph (b)(4)(ii);
0
h. Revising paragraph (b)(4)(iv);
0
i. 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) 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 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 (iv) of
this section:
(i) You can elect to comply with the PM per coke burn-off emission
limit (Option 1);
(ii) You can elect to comply with the PM concentration emission
limit (Option 2);
* * * * *
(iv) You can elect to comply with the Ni per coke burn-off emission
limit (Option 4).
* * * * *
(5) During periods of startup only, if your catalytic cracking unit
is followed by an electrostatic precipitator, 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 paragraphs (a)(1)
and (2) of this section; or
(ii) You can elect to maintain the opacity in the exhaust gas from
your catalyst regenerator at or below 30 percent opacity on a 6-minute
average basis.
(b) * * *
(4) * * *
(i) If you elect Option 1 in paragraph (a)(1)(i) 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] TP30JN14.018

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 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 (a)(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).

[[Page 36996]]

[GRAPHIC] [TIFF OMITTED] TP30JN14.019

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
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 (kg\2\/g)/(1,000 kg) (1,000 lb/(1,000
lb)).

[GRAPHIC] [TIFF OMITTED] TP30JN14.020

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 [THE DATE 18
MONTHS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN
THE FEDERAL REGISTER], A=0.18 g/million cal (0.10 lb/million Btu).
On or after [THE DATE 18 MONTHS AFTER THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], 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 (kg\2\/g)/(1,000
kg) (10\3\ lb/(1,000 lb)).

[GRAPHIC] [TIFF OMITTED] TP30JN14.021

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 2 in paragraph (a)(1)(ii) 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)(iv) 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] TP30JN14.022

Where:

ENi2 = Normalized mass emission rate of Ni, mg/kg coke
(lb/1,000 lb coke).

[GRAPHIC] [TIFF OMITTED] TP30JN14.023

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] TP30JN14.024

[[Page 36997]]

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) During periods of startup only, if you elect to comply with the
alternative limit in paragraph (a)(5)(ii) of this section, determine
continuous compliance by: collecting opacity readings using either a
continuous opacity monitoring system according to Sec. 63.1572 or
manual opacity observations following EPA Method 9 in Appendix A-4 to
part 60 of this chapter; and maintaining each 6-minute average opacity
at or below 30 percent.
0
41. Section 63.1565 is amended by:
0
a. Adding paragraph (a)(5);
0
b. Adding paragraph (b)(1)(iv); and
0
c. Adding paragraph (c)(3).
The additions read as follows:

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

(a) * * *
(5) During periods of startup only, if your catalytic cracking unit
is not followed by a CO boiler, thermal oxidizer, incinerator, flare or
similar combustion device, 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).
(b) * * *
(1) * * *
(iv) If you elect to comply with the alternative limit for periods
of startup in paragraph (a)(5)(ii) of this section, you must also
install, operate, and maintain a continuous parameter monitoring system
to measure and record the oxygen content (percent, dry basis) in the
catalyst regenerator vent.
* * * * *
(c) * * *
(3) Demonstrate continuous compliance with the alternative limit in
paragraph (a)(5)(ii) of this section by collecting the hourly average
oxygen concentration monitoring data according to Sec. 63.1572 and
maintaining the hourly average oxygen concentration at or above 1
volume percent (dry basis).
0
42. Section 63.1566 is amended by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(i); and
0
c. Revising paragraph (a)(4).
The revisions 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 [THE DATE 3 YEARS AFTER THE
DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL
REGISTER], the flare must meet the requirements of Sec. 63.670. Prior
to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL REGISTER], 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:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(i);
0
c. Adding paragraph (a)(4);
0
d. Revising paragraph (b)(1); and
0
e. Adding paragraphs (c)(3) and (4).
The revisions and additions 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 in 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 in Sec. 60.102a(f)(1) of this chapter (Option 1); or
* * * * *
(4) During periods of shutdown only, 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 shutdown purge gases to a flare. On
and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL
RULE AMENDMENTS IN THE FEDERAL REGISTER], the flare must meet the
requirements of Sec. 63.670. Prior to [THE DATE 3 YEARS AFTER THE DATE
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER],
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 shutdown purge gases to a to a
thermal oxidizer or incinerator operated at a minimum hourly average
temperature of 1,200 degrees Fahrenheit and a minimum hourly average
outlet oxygen (O2) concentration of 2 volume percent (dry
basis).
(b) * * *
(1) Install, operate, and maintain a continuous monitoring system
according to the requirements in Sec. 63.1572 and Table 31 of this
subpart. Except:
(i) If you elect to comply with the alternative limit for periods
of shutdown in paragraph (a)(4)(ii) of this section, then on and after
[THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL REGISTER], you must also install, operate,
calibrate, and maintain monitoring systems as specified in Sec. Sec.
63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE OF
PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you
must either install, operate, and maintain 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 install, operate, calibrate, and
maintain monitoring systems as specified in Sec. Sec. 63.670 and
63.671.
(ii) If you elect to comply with the alternative limit for periods
of

[[Page 36998]]

shutdown in paragraph (a)(4)(iii) of this section, you must also
install, operate, and maintain continuous parameter monitoring system
to measure and record the temperature and oxygen content (percent, dry
basis) in the vent from the thermal oxidizer or incinerator.
* * * * *
(c) * * *
(3) Demonstrate continuous compliance with the alternative limit in
paragraph (a)(4)(ii) of this section by meeting the requirements of
either paragraph (c)(3)(i) or (ii) of this section.
(i) On and after [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF
THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must meet the
requirements of paragraphs (c)(3)(i)(A) through (C) of this section.
(A) Collect the flare monitoring data according to Sec. Sec.
63.670 and 63.671.
(B) Keep the records specified in Sec. 63.655(i)(9).
(C) Maintain the selected operating parameters as specified in
Sec. 63.670.
(ii) Prior to [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF
THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must either
meet the requirements of paragraph (c)(3)(i) of this section or meet
the requirements of paragraphs (c)(3)(ii)(A) through (D) of this
section.
(A) Collect the flare monitoring data according to Sec. 63.1572.
(B) Record for each 1-hour period whether the monitor was
continuously operating and the pilot light was continuously present
during each 1-hour period.
(C) Maintain the net heating value of the gas being combusted at or
above the applicable limits in Sec. 63.11.
(D) Maintain the exit velocity at or below the applicable maximum
exit velocity specified in Sec. 63.11.
(4) Demonstrate continuous compliance with the alternative limit in
paragraph (a)(4)(iii) of this section by collecting the hourly average
temperature and oxygen concentration monitoring data according to Sec.
63.1572; maintaining the hourly average temperature at or above 1,200
degrees Fahrenheit; and maintaining the hourly average oxygen
concentration at or above 2 volume percent (dry basis).
0
44. Section 63.1570 is amended by:
0
a. Revising paragraphs (a) through (d); and
0
b. Removing and reserving paragraph (g).
The revisions 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 detailing the operation
and maintenance of the process and emissions control equipment.
* * * * *
0
45. Section 63.1571 is amended by:
0
a. Adding paragraph (a)(5);
0
b. Revising paragraph (b)(1);
0
c. Removing paragraph (b)(4);
0
d. Redesignating paragraph (b)(5) as (b)(4);
0
e. Revising paragraphs (d)(2) and (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) Conduct a performance test for PM or Ni, as applicable, from
catalytic cracking units at least once every 5 years for those units
monitored with CPMS, BLD, or COMS. You must conduct the first periodic
performance test no later than [THE DATE 18 MONTHS AFTER THE DATE OF
PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER].
Those units monitoring PM concentration with a PM CEMS are not required
to conduct a periodic PM performance test.
(b) * * *
(1) Conduct performance tests under such conditions as the
Administrator specifies to you based on representative performance of
the affected source for the period being tested. Representative
conditions exclude periods of startup and shutdown unless specified by
the Administrator or an applicable subpart. 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 such conditions represent normal operation. 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. Section 63.1564(b)(2) allows you to adjust the laboratory
measurements of the equilibrium catalyst Ni concentration to the
maximum level. You must make this adjustment using Equation 2 of this
section as follows:
[GRAPHIC] [TIFF OMITTED] TP30JN14.025

[[Page 36999]]

Where:

NiEmR2st = Average Ni emission rate calculated as the
arithmetic average Ni emission rate using Equation 8 of Sec.
63.1564 for each performance test run, mg/kg coke burn-off.

* * * * *
(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:
0
a. Revising paragraphs (c) introductory text, (c)(1), (c)(3) and
(c)(4); and
0
b. Revising paragraphs (d)(1) and (2).
The revisions 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 [THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF
THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], you must install,
operate, calibrate, and maintain monitoring systems as specified in
Sec. Sec. 63.670 and 63.671. Prior to [THE DATE 3 YEARS AFTER THE DATE
OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER],
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 meet the requirements in Table 41 of this
subpart for BLD systems.
* * * * *
(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);
0
c. Revising newly redesignated paragraph (c) introductory text;
0
d. Revising newly redesignated paragraph (d) introductory text;
0
e. Revising newly redesignated paragraph (f) introductory text; and
0
f. Revising newly redesignated paragraph (g)(1).
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 paragraph (c)(1) or
(2) of this section for a catalytic reforming unit.
* * * * *
(d) Can I use another type of monitoring system? You may request
approval from your permitting authority to 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. Your request must contain a
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 (a)(3) 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

[[Page 37000]]

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.
* * * * *
0
49. Section 63.1575 is amended by:
0
a. Revising paragraphs (d) introductory text, (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 (e)(6);
0
f. Revising paragraphs (f)(1) and (2);
0
g. Removing and reserving paragraph (h); and
0
h. 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.
(1) [Reserved]
* * * * *
(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 (c)(1)(i) or
(c)(1)(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 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. On and after [THE DATE 3 YEARS AFTER DATE OF
PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE FEDERAL REGISTER], if
required to submit the results of a performance test or CEMS
performance evaluation, you must submit the results using EPA's
Electronic Reporting Tool (ERT) 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 according to the method specified by either paragraph
(k)(1)(i) or (k)(1)(ii) of this section.
(i) For data collected using test methods supported by the EPA's
ERT as listed on the EPA's ERT Web site (https://www.epa.gov/ttn/chief/ert/), you must submit the results of the performance test to
the Compliance and Emissions Data Reporting Interface (CEDRI) accessed
through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/epa_home.asp), unless the Administrator approves another approach.
Performance test data must be submitted in a file format generated
through use of the EPA's ERT. 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, including information claimed to be CBI, on a compact disc
or other commonly used electronic storage media (including, but not
limited to, flash drives) by registered letter to the EPA. The
electronic media must be clearly marked as CBI and mailed to

[[Page 37001]]

U.S. EPA/OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD
C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file with
the CBI omitted must be submitted to the EPA via CDX as described
earlier in this paragraph.
(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, 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 test required by Sec. 63.1571(a) and (b), you
must submit the results of the performance evaluation according to the
method specified by either paragraph (k)(2)(i) or (k)(2)(ii) of this
section.
(i) For data collection of relative accuracy test audit (RATA)
pollutants that are supported by the EPA's ERT as listed on the ERT Web
site, the owner or operator must submit the results of the performance
evaluation to the CEDRI that is accessed through the EPA's CDX, unless
the Administrator approves another approach. Performance evaluation
data must be submitted in a file format generated through the use of
the EPA's ERT. 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, including information claimed to be CBI, on a compact disc
or other commonly used electronic storage media (including, but not
limited to, flash drives) by registered letter to the EPA. The
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAQPS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02,
4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI
omitted must be submitted to the EPA via CDX as described earlier in
this paragraph.
(ii) For any performance evaluation data with RATA pollutants that
are not supported by the EPA's ERT as listed on the EPA's ERT Web site,
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:
0
a. Revising paragraph (a)(2);
0
b. Revising paragraphs (b)(3) and (5).
The revisions 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 section introductory text and
0
b. 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 this part (Sec. Sec. 63.1
through 63.15), and in this section as listed. If the same term is
defined in subpart A 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.
* * * * *
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.

[[Page 37002]]

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. (1.0 lb/1,000 lb) of coke burn-
off. Before [THE DATE 18
MONTHS AFTER THE DATE OF
PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL
REGISTER], 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). 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.
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 1: PM per coke burn-off PM emissions must not exceed
limit, not subject to the NSPS for PM the limits specified in Item 1
in 40 CFR 60.102 or in 40 CFR of this table.
60.102a(b)(1).
5. Option 2: PM concentration limit, PM emissions must not exceed
not subject to the NSPS for PM in 40 0.040 gr/dscf corrected to 0
CFR 60.102 or in 40 CFR 60.102a(b)(1). percent excess air.
6. 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 in 40 CFR 60.102a(b)(1). hour (mg/hr) (0.029 lb/hr).
7. 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 in 40 CFR of coke burn-off in the
60.102a(b)(1). 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 a. Continuous opacity Not applicable......... Not applicable.
CFR 60.102. monitoring system used
to comply with the 30
percent opacity limit
in 40 CFR 60.102
before [THE DATE 18
MONTHS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER].
b. Continuous opacity Cyclone, fabric filter, Maintain the 3-hour
monitoring system used or 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 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; and
maintain the 3-hour
rolling average total
power and secondary
current above the
limit established in
the performance test.
d. Continuous parameter Wet scrubber........... Maintain the 3-hour
monitoring systems. rolling average
pressure drop above
the limit established
in the performance
test; and maintain the
3-hour rolling average
liquid-to-gas ratio
above the limit
established in the
performance test.

[[Page 37003]]

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.
2. Subject to NSPS for PM in 40 CFR a. PM CEMS............. Not applicable......... Not applicable.
60.102a(b)(1)(i).
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 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; and
maintain the 3-hour
rolling average total
power and secondary
current above the
limit established in
the performance test.
d. Continuous parameter Wet scrubber........... Maintain the 3-hour
monitoring systems. rolling average
pressure drop above
the limit established
in the performance
test; and maintain the
3-hour rolling average
liquid-to-gas ratio
above the limit
established in the
performance test.
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 1: PM per coke burn-off a. Continuous opacity Cyclone, fabric filter, Maintain the 3-hour
limit not subject to the NSPS for PM monitoring system used or electrostatic rolling average
in 40 CFR 60.102 or 40 CFR to comply with a site- precipitator. opacity of emissions
60.102a(b)(1). specific opacity limit. from your catalyst
regenerator vent no
higher than the site-
specific opacity limit
established during the
performance test.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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) Maintain the daily
monitoring systems. precipitator. average gas flow rate
or daily average coke
burn-off rate no
higher than the limit
established in the
performance test.

[[Page 37004]]

(2) Maintain the 3-hour
rolling average total
power and secondary
current above the
limit established in
the performance test.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], you may
maintain the daily
average voltage and
secondary current (or
total power input)
above the limit
established in the
performance test.
ii. Wet scrubber....... (1) Maintain the 3-hour
rolling average
pressure drop above
the limit established
in the performance
test. Alternatively,
before [THE DATE 18
MONTHS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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).
(2) Maintain the 3-hour
rolling average liquid-
to-gas ratio above the
limit established in
the performance test.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], you may
maintain the daily
average liquid-to-gas
ratio above the limit
established in the
performance test.
c. 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.
5. Option 2: PM concentration limit PM CEMS................ Any.................... Not applicable.
not subject to the NSPS for PM in 40
CFR 60.102 or 40 CFR 60.102a(b)(1).
6. 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
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], you may
maintain the daily
average Ni operating
value no higher than
the limit established
during the performance
test.

[[Page 37005]]

b. Continuous parameter i. Electrostatic (1) Maintain the daily
monitoring systems. precipitator. average gas flow rate
or daily average coke
burn-off rate no
higher than the limit
established during the
performance test.
(2) Maintain the
monthly rolling
average of the
equilibrium catalyst
Ni concentration no
higher than the limit
established during the
performance test.
(3) Maintain the 3-hour
rolling average total
power and secondary
current above the
limit established in
the performance test.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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) Maintain the 3-hour
rolling average
pressure drop above
the limit established
in the performance
test. Alternatively,
before [THE DATE 18
MONTHS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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).
(3) Maintain the 3-hour
rolling average liquid-
to-gas ratio above the
limit established in
the performance test.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], you may
maintain the daily
average liquid-to-gas
ratio above the limit
established during the
performance test.

[[Page 37006]]

7. Option 4: Ni per coke burn-off a. Continuous opacity Cyclone, baghouse, or Maintain the 3-hour
limit not subject to the NSPS for PM monitoring system. 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
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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) Maintain the 3-hour
rolling average total
power and secondary
current above the
limit established in
the performance test.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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) Maintain the 3-hour
rolling average
pressure drop above
the limit established
in the performance
test. Alternatively,
before [THE DATE 18
MONTHS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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).
(3) Maintain the 3-hour
rolling average liquid-
to-gas ratio above the
limit established in
the performance test.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], you may
maintain the daily
average liquid-to-gas
ratio above the limit
established during the
performance test.
----------------------------------------------------------------------------------------------------------------

[[Page 37007]]

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 You shall install,
For each new or existing type of control operate, and
catalytic cracking unit . . . device for your maintain a . . .
vent . . .
------------------------------------------------------------------------
1. Subject to the NSPS for PM in a. Cyclone........ Continuous opacity
40 CFR 60.102. monitoring system
to measure and
record the
opacity of
emissions from
each catalyst
regenerator vent.
b. Electrostatic Continuous opacity
precipitator. 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\ and the total
power 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\ coke
burn-off rate or
the gas flow rate
entering or
exiting the
control
device,\1\ and
total liquid (or
scrubbing liquor)
flow rate to the
control device.
Alternatively,
before [THE DATE
3 YEARS AFTER THE
DATE OF
PUBLICATION OF
THE FINAL RULE
AMENDMENTS IN THE
FEDERAL
REGISTER],
continuous
opacity
monitoring system
to measure and
record the
opacity of
emissions from
each catalyst
regenerator vent.
d. Fabric Filter.. Continuous bag
leak detection
system to measure
and record
increases in
relative
particulate
loading from each
catalyst
regenerator vent
or a continuous
opacity
monitoring system
to measure and
record the
opacity of
emissions from
each catalyst
regenerator vent.
2. Subject to NSPS for PM in 40 a. Cyclone........ Continuous opacity
CFR 60.102a(b)(1)(i) electing monitoring system
to meet the PM per coke burn- to measure and
off limit. record the
opacity of
emissions from
each catalyst
regenerator vent.
b. Electrostatic Continuous opacity
precipitator. 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,\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.
3. Subject to NSPS for PM in 40 Any............... Continuous
CFR 60.102a(b)(1)(i) electing emission
to meet the PM concentration monitoring system
limit. to measure and
record the
concentration of
PM and oxygen
from each
catalyst
regenerator vent.
4. Subject to NSPS for PM in 40 Any............... See item 2 of this
CFR 60.102a(b)(1)(ii) electing table.
to meet the PM per coke burn-
off limit.
5. Subject to NSPS for PM in 40 Any............... See item 3 of this
CFR 60.102a(b)(1)(ii) electing table.
to meet the PM concentration
limit.

[[Page 37008]]

6. Option 1: PM per coke burn- Any............... See item 1 of this
off limit not subject to the table.
NSPS for PM in 40 CFR 60.102 or
40 CFR 60.120a(b)(1).
7. Option 2: PM concentration Any............... See item 3 of this
limit not subject to the NSPS table.
for PM in 40 CFR 60.102 or 40
CFR 60.120a(b)(1).
8. Option 3: Ni lb/hr limit not a. Cyclone........ Continuous opacity
subject to the NSPS for PM in monitoring system
40 CFR 60.102 or in 40 CFR to measure and
60.102a(b)(1). record the
opacity of
emissions from
each catalyst
regenerator vent
and continuous
parameter
monitoring system
to measure and
record the coke
burn-off rate or
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 coke
burn-off rate or
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 8.a of
this table.
9. Option 4: Ni lb/1,000 lbs of a. Cyclone........ Continuous opacity
coke burn-off limit not subject monitoring system
to the NSPS for PM in 40 CFR to measure and
60.102 or in 40 CFR record the
60.102a(b)(1). 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 coke
burn-off rate or
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 9.a of
this table.
------------------------------------------------------------------------
\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.

[[Page 37009]]

0
55. Table 4 to subpart UUU of part 63 is revised to read as follows:
As stated in Sec. 63.1564(b)(2), 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 Not Subject to the New Source Performance Standard (NSPS) for Particulate Matter (PM)
----------------------------------------------------------------------------------------------------------------
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 2F in Appendix A-1 to
rate. part 60 of this
chapter, or 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.
2. Option 1: PM per coke burn-off a. Measure PM emissions Method 5, 5B, or 5F (40 You must maintain a
limit, not subject to the NSPS for CFR part 60, Appendix sampling rate of at
PM in 40 CFR 60.102 or in 40 CFR A-3) to determine PM least 0.15 dry
60.102a(b)(1). 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. Option 2: PM concentration limit, a. Measure PM Method 5, 5B, or 5F (40 You must maintain a
not subject to the NSPS for PM in 40 concentration. CFR part 60, Appendix sampling rate of at
CFR 60.102 or in 40 CFR A-3) to determine PM least 0.15 dry
60.102a(b)(1). concentration 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
concentration and
associated moisture
content for unit with
wet scrubber.

[[Page 37010]]

4. 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 in 40 CFR 60.102a(b)(1).
b. Compute Ni emission Equation 5 of Sec.
rate (lb/hr). 63.1564.
c. Determine the XRF procedure in You must obtain 1
equilibrium catalyst Appendix A to this sample for each of the
Ni concentration. subpart; \1\ or EPA 3 runs; determine and
Method 6010B or 6020 record the equilibrium
or EPA Method 7520 or catalyst Ni
7521 in SW-846; \2\ or concentration for each
an alternative to the of the 3 samples; and
SW-846 method 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 hourly average
Method 29 test. opacity from all the 6-
minute averages.
(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
from all the readings.
5. 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 in 40 CFR
60.102a(b)(1).
b. Compute Ni emission Equations 1 and 8 of
rate (lb/1,000 lb of Sec. 63.1564.
coke burn-off).
c. Determine the See item 4.c. of this You must obtain 1
equilibrium catalyst table. sample for each of the
Ni concentration. 3 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 hourly average
Method 29 test. opacity from all the 6-
minute averages.
(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
from all the readings.

[[Page 37011]]

e. Record the catalyst
addition rate for each
test and schedule for
the 10-day period
prior to the test.
6. If you elect Option 1 in item 4 in a. Establish each Data from the
Table 1, Option 3 in item 6 in Table operating limit in continuous parameter
1, or Option 4 in item 7 in Table 1 Table 2 of this monitoring systems and
of this subpart and you use subpart that applies applicable performance
continuous parameter monitoring to you. test methods.
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.
(2) You must determine
and record the 3-hr
average gas flow rate
from all the readings.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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: voltage continuous parameter voltage, current, and
and secondary current monitoring systems and secondary current
(or total power input). applicable performance monitoring data every
test methods. 15 minutes during the
entire period of the
performance test.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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 and the 3-
hr average secondary
current.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], you may
determine and record
the minimum hourly
average voltage and
secondary current (or
total power input)
from all the readings.
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.

[[Page 37012]]

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.
(2) You must determine
and record the 3-hr
average pressure drop
from all the readings.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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.
(2) You must determine
and record the hourly
average liquid-to-gas
ratio from all the
readings.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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 [THE DATE 18
MONTHS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], you may
determine and record
the hourly average
rate of all the
readings.

[[Page 37013]]

(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).
\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
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.

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
catalytic cracking unit For the following You have
catalyst regenerator vent . emission limit . . . demonstrated initial
. . compliance if . . .
------------------------------------------------------------------------
1. Subject to the NSPS for PM emissions must You have already
PM in 40 CFR 60.102. not exceed 1.0 gram conducted a
per kilogram (g/kg) performance test to
(1.0 lb/1,000 lb) demonstrate initial
of coke burn-off. compliance with the
Before [THE DATE 18 NSPS and the
MONTHS AFTER THE measured PM
DATE OF PUBLICATION emission rate is
OF THE FINAL RULE less than or equal
AMENDMENTS IN THE to 1.0 g/kg (1.0 lb/
FEDERAL REGISTER], 1,000 lb) of coke
if the discharged burn-off in the
gases pass through catalyst
an incinerator or regenerator. As
waste heat boiler part of the
in which you burn Notification of
auxiliary or Compliance Status,
supplemental liquid you must certify
or solid fossil that your vent
fuel, the meets the PM limit.
incremental rate of You are not
PM must not exceed required to do
43.0 grams per another performance
Gigajoule (g/GJ) or test to demonstrate
0.10 pounds per initial compliance.
million British As part of your
thermal units (lb/ Notification of
million Btu) of Compliance Status,
heat input you certify that
attributable to the your BLD; CO2, O2,
liquid or solid or CO monitor; or
fossil fuel; and continuous opacity
the opacity of monitoring system
emissions must not meets the
exceed 30 percent, requirements in
except for one 6- Sec. 63.1572.
minute average
opacity reading in
any 1-hour period.
2. Subject to NSPS for PM in PM emissions must You have already
40 CFR 60.102a(b)(1)(i), not exceed 0.5 g/kg conducted a
electing to meet the PM per (0.5 lb PM/1,000 performance test to
coke burn-off limit. lb) of coke burn- demonstrate initial
off or, 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.

[[Page 37014]]

3. Subject to NSPS for PM in PM emissions must You have already
40 CFR 60.102a(b)(1)(ii), not exceed 1.0 g/kg conducted a
electing to meet the PM per coke burn-off (1 lb/ performance test to
coke burn-off limit. 1000 lb coke burn- demonstrate initial
off). compliance with the
NSPS and the
measured PM
emission rate is
less than or equal
to 0.5 kg/1,000 kg
(0.5 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, 0.020 grain conducted a
electing to meet the PM per dry standard performance test to
concentration limit. cubic feet (gr/ demonstrate initial
dscf) corrected to compliance with the
0 percent excess NSPS and the
air. measured PM
concentration is
less than or equal
to 0.020 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.
5. Subject to NSPS for PM in If a PM CEMS is You have already
40 CFR 60.102a(b)(1)(ii), used, 0.040 gr/dscf conducted a
electing to meet the PM corrected to 0 performance test to
concentration limit. percent excess air. demonstrate initial
compliance with the
NSPS and the
measured PM
concentration is
less than or equal
to 0.040 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 1: PM per coke PM emissions must The average PM
burn-off limit not subject not exceed 1.0 gram emission rate,
to the NSPS for PM in 40 per kilogram (g/kg) measured using EPA
CFR 60.102 or 40 CFR (1.0 lb/1,000 lb) Method 5, 5B, or 5F
60.120a(b)(1). of coke burn-off. (for a unit without
Before [THE DATE 3 a wet scrubber) or
YEARS AFTER THE 5 or 5B (for a unit
DATE OF PUBLICATION with a wet
OF THE FINAL RULE scrubber), over the
AMENDMENTS IN THE period of the
FEDERAL REGISTER], initial performance
PM emission must test, is no higher
not exceed 1.0 g/kg than 1.0 g/kg coke
(1.0 lb/1,000 lb) burn-off (1.0 lb/
of coke burn-off in 1,000 lb) in the
the catalyst catalyst
regenerator; if the regenerator. The PM
discharged gases emission rate is
pass through an calculated using
incinerator or Equations 1, 2, and
waste heat boiler 3 of Sec.
in which you burn 63.1564. If you use
auxiliary or a BLD; CO2, O2, CO
supplemental liquid monitor; or
or solid fossil continuous opacity
fuel, the monitoring system,
incremental rate of your performance
PM must not exceed evaluation shows
43.0 g/GJ (0.10 lb/ the system meets
million Btu) of the applicable
heat input requirements in
attributable to the Sec. 63.1572.
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.
7. Option 2: PM PM emissions must The average PM
concentration limit, not not exceed 0.040 gr/ concentration,
subject to the NSPS for PM dscf corrected to 0 measured using EPA
in 40 CFR 60.102 or in 40 percent excess air. Method 5, 5B, or 5F
CFR 60.102a(b)(1). (for a unit without
a wet scrubber) or
Method 5 or 5B (for
a unit with a wet
scrubber), 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.

[[Page 37015]]

8. Option 3: not subject to Nickel (Ni) The average Ni
the NSPS for PM. emissions from your emission rate,
catalyst measured using
regenerator vent Method 29 over the
must not exceed period of the
13,000 mg/hr (0.029 initial performance
lb/hr). 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.
9. Option 4: Ni per coke Ni emissions from The average Ni
burn-off limit not subject your catalyst emission rate,
to the NSPS for PM. regenerator vent measured using
must not exceed 1.0 Method 29 over the
mg/kg (0.001 lb/ period of the
1,000 lb) of coke initial performance
burn-off in the test, is not more
catalyst than 1.0 mg/kg
regenerator. (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
For each new and existing emission limit for You shall
catalytic cracking unit . . your catalyst demonstrate
. regenerator vent . . continuous
. compliance by . . .
------------------------------------------------------------------------
1. Subject to the NSPS for a. PM emissions must i. Determining and
PM in 40 CFR 60.102. not exceed 1.0 gram recording each day
per kilogram (g/kg) the average coke
(1.0 lb/1,000 lb) burn-off rate
of coke burn-off. (thousands of
Before [THE DATE 18 kilograms per hour)
MONTHS AFTER THE using Equation 1 in
DATE OF PUBLICATION Sec. 63.1564 and
OF THE FINAL RULE the hours of
AMENDMENTS IN THE operation for each
FEDERAL REGISTER], catalyst
if the discharged regenerator.
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. Maintaining PM
emission rate below
1.0 g/kg (1.0 lb/
1,000 lb) of coke
burn-off.
iii. Conducting a
performance test
before [THE DATE 18
MONTHS AFTER THE
DATE OF PUBLICATION
OF THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER]
and once every five
years thereafter.
iv. Collecting the
applicable
continuous
parametric
monitoring system
data according to
Sec. 63.1572 and
maintaining each
rolling 3-hr
average above or
below (as
applicable) the
average determined
during the
performance test.

[[Page 37016]]

v. 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 the site-
specific opacity
determined during
the performance
test.
Alternatively,
before [THE DATE 18
MONTHS AFTER THE
DATE OF PUBLICATION
OF THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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.
vi. Before [THE DATE
18 MONTHS AFTER THE
DATE OF PUBLICATION
OF THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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 0.5 g/kg recording each day
electing to meet the PM per (0.5 lb PM/1,000 the average coke
coke burn-off limit.. lb) of coke burn- burn-off rate
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 PM/
1,000 lb) of coke
burn-off;
conducting a
performance test
once every year;
collecting the
applicable
continuous
parametric
monitoring system
data according to
Sec. 63.1572 and
maintaining each
rolling 3-hr
average above or
below (as
applicable) the
average determined
during the
performance test;
collecting the
continuous opacity
monitoring data for
each regenerator
vent according to
Sec. 63.1572 and
maintaining each 6-
minute average at
or below the site-
specific opacity
determined during
the performance
test.
3. Subject to NSPS for PM in PM emissions must Determining and
40 CFR 60.102a(b)(1)(ii), not exceed 1.0 g/kg recording each day
electing to meet the PM per coke burn-off (1 lb/ the average coke
coke burn-off limit. 1,000 lb coke burn- burn-off rate
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/
1,000 lb) of coke
burn-off;
conducting a
performance test
once every year;
collecting the
applicable
continuous
parametric
monitoring system
data according to
Sec. 63.1572 and
maintaining each
rolling 3-hr
average above or
below (as
applicable) the
average determined
during the
performance test;
collecting the
continuous opacity
monitoring data for
each regenerator
vent according to
Sec. 63.1572 and
maintaining each 6-
minute average at
or below the site-
specific opacity
determined during
the performance
test.
4. Subject to NSPS for PM in If a PM CEMS is Maintaining PM
40 CFR 60.102a(b)(1)(i), used, 0.020 grain concentration below
electing to meet the PM per dry standard 0.020 gr/dscf
concentration limit. cubic feet (gr/ corrected to 0
dscf) corrected to percent excess air.
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, 0.040 gr/dscf concentration below
electing to meet the PM corrected to 0 0.040 gr/dscf
concentration limit. percent excess air. corrected to 0
percent excess air.

[[Page 37017]]

6. Option 1: PM per coke See item 1 of this See item 1 of this
burn-off limit, not subject table. table.
to the NSPS for PM in 40
CFR 60.102 or in 40 CFR
60.102a(b)(1).
7. Option 2: PM PM emissions must See item 5 of this
concentration limit, not not exceed 0.040 gr/ table.
subject to the NSPS for PM dscf corrected to 0
in 40 CFR 60.102 or in 40 percent excess air.
CFR 60.102a(b)(1).
8. Option 3: Ni lb/hr limit, Ni emissions must Maintaining Ni
not subject to the NSPS for not exceed 13,000 emission rate below
PM in 40 CFR 60.102 or in mg/hr (0.029 lb/hr). 13,000 mg/hr (0.029
40 CFR 60.102a(b)(1). lb/hr); conducting
a performance test
before [THE DATE 18
MONTHS AFTER THE
DATE OF PUBLICATION
OF THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER]
and once every five
years thereafter;
and collecting the
applicable
continuous
parametric
monitoring system
data according to
Sec. 63.1572 and
maintaining each
rolling 3-hr
average above or
below (as
applicable) the
average determined
during the
performance test.
9. Option 4: Ni per coke Ni emissions must Determining and
burn-off limit, not subject not exceed 1.0 mg/ recording each day
to the NSPS for PM in 40 kg (0.001 lb/1,000 the average coke
CFR 60.102 or in 40 CFR lb) of coke burn- burn-off rate
60.102a(b)(1). off in the catalyst (thousands of
regenerator. kilograms per hour)
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;
conducting a
performance test
before [THE DATE 18
MONTHS AFTER THE
DATE OF PUBLICATION
OF THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER]
and once every five
years thereafter;
and collecting the
applicable
continuous
parametric
monitoring system
data according to
Sec. 63.1572 and
maintaining each
rolling 3-hr
average above or
below (as
applicable) the
average determined
during the
performance test.
------------------------------------------------------------------------

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 a. Continuous opacity Not applicable......... Complying with Table 6
60.102. monitoring system used of this subpart.
to comply with 30
percent opacity limit..
b. Continuous The average gas flow Collecting the hourly
parametric monitoring rate entering or and 3-hr rolling
systems--electrostatic exiting the control average gas flow rate
precipitator. device must not exceed monitoring data
the operating limit according to Sec.
established during the 63.1572; and
performance test.. maintaining the 3-hr
rolling average gas
flow rate at or below
the limit established
during the performance
test.
The average total power Collecting the hourly
and secondary current and 3-hr rolling
to the control device average total power
must not fall below and secondary current
the operating limit monitoring data
established during the according to Sec.
performance test. 63.1572; and
maintaining the 3-hr
rolling average total
power and secondary
current at or above
the limit established
during the performance
test.

[[Page 37018]]

c. Continuous The average pressure Collecting the hourly
parametric monitoring drop across the and 3-hr rolling
systems--wet scrubber. scrubber must not fall average pressure drop
below the operating monitoring data
limit established according to Sec.
during the performance 63.1572; and
test. maintaining the 3-hr
rolling average
pressure drop at or
above the limit
established during the
performance test.
The average liquid-to- Collecting the hourly
gas ratio must not and 3-hr rolling
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.
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.
e. Continuous opacity The average opacity Collecting the hourly
monitoring system, must not exceed the and 3-hr rolling
used for site-specific opacity established average opacity
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 limit
established during the
performance test.
2. Subject to NSPS for PM in 40 CFR Any.................... Any.................... See items 1.b, 1.c,
60.102a(b)(1)(ii), electing to meet 1.d, and 1.e of this
the PM per coke burn-off limit. table.
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.
PM concentration limit.
4. Option 1: PM per coke burn-off a. Continuous opacity The opacity of Collecting the 3-hr
limit, not subject to the NSPS for monitoring system. emissions from your rolling average
PM in 40 CFR 60.102 or in 40 CFR catalyst regenerator continuous opacity
60.102a(b)(1). vent must not exceed monitoring system data
the site-specific according to Sec.
opacity operating 63.1572; and
limit established maintaining the 3-hr
during the performance rolling average
test. opacity at or below
the site-specific
limit. Alternatively,
before [THE DATE 18
MONTHS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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.

[[Page 37019]]

b. Continuous parameter i. The average gas flow Collecting the hourly
monitoring systems-- rate entering or and 3-hr rolling
electrostatic exiting the control average gas flow rate
precipitator. device must not exceed monitoring data
the operating limit according to Sec.
established during the 63.1572; and
performance test. maintaining the 3-hr
rolling average gas
flow rate at or below
the limit established
during the performance
test. Alternatively,
before [THE DATE 18
MONTHS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], collecting
the hourly and daily
average gas flow rate
monitoring data
according to Sec.
63.1572; \1\ and
maintaining the daily
average gas flow rate
at or below the limit
established during the
performance test.
ii. The average voltage Collecting the hourly
and secondary current and 3-hr rolling
(or total power input) average total power
to the control device and secondary current
must not fall below monitoring data
the operating limit according to Sec.
established during the 63.1572; and
performance test.. maintaining the 3-hr
rolling average total
power and secondary
current at or above
the limit established
during the performance
test. Alternatively,
before [THE DATE 18
MONTHS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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.
c. Continuous parameter i. The average pressure Collecting the hourly
monitoring systems-- drop across the and 3-hr rolling
wet scrubber. scrubber must not fall average pressure drop
below the operating monitoring data
limit established according to Sec.
during the performance 63.1572; and
test. maintaining the 3-hr
rolling average
pressure drop at or
above the limit
established during the
performance test.
Alternatively, before
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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.

[[Page 37020]]

ii. The average liquid- Collecting the hourly
to-gas ratio must not and 3-hr rolling
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
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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.
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.
e. Continuous opacity The average opacity Collecting the hourly
monitoring system, must not exceed the and 3-hr rolling
used for site-specific opacity established average opacity
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 limit
established during the
performance test.
5. Option 2: PM concentration limit, PM CEMS................ Not applicable......... Complying with Table 6
not subject to the NSPS for PM in 40 of this subpart.
CFR 60.102 or in 40 CFR
60.102a(b)(1)..
6. 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 37021]]

(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
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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 4.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 voltage See item 4.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 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 pressure See item 4.c.i of this
monitoring systems-- drop must not fall table.
wet scrubber. below the operating
limit established in
the performance test.
ii. The average liquid- See item 4.c.ii of this
to-gas ratio must not table.
fall below the
operating limit
established during 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.. Increases in relative See item 4.d of this
particulate. table.
e. Continuous opacity The average opacity See item 4.e of this
monitoring system, must not exceed the table.
used for site-specific opacity established
opacity limit--Cyclone during the performance
or electrostatic test.
precipitator.

[[Page 37022]]

7. 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 gas
flow rate monitoring
data according to Sec.
63.1572; \1\
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
[THE DATE 18 MONTHS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], 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 daily average See item 4.b.i of this
monitoring systems-- gas flow rate to the table.
electrostatic control device must
precipitator. not exceed the level
established in the
performance test.
ii. The daily average See item 4.b.ii of this
voltage and secondary table.
current (or total
power input) must not
fall below the level
established in the
performance test.
iii. The monthly See item 6.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 daily average See item 4.c.i of this
monitoring systems-- pressure drop must not table.
wet scrubber. fall below the
operating limit
established in the
performance test.
....................... ii. The daily average See item 4.c.ii of this
liquid-to-gas ratio table.
must not fall below
the operating limit
established during the
performance test.
....................... iii. The monthly See item 6.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.. Increases in relative See item 4.d of this
particulate. table.
e. Continuous opacity The average opacity See item 4.e of this
monitoring system, must not exceed the table.
used for site-specific opacity established
opacity limit--Cyclone during the performance
or electrostatic test.
precipitator.
----------------------------------------------------------------------------------------------------------------
\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.

[[Page 37023]]

\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 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
59. Table 8 to subpart UUU of part 63 is amended by revising the entry
for item 2 to read as follows:
* * * * *

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 emission limit for each catalyst
catalytic cracking unit . . . regenerator vent . . .
------------------------------------------------------------------------

* * * * * * *
2. Not subject to the NSPS for CO a. CO emissions from the catalyst
in 40 CFR 60.103. 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 [THE DATE
3 YEARS AFTER THE DATE OF
PUBLICATION OF THE FINAL RULE
AMENDMENTS IN THE FEDERAL
REGISTER], the flare must meet the
requirements of Sec. 63.670.
Prior to [THE DATE 3 YEARS AFTER
THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE
FEDERAL REGISTER], 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 amended by revising the entry
for item 2 to read as follows:
* * * * *

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 . . .
----------------------------------------------------------------------------------------------------------------

* * * * * * *
2. Not subject to the NSPS for CO in a. Continuous emission Not applicable......... Not applicable.
40 CFR 60.103. 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.

[[Page 37024]]

iii. Flare............. On and after [THE DATE
3 YEARS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], the flare
must meet the
requirements of Sec.
63.670. Prior to [THE
DATE 3 YEARS AFTER THE
DATE OF PUBLICATION OF
THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER], 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
61. Table 10 to subpart UUU of part 63 is amended by revising the entry
for item 2 to read as follows:
* * * * *

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 vent of continuous
. . . . monitoring system .
. .
------------------------------------------------------------------------

* * * * * * *
2. Not subject to the NSPS a. Thermal Continuous emission
for CO in 40 CFR 60.103. incinerator. 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 or Continuous emission
boiler with a monitoring system
design heat input to measure and
capacity under 44 record the
MW or process concentration by
heater or boiler in volume (dry basis)
which all vent of CO emissions
streams are not from each catalyst
introduced into the regenerator vent;
flame zone. or continuous
parameter
monitoring systems
to measure and
record the
combustion zone
temperature.
c. Flare............ On and after [THE
DATE 3 YEARS AFTER
THE DATE OF
PUBLICATION OF THE
FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
the monitoring
systems required in
Sec. Sec. 63.670
and 63.671. Prior
to [THE DATE 3
YEARS AFTER THE
DATE OF PUBLICATION
OF THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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 device Continuous emission
monitoring system
to measure and
record the
concentration by
volume (dry basis)
of CO emissions
from each catalyst
regenerator vent.
------------------------------------------------------------------------

[[Page 37025]]

0
62. Table 11 to subpart UUU of part 63 is amended by revising 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 to part
continuous parameter monitoring basis) of emissions 60 of this chapter, as
systems. exiting the control 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.
f. If you use a flare, Method 22 (40 CFR part On and after [THE DATE
conduct visible 60, appendix A). 3 YEARS AFTER THE DATE
emission observations. OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], meet the
requirements of Sec.
63.670. Prior to [THE
DATE 3 YEARS AFTER THE
DATE OF PUBLICATION OF
THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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.

[[Page 37026]]

g. If you use a flare, 40 CFR 63.11(b)(6) On and after [THE DATE
determine that the through (8). 3 YEARS AFTER THE DATE
flare meets the OF PUBLICATION OF THE
requirements for net FINAL RULE AMENDMENTS
heating value of the IN THE FEDERAL
gas being combusted REGISTER], the flare
and exit velocity. must meet the
requirements of Sec.
63.670. Prior to [THE
DATE 3 YEARS AFTER THE
DATE OF PUBLICATION OF
THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER], the
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 amended by revising the entry
for item 2 to read as follows:
* * * * *

Table 12 to Subpart UUU of Part 63--Initial Compliance With Organic HAP
Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
For each new and existing You have
catalytic cracking unit . . For the following demonstrated initial
. emission limit . . . compliance if . . .
------------------------------------------------------------------------

* * * * * * *
2. Not subject to the NSPS a. CO emissions from i. If you use a
for CO in 40 CFR 60.103. your catalyst continuous
regenerator vent or parameter
CO boiler serving monitoring system,
the catalytic the average CO
cracking unit must emissions measured
not exceed 500 ppmv by Method 10 over
(dry basis). the period of the
initial performance
test are less than
or equal to 500
ppmv (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 [THE
flare, visible DATE 3 YEARS AFTER
emissions must not THE DATE OF
exceed a total of 5 PUBLICATION OF THE
minutes during any FINAL RULE
2 operating hours. AMENDMENTS IN THE
FEDERAL REGISTER],
the flare meets the
requirements of
Sec. 63.670.
Prior to [THE DATE
3 YEARS AFTER THE
DATE OF PUBLICATION
OF THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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
Sec. 63.670.
------------------------------------------------------------------------

0
64. Table 13 to subpart UUU of part 63 is amended by revising the entry
for item 2 to read as follows:
* * * * *

[[Page 37027]]

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 . . .
----------------------------------------------------------------------------------------------------------------

* * * * * * *
2. Not subject to the NSPS for CO in i. CO emissions from Continuous emission Same as above.
40 CFR 60.103. your catalyst monitoring system.
regenerator vent or CO
boiler serving the
catalytic cracking
unit must not exceed
500 ppmv (dry basis).
ii. 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).
iii. Visible emissions Control device-flare... On and after [THE DATE
from a flare must not 3 YEARS AFTER THE DATE
exceed a total of 5 OF PUBLICATION OF THE
minutes during any 2- FINAL RULE AMENDMENTS
hour period. IN THE FEDERAL
REGISTER], meeting the
requirements of Sec.
63.670. Prior to [THE
DATE 3 YEARS AFTER THE
DATE OF PUBLICATION OF
THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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 amended by revising the entry
for item 2 to read as follows:
* * * * *

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 . . .
----------------------------------------------------------------------------------------------------------------

* * * * * * *
2. Not subject to the NSPS for CO in a. Continuous emission Not applicable......... Complying with Table 13
40 CFR 60.103. monitoring system. of this subpart.
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.

[[Page 37028]]

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 into the limit established
the flame zone. during the performance
test.
d. Continuous parameter The flare pilot light On and after [THE DATE
monitoring system-- must be present at all 3 YEARS AFTER THE DATE
flare. times and the flare OF PUBLICATION OF THE
must be operating at FINAL RULE AMENDMENTS
all times that IN THE FEDERAL
emissions may be REGISTER], meeting the
vented to it. requirements of Sec.
63.670. Prior to [THE
DATE 3 YEARS AFTER THE
DATE OF PUBLICATION OF
THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
collecting the flare
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
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
For each applicable process vent during initial catalyst depressuring
for a new or existing catalytic and catalyst purging operations . .
reforming unit . . . .
------------------------------------------------------------------------
1. Option 1....................... On and after [THE DATE 3 YEARS AFTER
THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE
FEDERAL REGISTER], vent emissions
to a flare that meets the
requirements of Sec. 63.670.
Prior to [THE DATE 3 YEARS AFTER
THE DATE OF PUBLICATION OF THE
FINAL RULE AMENDMENTS IN THE
FEDERAL REGISTER], 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:
* * * * *

[[Page 37029]]

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 [THE
DATE 3 YEARS AFTER
THE DATE OF
PUBLICATION OF THE
FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
the flare must meet
the requirements of
Sec. 63.670. Prior
to [THE DATE 3 YEARS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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:
* * * * *

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 [THE
DATE 3 YEARS AFTER
THE DATE OF
PUBLICATION OF THE
FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
the monitoring
systems required in
Sec. Sec. 63.670
and 63.671. Prior to
[THE DATE 3 YEARS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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:
0
a. Revising the column headings and
0
b. Revising the entry for item 1.
The revisions 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 [THE DATE
emission observations. 60, appendix A). 3 YEARS AFTER THE DATE
OF PUBLICATION OF THE
FINAL RULE AMENDMENTS
IN THE FEDERAL
REGISTER], the flare
must meet the
requirements of Sec.
63.670. Prior to [THE
DATE 3 YEARS AFTER THE
DATE OF PUBLICATION OF
THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],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.

[[Page 37030]]

b. Determine that the 40 CFR 63.11(b)(6) On and after [THE DATE
flare meets the through (8). 3 YEARS AFTER THE DATE
requirements for net OF PUBLICATION OF THE
heating value of the FINAL RULE AMENDMENTS
gas being combusted and IN THE FEDERAL
exit velocity. REGISTER], the flare
must meet the
requirements of Sec.
63.670. Prior to [THE
DATE 3 YEARS AFTER THE
DATE OF PUBLICATION OF
THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER], 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 [THE
from a flare must DATE 3 YEARS AFTER
not exceed a total THE DATE OF
of 5 minutes during PUBLICATION OF THE
any 2 consecutive FINAL RULE
hours. AMENDMENTS IN THE
FEDERAL REGISTER],
the flare meets the
requirements of
Sec. 63.670.
Prior to [THE DATE
3 YEARS AFTER THE
DATE OF PUBLICATION
OF THE FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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:
* * * * *

Table 20 to Subpart UUU of Part 63--Continuous Compliance With Organic
HAP Emission Limits for Catalytic Reforming Units
------------------------------------------------------------------------
You shall demonstrate
continuous compliance
For each applicable process For this emission during initial
vent for a new or existing limit . . . catalyst depressuring
catalytic reforming unit . . . and catalyst purging
operations by . . .

------------------------------------------------------------------------
1. Option 1................... Vent emissions On and after [THE
from your DATE 3 YEARS AFTER
process vent to THE DATE OF
a flare. PUBLICATION OF THE
FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
meeting the
requirements of Sec.
63.670. Prior to
[THE DATE 3 YEARS
AFTER THE DATE OF
PUBLICATION OF THE
FINAL RULE
AMENDMENTS IN THE
FEDERAL REGISTER],
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.

[[Page 37031]]

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

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
For each applicable process vent continuous compliance
for a new or existing catalytic If you use . . . For this operating during initial catalyst
reforming unit . . . limit . . . depressuring and purging
operations by . . .
----------------------------------------------------------------------------------------------------------------
1. Option 1........................ Flare................. The flare pilot light On and after [THE DATE 3
must be present at all YEARS AFTER THE DATE OF
times and the flare PUBLICATION OF THE FINAL
must be operating at RULE AMENDMENTS IN THE
all times that FEDERAL REGISTER],
emissions may be meeting the requirements
vented to it. of Sec. 63.670. Prior
to [THE DATE 3 YEARS
AFTER THE DATE OF
PUBLICATION OF THE FINAL
RULE AMENDMENTS IN THE
FEDERAL REGISTER],
collecting flare
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
For . . . reforming unit process vent during
coke burn-off and catalyst
rejuvenation . . .
------------------------------------------------------------------------

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

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
If you use this type of control type of continuous monitoring system
device for your vent . . . . . .
------------------------------------------------------------------------

[[Page 37032]]

* * * * * * *
2. Internal scrubbing system or no Colormetric tube sampling system to
control device (e.g., hot regen measure the HCl concentration in
system) to meet HCl outlet the catalyst regenerator exhaust
concentration limit. 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 Continuous parameter monitoring
meet HCl percent reduction system to measure and record the
standard. 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 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 . . . Using . . . According to these
requirements . . .
----------------------------------------------------------------------------------------------------------------

* * * * * * *
2. Wet scrubber.................... a. Establish operating i. Data from Measure and record the pH
limit for pH level or continuous parameter or alkalinity of the water
alkalinity. monitoring systems. (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 pH
procedure in Sec. of the water (or scrubbing
63.1573 (b)(1). 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.
iii. Alternative Measure and record the
alkalinity method in alkalinity of the water
Sec. 63.1573(c)(2). (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 a. Establish operating i. Data from Measure and record the pH
meeting HCl percent reduction limit for pH level or continuous parameter alkalinity of the water
standard. alkalinity. monitoring system. (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.

[[Page 37033]]

ii. Alternative pH Measure and record pH of
method in Sec. the water (or scrubbing
63.1573(c)(1). 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 of the water
Sec. 63.1573(c)(2). (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.

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

0
76. Table 28 to subpart UUU of part 63 is amended by revising the entry
for item 5 and footnote 1 to read as follows:
The revisions 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 compliance
catalytic reforming unit using For this during coke burn-off
this type of control device or operating limit . and catalyst
system . . . . . rejuvenation by . . .

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

* * * * * * *
5. Moving-bed gas-solid a. The daily Collecting the hourly
adsorption system (e.g., average and daily average
Chlorsorb\TM\ System. temperature of temperature
the gas entering monitoring data
or exiting the according to Sec.
adsorption 63.1572; and
system must not maintaining the
exceed the limit daily average
established temperature below
during the the operating limit
performance test. established during
the performance
test.
b. The weekly Collecting samples of
average chloride the sorbent exiting
level on the the adsorption
sorbent entering system three times
the adsorption per week (on non-
system must not consecutive days);
exceed the and analyzing the
design or samples for total
manufacturer's chloride; \3\ and
recommended determining and
limit (1.35 recording the weekly
weight percent average chloride
for the concentration; and
Chlorsorb\TM\ maintaining the
System). chloride
concentration below
the design or
manufacturer's
recommended limit
(1.35 weight percent
for the
Chlorsorb\TM\
System).
c. The weekly Collecting samples of
average chloride the sorbent exiting
level on the the adsorption
sorbent exiting system three times
the adsorption per week (on non-
system must not consecutive days);
exceed the and analyzing the
design or samples for total
manufacturer's chloride
recommended concentration; and
limit (1.8 determining and
weight percent recording the weekly
for the average chloride
Chlorsorb\TM\ concentration; and
System). 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.
* * * * *

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.

[[Page 37034]]

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. Each new or existing Claus sulfur a. 250 ppmv (dry basis) of
recovery unit part of a sulfur sulfur dioxide (SO2) at zero
recovery plant with design capacity percent excess air, or
greater than 20 long tons per day and concentration determined using
subject to the NSPS for sulfur oxides Equation 1 of 40 CFR
in 40 CFR 60.104(a)(2) or in 40 CFR 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.
2. Each new or existing sulfur recovery a. 250 ppmv (dry basis) of SO2
unit (Claus or other type, regardless at zero percent excess air, or
of size) not subject to the NSPS for concentration determined using
sulfur oxides in 40 CFR 60.104(a)(2) Equation 1 of 40 CFR
or in 40 CFR 60.102a(f)(1): Option 1 60.102a(f)(1)(i), if you use
(Elect NSPS). 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. Each new or existing sulfur recovery 300 ppmv of total reduced
unit (Claus or other type, regardless sulfur (TRS) compounds,
of size) not subject to the NSPS for expressed as an equivalent SO2
sulfur oxides in 40 CFR 60.104(a)(2) concentration (dry basis) at
or in 40 CFR 60.102a(f)(1): Option 2 zero percent oxygen.
(TRS limit).
------------------------------------------------------------------------

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
------------------------------------------------------------------------
If use this type
For . . . of control You shall meet this
device operating limit . . .
------------------------------------------------------------------------
1. Each new or existing Claus Not applicable.. Not applicable.
sulfur recovery unit part of a
sulfur recovery plant with
design capacity greater than
20 long tons per day and
subject to the NSPS for sulfur
oxides in 40 CFR 60.104(a)(2)
or in 40 CFR 60.102a(f)(1).
2. Each new or existing sulfur Not applicable.. Not applicable.
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 in 40 CFR 60.102a(f)(1):
Option 1 (Elect NSPS).
3. Each new or existing sulfur Not applicable.. Not applicable.
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 in 40 CFR 60.102a(f)(1):
Option 2 (TRS limit), if using
continuous emissions
monitoring systems.
4. Each new or existing sulfur Thermal Maintain the daily
recovery unit (Claus or other incinerator. average combustion
type, regardless of size) not zone temperature
subject to the NSPS for sulfur above the limit
oxides in 40 CFR 60.104(a)(2) established during
or in 40 CFR 60.102a(f)(1): the performance
Option 2 (TRS limit), if using test; and maintain
continuous parameter the daily average
monitoring systems. oxygen concentration
in the vent stream
(percent, dry basis)
above the limit
established during
the performance
test.
------------------------------------------------------------------------

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. Each new or existing Claus a. 250 ppmv (dry Continuous
sulfur recovery unit part of a basis) of SO2 at emission
sulfur recovery plant with zero percent monitoring system
design capacity greater than excess air if you to measure and
20 long tons per day and use an oxidation record the hourly
subject to the NSPS for sulfur or reduction average
oxides in 40 CFR 60.104(a)(2) control system concentration of
or in 40 CFR 60.102a(f)(1). followed by SO2 (dry basis)
incineration. at zero percent
excess air for
each exhaust
stack. This
system must
include an oxygen
monitor for
correcting the
data for excess
air.

[[Page 37035]]

b. 300 ppmv of Continuous
reduced sulfur emission
compounds monitoring system
calculated as ppmv to measure and
SO2 (dry basis) at record the hourly
zero percent average
excess air if you concentration of
use a reduction reduced sulfur
control system and oxygen (O2)
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 Complete either
Equation 1 of 40 item 1.a or item
CFR 1.b; and you must
60.102a(f)(1)(i) also install and
to set your operate a
emission limit. continuous
emission
monitoring system
to measure and
record the O2
concentration for
the inlet air/
oxygen supplied
to the system.
2. Option 1: Elect NSPS. Each a. 250 ppmv (dry Continuous
new or existing sulfur basis) of SO2 at emission
recovery unit (Claus or other zero percent monitoring system
type, regardless of size) not excess air if you to measure and
subject to the NSPS for sulfur use an oxidation record the hourly
oxides in paragraph (a) (2) of or reduction average
40 CFR 60.104 or in 40 CFR control system concentration of
60.102a(f)(1). followed by SO2 (dry basis),
incineration. at 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
reduced sulfur emission
compounds monitoring system
calculated as ppmv to measure and
SO2 (dry basis) at record the hourly
zero percent average
excess air if you concentration of
use a reduction reduced sulfur
control system and O2 emissions
without for each exhaust
incineration. 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.
c. If you use Complete either
Equation 1 of 40 item 2.a or item
CFR 2.b; and you must
60.102a(f)(1)(i) also install and
to set your operate a
emission limit. continuous
emission
monitoring system
to measure and
record the O2
concentration for
the inlet air/
oxygen supplied
to the system.
3. Option 2: TRS limit. Each 300 ppmv of total i. Continuous
new or existing sulfur reduced sulfur emission
recovery unit (Claus or other (TRS) compounds, monitoring system
type, regardless of size) not expressed as an to measure and
subject to the NSPS for sulfur equivalent SO2 record the hourly
oxides in 40 CFR 60.104(a)(2) concentration (dry average
or in 40 CFR 60.102a(f)(1). basis) at zero concentration of
percent oxygen. 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.
------------------------------------------------------------------------

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.

[[Page 37036]]

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. Each new and existing sulfur Measure SO2 Data from continuous Collect SO2 monitoring
recovery unit: Option 1 (Elect NSPS). 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.
Measure O2 Data from continuous Collect O2 monitoring
concentration for the emission monitoring data every 15 minutes
inlet air/oxygen system. 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
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).
2. Each new and existing sulfur Measure the Data from continuous Collect TRS data every
recovery unit: Option 2 (TRS limit), concentration of emission monitoring 15 minutes for 24
using CEMS. 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.
3. Each new and existing sulfur a. Select sampling Method 1 or 1A in Sampling sites must be
recovery unit: Option 2 (TRS limit), port's location and Appendix A-1 to part located at the outlet
if using continuous parameter the number of traverse 60 of this chapter. of the control device
monitoring systems. ports. and prior to any
releases to the
atmosphere.
b. Determine velocity Method 2, 2A, 2C, 2D,
and volumetric flow 2F, or 2G in appendix
rate. A to part 60 of this
chapter, as applicable.
c. Conduct gas Method 3, 3A, or 3B in Take the samples
molecular weight appendix A to part 60 simultaneously with
analysis; obtain the 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 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 to part 60 area of the duct is
of this chapter, as less than 5 square
applicable. meters (m\2\) or 54
square feet, you must
use the centroid of
the cross section as
the sampling point. If
the cross-sectional
area is 5 m\2\ 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.

[[Page 37037]]

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.

Table 33 to Subpart UUU of Part 63--Initial Compliance With HAP Emission
Limits for Sulfur Recovery Units
------------------------------------------------------------------------
For the following
emission limit . You have demonstrated
For . . . . . initial compliance if
. . .
------------------------------------------------------------------------
1. Each new or existing Claus a. 250 ppmv (dry You have already
sulfur recovery unit part of basis) SO2 at conducted a
a sulfur recovery plant with zero percent performance test to
design capacity greater than excess air, or demonstrate initial
20 long tons per day and concentration compliance with the
subject to the NSPS for determined using NSPS and each 12-
sulfur oxides in 40 CFR Equation 1 of 40 hour rolling average
60.104(a)(2) or in 40 CFR CFR concentration of SO2
60.102a(f)(1). 60.102a(f)(1)(i) emissions measured
, if you use an by the continuous
oxidation or emission monitoring
reduction system is less than
control system or equal to 250 ppmv
followed by (dry basis) at zero
incineration. 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 demonstrate initial
ppmv SO2 (dry compliance with the
basis) at zero NSPS and each 12-
percent excess hour rolling average
air, or concentration of
concentration reduced sulfur
determined using compounds measured
Equation 1 of 40 by your continuous
CFR emission monitoring
60.102a(f)(1)(i) system is less than
, if you use a or equal to 300
reduction ppmv, calculated as
control system ppmv SO2 (dry basis)
without at zero percent
incineration. 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. Each a. 250 ppmv (dry Each 12-hour rolling
new or existing sulfur basis) of SO2 at average
recovery unit (Claus or other zero percent concentration of SO2
type, regardless of size) not excess air, or emissions measured
subject to the NSPS for concentration by the continuous
sulfur oxides in 40 CFR determined using emission monitoring
60.104(a)(2) or in 40 CFR Equation 1 of 40 system during the
60.102a(f)(1). CFR initial performance
60.102a(f)(1)(i) test is less than or
, if you use an equal to 250 ppmv
oxidation or (dry basis) at zero
reduction percent excess air,
control system or the concentration
followed by determined using
incineration. 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.

[[Page 37038]]

b. 300 ppmv of Each 12-hour rolling
reduced sulfur average
compounds concentration of
calculated as reduced sulfur
ppmv SO2 (dry compounds measured
basis) at zero by the continuous
percent excess emission monitoring
air, or system during the
concentration initial performance
determined using test is less than or
Equation 1 of 40 equal to 300 ppmv,
CFR calculated as ppmv
60.102a(f)(1)(i) SO2 (dry basis) at
, if you use a zero percent excess
reduction air, or the
control system concentration
without determined using
incineration. 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.
3. Option 2: TRS limit. Each 300 ppmv of TRS If you use continuous
new or existing sulfur compounds parameter monitoring
recovery unit (Claus or other expressed as an systems, the average
type, regardless of size) not equivalent SO2 concentration of TRS
subject to the NSPS for concentration emissions measured
sulfur oxides in 40 CFR (dry basis) at using Method 15
60.104(a)(2) or in 40 CFR zero percent during the initial
60.102a(f)(1). oxygen. 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 demonstrate
For this emission continuous compliance
For . . . limit . . . by . . .

------------------------------------------------------------------------
1. Each new or existing Claus a. 250 ppmv (dry Collecting the hourly
sulfur recovery unit part of basis) of SO2 at average SO2
a sulfur recovery plant with zero percent monitoring data (dry
design capacity greater than excess air, or basis, percent
20 long tons per day and concentration excess air)
subject to the NSPS for determined using according to Sec.
sulfur oxides in 40 CFR Equation 1 of 40 63.1572; determining
60.104(a)(2) or in 40 CFR CFR and recording each
60.102a(f)(1). 60.102a(f)(1)(i) 12-hour rolling
, if you use an average
oxidation or concentration of
reduction SO2; maintaining
control system each 12-hour rolling
followed by average
incineration. 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 hourly
reduced sulfur average reduced
compounds sulfur (and air or
calculated as O2 dilution and
ppmv SO2 (dry oxidation)
basis) at zero monitoring data
percent excess according to Sec.
air, or 63.1572; determining
concentration and recording each
determined using 12-hour rolling
Equation 1 of 40 average
CFR concentration of
60.102a(f)(1)(i) reduced sulfur;
, if you use a maintaining each 12-
reduction hour rolling average
control system concentration of
without reduced sulfur at or
incineration. 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.
2. Option 1: Elect NSPS. Each a. 250 ppmv (dry Collecting the hourly
new or existing sulfur basis) of SO2 at average SO2 data
recovery unit (Claus or other zero percent (dry basis, percent
type, regardless of size) not excess air, or excess air)
subject to the NSPS for concentration according to Sec.
sulfur oxides in 40 CFR determined using 63.1572; determining
60.104(a)(2) or in 40 CFR Equation 1 of 40 and recording each
60.102a(f)(1). CFR 12-hour rolling
60.102a(f)(1)(i) average
, if you use an concentration of
oxidation or SO2; maintaining
reduction each 12-hour rolling
control system average
followed by concentration of SO2
incineration. 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 hourly
reduced sulfur average reduced
compounds sulfur (and air or
calculated as O2 dilution and
ppmv SO2 (dry oxidation)
basis) at zero monitoring data
percent excess according to Sec.
air, or 63.1572; determining
concentration and recording each
determined using 12-hour rolling
Equation 1 of 40 average
CFR concentration of
60.102a(f)(1)(i) reduced sulfur;
, if you use a maintaining each 12-
reduction hour rolling average
control system concentration of
without reduced sulfur at or
incineration. 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 parameter
recovery unit (Claus or other expressed as an monitoring systems,
type, regardless of size) not SO2 collecting the
subject to the NSPS for concentration hourly average TRS
sulfur oxides in 40 CFR (dry basis) at monitoring data
60.104(a)(2) or in 40 CFR zero percent according to Sec.
60.102a(f)(1). oxygen or 63.1572 and
reduced sulfur maintaining each 12-
compounds hour average
calculated as concentration of TRS
ppmv SO2 (dry at or below the
basis) at zero applicable emission
percent excess limitation; or
air.

[[Page 37039]]

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 demonstrate
For this continuous compliance
For . . . operating limit . by . . .
. .
------------------------------------------------------------------------
1. Each new or existing Claus Not applicable... Meeting the
sulfur recovery unit part of requirements of
a sulfur recovery plant with Table 34 of this
design capacity greater than subpart.
20 long tons per day and
subject to the NSPS for
sulfur oxides in paragraph 40
CFR 60.104(a)(2) or in 40 CFR
60.102a(f)(1).
2. Option 1: Elect NSPS. Each Not applicable... Meeting the
new or existing sulfur requirements of
recovery unit (Claus or other Table 34 of this
type, regardless of size) not subpart.
subject to the NSPS for
sulfur oxides in 40 CFR
60.104(a)(2) or in 40 CFR
60.102a(f)(1).
3. Option 2: TRS limit. Each a. Maintain the Collecting the hourly
new or existing sulfur daily average and daily average
recovery unit (Claus or other combustion zone temperature
type, regardless of size) not temperature monitoring data
subject to the NSPS for above the level according to Sec.
sulfur oxides in 40 CFR established 63.1572; and
60.104(a)(2) or in 40 CFR during the maintaining the
60.102a(f)(1). performance test. daily average
combustion zone
temperature at or
above the limit
established during
the performance
test.
b. The daily Collecting the hourly
average oxygen and daily average O2
concentration in monitoring data
the vent stream according to Sec.
(percent, dry 63.1572; and
basis) must not maintaining the
fall below the average O2
level concentration above
established the level
during the established during
performance test. the performance
test.
------------------------------------------------------------------------

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
emission monitoring system . . . Must meet these requirements . . .

------------------------------------------------------------------------
1. Continuous opacity monitoring Performance specification 1 (40 CFR
system. part 60, Appendix B).
2. PM CEMS; this monitor must The requirements in 40 CFR
include an O2 monitor for 60.105a(d).
correcting the data for excess
air.
3. CO2, O2, and CO monitors for The requirements in 40 CFR
coke burn-off rate. 60.105a(b)(2).
4. CO continuous emission Performance specification 4 (40 CFR
monitoring system. 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.

[[Page 37040]]

5. CO continuous emission Performance specification 4 (40 CFR
monitoring system used to part 60, Appendix B); and span
demonstrate emissions average value of 100 ppm.
under 50 ppm (dry basis).
6. SO2 continuous emission Performance specification 2 (40 CFR
monitoring system for sulfur part 60, Appendix B); span value of
recovery unit with oxidation 500 ppm SO2, or if using Equation 1
control system or reduction of 40 CFR 60.102a(f)(1)(i), span
control system; this monitor must value of two times the limit at the
include an O2 monitor for highest O2 concentration; use
correcting the data for excess Methods 6 or 6C (40 CFR part 60,
air. 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.
7. Reduced sulfur and O2 Performance specification 5 (40 CFR
continuous emission monitoring part 60, Appendix B), except
system for sulfur recovery unit calibration drift specification is
with reduction control system not 2.5 percent of the span value
followed by incineration; this instead of 5 percent; span value is
monitor must include an O2 450 ppm reduced sulfur, or if using
monitor for correcting the data Equation 1 of 40 CFR
for excess air unless exempted. 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.
8. Instrument with an air or O2 Performance specification 5 (40 CFR
dilution and oxidation system to part 60, Appendix B); span value of
convert reduced sulfur to SO2 for 375 ppm SO2 or if using Equation 1
continuously monitoring the of 40 CFR 60.102a(f)(1)(i), span
concentration of SO2 instead of value of two times the limit at the
reduced sulfur monitor and O2 highest O2 concentration; use
monitor. Methods 15 or 15A for certifying
the reduced sulfur monitor and 3A
or 3B 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.
9. TRS continuous emission Performance specification 5 (40 CFR
monitoring system for sulfur part 60, Appendix B).
recovery unit; this monitor must
include an O2 monitor for
correcting the data for excess
air.
10. O2 monitor for oxygen If necessary due to interferences,
concentration. 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.
11. O2 monitor for oxygen Install, operate, and maintain each
concentration in inlet or supply. O2 monitor according to Performance
Specification 3 of Appendix B to
part 60; the span value for the O2
monitor must be selected between 20
and 100 percent; conduct
performance evaluations for O2
monitor according to Performance
Specification 3 of Appendix B to
part 60, and must use Method 3A or
3B of Appendix A-2 to part 60 for
conducting relative accuracy
evaluations; comply with applicable
quality assurance procedures of
Appendix F to part 60 for each
monitor, including annual accuracy
determinations for each O2 monitor
and daily calibration drift
determinations.
------------------------------------------------------------------------

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 sampling Use a colormetric tube sampling
system. 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.
4. BLD............................ Follow the requirements in 40 CFR
60.105a(c).
5. Voltage, secondary current, or Use meters with an accuracy of at
total power input sensors. least 5 percent over
the operating range.
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 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; and record the results
of each calibration check and
inspection.

[[Page 37041]]

6. Pressure/Pressure drop \1\ Locate the pressure sensor(s) in a
sensors. position that provides a
representative measurement of the
pressure; minimizes or eliminates
pulsating pressure, vibration, and
internal and external corrosion.
Use a gauge with an accuracy of at
least 5 percent over
the operating range or 0.5 inches
of water column, whichever is
greater.
Check pressure tap for plugs at
least once a week; using a
manometer, check gauge calibration
quarterly and transducer
calibration monthly; conduct
calibration checks following any
period of more than 24 hours
throughout which the sensor exceeds
the manufacturer's specified
maximum operating pressure range or
install a new pressure sensor; at
least monthly, inspect all
components for integrity, all
electrical connections for
continuity, and all mechanical
connections for leakage; record the
results of each calibration check
and inspection.
7. Air flow rate, gas flow rate, Locate the flow sensor(s) and other
or total water (or scrubbing necessary equipment (such as
liquid) flow rate sensors. 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 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, or 0.5 gallons per minute
for liquid flow, or 10 cubic feet
per minute for gas flow, whichever
is greater.
Conduct a flow sensor calibration
check at least semiannually;
conduct calibration checks
following any period of more than
24 hours throughout which the
sensor exceeds the manufacturer's
specified maximum operating range
or install a new flow sensor; at
least monthly, inspect all
components for leakage; record the
results of each calibration check
and inspection.
8. 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 of the temperature being
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
sensor exceeds the manufacturer's
specified maximum operating
temperature range, or install a new
temperature sensor; at least
monthly, inspect all components for
integrity and all electrical
connections for continuity,
oxidation, and galvanic corrosion;
record the results of each
calibration check and inspection.
9. Oxygen content sensors \2\..... 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.
Conduct calibration checks at least
quarterly; conduct calibration
checks following any period of more
than 24 hours throughout which the
sensor exceeds the manufacturer's
specified maximum operating range,
or install a new oxygen sensor; at
least monthly, 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. These
requirements 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.

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 not 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 [THE DATE Within 60 days
performance evaluation data. 3 YEARS AFTER THE after the date
DATE OF PUBLICATION of completing
OF THE FINAL RULE each test
AMENDMENTS IN THE according to
FEDERAL REGISTER], the
the information requirements in
specified in Sec. Sec.
63.1575(k)(1). 63.1575(k).
------------------------------------------------------------------------

[[Page 37042]]

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
----------------------------------------------------------------------------------------------------------------
Citation Subject Applies to subpart 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 subpart UUU
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 Yes
part after a Relevant
Standard has been set
under this part.
Sec. 63.1(c)(2).................. No.................... Area sources are not
subject to subpart UUU.
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 Yes
Permit Program.
Sec. 63.2........................ Definitions........... Yes................... Sec. 63.1579 of subpart
UUU specifies that if the
same term is defined in
subparts A and UUU, it
shall have the meaning
given in subpart UUU.
Sec. 63.3........................ Units and Yes
Abbreviations.
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 Yes................... Except subpart UUU
Approval of specifies the application
Construction or is submitted as soon as
Reconstruction--Gener practicable before startup
al Application but not later than 90 days
Requirements. after the promulgation
date if construction or
reconstruction had
commenced and initial
startup had not occurred
before promulgation.
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.................... Subpart UUU 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 Yes
Construction or
Reconstruction.
Sec. 63.5(f)(1).................. Approval of Yes
Construction 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 Yes
Standards and
Maintenance--Applicab
ility.
Sec. 63.6(b)(1)-(4).............. Compliance Dates for Yes
New and Reconstructed
Sources.
Sec. 63.6(b)(5).................. Yes................... Except that subpart UUU
specifies different
compliance dates for
sources.
Sec. 63.6(b)(6).................. [Reserved]............ Not applicable

[[Page 37043]]

Sec. 63.6(b)(7).................. Compliance Dates for Yes
New and Reconstructed
Area Sources That
Become Major.
Sec. 63.6(c)(1)-(2).............. Compliance Dates for Yes................... Except that subpart UUU
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 No.................... See Sec. 63.1570(c) for
Minimize 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 Yes
Standards 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 Yes
Standards 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
Sec. 63.6(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 No
Opacity/VE Standards.
Sec. 63.6(h)(2)(i)............... Determining Compliance No.................... Subpart UUU specifies
with Opacity/VE methods.
Standards.
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 Yes................... Applies to Method 22 tests.
Opacity/VE
Observation Date.
Sec. 63.6(h)(5).................. Conducting Opacity/VE No
Observations.
Sec. 63.6(h)(6).................. Records of Conditions Yes................... Applies to Method 22
During Opacity/VE observations.
Observations.
Sec. 63.6(h)(7)(i)............... Report COM Monitoring Yes
Data from Performance
Test.
Sec. 63.6(h)(7)(ii).............. Using COM Instead of No
Method 9.
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 Yes
Visual Observations.
Sec. 63.6(h)(8).................. Determining Compliance Yes
with Opacity/VE
Standards.
Sec. 63.6(h)(9).................. Adjusted Opacity Yes
Standard.
Sec. 63.6(i)(1)-(14)............. Extension of Yes................... Extension of compliance
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

[[Page 37044]]

Sec. 63.6(j)..................... Presidential Yes
Compliance Exemption.
Sec. 63.7(a)(1).................. Performance Test Yes................... Except that subpart UUU
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 subpart UUU
specifies notification at
least 30 days prior to the
scheduled test date rather
than 60 days.
Sec. 63.7(c)..................... Quality Assurance Yes
Program/Site-Specific
Test Plan.
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 Yes
Method.
Sec. 63.7(g)..................... Data Analysis, Yes................... Except performance test
Recordkeeping, reports must be submitted
Reporting. 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 Yes
Requirements--Applica
bility.
Sec. 63.8(a)(2).................. Performance Yes
Specifications.
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................... Subpart UUU specifies the
Multiple Monitoring required monitoring
Systems. locations.
Sec. 63.8(c)(1).................. Monitoring System Yes
Operation and
Maintenance.
Sec. 63.8(c)(1)(i)............... General Duty to No.................... See Sec. 63.1570(c).
Minimize Emissions
and CMS Operation.
Sec. 63.8(c)(1)(ii).............. Keep Necessary Parts Yes
for CMS.
Sec. 63.8(c)(1)(iii)............. Requirement to Develop No
SSM Plan for CMS.
Sec. 63.8(c)(2)-(3).............. Monitoring System Yes................... Except that subpart UUU
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 Yes
Procedures.
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 Yes
Program for CMS.
Sec. 63.8(d)(3).................. Written Procedures for No
CMS.
Sec. 63.8(e)..................... CMS Performance Yes................... Except that results are to
Evaluation. 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 subpart UUU
Methods. specifies procedures for
requesting alternative
monitoring systems and
alternative parameters.
Sec. 63.8(f)(6).................. Alternative to Yes................... Applicable to continuous
Relative Accuracy emission monitoring
Test. systems if performance
specification requires a
relative accuracy test
audit.
Sec. 63.8(g)(1)-(4).............. Reduction of Yes................... Applies to continuous
Monitoring Data. opacity monitoring system
or continuous emission
monitoring system.

[[Page 37045]]

Sec. 63.8(g)(5).................. Data Reduction........ No.................... Subpart UUU specifies
requirements.
Sec. 63.9(a)..................... Notification Yes................... Duplicate Notification of
Requirements--Applica Compliance Status report
bility. 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 Yes
of Compliance.
Sec. 63.9(d)..................... New Source Yes
Notification for
Special Compliance
Requirements.
Sec. 63.9(e)..................... Notification of Yes................... Except that notification is
Performance Test. required at least 30 days
before test.
Sec. 63.9(f)..................... Notification of VE/ Yes
Opacity Test.
Sec. 63.9(g)..................... Additional Yes
Notification
Requirements for
Sources with
Continuous Monitoring
Systems.
Sec. 63.9(h)..................... Notification of Yes................... Except that subpart UUU
Compliance 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 Yes
Deadlines.
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.
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 No
Minimize 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 Yes
Recordkeeping
Requirements for CMS--
Identifying
Exceedances and
Excess Emissions.
Sec. 63.10(c)(9)................. [Reserved]............ Not applicable
Sec. 63.10(c)(10)................ Recording Nature and No.................... See Sec. 63.1576(a)(2)
Cause 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.

[[Page 37046]]

Sec. 63.10(d)(2)................. Performance Test No.................... Subpart UUU requires
Results. 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 Yes
Observations.
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.................... Subpart UUU specifies the
Performance Reports. applicable requirements.
Sec. 63.10(e)(4)................. COMS Data Reports..... Yes
Sec. 63.10(f).................... Recordkeeping/ Yes
Reporting Waiver.
Sec. 63.11(a).................... Control Device and Yes
Work Practice
Requirements--Applica
bility.
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 Yes
Practice for
Monitoring Equipment
for Leaks.
Sec. 63.12....................... State Authority and Yes
Delegations.
Sec. 63.13....................... Addresses............. Yes
Sec. 63.14....................... Incorporation by Yes
Reference.
Sec. 63.15....................... Availability of Yes
Information and
Confidentiality.
Sec. 63.16....................... Performance Track Yes
Provisions.
----------------------------------------------------------------------------------------------------------------

0
88. Appendix A to subpart UUU of part 63 is amended by:
0
a. Revising the first sentence of section 2.1; and
0
b. Revising section 7.1.3.
The revisions 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.
* * * * *

Appendix A to Part 63--[AMENDED]

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

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 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 and 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 unless the compound or sorbent has already been
validated and reported in one of the following national/
international standard methods: ISO 16017-2:2003 (incorporated by
reference--see Sec. 63.14), ASTM D6196-03(2009) (incorporated by
reference--see Sec. 63.14), or BS EN 14662-4:2005 (incorporated by
reference--see Sec. 63.14), or 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/m\3\) 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.)) stainless steel
sorbent tubes packed with Carbograph 1 TD\TM\, Carbopack B\TM\, or
Carbopack X[supreg] 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 over an extended
period of time using multiple sampling episodes (e.g., 26 x 14-day
sampling episodes). The duration of each sampling period must be 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.

[[Page 37047]]

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 the fenceline
or facility 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 the facility fenceline or property boundaries and collection of
local meteorological data. It may be used to determine average
concentration of VOC at a facility fenceline or property boundaries
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.
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 Retention volume is the maximum mass of VOC that can be
collected before the capacity of the sorbent is exceeded and back
diffusion of the VOC from the tube occurs.
3.8 Sampling episode is the length of time each passive sampler
is exposed during field monitoring. The sampling episode for this
method is 14 days.
3.9 Sorbent tube (Also referred to as tube, PS tube, sorbent
tube, and sampling tube) is a stainless steel or inert coated
stainless steel tube. Standard PS tube dimensions for this method
are 3.5-inch (89 mm) long x 0.25-inch (6.4 mm) o.d. stainless steel
tubes with an i.d. of 5 mm, a cross-sectional area of 19.6 mm\2\ 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. General guidance
for siting can be found in EPA-454/B-13-003, Quality Assurance
Handbook for Air Pollution Measurement Systems, Volume II: Ambient
Air Quality Monitoring Program, May 2013 (Reference 3) (incorporated
by reference--see Sec. 63.14). 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 excludes 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 retention

[[Page 37048]]

volume (i.e., 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 fenceline
or 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
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 that 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 (2009) (Reference 14) (incorporated by reference--see
Sec. 63.14) and ISO 16017-2:2003 (Reference 13) (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).
[GRAPHIC] [TIFF OMITTED] TP30JN14.026

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 (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

[[Page 37049]]

(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, Quality Assurance Handbook for Air Pollution Measurement
Systems, Volume IV: Meteorological Measurements, Version 2.0
(Final), March 2008 (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 boundary. You will place passive samplers on the
facility property boundary at different angles circling the
geometric center of the facility based on the size of the area (or
subarea) or at different distances based on the size and boundary
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.
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.
8.2.2.1.1 For regularly shaped facilities with an area of less
than or equal to 750 acres, measure angles around the center point
of 30 degrees for a total of twelve 30 degree measurements.
8.2.2.1.2 For regularly shaped facilities covering an area
greater than 750 acres but less than or equal to 1,500 acres,
measure from the center point angles of 20 degrees for a total of
eighteen 20 degree measurements. 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.
8.2.2.1.4 Place samplers securely on a pole or supporting
structure at 1.5 to 3 meters above ground level at each point just
beyond the intersection where the measured angle intersects the
property boundary.
8.2.2.1.5 Extra samplers must be placed near known sources of
VOCs at the test facility. In the case that a potential emission
source is within 50 meters of the property 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) to
provide sufficient coverage of all area sources.
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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

[[Page 37050]]

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 8.2), measure angles of 30 degrees from the center point for
a total of twelve 30 degree measurements.
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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 8.3), measure angles of 20
degrees from the center point for a total of eighteen 20 degree
measurements.
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.
8.2.2.3 Locate each sampling point just beyond the intersection
of the measured angle and the outer property boundary.
8.2.2.4 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 more than one point
along the subarea's outer boundary.

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8.2.3 Option 2 for Determining Sampling Locations.
8.2.3.1 For facilities with a boundary length of less than
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 boundary length greater than
24,000 feet, sampling locations are spaced 2,000 250
feet apart.
8.2.3.4 Place samplers securely on a pole or supporting
structure at 1.5 to 3 meters above ground level.
8.2.3.5 Extra samplers must be placed near known sources of VOCs
at the test facility. In the case that a potential emission source
is within 50 meters of the property 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 8.4, the facility added three
additional monitors (i.e., light shaded sampler locations) to
provide sufficient coverage of all area sources.

[[Page 37052]]

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8.3 Siting a Meteorological Station. A dedicated 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, Meteorological Monitoring Guidance for Regulatory
Modeling Applications, February 2000 (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. 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 from large paved areas.
8.3.4 Collect and record meteorological data, including wind
speed, wind direction, and temperature and average data on an hourly
basis. Collect daily unit vector wind direction data plus average
temperature and barometric pressure measurements of the sampled air
to enable calculation of concentrations at standard conditions.
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 from 48
hours 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. The sampling tubes must 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 at a height of 1.5 to 2 meters
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 at at least
one monitoring location during each field monitoring exercise.
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.)
8.5.9 Expose the sampling tubes for the 14-day sampling period.
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. One field blank tube is
required for every 10 sampled tubes on a monitoring exercise. No

[[Page 37053]]

less than two field blanks should be collected, regardless of the
size of the monitoring study. Record the tube number(s) for the
field blank(s) on the field sample data sheet.
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.
8.6.6 Collect daily unit vector wind direction data plus average
temperature and barometric pressure measurements to enable
calculation of concentrations at standard conditions. You must
supply this information to the laboratory with the samples.

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, Quality Assurance
Handbook for Air Pollution Measurement Systems, Volume IV:
Meteorological Measurements, Version 2.0 (Final), 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) can be calculated for
any specified period at each PS location using Equation 12.1.
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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 episodes 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.
12.3.3 Information on published or documented events on- and
off-site may also be included in the associated sampling episode
report to explain elevated concentrations if relevant. For example,
you

[[Page 37054]]

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 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.

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 Measurement 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, 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(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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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 Carbopack X or equivalent 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 a given compound or set of the compounds listed in 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 Appendix A to this method unless the compound or
sorbent has already been validated and reported in one of the
following national/international standard methods: ISO 16017-
2:2003(incorporated by reference--see Sec. 63.14), ASTM D6196-
03(2009) (incorporated by reference--see Sec. 63.14), or BS EN
14662-4:2005 (incorporated by reference--see Sec. 63.14), or 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 desorping the sampling tube, refocusing on a focusing
trap, desorping 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 back diffusion
becomes significant--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 Calibration verification sample. 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 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.
3.10 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.
3.11 o.d. is outer diameter.
3.12 ppbv is parts per billion by volume.
3.13 Retention volume is the volume of gas required to move an
analyte vapor plug through the sorbent tube at a given temperature
during active (pumped) sampling. Note that retention volume provides
another measure of the strength of sorbent:sorbate (analyte)
affinity and is closely related to breakthrough volume--See
discussion in Section 3.2 above.
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 means 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 polymer
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.

[[Page 37057]]

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 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] TP30JN14.034

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 only be used for tube conditioning only
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

[[Page 37058]]

through the septum of a conventional GC 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 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 (incorporated by reference--see Sec. 63.14) or
ASTM D6196-03(2009) (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 unless the compound
or sorbent has already been validated and reported in one of the
following national/international standard methods: ISO 16017-2:2003
(incorporated by reference--see Sec. 63.14), ASTM D6196-03(2009)
(incorporated by reference--see Sec. 63.14), or BS EN 14662-4:2005
(incorporated by reference--see Sec. 63.14)--or 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.
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 yearly 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 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

[[Page 37059]]

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 flow
([deg]C) ([deg]C) rate
----------------------------------------------------------------------------------------------------------------
Carbotrap C[supreg].................................... >400 350 100 mL/min.
Carbopack C[supreg]
Anasorb[supreg] GCB2
Carbograph 1 TD
Carbotrap[supreg]
Carbopack B[supreg]
Anasorb[supreg] GCB1
Tenax[supreg] TA....................................... 350 330 100 mL/min.
Carbopack[supreg] 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 samplers will also be required:
Laboratory blanks as specified in Section 9.3.2 (two per sampling
episode minimum), field blanks as specified in Section 9.3.4 (two
per sampling episode minimum), calibration verification tubes as
specified in Section 10.9.4. (at least one per analysis sequence or
every 24 hours), and paired (duplicate) samples as specified in
Section 9.4 (at least one pair of duplicate samples 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 Analytical System Blank. The analytical system must be
demonstrated to be contaminant free by carrying out an analysis
without a sorbent tube--i.e., by desorbing an empty tube or by
desorbing the focusing trap alone. Since no internal standards can
be added directly to the empty tube, the system blank must have less
than or equal to 0.2 ppbv or three times the detection limit for
each target compound, whichever is larger based on the response
factors for the continuing calibration verification sample. Perform
a system 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. Flag all sample
data from analytical sequences that fail the system blank check and
provide a narrative on how the failure affects the data use.
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 (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 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 and Laboratory Blanks.
9.3.1 Field and laboratory 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 At least two laboratory blanks are required per monitoring
episode. These laboratory blanks must be stored in the laboratory
under clean controlled ambient temperature conditions throughout the
monitoring period. Analyze one laboratory blank at the beginning and
one at the end of the associated field sample runs.
9.3.3 Laboratory blank/artifact levels must meet the
requirements of Section 9.2.2 (see also Table 17.1). Flag all data
that do not meet this criterion with a note that associated results
are estimated, and likely to be biased high due to laboratory blank
background.

[[Page 37060]]

9.3.4 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 (see Method 325B). The long-term
storage caps must be in place and must be stored outside the
shipping container at the sampling location (see Method 325B). 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.
9.3.5 Field blanks must contain no greater than one-third of the
measured target analyte or compliance limit for field samples (see
Table 17.1). 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 (collocated) 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 Limit of Detection. Determine the limit of detection under
the analytical conditions selected (see Section 11.3) using the
procedure in Section 15 of Method 301. The limit of detection 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 measure
analytes such as benzene at concentrations as low as 10 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 routine, single-level calibration verification 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] TP30JN14.035

Where:

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 daily single-level calibration
verification checks may also be applied for this purpose.
[GRAPHIC] [TIFF OMITTED] TP30JN14.036

Where:

A1 = A measurement value taken from one spiked tube.
A2 = A measurement value taken from a second spiked tube.
[Amacr] = 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] TP30JN14.037

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 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 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 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.

[[Page 37061]]

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 Calibrations Checks at the Start of a Sequence. Run
single-level calibration checks 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 routine calibration
check 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 daily calibration standard. The percent
deviation between the initial calibration and the daily calibration
check for all compounds must be within 30 percent.
9.14 Calibration Verification at the End of a Sequence. Run
another single level standard after running each sequence of
samples. The initial calibration check for a subsequent set of
samples may be used as the final calibration check 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 calibration verification.
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 5.0 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 of carrier
gas using a precision syringe and an unheated injector (Section
6.6). 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 and allowed to
warm to the temperature of the injection body. The liquid is then
quickly injected. The result is the cool liquid contacts the hot
syringe tip and the sample is completely forced into the injector
and onto the sorbent cartridge. A bias occurs with this method when
sample is drawn continuously up into the syringe to the specified
volume 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

[[Page 37062]]

should be refrigerated if there is any risk of chemical interaction
or degradation.
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 and relevant
parts of Section 9.5.
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
single-level calibration verification 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 Single-level calibrations checks must be carried out on
a regular routine basis as described in Section 9.6.
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
Characteristic ion(s)
Compound CAS No. BP ([deg]C) Vapor 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-Dichloroethane............................ 75-34-3 57.0 230 99 63 65, 83, 85, 98,
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 A calibration verification.
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 A single-level calibration verification standard tube
after 10 field samples.
11.1.1.7 A single-level calibration verification standard tube
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.
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

[[Page 37063]]

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 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
routine, single-level calibration verification standards are within
30 percent of the most recent 5-point calibration (see Section
10.9.5). Include relevant routine, single-level calibration data in
the supporting information in the data report for each set of
samples.
11.3.2.5 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 episode.
12.1.3 Keep records of sorbent tube packing if tubes are
manually prepared in the 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
daily unit vector wind direction, daily average temperature, and
daily average barometric pressure for the sample collection period.
See Section 8.6.5 of Method 325A.
12.1.8 Laboratory personnel must record the sample receipt date,
and analysis date.

[[Page 37064]]

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 episode.
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] TP30JN14.038

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] TP30JN14.039

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] TP30JN14.040

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] TP30JN14.041

Where:

R1, R2 = Values that are being compared (i.e., response factors in
calibration verification).
12.2.2 Determine the equivalent concentration of compounds in
atmospheres as follows.
12.2.3 For passive sorbent tube samples, calculate the
concentration of the target compound(s) in the sampled air, in
[mu]g/m\3\ by using Equation 12.5 (Reference 21).
[GRAPHIC] [TIFF OMITTED] TP30JN14.042

Where:

Cm = The concentration of target compound in the air
sampled ([mu]g/m\3\).
mmeas = The mass of the compound as measured in the
sorbent tube ([mu]g).
U = The diffusive uptake rate (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 limits of detection 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 for Selected Clean Air
Act Compounds
------------------------------------------------------------------------
Carbopack X
Compound uptake rate
(ml/min) \a\
------------------------------------------------------------------------
1,1-Dichloroethene...................................... 0.570.14
3-Chloropropene......................................... 0.510.3
1,1-Dichloroethane...................................... 0.570.1
1,2-Dichloroethane...................................... 0.570.08
1,1,1-Trichloroethane................................... 0.510.1
Benzene................................................. 0.660.06
Carbon tetrachloride.................................... 0.510.06
1,2-Dichloropropane..................................... 0.520.1
Trichloroethene......................................... 0.50.05
1,1,2-Trichloroethane................................... 0.490.13
Toluene................................................. 0.520.14
Tetrachloroethene....................................... 0.480.05
Chlorobenzene........................................... 0.510.06
Ethylbenzene............................................ 0.460.07
m,p-Xylene.............................................. 0.460.09
Styrene................................................. 0.50.14
o-Xylene................................................ 0.460.12

[[Page 37065]]

p-Dichlorobenzene....................................... 0.450.05
------------------------------------------------------------------------
\a\ Reference 3, McClenny, J. Environ. Monit. 7:248-256.

12.2.4 Correct target concentrations determined at the sampling
site temperature and atmospheric pressure to standard conditions (25
[deg]C and 760 mm mercury) using Equation 12.6 (Reference 22).
[GRAPHIC] [TIFF OMITTED] TP30JN14.043

Where:

tss = The temperature at the sampling site (K).
Pss = The pressure at the sampling site (mm Hg).

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.
13.1 The valid range for measurement of VOC is approximately 0.5
[mu]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 X solid adsorbent followed by thermal 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 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

[[Page 37066]]

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. ASTM D4597-10, Standard Practice for Sampling Workplace
Atmospheres to collect Gases or Vapors with Solid Sorbent Diffusive
Samplers.
22. 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.
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: 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 Daily \a\ prior to sample Evaluation criteria 1) Retune and or
Tune Performance Check. analysis. presented in Section 2) Perform Maintenance.
9.5 and Table 9.2.
Five point calibration bracketing Following any major 1) Percent Deviation 1) Repeat calibration
the expected sample change, repair or (%DEV) of response sample analysis.
concentration. maintenance or if daily factors 30%.
CCV does not meet method
requirements.
Recalibration not to
exceed three months.
2) Relative Retention 2) Repeat linearity
Times (RRTs) for target check
peaks 0.06
units from mean RRT.
3) Prepare new
calibration standards
as necessary and repeat
analysis.
Calibration Verification (CCV Following the calibration The response factor 1) Repeat calibration
Second source calibration curve. 30% DEV check
verification check). from calibration curve
average response factor.
2) Repeat calibration
curve.
System Blank Analysis............ Daily \a\ following 1) <=0.2 ppbv per 1) Repeat analysis with
bromofluorobenzene and analyte or <=3 times new blank tube.
calibration check; prior the LOD, whichever is
to sample analysis. greater.
2) Internal Standard 2) Check system for
(IS) area response leaks, contamination.
40% and IS
Retention Time (RT)
0.33 min.
of most recent
calibration check.
3) Analyze additional
blank.
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 of times the LOD,
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.

[[Page 37067]]

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[[Page 37068]]

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BILLING CODE 6560-50-P

[[Page 37069]]

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[[Page 37070]]

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BILLING CODE 6560-50-C

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, unless the
compound or

[[Page 37071]]

sorbent has already been validated and reported in one of the
following national/international standard methods: ISO 16017-2:2003
(incorporated by reference--see Sec. 63.14), ASTM D6196-03(2009)
(incorporated by reference--see Sec. 63.14), or BS EN 14662-4:2005
(incorporated by reference--see Sec. 63.14), or 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

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
for an example exposure chamber). 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 active SUMMA
canister sampling.
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 SUMMA
canisters. 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 generate a minimum of four exposed 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 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 measure the relative humidity in the test gas as
part of the record of the passive sorbent sampler evaluation.
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 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 50 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 equal 100 percent
of the volume of the chamber per minute (i.e., one chamber air
change per minute) and 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 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

[[Page 37072]]

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 hourly intervals
or at the beginning, middle, and end of the exposure time, whichever
is greater.
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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[[Page 37073]]

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

[[Page 37074]]

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 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 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
min (2 week) rates mL/min (2 week)
----------------------------------------------------------------------------------------------------------------
Carbopack 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 X solid adsorbent followed by thermal desorption/GC/MS analysis--
laboratory studies. J. Environ. Monit. 7:248-256.

A.13.2 Data Analysis and Calculations for Method Evaluation
A.13.2.1 Calculate the theoretical concentration of VOC
standards using Equation A.1.
[GRAPHIC] [TIFF OMITTED] TP30JN14.050

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.
[GRAPHIC] [TIFF OMITTED] TP30JN14.051

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.
[GRAPHIC] [TIFF OMITTED] TP30JN14.052

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.
[GRAPHIC] [TIFF OMITTED] TP30JN14.053

[[Page 37075]]

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.
[GRAPHIC] [TIFF OMITTED] TP30JN14.054

Where:

[Delta]95[percnt] = 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.
[GRAPHIC] [TIFF OMITTED] TP30JN14.055

Where:

RA = Relative accuracy.
Xi = The mean value of all Xi.
XA = The average concentration of analyte measured by the
active measurement method.
[Delta]95[percnt] = 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. 2014-12167 Filed 6-26-14; 8:45 am]
BILLING CODE 6560-50-P

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