Vol. 76 Tuesday, No. 163 August 23, 2011

Part II

Environmental Protection Agency

40 CFR Parts 60 and 63 Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews; Proposed Rule

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ENVIRONMENTAL PROTECTION ADDRESSES: Submit your comments, recommends that you include your AGENCY identified by Docket ID Number EPA– name and other contact information in HQ–OAR–2010–0505, by one of the the body of your comment and with any 40 CFR Parts 60 and 63 following methods: disk or CD–ROM you submit. If the EPA • [EPA–HQ–OAR–2010–0505; FRL–9448–6] Federal eRulemaking Portal: http:// cannot read your comment due to www.regulations.gov: Follow the technical difficulties and cannot contact RIN 2060–AP76 instructions for submitting comments. you for clarification, the EPA may not • Agency Web site: http:// be able to consider your comment. Oil and Natural Gas Sector: New www.epa.gov/oar/docket.html. Follow Electronic files should avoid the use of Source Performance Standards and the instructions for submitting special characters, any form of National Emission Standards for comments on the Air and Radiation encryption, and be free of any defects or Hazardous Air Pollutants Reviews Docket Web site. viruses. For additional information • E-mail: [email protected]. AGENCY: Environmental Protection about the EPA’s public docket, visit the Include Docket ID Number EPA–HQ– Agency (EPA). EPA Docket Center homepage at http:// OAR–2010–0505 in the subject line of ACTION: Proposed rule. www.epa.gov/epahome/dockets.htm. the message. For additional instructions on • Facsimile: (202) 566–9744. SUMMARY: submitting comments, go to section II.C This action announces how • Mail: Attention Docket ID Number of the SUPPLEMENTARY INFORMATION the EPA proposes to address the reviews EPA–HQ–OAR–2010–0505, 1200 section of this preamble. of the new source performance Pennsylvania Ave., NW., Washington, standards for volatile organic compound DC 20460. Please include a total of two Docket: All documents in the docket and sulfur dioxide emissions from copies. In addition, please mail a copy are listed in the http:// natural gas processing plants. We are of your comments on the information www.regulations.gov index. Although proposing to add to the source category collection provisions to the Office of listed in the index, some information is list any oil and gas operation not Information and Regulatory Affairs, not publicly available, e.g., CBI or other covered by the current listing. This Office of Management and Budget information whose disclosure is action also includes proposed (OMB), Attn: Desk Officer for the EPA, restricted by statute. Certain other amendments to the existing new source 725 17th Street, NW., Washington, DC material, such as copyrighted material, performance standards for volatile 20503. is not placed on the Internet and will be organic compounds from natural gas • Hand Delivery: United States publicly available only in hard copy. processing plants and proposed Environmental Protection Agency, EPA Publicly available docket materials are standards for operations that are not West (Air Docket), Room 3334, 1301 available either electronically through covered by the existing new source Constitution Ave., NW., Washington, http://www.regulations.gov or in hard performance standards. In addition, this DC 20004, Attention Docket ID Number copy at the U.S. Environmental action proposes how the EPA will EPA–HQ–OAR–2010–0505. Such Protection Agency, EPA West (Air address the residual risk and technology deliveries are only accepted during the Docket), Room 3334, 1301 Constitution review conducted for the oil and natural Docket’s normal hours of operation, and Ave., NW., Washington, DC 20004. The gas production and natural gas special arrangements should be made Public Reading Room is open from transmission and storage national for deliveries of boxed information. 8:30 a.m. to 4:30 p.m., Monday through emission standards for hazardous air Instructions: Direct your comments to Friday, excluding legal holidays. The pollutants. This action further proposes Docket ID Number EPA–HQ–OAR– telephone number for the Public standards for emission sources within 2010–0505. The EPA’s policy is that all Reading Room is (202) 566–1744, and these two source categories that are not comments received will be included in the telephone number for the Air Docket currently addressed, as well as the public docket without change and is (202) 566–1742. amendments to improve aspects of these may be made available online at http:// FOR FURTHER INFORMATION CONTACT: national emission standards for www.regulations.gov, including any Bruce Moore, Sector Policies and hazardous air pollutants related to personal information provided, unless Programs Division, Office of Air Quality applicability and implementation. the comment includes information Planning and Standards (E143–01), Finally, this action addresses provisions claimed to be confidential business Environmental Protection Agency, in these new source performance information (CBI) or other information Research Triangle Park, North Carolina standards and national emission whose disclosure is restricted by statute. 27711, telephone number: (919) 541– standards for hazardous air pollutants Do not submit information that you 5460; facsimile number: (919) 685–3200; related to emissions during periods of consider to be CBI or otherwise e-mail address: [email protected]. startup, shutdown and malfunction. protected through http:// SUPPLEMENTARY INFORMATION: DATES: Comments must be received on www.regulations.gov or e-mail. The or before October 24, 2011. http://www.regulations.gov Web site is Organization of This Document. The Public Hearing. Three public hearings an ‘‘anonymous access’’ system, which following outline is provided to aid in will be held to provide the public an means the EPA will not know your locating information in this preamble. opportunity to provide comments on identity or contact information unless I. Preamble Acronyms and Abbreviations this proposed rulemaking. One will be you provide it in the body of your II. General Information held in the Dallas, Texas area, one in comment. If you send an e-mail A. Does this action apply to me? Pittsburgh, Pennsylvania, and one in comment directly to the EPA without B. Where can I get a copy of this document Denver, Colorado, on dates to be going through http:// and other related information? announced in a separate document. www.regulations.gov, your e-mail C. What should I consider as I prepare my comments for the EPA? Each hearing will convene at 10 a.m. address will be automatically captured D. When will a public hearing occur? local time. For additional information and included as part of the comment III. Background Information on the public hearings and requesting to that is placed in the public docket and A. What are standards of performance and speak, see the SUPPLEMENTARY made available on the Internet. If you NSPS? INFORMATION section of this preamble. submit an electronic comment, the EPA B. What are NESHAP?

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C. What litigation is related to this Minority Populations and Low-Income MIR Maximum Individual Risk proposed action? Populations MIRR Monitoring, Inspection, D. What is a sector-based approach? Recordkeeping and Reporting IV. Oil and Natural Gas Sector I. Preamble Acronyms and MMtCO2e Million Metric Tons of Carbon V. Summary of Proposed Decisions and Abbreviations Dioxide Equivalents Actions Several acronyms and terms used to NAAQS National Ambient Air Quality A. What are the proposed revisions to the describe industrial processes, data Standards NSPS? NAC/AEGL National Advisory Committee B. What are the proposed decisions and inventories and risk modeling are for Acute Exposure Guideline Levels for actions related to the NESHAP? included in this preamble. While this Hazardous Substances C. What are the proposed notification, may not be an exhaustive list, to ease NAICS North American Industry recordkeeping and reporting the reading of this preamble and for Classification System requirements for this proposed action? reference purposes, the following terms NAS National Academy of Sciences D. What are the innovative compliance and acronyms are defined here: NATA National Air Toxics Assessment approaches being considered? NEI National Emissions Inventory E. How does the NSPS relate to permitting ACGIH American Conference of NEMS National Energy Modeling System of sources? Governmental Industrial Hygienists NESHAP National Emissions Standards for VI. Rationale for Proposed Action for NSPS ADAF Age-Dependent Adjustment Factors Hazardous Air Pollutants A. What did we evaluate relative to NSPS? AEGL Acute Exposure Guideline Levels NGL Natural Gas Liquids B. What are the results of our evaluations AERMOD The air dispersion model used by NIOSH National Institutes for Occupational and proposed actions relative to NSPS? the HEM–3 model Safety and Health API American Petroleum Institute VII. Rationale for Proposed Action for NOX Oxides of Nitrogen NESHAP BACT Best Available Control Technology NRC National Research Council A. What data were used for the NESHAP BID Background Information Document NSPS New Source Performance Standards analyses? BPD Barrels Per Day NSR New Source Review BSER Best System of Emission Reduction B. What are the proposed decisions NTTAA National Technology Transfer and BTEX Benzene, Ethylbenzene, Toluene and regarding certain unregulated emissions Advancement Act Xylene sources? OAQPS Office of Air Quality Planning and CAA Clean Air Act C. How did we perform the risk assessment Standards CalEPA California Environmental and what are the results and proposed OMB Office of Management and Budget Protection Agency decisions? PB–HAP Hazardous air pollutants known to CBI Confidential Business Information be persistent and bio-accumulative in the D. How did we perform the technology CEM Continuous Emissions Monitoring environment review and what are the results and CEMS Continuous Emissions Monitoring PFE Potential for Flash Emissions proposed decisions? System PM Particulate Matter E. What other actions are we proposing? CFR Code of Federal Regulations PM Particulate Matter (2.5 microns and VIII. What are the cost, environmental, 2.5 CIIT Chemical Industry Institute of less) energy and economic impacts of the Toxicology POM Polycyclic Organic Matter proposed 40 CFR part 60, subpart OOOO CO Carbon Monoxide PPM Parts Per Million and amendments to subparts HH and CO2 Carbon Dioxide PPMV Parts Per Million by Volume HHH of 40 CFR part 63? CO2e Carbon Dioxide Equivalent PSIG Pounds per square inch gauge A. What are the affected sources? DOE Department of Energy PTE Potential to Emit B. How are the impacts for this proposal ECHO Enforcement and Compliance QA Quality Assurance evaluated? History Online RACT Reasonably Available Control C. What are the air quality impacts? e-GGRT Electronic Greenhouse Gas Technology D. What are the water quality and solid Reporting Tool RBLC RACT/BACT/LAER Clearinghouse waste impacts? EJ Environmental Justice REC Reduced Emissions Completions E. What are the secondary impacts? EPA Environmental Protection Agency REL CalEPA Reference Exposure Level F. What are the energy impacts? ERPG Emergency Response Planning RFA Regulatory Flexibility Act G. What are the cost impacts? Guidelines RfC Reference Concentration H. What are the economic impacts? ERT Electronic Reporting Tool RfD Reference Dose I. What are the benefits? GCG Gas Condensate Glycol RIA Regulatory Impact Analysis IX. Request for Comments GHG Greenhouse Gas RICE Reciprocating Internal Combustion X. Submitting Data Corrections GOR Gas to Oil Ratio Engines XI. Statutory and Executive Order Reviews GWP Global Warming Potential RTR Residual Risk and Technology Review A. Executive Order 12866: Regulatory HAP Hazardous Air Pollutants SAB Science Advisory Board Planning and Review and Executive HEM–3 Human Exposure Model, version 3 SBREFA Small Business Regulatory Order 13563: Improving Regulation and HI Hazard Index Enforcement Fairness Act Regulatory Review HP Horsepower SCC Source Classification Codes B. Paperwork Reduction Act HQ Hazard Quotient SCFH Standard Cubic Feet Per Hour C. Regulatory Flexibility Act H2S Hydrogen Sulfide SCFM Standard Cubic Feet Per Minute D. Unfunded Mandates Reform Act ICR Information Collection Request SCM Standard Cubic Meters E. Executive Order 13132: Federalism IPCC Intergovernmental Panel on Climate SCMD Standard Cubic Meters Per Day F. Executive Order 13175: Consultation Change SCOT Shell Claus Offgas Treatment and Coordination With Indian Tribal IRIS Integrated Risk Information System SIP State Implementation Plan Governments km Kilometer SISNOSE Significant Economic Impact on a G. Executive Order 13045: Protection of kW Kilowatts Substantial Number of Small Entities Children From Environmental Health LAER Lowest Achievable Emission Rate S/L/T State and Local and Tribal Agencies and Safety Risks lb Pounds SO2 Sulfur Dioxide H. Executive Order 13211: Actions LDAR Leak Detection and Repair SSM Startup, Shutdown and Malfunction Concerning Regulations That MACT Maximum Achievable Control STEL Short-term Exposure Limit Significantly Affect Energy Supply, Technology TLV Threshold Limit Value Distribution, or Use MACT Code Code within the NEI used to TOSHI Target Organ-Specific Hazard Index I. National Technology Transfer and identify processes included in a source TPY Tons per Year Advancement Act category TRIM Total Risk Integrated Modeling System J. Executive Order 12898: Federal Actions Mcf Thousand Cubic Feet TRIM.FaTE A spatially explicit, To Address Environmental Justice in Mg/yr Megagrams per year compartmental mass balance model that

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describes the movement and VCS Voluntary Consensus Standards proposal are listed in Table 1 of this transformation of pollutants over time, VOC Volatile Organic Compounds preamble. These standards and any through a user-defined, bounded system VRU Vapor Recovery Unit changes considered in this rulemaking that includes both biotic and abiotic would be directly applicable to sources compartments II. General Information as a Federal program. Thus, Federal, TSD Technical Support Document A. Does this action apply to me? UF Uncertainty Factor state, local and tribal government UMRA Unfunded Mandates Reform Act The regulated industrial source entities are not affected by this proposed URE Unit Risk Estimate categories that are the subject of this action.

TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS PROPOSED ACTION

Category NAICS Examples of regulated entities code 1

Industry ...... 211111 Crude Petroleum and Natural Gas Extraction. 211112 Natural Gas Liquid Extraction. 221210 Natural Gas Distribution. 486110 Pipeline Distribution of Crude Oil. 486210 Pipeline Transportation of Natural Gas. Federal government ...... Not affected. State/local/tribal government ...... Not affected. 1 North American Industry Classification System.

This table is not intended to be within the disk or CD ROM the specific III. Background Information exhaustive, but rather provides a guide information that is claimed as CBI. In A. What are standards of performance for readers regarding entities likely to be addition to one complete version of the and NSPS? affected by this action. To determine comment that includes information whether your facility would be claimed as CBI, a copy of the comment 1. What is the statutory authority for regulated by this action, you should that does not contain the information standards of performance and NSPS? examine the applicability criteria in the claimed as CBI must be submitted for Section 111 of the Clean Air Act regulations. If you have any questions inclusion in the public docket. If you (CAA) requires the EPA Administrator regarding the applicability of this action submit a CD ROM or disk that does not to list categories of stationary sources, if to a particular entity, contact the person contain CBI, mark the outside of the such sources cause or contribute FOR FURTHER listed in the preceding disk or CD ROM clearly that it does not significantly to air pollution, which may INFORMATION CONTACT section. contain CBI. Information not marked as reasonably be anticipated to endanger B. Where can I get a copy of this CBI will be included in the public public health or welfare. The EPA must document and other related docket and the EPA’s electronic public then issue performance standards for information? docket without prior notice. Information such source categories. A performance marked as CBI will not be disclosed standard reflects the degree of emission In addition to being available in the except in accordance with procedures docket, an electronic copy of this limitation achievable through the set forth in 40 CFR part 2. Send or application of the ‘‘best system of proposal will also be available on the deliver information identified as CBI EPA’s Web site. Following signature by emission reduction’’ (BSER) which the only to the following address: Roberto EPA determines has been adequately the EPA Administrator, a copy of this Morales, OAQPS Document Control proposed action will be posted on the demonstrated. The EPA may consider Officer (C404–02), Environmental certain costs and nonair quality health EPA’s Web site at the following address: Protection Agency, Office of Air Quality http://www.epa.gov/airquality/ and environmental impact and energy Planning and Standards, Research requirements when establishing oilandgas. Triangle Park, North Carolina 27711, Additional information is available on performance standards. Whereas CAA Attention Docket ID Number EPA–HQ– the EPA’s Residual Risk and Technology section 112 standards are issued for OAR–2010–0505. Review (RTR) Web site at http:// existing and new stationary sources, www.epa.gov/ttn/atw/rrisk/oarpg.html. D. When will a public hearing occur? standards of performance are issued for This information includes the most new and modified stationary sources. recent version of the rule, source We will hold three public hearings, These standards are referred to as new category descriptions, detailed one in the Dallas, Texas area, one in source performance standards (NSPS). emissions and other data that were used Pittsburgh, Pennsylvania, and one in The EPA has the authority to define the as inputs to the risk assessments. Denver, Colorado. If you are interested source categories, determine the in attending or speaking at one of the pollutants for which standards should C. What should I consider as I prepare public hearings, contact Ms. Joan Rogers be developed, identify the facilities my comments for the EPA? at (919) 541–4487 by September 6, 2011. within each source category to be Submitting CBI. Do not submit Details on the public hearings will be covered and set the emission level of the information containing CBI to the EPA provided in a separate notice and we standards. through http://www.regulations.gov or will specify the time and date of the CAA section 111(b)(1)(B) requires the e-mail. Clearly mark the part or all of public hearings on http://www.epa.gov/ EPA to ‘‘at least every 8 years review the information that you claim to be airquality/oilandgas. If no one requests and, if appropriate, revise’’ performance CBI. For CBI information on a disk or to speak at one of the public hearings by standards unless the ‘‘Administrator CD ROM that you mail to the EPA, mark September 6, 2011, then that public determines that such review is not the outside of the disk or CD ROM as hearing will be cancelled without appropriate in light of readily available CBI and then identify electronically further notice. information on the efficacy’’ of the

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standard. When conducting a review of regulates sulfur dioxide (SO2) emissions standards promulgated under CAA an existing performance standard, the from natural gas processing plants (40 section 112(d)(3), and may not be based EPA has discretion to revise that CFR part 60, subpart LLL). Other than on cost considerations. For new sources, standard to add emission limits for natural gas processing plants, EPA has the MACT floor cannot be less stringent pollutants or emission sources not not previously set NSPS for a variety of than the emission control that is currently regulated for that source oil and natural gas operations. achieved in practice by the best- category. controlled similar source. The MACT In setting or revising a performance B. What are NESHAP? floors for existing sources can be less standard, CAA section 111(a)(1) 1. What is the statutory authority for stringent than floors for new sources, provides that performance standards are NESHAP? but they cannot be less stringent than to ‘‘reflect the degree of emission Section 112 of the CAA establishes a the average emission limitation limitation achievable through the two-stage regulatory process to address achieved by the best-performing 12 application of the best system of percent of existing sources in the emissions of hazardous air pollutants emission reduction which (taking into category or subcategory (or the best- (HAP) from stationary sources. In the account the cost of achieving such performing five sources for categories or first stage, after the EPA has identified reduction and any nonair quality health subcategories with fewer than 30 categories of sources emitting one or and environmental impact and energy sources). In developing MACT more of the HAP listed in section 112(b) requirements) the Administrator standards, we must also consider of the CAA, section 112(d) of the CAA determines has been adequately control options that are more stringent calls for us to promulgate national demonstrated.’’ In this notice, we refer than the floor. We may establish emission standards for hazardous air to this level of control as the BSER. In standards more stringent than the floor pollutants (NESHAP) for those sources. determining BSER, we typically conduct based on the consideration of the cost of a technology review that identifies what ‘‘Major sources’’ are those that emit or achieving the emissions reductions, any emission reduction systems exist and have the potential to emit (PTE) 10 tons nonair quality health and environmental how much they reduce air pollution in per year (tpy) or more of a single HAP impacts and energy requirements. practice. Next, for each control system or 25 tpy or more of any combination of The EPA is then required to review identified, we evaluate its costs, HAP. For major sources, these these technology-based standards and to secondary air benefits (or disbenefits) technology-based standards must reflect revise them ‘‘as necessary (taking into resulting from energy requirements and the maximum degree of emission account developments in practices, nonair quality impacts such as solid reductions of HAP achievable (after processes, and control technologies)’’ no waste generation. Based on our considering cost, energy requirements less frequently than every 8 years, under evaluation, we would determine BSER. and nonair quality health and CAA section 112(d)(6). In conducting The resultant standard is usually a environmental impacts) and are this review, the EPA is not obliged to numerical emissions limit, expressed as commonly referred to as maximum completely recalculate the prior MACT a performance level (i.e., a rate-based achievable control technology (MACT) determination. NRDC v. EPA, 529 F.3d standard or percent control), that standards. 1077, 1084 (D.C. Cir. 2008). reflects the BSER. Although such MACT standards are to reflect The second stage in standard-setting standards are based on the BSER, the application of measures, processes, focuses on reducing any remaining EPA may not prescribe a particular methods, systems or techniques, ‘‘residual’’ risk according to CAA technology that must be used to comply including, but not limited to, measures section 112(f). This provision requires, with a performance standard, except in which, (1) reduce the volume of or first, that the EPA prepare a Report to instances where the Administrator eliminate pollutants through process Congress discussing (among other determines it is not feasible to prescribe changes, substitution of materials or things) methods of calculating risk or enforce a standard of performance. other modifications, (2) enclose systems posed (or potentially posed) by sources Typically, sources remain free to elect or processes to eliminate emissions, (3) after implementation of the MACT whatever control measures that they capture or treat pollutants when standards, the public health significance choose to meet the emission limits. released from a process, stack, storage or of those risks, and the EPA’s Upon promulgation, an NSPS becomes fugitive emissions point, (4) are design, recommendations as to legislation a national standard to which all new, equipment, work practice or operational regarding such remaining risk. The EPA modified or reconstructed sources must standards (including requirements for prepared and submitted this report comply. operator training or certification) or (5) (Residual Risk Report to Congress, EPA– are a combination of the above. CAA 453/R–99–001) in March 1999. Congress 2. What is the regulatory history section 112(d)(2)(A)–(E). The MACT did not act in response to the report, regarding performance standards for the standard may take the form of a design, thereby triggering the EPA’s obligation oil and natural gas sector? equipment, work practice or operational under CAA section 112(f)(2) to analyze In 1979, the EPA listed crude oil and standard where the EPA first determines and address residual risk. natural gas production on its priority either that, (1) a pollutant cannot be CAA section 112(f)(2) requires us to list of source categories for emitted through a conveyance designed determine for source categories subject promulgation of NSPS (44 FR 49222, and constructed to emit or capture the to MACT standards, whether the August 21, 1979). On June 24, 1985 (50 pollutant or that any requirement for or emissions standards provide an ample FR 26122), the EPA promulgated an use of such a conveyance would be margin of safety to protect public health. NSPS for the source category that inconsistent with law or (2) the If the MACT standards for HAP addressed volatile organic compound application of measurement ‘‘classified as a known, probable, or (VOC) emissions from leaking methodology to a particular class of possible human carcinogen do not components at onshore natural gas sources is not practicable due to reduce lifetime excess cancer risks to processing plants (40 CFR part 60, technological and economic limitations. the individual most exposed to subpart KKK). On October 1, 1985 (50 CAA sections 112(h)(1)–(2). emissions from a source in the category FR 40158), a second NSPS was The MACT ‘‘floor’’ is the minimum or subcategory to less than 1-in-1 promulgated for the source category that control level allowed for MACT million,’’ the EPA must promulgate

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residual risk standards for the source also, A Legislative History of the Clean risk ‘‘is an estimate of the upper bound category (or subcategory), as necessary, Air Act Amendments of 1990, volume 1, of risk based on conservative to provide an ample margin of safety to p. 877 (Senate debate on Conference assumptions, such as continuous protect public health. In doing so, the Report). We notified Congress in the exposure for 24 hours per day for 70 EPA may adopt standards equal to Residual Risk Report to Congress that years.’’ Id. We acknowledge that existing MACT standards if the EPA we intended to use the Benzene maximum individual lifetime cancer determines that the existing standards NESHAP approach in making CAA risk ‘‘does not necessarily reflect the are sufficiently protective. NRDC v. section 112(f) residual risk true risk, but displays a conservative EPA, 529 F.3d 1077, 1083 (D.C. Cir. determinations (EPA–453/R–99–001, p. risk level which is an upper-bound that 2008). (‘‘If EPA determines that the ES–11). is unlikely to be exceeded.’’ Id. existing technology-based standards In the Benzene NESHAP, we stated as Understanding that there are both provide an ‘‘ample margin of safety,’’ an overall objective: benefits and limitations to using then the Agency is free to readopt those * * * in protecting public health with an maximum individual lifetime cancer standards during the residual risk ample margin of safety, we strive to provide risk as a metric for determining rulemaking.’’) The EPA must also adopt maximum feasible protection against risks to acceptability, we acknowledged in the more stringent standards, if necessary, health from hazardous air pollutants by, (1) 1989 Benzene NESHAP that to prevent an adverse environmental protecting the greatest number of persons ‘‘consideration of maximum individual effect,1 but must consider cost, energy, possible to an individual lifetime risk level risk * * * must take into account the safety and other relevant factors in no higher than approximately 1-in-1 million; strengths and weaknesses of this doing so. and (2) limiting to no higher than measure of risk.’’ Id. Consequently, the Section 112(f)(2) of the CAA expressly approximately 1-in-10 thousand [i.e., 100-in- presumptive risk level of 100-in-1 preserves our use of a two-step process 1 million] the estimated risk that a person million (1-in-10 thousand) provides a living near a facility would have if he or she for developing standards to address any were exposed to the maximum pollutant benchmark for judging the acceptability residual risk and our interpretation of concentrations for 70 years. of maximum individual lifetime cancer ‘‘ample margin of safety’’ developed in risk, but does not constitute a rigid line the National Emission Standards for The Agency also stated that, ‘‘The for making that determination. Hazardous Air Pollutants: Benzene EPA also considers incidence (the The Agency also explained in the Emissions from Maleic Anhydride number of persons estimated to suffer 1989 Benzene NESHAP the following: Plants, Ethylbenzene/Styrene Plants, cancer or other serious health effects as ‘‘In establishing a presumption for MIR, Benzene Storage Vessels, Benzene a result of exposure to a pollutant) to be rather than a rigid line for acceptability, Equipment Leaks, and Coke By-Product an important measure of the health risk the Agency intends to weigh it with a Recovery Plants (Benzene NESHAP) (54 to the exposed population. Incidence series of other health measures and FR 38044, September 14, 1989). The measures the extent of health risk to the factors. These include the overall first step in this process is the exposed population as a whole, by incidence of cancer or other serious determination of acceptable risk. The providing an estimate of the occurrence health effects within the exposed second step provides for an ample of cancer or other serious health effects population, the numbers of persons margin of safety to protect public health, in the exposed population.’’ The Agency exposed within each individual lifetime which is the level at which the went on to conclude that ‘‘estimated risk range and associated incidence standards are set (unless a more incidence would be weighed along with within, typically, a 50-kilometer (km) stringent standard is required to other health risk information in judging exposure radius around facilities, the prevent, taking into consideration costs, acceptability.’’ As explained more fully science policy assumptions and energy, safety, and other relevant in our Residual Risk Report to Congress, estimation uncertainties associated with factors, an adverse environmental the EPA does not define ‘‘rigid line[s] of the risk measures, weight of the effect). acceptability,’’ but considers rather scientific evidence for human health The terms ‘‘individual most exposed,’’ broad objectives to be weighed with a effects, other quantified or unquantified ‘‘acceptable level,’’ and ‘‘ample margin series of other health measures and health effects, effects due to co-location of safety’’ are not specifically defined in factors (EPA–453/R–99–001, p. ES–11). of facilities and co-emission of the CAA. However, CAA section The determination of what represents an pollutants.’’ Id. 112(f)(2)(B) preserves the interpretation ‘‘acceptable’’ risk is based on a In some cases, these health measures set out in the Benzene NESHAP, and the judgment of ‘‘what risks are acceptable and factors taken together may provide United States Court of Appeals for the in the world in which we live’’ a more realistic description of the District of Columbia Circuit in NRDC v. (Residual Risk Report to Congress, p. magnitude of risk in the exposed EPA, 529 F.3d 1077, concluded that the 178, quoting the Vinyl Chloride population than that provided by EPA’s interpretation of subsection decision at 824 F.2d 1165) recognizing maximum individual lifetime cancer 112(f)(2) is a reasonable one. See NRDC that our world is not risk-free. risk alone. As explained in the Benzene v. EPA, 529 F.3d at 1083 (D.C. Cir., In the Benzene NESHAP, we stated NESHAP, ‘‘[e]ven though the risks ‘‘[S]ubsection 112(f)(2)(B) expressly that ‘‘EPA will generally presume that if judged ‘‘acceptable’’ by the EPA in the incorporates EPA’s interpretation of the the risk to [the maximum exposed] first step of the Vinyl Chloride inquiry Clean Air Act from the Benzene individual is no higher than are already low, the second step of the inquiry, determining an ‘‘ample margin standard, complete with a citation to the approximately 1-in-10 thousand, that of safety,’’ again includes consideration Federal Register’’). (D.C. Cir. 2008). See risk level is considered acceptable.’’ 54 FR 38045. We discussed the maximum of all of the health factors, and whether 1 ‘‘Adverse environmental effect’’ is defined in individual lifetime cancer risk (or to reduce the risks even further.’’ In the CAA section 112(a)(7) as any significant and maximum individual risk (MIR)) as ample margin of safety decision process, widespread adverse effect, which may be being ‘‘the estimated risk that a person the Agency again considers all of the reasonably anticipated to wildlife, aquatic life or living near a plant would have if he or health risks and other health natural resources, including adverse impacts on populations of endangered or threatened species or she were exposed to the maximum information considered in the first step. significant degradation of environmental qualities pollutant concentrations for 70 years.’’ Beyond that information, additional over broad areas. Id. We explained that this measure of factors relating to the appropriate level

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of control will also be considered, comment on our policy under the sources. On February 12, 1998 (63 FR including costs and economic impacts Benzene NESHAP, the EPA explained 7155), the EPA amended the source of controls, technological feasibility, that: ‘‘The policy chosen by the category list to add Natural Gas uncertainties and any other relevant Administrator permits consideration of Transmission and Storage as a major factors. Considering all of these factors, multiple measures of health risk. Not source category. the Agency will establish the standard only can the MIR figure be considered, On June 17, 1999 (64 FR 32610), the at a level that provides an ample margin but also incidence, the presence of EPA promulgated MACT standards for of safety to protect the public health, as noncancer health effects, and the the Oil and Natural Gas Production and required by CAA section 112(f). 54 FR uncertainties of the risk estimates. In Natural Gas Transmission and Storage 38046. this way, the effect on the most exposed major source categories. The Oil and individuals can be reviewed as well as Natural Gas Production NESHAP (40 2. How do we consider the risk results the impact on the general public. These CFR part 63, subpart HH) contains in making decisions? factors can then be weighed in each standards for HAP emissions from As discussed in the previous section individual case. This approach complies glycol dehydration process vents, of this preamble, we apply a two-step with the Vinyl Chloride mandate that storage vessels and natural gas process for developing standards to the Administrator ascertain an processing plant equipment leaks. The address residual risk. In the first step, acceptable level of risk to the public by Natural Gas Transmission and Storage the EPA determines if risks are employing [her] expertise to assess NESHAP (40 CFR part 63, subpart HHH) acceptable. This determination available data. It also complies with the contains standards for glycol ‘‘considers all health information, Congressional intent behind the CAA, dehydration process vents. including risk estimation uncertainty, which did not exclude the use of any In addition to these NESHAP for and includes a presumptive limit on particular measure of public health risk major sources, the EPA also maximum individual lifetime [cancer] from the EPA’s consideration with promulgated NESHAP for the Oil and risk (MIR) 2 of approximately 1-in-10 respect to CAA section 112 regulations, Natural Gas Production area source thousand [i.e., 100-in-1 million].’’ 54 FR and, thereby, implicitly permits category on January 3, 2007 (72 FR 26). 38045. In the second step of the process, consideration of any and all measures of These area source standards, which are the EPA sets the standard at a level that health risk which the Administrator, in based on generally available control provides an ample margin of safety ‘‘in [her] judgment, believes are appropriate technology, are also contained in 40 consideration of all health information, to determining what will ‘protect the CFR part 63, subpart HH. This proposed including the number of persons at risk public health.’ ’’ action does not impact these area source levels higher than approximately 1-in-1 For example, the level of the MIR is standards. million, as well as other relevant factors, only one factor to be weighed in C. What litigation is related to this including costs and economic impacts, determining acceptability of risks. The proposed action? technological feasibility, and other Benzene NESHAP explains ‘‘an MIR of factors relevant to each particular approximately 1-in-10 thousand should On January 14, 2009, pursuant to decision.’’ Id. ordinarily be the upper end of the range section 304(a)(2) of the CAA, WildEarth In past residual risk determinations, of acceptability. As risks increase above Guardians and the San Juan Citizens the EPA presented a number of human this benchmark, they become Alliance filed a Complaint alleging that health risk metrics associated with presumptively less acceptable under the EPA failed to meet its obligations emissions from the category under CAA section 112, and would be under CAA sections 111(b)(1)(B), review, including: The MIR; the weighed with the other health risk 112(d)(6) and 112(f)(2) to take actions numbers of persons in various risk measures and information in making an relative to the review/revision of the ranges; cancer incidence; the maximum overall judgment on acceptability. Or, NSPS and the NESHAP with respect to noncancer hazard index (HI); and the the Agency may find, in a particular the Oil and Natural Gas Production maximum acute noncancer hazard. In case, that a risk that includes MIR less source category. On February 4, 2010, estimating risks, the EPA considered than the presumptively acceptable level the Court entered a consent decree source categories under review that are is unacceptable in the light of other requiring the EPA to sign by July 28, located near each other and that affect health risk factors.’’ Similarly, with 2011,3 proposed standards and/or the same population. The EPA provided regard to the ample margin of safety determinations not to issue standards estimates of the expected difference in analysis, the Benzene NESHAP states pursuant to CAA sections 111(b)(1)(B), actual emissions from the source that: ‘‘EPA believes the relative weight 112(d)(6) and 112(f)(2) and to take final category under review and emissions of the many factors that can be action by February 28, 2012. allowed pursuant to the source category considered in selecting an ample margin D. What is a sector-based approach? MACT standard. The EPA also of safety can only be determined for discussed and considered risk each specific source category. This Sector-based approaches are based on estimation uncertainties. The EPA is occurs mainly because technological integrated assessments that consider providing this same type of information and economic factors (along with the multiple pollutants in a comprehensive in support of these actions. health-related factors) vary from source and coordinated manner to manage The Agency acknowledges that the category to source category.’’ emissions and CAA requirements. One Benzene NESHAP provides flexibility of the many ways we can address sector- regarding what factors the EPA might 3. What is the regulatory history based approaches is by reviewing consider in making our determinations regarding NESHAP for the oil and multiple regulatory programs together and how they might be weighed for each natural gas sector? whenever possible, consistent with all source category. In responding to On July 16, 1992 (57 FR 31576), the EPA published a list of major and area 3 On April 27, 2011, pursuant to paragraph 10(a) 2 Although defined as ‘‘maximum individual sources for which NESHAP are to be of the Consent Decree, the parties filed with the risk,’’ MIR refers only to cancer risk. MIR, one Court a written stipulation that changes the metric for assessing cancer risk, is the estimated published (i.e., the source category list). proposal date from January 31, 2011, to July 28, risk were an individual exposed to the maximum Oil and natural gas production facilities 2011, and the final action date from November 30, level of a pollutant for a lifetime. were listed as a category of major 2011, to February 28, 2012.

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applicable legal requirements. This processing, (3) natural gas transmission is associated gas from oil wells or non- approach essentially expands the and (4) natural gas distribution. Each of associated gas from gas or condensate technical analyses on costs and benefits these segments is briefly discussed wells, it commonly exists in mixtures of particular technologies, to consider below. with other hydrocarbons. These the interactions of rules that regulate Oil and natural gas production hydrocarbons are often referred to as sources. The benefit of multi-pollutant includes both onshore and offshore natural gas liquids (NGL). They are sold and sector-based analyses and operations. Production operations separately and have a variety of approaches includes the ability to include the wells and all related different uses. The raw natural gas often identify optimum strategies, considering processes used in the extraction, contains water vapor, hydrogen sulfide feasibility, cost impacts and benefits production, recovery, lifting, (H2S), carbon dioxide (CO2), helium, across the different pollutant types stabilization, separation or treating of oil nitrogen and other compounds. Natural while streamlining administrative and and/or natural gas (including gas processing consists of separating compliance complexities and reducing condensate). Production components certain hydrocarbons and fluids from conflicting and redundant requirements, may include, but are not limited to, the natural gas to produced ‘‘pipeline resulting in added certainty and easier wells and related casing head, tubing quality’’ dry natural gas. While some of implementation of control strategies for head and ‘‘Christmas tree’’ piping, as the processing can be accomplished in the sector under consideration. In order well as pumps, compressors, heater the production segment, the complete to benefit from a sector-based approach treaters, separators, storage vessels, processing of natural gas takes place in for the oil and gas industry, the EPA pneumatic devices and dehydrators. the natural gas processing segment. analyzed how the NSPS and NESHAP Production operations also include the Natural gas processing operations under consideration relate to each other well drilling, completion and workover separate and recover NGL or other non- and other regulatory requirements processes and includes all the portable methane gases and liquids from a stream currently under review for oil and gas non-self-propelled apparatus associated of produced natural gas through facilities. In this analysis, we looked at with those operations. Production sites components performing one or more of how the different control requirements include not only the ‘‘pads’’ where the the following processes: Oil and that result from these requirements wells are located, but also include condensate separation, water removal, interact, including the different stand-alone sites where oil, condensate, separation of NGL, sulfur and CO2 regulatory deadlines and control produced water and gas from several removal, fractionation of natural gas equipment requirements that result, the wells may be separated, stored and liquid and other processes, such as the different reporting and recordkeeping treated. The production sector also capture of CO2 separated from natural requirements and opportunities for includes the low pressure, small gas streams for delivery outside the states to account for reductions resulting diameter, gathering pipelines and facility. Natural gas processing plants from this rulemaking in their State related components that collect and are the only operations covered by the Implementation Plans (SIP). The transport the oil, gas and other materials existing NSPS. requirements analyzed affect criteria and wastes from the wells to the The pipeline quality natural gas pollutant, HAP and methane emissions refineries or natural gas processing leaves the processing segment and from oil and natural gas processes and plants. None of the operations upstream enters the transmission segment. cover the NSPS and NESHAP reviews. of the natural gas processing plant are Pipelines in the natural gas transmission As a result of the sector-based approach, covered by the existing NSPS. Offshore segment can be interstate pipelines that this rulemaking will reduce conflicting oil and natural gas production occurs on carry natural gas across state boundaries and redundant requirements. Also, the platform structures that house or intrastate pipelines, which transport sector-based approach facilitated the equipment to extract oil and gas from the gas within a single state. While streamlining of monitoring, the ocean or lake floor and that process interstate pipelines may be of a larger recordkeeping and reporting and/or transfer the oil and gas to diameter and operated at a higher requirements, thus, reducing storage, transport vessels or onshore. pressure, the basic components are the administrative and compliance Offshore production can also include same. To ensure that the natural gas complexities associated with complying secondary platform structures flowing through any pipeline remains with multiple regulations. In addition, connected to the platform structure, pressurized, compression of the gas is the sector-based approach promotes a storage tanks associated with the required periodically along the pipeline. comprehensive control strategy that platform structure and floating This is accomplished by compressor maximizes the co-control of multiple production and offloading equipment. stations usually placed between 40 and regulated pollutants while obtaining There are three basic types of wells: 100 mile intervals along the pipeline. At emission reductions as co-benefits. Oil wells, gas wells and associated gas a compressor station, the natural gas wells. Oil wells can have ‘‘associated’’ enters the station, where it is IV. Oil and Natural Gas Sector natural gas that is separated and compressed by reciprocating or The oil and natural gas sector processed or the crude oil can be the centrifugal compressors. includes operations involved in the only product processed. Once the crude In addition to the pipelines and extraction and production of oil and oil is separated from the water and other compressor stations, the natural gas natural gas, as well as the processing, impurities, it is essentially ready to be transmission segment includes transmission and distribution of natural transported to the refinery via truck, underground storage facilities. gas. Specifically for oil, the sector railcar or pipeline. We consider the oil Underground natural gas storage includes all operations from the well to refinery sector separately from the oil includes subsurface storage, which the point of custody transfer at a and natural gas sector. Therefore, at the typically consists of depleted gas or oil petroleum refinery. For natural gas, the point of custody transfer at the refinery, reservoirs and salt dome caverns used sector includes all operations from the the oil leaves the oil and natural gas for storing natural gas. One purpose of well to the customer. The oil and sector and enters the petroleum refining this storage is for load balancing natural gas operations can generally be sector. (equalizing the receipt and delivery of separated into four segments: (1) Oil and Natural gas is primarily made up of natural gas). At an underground storage natural gas production, (2) natural gas methane. However, whether natural gas site, there are typically other processes,

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including compression, dehydration public comment and data relevant to operation not covered by the current and flow measurement. several issues. The comments we listing and evaluating emissions from all The distribution segment is the final receive during the public comment oil and gas operations at the same time. step in delivering natural gas to period will help inform the rule We are also proposing standards for customers. The natural gas enters the development process as we work toward several new oil and natural gas affected distribution segment from delivery promulgating a final action. facilities. The proposed standards points located on interstate and would apply to affected facilities that intrastate transmission pipelines to A. What are the proposed revisions to commence construction, reconstruction business and household customers. The the NSPS? or modification after August 23, 2011. delivery point where the natural gas We reviewed the two NSPS that apply These standards, which include leaves the transmission segment and to the oil and natural gas industry. requirements for VOC, would be enters the distribution segment is often Based on our review, we believe that the contained in a new subpart, 40 CFR part called the ‘‘citygate.’’ Typically, utilities requirements at 40 CFR part 60, subpart 60, subpart OOOO. Subpart OOOO take ownership of the gas at the citygate. KKK, should be updated to reflect would incorporate 40 CFR part 60, Natural gas distribution systems consist requirements in 40 CFR part 60, subpart subpart KKK and 40 CFR part 60, of thousands of miles of piping, VVa for controlling VOC equipment subpart LLL, thereby having in this one including mains and service pipelines leaks at processing plants. We also subpart, all standards that are applicable to the customers. Distribution systems believe that the requirements at 40 CFR to the new and modified affected sometimes have compressor stations, part 60, subpart LLL, for controlling SO2 facilities described above. We also although they are considerably smaller emissions from natural gas processing propose to amend the title of subparts than transmission compressor stations. plants should be strengthened for KKK and LLL, accordingly, to apply Distribution systems include metering facilities with the highest sulfur feed only to affected facilities already subject stations, which allow distribution rates and the highest H2S to those subparts. Those operations companies to monitor the natural gas in concentrations. For a more detailed would not become subject to subpart the system. Essentially, these metering discussion, please see section VI.B.1 of OOOO unless they triggered stations measure the flow of gas and this preamble. applicability based on new or modified allow distribution companies to track In addition, there are significant VOC affected facilities under subpart OOOO. natural gas as it flows through the emissions from oil and natural gas We are proposing operational system. operations that are not covered by the standards for completions of Emissions can occur from a variety of two existing NSPS, including other hydraulically fractured gas wells. Based processes and points throughout the oil emissions at processing plants and on our review, we identified two and natural gas sector. Primarily, these emissions from upstream production, as subcategories of fractured gas wells for emissions are organic compounds such well as transmission and storage which well completions are conducted. as methane, ethane, VOC and organic facilities. In the 1984 notice that listed For non-exploratory and non- HAP. The most common organic HAP source categories (including Oil and delineation wells, the proposed are n-hexane and BTEX compounds Natural Gas) for promulgation of NSPS, operational standards would require (benzene, toluene, ethylbenzene and we noted that there were discrepancies reduced emission completion (REC), xylenes). Hydrogen sulfide (H2S) and between the source category names on commonly referred to as ‘‘green sulfur dioxide (SO2) are emitted from the list and those in the background completion,’’ in combination with pit- production and processing operations document, and we clarified our intent to flaring of gas not suitable for entering that handle and treat ‘‘sour gas.’’ Sour address all sources under an industry the gathering line. For exploratory and delineation wells (these wells generally gas is defined as natural gas with a heading at the same time. See 44 FR are not in close proximity to a gathering maximum H2S content of 0.25 gr/100 scf 49222, 49224–49225.4 We, therefore, line), we proposed an operational (4ppmv) along with the presence of CO2. believe that the currently listed Oil and In addition, there are significant standard that would require pit flaring. Natural Gas source category covers all emissions associated with the Well completions subject to the operations in this industry (i.e., reciprocating internal combustion standards would be limited to gas well production, processing, transmission, engines and combustion turbines that completions following hydraulic storage and distribution). To the extent power compressors throughout the oil fracturing operations. These there are oil and gas operations not and natural gas sector. However, completions include those conducted at covered by the currently listed Oil and emissions from internal combustion newly drilled and fractured wells, as Natural Gas source category, pursuant to engines and combustion turbines are well as completions conducted CAA section 111(b), we hereby modify covered by regulations specific to following refracturing operations at the category list to include all engines and turbines and, thus, are not various times over the life of the well. operations in the oil and natural gas addressed in this action. We have determined that a completion sector. Section 111(b) of the CAA gives associated with refracturing performed V. Summary of Proposed Decisions and the EPA broad authority and discretion at an existing well (i.e., a well existing Actions to list and establish NSPS for a category prior to August 23, 2011) is considered Pursuant to CAA sections 111(b), that, in the Administrator’s judgment, a modification under CAA section 112(d)(2), 112(d)(6) and 112(f), we are causes or contributes significantly to air 111(a), because physical change occurs proposing to revise the NSPS and pollution which may reasonably be to the existing well resulting in NESHAP relative to oil and gas to anticipated to endanger public health or emissions increase during the include the standards and requirements welfare. Pursuant to CAA section refracturing and completion operation. summarized in this section. More 111(b), we are modifying the source A detailed discussion of this details of the rationale for these category list to include any oil and gas determination is presented in the proposed standards and requirements Technical Support Document (TSD) in 4 The Notice further states that ‘‘The are provided in sections VI and VII of Administrator may also concurrently develop the docket. Therefore, the proposed this preamble. In addition, as part of standards for sources which are not on the priority standards would apply to completions these rationale discussions, we solicit list.’’ 44 FR at 49225. at new gas wells that are fractured or

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refractured along with completions require replacement of the rod packing 60, subpart LLL into the new subpart associated with fracturing or based on hours of usage. The owner or OOOO so that all requirements refracturing of existing gas wells. The operator of a reciprocating compressor applicable to the new and modified modification determination and affected facility would be required to facilities would be in one subpart. This resultant applicability of NSPS to the monitor the duration (in hours) that the would simplify and streamline completion operation following compressor is operated. When the hours compliance efforts on the part of the oil fracturing or refracturing of existing gas of operation reaches 26,000 hours, the and natural gas industry and could wells (i.e., wells existing before August owner or operator would be required to minimize duplication of notification, 23, 2011 would be limited strictly to the change the rod packing immediately. recordkeeping and reporting. wellhead, well bore, casing and tubing, However, to avoid unscheduled B. What are the proposed decisions and and any conveyance through which gas shutdowns when 26,000 hours is actions related to the NESHAP? is vented to the atmosphere and not be reached, owners and operators could extended beyond the wellhead to other track hours of operation such that This section summarizes the results of ancillary components that may be at the packing replacement could be our RTR for the Oil and Natural Gas well site such as existing storage coordinated with planned maintenance Production and the Natural Gas vessels, process vessels, separators, shutdowns before hours of operation Transmission and Storage source dehydrators or any other components or reached 26,000. Some operators may categories and our proposed decisions apparatus. prefer to replace the rod packing on a concerning these two 1999 NESHAP. We are also proposing VOC standards fixed schedule to ensure that the hours 1. Addressing Unregulated Emissions to reduce emissions from gas-driven of operation would not reach 26,000 Sources pneumatic devices. We are proposing hours. We solicit comment on the that each pneumatic device is an appropriateness of a fixed replacement Pursuant to CAA sections 112(d)(2) affected facility. Accordingly, the frequency and other considerations that and (3), we are proposing MACT proposed standards would apply to each would be associated with regular standards for subcategories of glycol newly installed pneumatic device replacement. dehydrators for which standards were (including replacement of an existing We are also proposing VOC standards not previously developed (hereinafter device). At gas processing plants, we are for new or modified storage vessels. The referred to as the ‘‘small dehydrators’’). proposing a zero emission limit for each proposed rule, which would apply to In the Oil and Natural Gas Production individual pneumatic controller. The individual vessels, would require that source category, the subcategory proposed emission standards would vessels meeting certain specifications consists of glycol dehydrators with an reflect the emission level achievable achieve at least 95-percent reduction in actual annual average natural gas from the use of non-gas-driven VOC emissions. Requirements would flowrate less than 85,000 standard cubic pneumatic controllers. At other apply to vessels with a throughput of 1 meters per day (scmd) or actual average locations, we are proposing a bleed limit barrel of condensate per day or 20 benzene emissions less than 0.9 of 6 standard cubic feet of gas per hour barrels of crude oil per day. These megagrams per year (Mg/yr). In the for an individual pneumatic controller, thresholds are equivalent to VOC Natural Gas Transmission and Storage which would reflect the emission level emissions of about 6 tpy. source category, the subcategory achievable from the use of low bleed For gas processing plants, we are consists of glycol dehydrators with an gas-driven pneumatic controllers. In updating the requirements for leak actual annual average natural gas both cases, the standards provide detection and repair (LDAR) to reflect flowrate less than 283,000 scmd or exemptions for certain applications procedures and leak thresholds actual average benzene emissions less based on functional considerations. established by 40 CFR 60, subpart VVa. than 0.9 Mg/yr. In addition, the proposed rule would The existing NSPS requires 40 CFR part The proposed MACT standards for the require measures to reduce VOC 60, subpart VV procedures and subcategory of small dehydrators at oil emissions from centrifugal and thresholds. and gas production facilities would reciprocating compressors. As explained For 40 CFR part 60, subpart LLL, require that existing affected sources in more detail below in section VI.B.4, which regulates SO2 emissions from meet a unit-specific BTEX limit of 1.10 ¥ we are proposing equipment standards natural gas processing plants, we × 10 4 grams BTEX/standard cubic for centrifugal compressors. The determined that affected facilities with meters (scm)-parts per million by proposed standards would require the sulfur feed rate of at least 5 long tons volume (ppmv) and that new affected use of dry seal systems. However, we per day or H2S concentration in the acid sources meet a BTEX limit of 4.66 × are aware that some owners and gas stream of at least 50 percent can 10¥6 grams BTEX/scm-ppmv. At operators may need to use centrifugal achieve up to 99.9-percent SO2 control, natural gas transmission and storage compressors with wet seals, and we are which is greater than the existing affected sources, the proposed MACT soliciting comment on the suitability of standard. Therefore, we are proposing standard for the subcategory of small a compliance option allowing the use of revision to the performance standards in dehydrators would require that existing wet seals combined with routing of subpart LLL as a result of this review. affected sources meet a unit-specific emissions from the seal liquid through For a more detailed discussion of this BTEX emission limit of 6.42 × 10¥5 a closed vent system to a control device proposed determination, please see grams BTEX/scm-ppmv and that new as an acceptable alternative to installing section VI.B.1 of this preamble. affected sources meet a BTEX limit of dry seals. We are proposing to address 1.10 × 10¥5 grams BTEX/scm-ppmv. Our review of reciprocating compliance requirements for periods of We are also proposing MACT compressors found that piston rod startup, shutdown and malfunction standards for storage vessels that are packing wear produces fugitive (SSM) for 40 CFR part 60, subpart currently not regulated under the Oil emissions that cannot be captured and OOOO. The SSM changes are discussed and Natural Gas Production NESHAP. conveyed to a control device. As a in detail in section VI.B.5 below. In The current MACT standards apply only result, we are proposing operational addition, we are proposing to to storage vessels with the potential for standards for reciprocating compressors, incorporate the requirements in 40 CFR flash emissions (PFE). As explained in such that the proposed rule would part 60, subpart KKK and 40 CFR part section VII, the original MACT analysis

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accounted for all storage vessels. We manufacturers’ performance testing as criteria for establishing the are, therefore, proposing to apply the alternative, and to clarify which devices affirmative defense. current MACT standards of 95-percent must be performance tested. The EPA has attempted to ensure that emission reduction to every storage We are also proposing to: Revise the we have neither overlooked nor failed to vessel at major source oil and natural parametric monitoring calibration propose to remove from the existing text gas production facilities. In conjunction provisions; require periodic any provisions that are inappropriate, with this change, we are proposing to unnecessary or redundant in the performance testing where applicable; amend the definition of associated absence of the SSM exemption, nor remove the allowance of a design equipment to exclude all storage included any such provisions in the analysis for all control devices other vessels, and not just those with the PFE, proposed new regulatory language. We than condensers; remove the from being considered ‘‘associated are specifically seeking comment on requirement for a minimum residence equipment.’’ This means that emissions whether there are any such provisions from all storage vessels, and not just time for an enclosed combustion device; that we have inadvertently overlooked those from storage vessels with the PFE, and add recordkeeping and reporting or incorporated. are to be included in the major source requirements to document carbon We are also revising the applicability determination. replacement intervals. These changes provisions of 40 CFR part 63, subpart are being proposed to bring the HH to clarify requirements regarding 2. What are the proposed decisions and NESHAP up-to-date based on what we actions related to the risk review? PTE determination and the scope of a have learned regarding control devices facility subject to subpart HH. Lastly, we For both the Oil and Natural Gas and compliance since the original are proposing several editorial Production and the Natural Gas promulgation date. corrections and plain language revisions Transmission and Storage source In addition, we are proposing the to improve these rules. categories, we find that the current elimination of the SSM exemption in C. What are the proposed notification, levels of emissions allowed by the the Oil and Natural Gas Production and MACT reflect acceptable levels of risk; recordkeeping and reporting the Natural Gas Transmission and requirements for this proposed action? however, the level of emissions allowed Storage NESHAP. As discussed in more by the alternative compliance option for detail below in section VII, consistent 1. What are the proposed notification, glycol dehydrator MACT (i.e., the with Sierra Club v. EPA, 551 F.3d 1019 recordkeeping and reporting option of reducing benzene emissions to (D.C. Cir. 2010), the EPA is proposing requirements for the proposed NSPS? less than 0.9 Mg/yr in lieu of the MACT that the established standards in these standard of 95-percent control) reflects The proposed 40 CFR part 60, subpart two NESHAP apply at all times. We are an unacceptable level of risk. We are, OOOO includes new requirements for proposing to revise Table 2 to both 40 therefore, proposing to eliminate the 0.9 several operations for which there are CFR part 63, subpart HH and 40 CFR Mg/yr alternative compliance option. no existing Federal standards. Most In addition, we are proposing that the part 63, subpart HHH to indicate that notably, as discussed in sections V.A MACT for these two oil and gas source certain 40 CFR part 63 general and VI.B of this preamble, the proposed categories, as revised per above, provide provisions relative to SSM do not apply, NSPS will cover completions and 5 an ample margin of safety to protect including: 40 CFR 63.6 (e)(1)(i) and recompletions of hydraulically fractured public health and prevent adverse (ii), 40 CFR 63.6(e)(3) (SSM plan gas wells. We estimate that over 20,000 environmental effects. requirement), 40 CFR 63.6(f)(1); 40 CFR completions and recompletions 63.7(e)(1), 40 CFR 63.8(c)(1)(i) and (iii), annually will be subject to the proposed 3. What are the proposed decisions and and the last sentence of 40 CFR requirements. Given the number of actions related to the technology 63.8(d)(3); 40 CFR 63.10(b)(2)(i),(ii), (iv) these operations, we believe that reviews of the existing NESHAP? and (v); 40 CFR 63.10(c)(10), (11) and notification and reporting must be For both the Oil and Natural Gas (15); and 40 CFR 63.10(d)(5). We are streamlined to the extent possible to Production and the Natural Gas also proposing to: (1) Revise 40 CFR minimize undue burden on owners and Transmission and Storage source 63.771(d)(4)(i) and 40 CFR operators, as well as state, local and categories, we are proposing no 63.1281(d)(4)(i) regarding operation of tribal agencies. In section V.D of this revisions to the existing NESHAP the control device to be consistent with preamble, we discuss some innovative pursuant to section 112(d)(6) of the the SSM compliance requirements; and implementation approaches being CAA. (2) revise the SSM-associated reporting considered and seek comment on these and other potential methods of 4. What other actions are we proposing? and recordkeeping requirements in 40 CFR 63.774, 40 CFR 63.775, 40 CFR streamlining notification and reporting We are proposing an alternative 63.1284 and 40 CFR 63.1285 to require for well completions covered by the performance test for non-flare, reporting and recordkeeping for periods proposed rule. combustion control devices. This test is of malfunction. In addition, as Owners or operators are required to to be conducted by the combustion explained below, we are proposing to submit initial notifications and annual control device manufacturer to add an affirmative defense to civil reports, and to retain records to assist in demonstrate the destruction efficiency documenting that they are complying penalties for exceedances of emission achieved by a specific model of with the provisions of the NSPS. These limits caused by malfunctions, as well combustion control device. This would notification, recordkeeping and allow a source to purchase a reporting activities include both 5 40 CFR 63.6(e)(1)(i) requires owners or operators performance tested device for to act according to the general duty to ‘‘operate and requirements of the 40 CFR part 60 installation at their site without being maintain any affected source, including associated General Provisions, as well as required to conduct a site-specific air pollution control equipment and monitoring requirements specific to 40 CFR part 60, performance test. A definition for equipment, in a manner consistent with safety and subpart OOOO. good air pollution control practices for minimizing Owners or operators of affected ‘‘flare’’ is being proposed in the emissions.’’ This general duty to minimize is NESHAP to clarify which combustion included in our proposed standard at 40 CFR facilities (except for pneumatic control devices fall under the 63.783(b)(1). controller and gas wellhead affected

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sources) must submit an initial of condensate per day and 21 barrels of requirements for the contents of the notification within 1 year after crude oil per day, required information periodic reports. For both 40 CFR part becoming subject to 40 CFR part 60, also includes calculations or other 63, subpart HH and 40 CFR part 63, subpart OOOO or by 1 year after the documentation of the throughput. For subpart HHH, we are proposing that the publication of the final rule in the onshore gas processing plants, semi- periodic reports also include periodic Federal Register, whichever is later. For annual reports are required, and include test results and information regarding pneumatic controllers, owners and information on number of pressure any carbon replacement events that operators are not required to submit an relief devices, number of pressure relief occurred during the reporting period. initial notification, but instead are devices for which leaks were detected 3. How is information submitted using required to report the installation of and pressure relief devices for which the Electronic Reporting Tool (ERT)? these affected facilities in their facility’s leaks were not repaired, as required in annual report. Owners or operators of 40 CFR 60.5396 of subpart OOOO. Performance test data are an wellhead affected facilities (well Records must be retained for 5 years important source of information that the completions) would also be required to and generally consist of the same EPA uses in compliance determinations, submit a 30-day advance notification of information required in the initial developing and reviewing standards, each well completion subject to the notification and annual and semiannual emission factor development, annual NSPS. In addition, annual reports are reports. emission rate determinations and other due 1 year after initial startup date for purposes. In these activities, the EPA 2. What are the proposed amendments has found it ineffective and time your affected facility or 1 year after the to notification, recordkeeping and date of publication of the final rule in consuming, not only for owners and reporting requirements for the operators, but also for regulatory the Federal Register, whichever is later. NESHAP? The notification and annual reports agencies, to locate, collect and submit must include information on all affected We are proposing to revise certain performance test data because of varied facilities owned or operated that were recordkeeping requirements of 40 CFR locations for data storage and varied new, modified or reconstructed sources part 63, subpart HH and 40 CFR part 63, data storage methods. In recent years, during the reporting period. A single subpart HHH. Specifically, we are though, stack testing firms have report may be submitted covering proposing that facilities using carbon typically collected performance test data multiple affected facilities, provided adsorbers as a control device keep in electronic format, making it possible that the report contains all the records of their carbon replacement to move to an electronic data submittal information required by 40 CFR schedule and records for each carbon system that would increase the ease and 60.5420(b). This information includes replacement. In addition, owners and efficiency of data submittal and improve general information on the facility (i.e., operators are required to keep records of data accessibility. company name and address, etc.), as the occurrence and duration of each Through this proposal, the EPA is well as information specific to malfunction or operation of the air taking a step to increase the ease and individual affected facilities. pollution control equipment and efficiency of data submittal and improve For wellhead affected facilities, this monitoring equipment. data accessibility. Specifically, the EPA information includes details of each In addition, in conjunction with the is proposing that owners and operators well completion during the period, proposed MACT standards for small of oil and natural gas sector facilities including duration of periods of gas glycol dehydration units and storage submit electronic copies of required recovery, flaring and venting. For vessels that do not have the PFE in the performance test reports to the EPA’s centrifugal compressor affected proposed amendment to 40 CFR part 63, WebFIRE database. The WebFIRE facilities, information includes subpart HH, we are proposing that database was constructed to store documentation that the compressor is owners and operators of affected small performance test data for use in fitted with dry seals. For reciprocating glycol dehydration units and storage developing emission factors. A compressors, information includes the vessels submit an initial notification description of the WebFIRE database is cumulative hours of operation of each within 1 year after becoming subject to available at http://cfpub.epa.gov/ compressor and records of rod packing subpart HH or by 1 year after the oarweb/index.cfm?action=fire.main. replacement. publication of the final rule in the As proposed above, data entry would Information for pneumatic device Federal Register, whichever is later. be through an electronic emissions test affected facilities includes location and Similarly, in conjunction with the report structure called the Electronic manufacturer specifications of each proposed MACT standards for small Reporting Tool (ERT). The ERT will be pneumatic controller installed during glycol dehydration units in the able to transmit the electronic report the period and documentation that proposed 40 CFR part 63, subpart HHH through the EPA’s Central Data supports any exemption claimed amendments, we are proposing that Exchange network for storage in the allowing use of high bleed controllers. owners and operators of small glycol WebFIRE database making submittal of For controllers installed at gas dehydration units submit an initial data very straightforward and easy. A processing plants, the owner or operator notification within 1 year after description of the ERT can be found at would document the use of non-gas becoming subject to subpart HHH or by http://www.epa.gov/ttn/chief/ert/ driven devices. For controllers installed 1 year after the publication of the final ert_tool.html. in locations other than at gas processing rule in the Federal Register, whichever The proposal to submit performance plants, owners or operators would is later. Affected sources under either 40 test data electronically to the EPA provide manufacturer’s specifications CFR part 63, subpart HH or subpart would apply only to those performance that document bleed rate not exceeding HHH that plan to be area sources by the tests conducted using test methods that 6 cubic feet per hour. compliance dates will be required to will be supported by the ERT. The ERT For storage vessel affected facilities, submit a notification describing their contains a specific electronic data entry required report information includes schedule for the actions planned to form for most of the commonly used information that documents control achieve area source status. EPA reference methods. A listing of the device compliance, if applicable. For The proposed amendments to the pollutants and test methods supported vessels with throughputs below 1 barrel NESHAP also include additional by the ERT is available at http://

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www.epa.gov/ttn/chief/ert/ert_tool.html. significant time, money and effort while consider providing for such options in We believe that industry would benefit also improving the quality of emission the final action. Further, we request from this proposed approach to inventories and, as a result, air quality comments and suggestions on all electronic data submittal. Having these regulations. aspects of the innovative compliance data, the EPA would be able to develop approaches discussed below and how D. What are the innovative compliance improved emission factors, make fewer they may be implemented approaches being considered? information requests, and promulgate appropriately. We are seeking comment better regulations. Given the potential number and regarding the scope of application of One major advantage of the proposed diversity of sources affected by this one or more of these approaches, i.e., submittal of performance test data action, we are exploring optional which provisions of the standards being through the ERT is a standardized approaches to provide the regulated proposed here would be suitable for method to compile and store much of community, the regulators and the specific compliance approaches, and the documentation required to be public a more effective mechanism that whether the approaches should be reported by this rule. Another advantage maximizes compliance and alternatives to the requirements in the is that the ERT clearly states testing transparency while minimizing burden. regulations. information that would be required. Under a traditional approach, owners The guiding principles we are Another important benefit of submitting or operators would provide notifications following in considering these these data to the EPA at the time the and keep records of information approaches to compliance are: (1) source test is conducted is that it should required by the NSPS. In addition, they Simplicity and ease of understanding substantially reduce the effort involved would certify compliance with the and implementation; (2) transparency in data collection activities in the NSPS as part of a required annual report and public accessibility; (3) electronic future. When the EPA has performance that would include compliance-related implementation where appropriate; and test data in hand, there will likely be information, such as details of each well (4) encouragement of compliance by fewer or less substantial data collection completion event and information making compliance easier than requests in conjunction with documenting compliance with other noncompliance. Below are some tools prospective required residual risk requirements of the NSPS. The EPA, that, when used in tandem with assessments or technology reviews. This state or local agency would then emissions limits and operational would result in a reduced burden on physically inspect the affected facilities standards, the Agency believes could both affected facilities (in terms of and/or audit the records retained by the both assure compliance and reduced manpower to respond to data owner or operator. As an alternative to transparency, while minimizing burden collection requests) and the EPA (in the traditional approach, we are seeking on affected sources and regulatory terms of preparing and distributing data an innovative way to provide for more agencies. collection requests and assessing the transparency to the public and less 1. Registration of Wells and Advance results). burden on the regulatory agencies and State, local and tribal agencies could owners and operators, especially as it Notification of Planned Completions also benefit from more streamlined and relates to modification of existing Although the proposed NSPS will not accurate review of electronic data sources through recompletions of require approval to drill or complete submitted to them. The ERT would hydraulically fractured gas wells. These wells, it is important that regulatory allow for an electronic review process innovative approaches would provide agencies know when completions of rather than a manual data assessment compliance assurance in light of the hydraulically fractured wells are to be making review and evaluation of the absence of requirements for CAA title V performed. Notification should occur source provided data and calculations permitting of non-major sources. sufficiently in advance to allow for easier and more efficient. Finally, Section V.E of this preamble discusses inspections or audits to certify or verify another benefit of the proposed data permitting implications associated with that the operator will have in place and submittal to WebFIRE electronically is the NSPS and presents a proposed use the appropriate controls during the that these data would greatly improve rationale for exempting non-major completion. To that end, the proposed the overall quality of existing and new sources subject to the NSPS from title V NSPS requires a 30-day advance emissions factors by supplementing the permitting requirements. As discussed notification of each completion or pool of emissions test data for in sections V.A, V.C and VI.B of this recompletion of a hydraulically establishing emissions factors and by preamble, the proposed NSPS will cover fractured gas well. The advance ensuring that the factors are more completions and recompletions of notification would require that owners representative of current industry hydraulically fractured gas wells. We or operators provide the anticipated operational procedures. A common estimate that over 20,000 completions date of the completion, the geographic complaint heard from industry and and recompletions annually will be coordinates of the well and identifying regulators is that emission factors are subject to the proposed requirements. information concerning the owner or outdated or not representative of a As a result, we believe that notification operator and responsible company particular source category. With timely and reporting associated with well official. We believe this notification receipt and incorporation of data from completions must be streamlined to the requirement serves as the registration most performance tests, the EPA would extent possible to minimize undue requirement and could be streamlined be able to ensure that emission factors, burden on owners and operators, as well through optional electronic reporting when updated, represent the most as state, local and tribal agencies. with web-based public access or other current range of operational practices. In Though the requirements being methods. We seek comment on potential summary, in addition to supporting proposed here are based on the methodologies that would minimize regulation development, control strategy traditional approach to compliance and burden on operators, while providing development and other air pollution do not include specific regulatory timely and useful information for control activities having an electronic provisions for innovative compliance regulators and the public. We also database populated with performance tools, we have included discussions solicit comment on provisions for a test data would save industry, state, below that describe how some of these follow-up notification one or two days local, tribal agencies and the EPA optional tools could work, and we will before an impending completion via

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telephone or by electronic means, since notification unnecessary. The emissions at the emissions source level it is difficult to predict exactly when a clearinghouse could also house (e.g., well completions, well unloading, well will be ready for completion a information on past completions and compressors, gas plant leaks, etc.), will month in advance. However, we would copies of compliance certifications. We aggregate emissions at the basin level for expect an owner or operator to provide seek comment on whether annual e-reporting purposes. As a result, it may the follow-up notification only in cases reports for well completions would be be difficult to merge reporting under where the completion date was needed if a suitable third party NSPS subpart OOOO with GHG expected to deviate from the original verification program was in place and Reporting Rule subpart W methane date provided. We ask for suggestions already housed that same information. reporting, especially if manual reporting regarding how much advance We also solicit comment on the range of is used. However, since the operator notification is needed and the most potential activities the third party would have these emissions details at effective method of providing sufficient verification program could handle with the individual well level (because that and accurate advance notification of regard to well completions. will be how they would develop their well completions. In this proposed action, there are also basin-wide estimates), we do not believe provisions for applying third party 2. Third Party Verification it would be a significant burden to verification to the required electronic require owners or operators to report the To complement the annual reporting using the ERT (see section data they already have for subpart W in compliance certification required under V.C.3 above for a discussion of the ERT). an ERT for NSPS and NESHAP the proposed NSPS, we are considering As stated above, all sources must use compliance purposes. However, if the e- and seeking comment on the potential the ERT to submit all performance test GGRT is not structured to provide for use of third party verification to assure reports (required in 40 CFR parts 60, 61 reporting of other pollutants besides compliance. Since the emission sources and 63) to the EPA. There is an option GHG (e.g., VOC and HAP), then there in the oil and natural gas sector, in the ERT for state, local and tribal may be some modification of the especially well completions, are widely agencies to review and verify that the database required to accommodate the geographically dispersed (often in very information submitted to the EPA is other pollutants. remote locations), compliance assurance truthful, accurate and complete. Third can be very difficult and burdensome party verifiers could be contractors or 4. Provisions for Encouraging Innovative for state, local and tribal agencies and other personnel familiar with oil and Technology EPA permitting staff, inspectors and natural gas exploration and production. The oil and natural gas industry has compliance officers. Additionally, we We are seeking comment on appropriate a long history of innovation in believe that verification of the data third party reviewers and qualifications developing new exploration and collection, compilation and calculations and registration requirements under production methods, along with by an independent and impartial third such a program. We want to state clearly techniques to minimize product losses party could facilitate the demonstration here that third party verification would and reduce adverse environmental of compliance for the public. not supersede or substitute for impacts. These efforts are often Verification of emissions data can also inspections or audit of data and undertaken with tremendous amounts be beneficial to owners and operators by information by state, local and tribal of research, including pilot applications providing certainty of compliance agencies and the EPA. status. Potential issues with third party at operating facilities in the field. As mentioned above, notification and verification include costs incurred by Absent regulation, these developmental reporting requirements associated with industry and approval of third party activities, some of which ultimately are well completions are likely applications verifiers. The cost of third party not successful, can proceed without risk for third party verification used in verification would be borne by the of violation of any standards. However, tandem with the required annual affected industries. We are seeking as more emission sources in this source compliance certification. The third comment on whether third party category are covered by regulation, as in party verification program could be verification paid for by industry would the case of the action being proposed used in a variety of ways to ease result in impartial, accurate and here, there likely will be situations regulatory burden on the owners and complete data information. The EPA, where innovation and development of operators and to leverage compliance working with state, local and tribal new control techniques potentially assurance efforts of the EPA and state, agencies and industry, would expect to could be stifled by risk of violation. local and tribal agencies. The third party develop guidance for third party We believe it is important to facilitate, agent could serve as a clearinghouse for verifiers. We are seeking comment on not hinder, innovation and continued notifications, records and annual whether or not the EPA should approve development of new technology that can compliance certifications submitted by third party verifiers. result in enhanced environmental owners and operators. This would performance of facilities and sources provide online access to completion 3. Electronic Reporting Using Existing affected by the EPA’s regulations. information by regulatory agencies and Mechanisms However, any approaches to the public. Having notifications The proposed 40 CFR part 60, subpart accommodate technology development submitted to the clearinghouse would OOOO and final Greenhouse Gas (GHG) must be designed and implemented in relieve state, local and tribal agencies of Mandatory Reporting Rule, 40 CFR part accordance with the CAA and other the burden of receiving thousands of 98, subpart W, provide details on flare statutes. We seek comment on paper or e-mail well completion and vented emission sources and how to approaches that may be suitable for notifications each year, yet still provide estimate their emissions. We solicit allowing temporary field testing of them quick access to the information. comment on requiring sources to technology in development. These Using a third party agent, it is possible electronically submit their emissions approaches could include not only that notifications of well completions data for the oil and gas rules proposed established procedures under the CAA could be submitted with an advance here. The EPA’s Electronic Greenhouse and its implementing regulations, but period much less than 30 days that Gas Reporting Tool (e-GGRT) for 40 CFR new ways to apply or interpret these could make a 2 day follow-up part 98, subpart W, while used to report provisions to avoid impeding

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innovation while remaining lands, where many oil and gas sources as a result of being subject to one or environmentally responsible and legal. are located. more of the proposed NSPS identified The proposed standards will lead to above (hereinafter referred to as the E. How does the NSPS relate to better control of and reduced emissions ‘‘proposed NSPS’’); however, if they permitting of sources? from oil and gas production, gas were otherwise required to obtain title 1. How does this action affect permitting processing and transmission and V permits, such requirement(s) would requirements? storage, including wells. In some not be affected by the proposed The proposed rules do not change the instances, we anticipate that complying exemption. Federal requirements for determining with the NSPS would reduce emissions Consistent with the statute, the EPA whether oil and gas sources are major from these smaller sources to below the believes that compliance with title V sources for purposes of nonattainment minor source applicability thresholds. permitting is ‘‘unnecessarily major New Source Review (NSR), In those cases, sources that would burdensome’’ for the oil and gas NSPS prevention of significant deterioration, otherwise have been subject to minor non-major sources. The EPA’s inquiry CAA title V, or HAP major sources NSR would not need to get minor NSR into whether this criterion was satisfied pursuant to CAA section 112. permits as a result of being subject to is based primarily upon consideration of Specifically, if an owner or operator is the NSPS. Accordingly, the number of the following four factors: (1) Whether not currently required to get a major minor NSR permits, as well as the title V would result in significant NSR or title V permit for oil and gas Agency resources needed to issue them, improvements to the compliance sources, including well completions, it would be reduced. requirements that we are proposing for We expect the emission reductions would not be required to get a major the oil and gas NSPS affected non-major achieved from the proposed standards NSR or title V permit as a result of these sources; (2) whether title V permitting to significantly improve ozone proposed standards. EPA-approved state would impose a significant burden on nonattainment problems in areas where and local major source permitting these non-major sources and whether oil and gas production occurs. Strategies programs would not be affected. That is, that burden would be aggravated by any for attaining and maintaining the state and local agencies with EPA- difficulty these sources may have in national ambient air quality standards approved programs will still make case- obtaining assistance from permitting (NAAQS) are a function of SIP (or, in by-case major source determinations for agencies; (3) whether the costs of title V some instances, Federal Implementation purposes of major NSR and title V, permitting for these non-major sources Plans and Tribal Implementation Plans) relying on the regulatory criteria, as would be justified, taking into 6 pursuant to CAA section 110. In explained in the McCarthy Memo. consideration any potential gains in developing plans to attain and maintain Consistent with the McCarthy Memo, compliance likely to occur for such the NAAQS, EPA works with state, local whether or not a permitting authority sources; and (4) whether there are or Tribal agencies to account for growth should aggregate two or more pollutant- implementation and enforcement and develop overall control strategies emitting activities into a single major programs in place that are sufficient to that address existing and expected stationary source for purposes of NSR assure compliance with the proposed emissions. The reductions achieved by and title V remains a case-by-case Oil and Natural Gas NSPS without the standards will make it easier for decision in which permitting authorities relying on title V permits. Not all of the state and local agencies to plan for and retain the discretion to consider the four factors must weigh in favor of an to attain and maintain the ozone factors relevant to the specific exemption. See 70 FR 75320, 75323 NAAQS. circumstances of the permitted (Title V Exemption Rule). Instead, the activities. 2. How does this action affect factors are to be considered in In addition, the proposed standards applicability of CAA title V? combination and the EPA determines would not change the requirements for Under section 502(a) of the CAA, the whether the factors, taken together, determining whether oil and gas sources support an exemption from title V for are subject to minor NSR. Nor would the EPA may exempt one or more non-major sources 7 subject to CAA section 111 the oil and gas non-major sources. proposed standards affect existing EPA- Additionally, consistent with the approved state and local minor NSR (NSPS) standards from the requirements of title V if the EPA finds that guidance provided by the legislative rules, as well as policies and practices 8 compliance with such requirements is history of CAA section 502(a), we implementing those rules. Many state considered whether exempting the Oil and local agencies have already adopted ‘‘impracticable, infeasible, or unnecessarily burdensome’’ on such and Natural Gas NSPS non-major minor NSR permitting programs that sources would adversely affect public provide for control of emissions from sources. The EPA determine whether to exempt a non-major source from title V health, welfare or the environment. The relatively small emission sources, first factor is whether title V would including various pieces of equipment at the time we issue the relevant CAA section 111 standards (40 CFR result in significant improvements to used in oil and gas fields. State and the compliance requirements in the local agencies would be able to continue 70.3(b)(2)). We are proposing in this action to exempt from the requirements proposed NSPS. A finding that title V to use any EPA-approved General would not result in significant Permits, Permits by Rule, and other of title V non-major sources that would be subject to the proposed NSPS for improvements to the compliance similar streamlining mechanisms to requirements in the proposed NSPS permit oil and gas sources such as wells. well completions, pneumatic devices, compressors, and/or storage vessels. would support a conclusion that title V We recently promulgated the final permitting is ‘‘unnecessary’’ for non- Tribal Minor NSR rules for use in These non-major sources (hereinafter issuing minor issue permits on tribal referred to as the ‘‘oil and gas NSPS non-major sources’’) would not be 8 The legislative history of section 502(a) suggests that EPA should not grant title V exemptions where 6 Withdrawal of Source Determinations for Oil required to obtain title V permits solely doing so would adversely affect public health, and Gas Industries, September 22, 2009. This memo welfare or the environment. (See Chafee-Baucus continues to articulate the Agency’s interpretation 7 CAA section 502(a) prohibits title V exemption Statement of Senate Managers, Environment and for major NSR and title V permitting of oil and gas for any major source, which is defined in CAA Natural Resources Policy Division 1990 CAA Leg. sources. section 501(2) and 40 CFR 70.2. Hist. 905, Compiled November 1993.)

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major sources subject to the Oil and NSPS for well completions are sufficient equipment standards.9 For each of these Natural Gas Production NSPS. to ensure that the Administrator, the affected facilities, the proposed NSPS One way that title V may improve state, local and tribal agencies and the would require: (1) Construction, startup compliance is by requiring monitoring public are aware of completion events and modification notifications, as (including recordkeeping designed to before they are performed to provide required by 40 CFR 60.7(a); (2) annual serve as monitoring) to assure opportunity for inspection. Sufficient reports; (3) for each pneumatic compliance with permit terms and documentation would also be required controller installed or modified conditions reflecting the emission to be retained and reported to the (including replacement of an existing limitations and control technology Administrator to assure compliance controller), records of location and date requirements imposed in the standard. of installation and documentation that with the NSPS for well completions. In See 40 CFR 70.6(c)(1) and 40 CFR each controller emits no more than the light of the above, we have determined 71.6(c)(1). The ‘‘periodic monitoring’’ applicable emission limit or is exempt provisions of 40 CFR 70.6(a)(3)(i)(B) and that additional monitoring through title (with rationale for the exemption); (4) 40 CFR 71.6(a)(3)(i)(B) require new V is not needed and that the monitoring, for each centrifugal compressor, records monitoring to be added to the permit recordkeeping and reporting that document that each new or when the underlying standard does not requirements described above are modified compressor is equipped with already require ‘‘periodic testing or sufficient to assure compliance with the dry seals; and (5) for each new or instrumental or noninstrumental proposed requirements for well modified reciprocating compressor, monitoring (which may consist of completions. records of rod packing replacement, recordkeeping designed to serve as With respect to storage vessels, the including elapsed operating hours since monitoring).’’ In addition, title V proposed NSPS would require 95- the previous rod packing installation. imposes a number of recordkeeping and percent control of VOC emissions. The For these other affected sources reporting requirements that may be proposed standard could be met by a described above, the proposed NSPS important for assuring compliance. vapor recovery unit, a flare control provide monitoring in the form of These include requirements for a recordkeeping (as described above) that device or other control device. The monitoring report at least every 6 would assure compliance with the proposed NSPS would require an initial months, prompt reports of deviations, proposed operational, work practice or and an annual compliance certification. performance test followed by equipment standards. Monitoring by See 40 CFR 70.6(a)(3) and 40 CFR continuous monitoring of the control means other than recordkeeping would 71.6(a)(3), 40 CFR 70.6(c)(1) and 40 CFR device used to meet the 95-percent not be practical or appropriate for these 71.6(c)(1), and 40 CFR 70.6(c)(5) and 40 control. We believe that the monitoring standards. Records are required to CFR 71.6(c)(5). To determine whether requirements described above are ensure that these standards and title V permits would add significant sufficient to assure compliance with the practices are followed. We believe that compliance requirements to the proposed NSPS for storage vessels and, the monitoring, recordkeeping and proposed NSPS, we compared the title therefore, additional monitoring through reporting requirements described above V monitoring, recordkeeping and title V is not needed. In addition to are sufficient to assure compliance with reporting requirements mentioned monitoring, as part of the first factor, we the proposed NSPS for pneumatic above to those requirements proposed have considered the extent to which controllers and compressors. for the Oil and Natural Gas NSPS title V could potentially enhance We acknowledge that title V might affected facilities. compliance through recordkeeping or provide for additional compliance For wellhead affected facilities (well reporting requirements. The proposed requirements for these non-major completions), the proposed NSPS would NSPS would require (1) construction, sources, but we have determined, as require (1) 30-day advance notification startup and modification notifications, explained above, that the monitoring, of each well completion to be as required by 40 CFR 60.7(a); and (2) recordkeeping and reporting performed; (2) noninstrumental requirements in this proposed NSPS are monitoring, which is achieved through annual reports that identify all storage vessel affected facilities of the owner or sufficient to assure compliance with the documentation and recordkeeping of proposed standards for well procedures followed during each operator and documentation of periods of non-compliance. The proposed NSPS completions, storage vessels, pneumatic completion, including total duration of controllers and compressors. Further, would also require records documenting the completion event, amount of time given the nature of some of the liquid throughput of condensate or gas is recovered using reduced emission operations and the types of the completion techniques, amount of time crude oil (to determine applicability), as requirements at issue, the additional gas is combusted, amount of time gas is provided for in the proposed rule. compliance requirements under title V vented to the atmosphere and Recordkeeping would also include would not significantly improve the justification for periods when gas is records of the initial performance test compliance requirements in this combusted or vented rather than being and other information that document proposed NSPS. For instance, well recovered; (3) reports of cases where compliance with applicable emission completions occur over a very short well completions were not performed in limit. These requirements are similar to period (generally 3 to 10 days), and the compliance with the NSPS; (4) annual those under title V. In light of the above, proposed NSPS for pneumatic reports that document all completions we believe that the monitoring, controllers and centrifugal compressors performed during the reporting period recordkeeping and reporting can be met by simply installing the (a single report may be used to requirements described above are equipment that meet the proposed document multiple completions sufficient to assure compliance with the emission limit; therefore, the semi- conducted by a single owner or operator proposed NSPS for storage vessels. annual reporting requirement under title during the reporting period); and (5) V would not improve compliance with annual compliance certifications For pneumatic controllers, centrifugal compressors and reciprocating submitted with the annual report. 9 compressors, the proposed NSPS are in The proposed numeric standards for pneumatic These monitoring, recordkeeping and controllers reflect the use of specific equipment reporting requirements in the proposed the form of operational, work practice or (either non-gas driven device or low-bleed device).

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these proposed NSPS and, in fact, may imposed on 40 CFR part 70 sources potential burdens that title V may seem inappropriate for such short term (hence, burden on sources), see the impose on these sources. In addition, operations. requirements of 40 CFR 70.3, 40 CFR below in our consideration of the fourth For the reasons stated above, we 70.5, 40 CFR 70.6, and 40 CFR 70.7. The factor, we find that there are adequate believe that title V would not result in activities described above, which are implementation and enforcement significant improvements to the quite extensive and time consuming, programs in place to assure compliance compliance requirements that are would be a significant burden on the with the proposed NSPS. In light of the provided in this proposed NSPS. non-major sources that would be subject above, we find that the costs of title V Therefore, the first factor supports a to the proposed NSPS, in particular for permitting are not justified for the conclusion that title V permitting is well completion and/or pneumatic sources we propose to exempt. ‘‘unnecessary’’ for non-major sources devices, considering the short duration Accordingly, the third factor supports subject to the Oil and Natural Gas NSPS. of a well completion and the one time title V exemption for the oil and gas The second factor we considered is equipment installation of a pneumatic NSPS non-major sources. whether title V permitting would controller for meeting the proposed The fourth factor we considered is impose significant burdens on the oil NSPS. Furthermore, some of the non- whether there are implementation and and natural gas NSPS non-major sources major sources that would be subject to enforcement programs in place that are and whether that burden would be the proposed NSPS may be small sufficient to assure compliance with the aggravated by any difficulty these entities that may lack the technical proposed NSPS for oil and gas sources sources may have in obtaining resources and, therefore, need assistance without relying on title V permits. The assistance from permitting agencies. from the permitting authorities to CAA provides States the opportunity to Subjecting any source to title V comply with the title V permitting take delegation of NSPS. Before the EPA permitting imposes certain burdens and requirements. Based on our projections, will delegate the program, the EPA will costs that do not exist outside of the title over 20,000 well completions (for both evaluate the state programs to ensure V program. EPA estimated that the new hydraulically fractured gas wells that states have adequate capability to average cost of obtaining and complying and for existing gas wells that are enforce the CAA section 111 regulations with a title V permit was $65,700 per subsequently fractured or re-fractured) and provide assurances that they will source for a 5-year permit period, will be performed each year. For enforce the NSPS. In addition, EPA including fees. See Information pneumatic controller affected facilities, retains authority to enforce this NSPS Collection Request (ICR) for Part 70 we estimate that approximately 14,000 anytime under CAA sections 111, 113 Operating Permit Regulations, January new controllers would be subject to the and 114. Accordingly, we can enforce 2007, EPA ICR Number 1587.07. EPA NSPS each year. Our estimated numbers the monitoring, recordkeeping and does not have specific estimates for the of affected facilities that would be reporting requirements, which, as burdens and costs of permitting the oil subject to the proposed NSPS for storage discussed under the first factor, are and gas NSPS non-major sources; vessels and compressors are smaller adequate to assure compliance with this however, there are certain activities (around 500 compressors and 300 NSPS. Also, states and the EPA often associated with the 40 CFR part 70 and storage vessels). Although we do not conduct voluntary compliance 40 CFR part 71 rules. These activities know the total number of non-major assistance, outreach and education are mandatory and impose burdens on sources that would be subject to the programs (compliance assistance any facility subject to title V. They programs), which are not required by proposed NSPS, based on the estimated include reading and understanding statute. We determined that these numbers of affected facilities, we permit program regulations; obtaining additional programs will supplement anticipate a significant increase in the and understanding permit application and enhance the success of compliance number of permit applications that forms; answering follow-up questions with these proposed standards. We permitting authorities would have to from permitting authorities after the believe that the statutory requirements process each year. This significant application is submitted; reviewing and for implementation and enforcement of burden on the permitting authorities understanding the permit; collecting this NSPS by the delegated states, the raises a concern with the potential records; preparing and submitting EPA and the additional assistance difficulty or delay that the small entities monitoring reports; preparing and programs described above together are submitting prompt deviation reports, as may face in obtaining sufficient sufficient to assure compliance with defined by the state, which may include assistance from the permitting these proposed standards without a combination of written, verbal and authorities. relying on title V permitting. other communication methods; The third factor we considered is Our balance of the four factors collecting information, preparing and whether the costs of title V permitting strongly supports a finding that title V submitting the annual compliance for these area sources would be is unnecessarily burdensome for the oil certification; preparing applications for justified, taking into consideration any and gas non-major sources. While title permit revisions every 5 years; and, as potential gains in compliance likely to V might add additional compliance needed, preparing and submitting occur for such sources. We concluded, requirements if imposed, we believe applications for permit revisions. In in considering the first factor, that the that there would not be significant addition, although not required by the monitoring, recordkeeping and improvements to the compliance permit rules, many sources obtain the reporting requirements in this proposed requirements in this proposed rule contractual services of consultants to NSPS assure compliance with the because the proposed rule requirements help them understand and meet the proposed standards, that title V would are specifically designed to assure permitting program’s requirements. The not result in significant improvement to compliance with the proposed NSPS ICR for 40 CFR part 70 provides these compliance requirements and, and, as explained above, some of the additional information on the overall that, in some instances, certain title V title V requirements may not be burdens and costs, as well as the compliance requirements may not be appropriate for certain operations and/ relative burdens of each activity appropriate. In addition, as discussed or proposed standards. We are also described here. Also, for a more above in our consideration of the second concerned with the potential burden comprehensive list of requirements factor, we have concerns with the that title V may impose on some of these

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sources. In light of little or no potential VI. Rationale for Proposed Action for Available Control Technology (RACT)/ gain in compliance if title V were NSPS Best Available Control Technology (BACT)/Lowest Achievable Emission required, we do not believe that the A. What did we evaluate relative to Rate (LAER) Clearinghouse (RBLC) costs of title V permitting is justified in NSPS? this case. Finally, there are adequate database, and emerging technologies implementation and enforcement As noted above, there are two existing that have been identified by partners in programs in place to assure compliance NSPS that address emissions from the the Natural Gas STAR program. with these proposed standards. Thus, Oil and Natural Gas source category. The current NSPS for equipment leaks These NSPS are relatively narrow in of VOC at natural gas processing plants we propose that title V permitting is scope, as they address emissions only at (40 CFR part 60, subpart KKK) requires ‘‘unnecessarily burdensome’’ for the oil natural gas processing plants. compliance with specific provisions of and gas non-major sources. Specifically, 40 CFR part 60, subpart 40 CFR part 60, subpart VV, which is a In addition to evaluating whether KKK addresses VOC emissions from LDAR program, based on the use of EPA compliance with title V requirements is leaking equipment at onshore natural Method 21 to identify equipment leaks. ‘‘unnecessarily burdensome,’’ EPA also gas processing plants and 40 CFR part In addition to the subpart VV considered, consistent with guidance 60, subpart LLL addresses SO2 requirements, we reviewed the LDAR provided by the legislative history of emissions from natural gas processing requirements in 40 CFR part 60, subpart section 502(a), whether exempting oil plants. VVa. This LDAR program is considered and gas NSPS non-major sources from CAA section 111(b)(1)(B) requires the to be more stringent than the subpart VV title V requirements would adversely EPA to review and revise, if appropriate, requirements, because it has lower affect public health, welfare or the NSPS standards. Accordingly, we component leak threshold definitions environment. The title V permit evaluated whether the existing NSPS and more frequent monitoring, in program does not impose new reflect the BSER for the emission comparison to the subpart VV program. Furthermore, subpart VVa requires substantive air quality control sources that they address. This review monitoring of connectors, while subpart requirements on sources, but instead was conducted by examining currently used, new and emerging control systems VV does not. We also reviewed options requires that certain procedural based on optical gas imaging. measures be followed, particularly with and assessing whether they represent advances in emission reduction As mentioned above, the currently respect to determining compliance with techniques from those upon which the required LDAR program for natural gas applicable requirements. As stated in existing NSPS are based, including processing plants (40 CFR part 60, our consideration of factor one, title V advances in LDAR approaches and SO2 subpart KKK) is based on EPA Method would not lead to significant control at natural gas processing plants. 21, which requires the use of an organic improvements in the compliance For each new or emerging control vapor analyzer to monitor components requirements for the proposed NSPS. option identified, we then evaluated and to measure the concentration of the For the reason stated above, we believe emission reductions, costs, energy emissions in identifying leaks. We that exempting these non-major sources requirements and non-air quality recognize that there have been from title V permitting requirements impacts, such as solid waste generation. advancements in the use of optical gas would not adversely affect public In this package, we have also imaging to detect leaks from these same health, welfare or the environment. evaluated whether there were additional types of components. These instruments pollutants emitted by facilities in the do not yet provide a direct measure of On the contrary, we are concerned leak concentrations. The instruments that requiring title V in this case could Oil and Natural Gas source category that warrant regulation and for which we instead provide a measure of a leak potentially adversely affect public relative to an instrument specific health, welfare or the environment. As have adequate information to promulgate standards of performance. calibration point. Since the mentioned above, we anticipate a promulgation of 40 CFR part 60, subpart significant increase in the number of Finally, we have identified additional processes in the Oil and Natural Gas KKK (which requires Method 21 leak permit applications that permitting source category for which it may be measurement monthly), the EPA has authorities would have to process each appropriate to develop performance updated the 40 CFR part 60 General year. Depending on the number of non- standards. This would include Provisions to allow the use of advanced major sources that would be subject to leak detection tools, such as optical gas processes that emit the currently imaging and ultrasound equipment as this rule, requiring permits for those regulated pollutants, VOC and SO , as 2 an alternative to the LDAR protocol sources, at least in the first few years of well as any additional pollutants for based on Method 21 leak measurements implementation, could potentially which we determined regulation to be (see 40 CFR 60.18(g)). The alternative adversely affect public health, welfare appropriate. or the environment by shifting state work practice allowing use of these agencies resources away from assuring B. What are the results of our advanced technologies includes a compliance for major sources (which evaluations and proposed actions provision for conducting a Method 21- cannot be exempt from title V) to relative to NSPS? based LDAR check of the regulated equipment annually to verify good issuing new permits for these non-major 1. Do the existing NSPS reflect the BSER sources, potentially reducing overall air performance. for sources covered? In our review, we evaluated 4 options program effectiveness. Consistent with our obligations under in considering BSER for VOC equipment Based on the above analysis, we CAA section 111(b), we evaluated leaks at natural gas processing plants. conclude that title V permitting would whether the control options reflected in One option we evaluated consists of be ‘‘unnecessarily burdensome’’ for oil the current NSPS for the Oil and Natural changing from a 40 CFR part 60, subpart and gas NSPS non-major sources. We Gas source category still represent VV-level program, which is what 40 are, therefore, proposing that these non- BSER. To evaluate the BSER options for CFR part 60, subpart KKK currently major sources be exempt from title V equipment leaks, we reviewed EPA’s requires, to a 40 CFR part 60, subpart permitting requirements. current LDAR programs, the Reasonably VVa program, which applies to new

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synthetic organic chemical plants after were unable to estimate the VOC Claus sulfur recovery unit produces 2006. Subpart VVa lowers the leak emissions achieved by an optical elemental sulfur from H2S in a series of definition for valves from 10,000 parts imaging program alone, we were unable catalytic stages, recovering up to 97- per million (ppm) to 500 ppm, and to estimate the cost effectiveness of this percent recovery of the sulfur from the requires the monitoring of connectors. option. acid gas from the sweetening process. In our analysis of these impacts, we Finally, we evaluated a fourth option Further, sulfur recovery is accomplished estimated that, for a typical natural gas similar to the third option, except that by making process modifications or by processing plant, the incremental cost the optical gas imaging would be employing a tail gas treatment process effectiveness of changing from the performed annually rather than to convert the unconverted sulfur current subpart VV-level program to a monthly. For this option, we estimated compounds from the Claus unit. subpart VVa-level program using the annual cost to be $43,851, based on We evaluated process modifications Method 21 is $3,352 per ton of VOC camera purchase, or $18,479, based on and tail gas treatment options when we reduction. camera rental. proposed 40 CFR part 60, subpart LLL. In evaluating 40 CFR part 60, subpart We request comment on the 49 FR 2656, 2659–2660 (1984). As we VVa-level LDAR at processing plants, applicability of an LDAR program based explained in the preamble to the we also analyzed separately the solely on the use of optical gas imaging. proposed subpart LLL, control through individual types of components (valves, Of most use to us would be information sulfur recovery with tail gas treatment connectors, pressure relief devices and on the effectiveness of this and, may not always be cost effective, open-ended lines) to determine cost potentially, other advanced depending on sulfur feed rate and inlet effectiveness for individual measurement technologies, to detect H2S concentrations. Therefore, other components. Detailed discussions of and repair small leaks on the same order methods of increasing sulfur recovery these component-by-component or smaller than specified in the 40 CFR via process modifications were analyses are included in the TSD in the part 60, subpart VVa equipment leak evaluated. As shown in the original docket. Cost effectiveness ranged from requirements and the effects of evaluation, the performance capabilities $144 per ton of VOC (for valves) to increased frequency of and associated and costs of each of these technologies $4,360 per ton of VOC (for connectors), leak detection, recording and repair are highly dependent on the ratio of H2S with no change in requirements for practices. and CO2 in the gas stream and the total pressure relief devices and open-ended Because we could not estimate the quantity of sulfur in the gas stream lines. cost effectiveness of options 3 and 4, we being treated. The most effective means Another option we evaluated for gas could not identify either of these two of control was selected as BSER for the processing plants was the use of optical options as BSER for reducing VOC leaks different stream characteristics. As a gas imaging combined with an annual at gas processing plants. Because result, separate emissions limitations EPA Method 21 check (i.e., the options 1 and 2 have achieved were developed in the form of equations alternative work practice for monitoring equivalent VOC reduction and are both that calculate the required initial and equipment for leaks at 40 CFR 60.18(g)). cost effective, we believe that both continuous emission reduction We had previously determined that the options 1 and 2 reflect BSER for LDAR efficiency for each plant. The equations VOC reduction achieved by this for natural gas processing plants. As were based on the design performance combination of optical gas imaging and mentioned above, option 1 is the LDAR capabilities of the technologies selected Method 21 would be equivalent to in 40 CFR part 60, subpart VVa and as BSER relative to the gas stream reductions achieved by the 40 CFR part option 2 is the alternative work practice characteristics. 49 FR 2656, 2663–2664 at 40 CFR 60.18(g) and is already 60, subpart VVa-level program. Based (1984). The emission limit for sulfur available to use as an alternative to on that emission reduction level, we feed rates at or below 5 long tons per subpart VVa LDAR. Therefore, we determined the cost effectiveness of this day, regardless of H2S content, was 79 propose that the NSPS for equipment option to be $6,462 per ton of VOC percent. For facilities with sulfur feed leaks of VOC at gas processing plants be reduction. This analysis is based on the rates above 5 long tons per day, the revised to require compliance with the facility purchasing an optical gas emission limits ranged from 79 percent subpart VVa equipment leak imaging system costing $85,000. at an H2S content below 10 percent to requirements. 99.8 percent for H2S contents at or However, we identified at least one For 40 CFR part 60, subpart LLL, we manufacturer who rents the optical gas above 50 percent. reviewed control systems for SO2 To review these emission limitations, imaging systems. That manufacturer emissions from sweetening units located we performed a search of the RBLC rents the optical gas imaging system for at natural gas processing plants, database and state regulations. No state $3,950 per week. Using this rental cost including those followed by a sulfur regulations identified had emission in place of the purchase cost, the VOC recovery unit. Subpart LLL provides limitations more stringent than 40 CFR cost effectiveness of the monthly optical specific standards for SO2 emission part 60, subpart LLL. However, the gas imaging combined with annual reduction efficiency, on the basis of RBLC database search identified two Method 21 checks is $4,638 per ton of 10 sulfur feed rate and the sulfur content entries with SO2 emission reductions of VOC reduction. A third option we of the natural gas. 99.9 percent. One entry is for a facility evaluated consisted of monthly optical According to available literature, the in Bakersfield, California, with a 90 long gas imaging without an annual Method most widely used process for converting ton per day sulfur recovery unit 21 check. We estimated the annual cost H2S in acid gases (i.e., H2S and CO2) followed by an amine-based tail-gas of the monthly optical gas imaging separated from natural gas by a treating unit. The second entry is for a LDAR program to be $76,581, based on sweetening process (such as amine facility in Coden, Alabama, with a camera purchase, or $51,999, based on treating) into elemental sulfur is the sulfur recovery unit with a sulfur feed camera rental. However, because we Claus process. Sulfur recovery rate of 280 long tons per day, followed efficiencies are higher with higher by selective catalytic reduction and a 10 Because optical gas imaging is used to view several pieces of equipment at a facility at once to concentrations of H2S in the feed stream tail gas incinerator. However, neither of survey for leaks, options involving imaging are not due to the thermodynamic equilibrium these entries contained information amenable to a component by component analysis. limitation of the Claus process. The regarding the H2S contents of the feed

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stream. Because the sulfur recovery would increase the 2009 Inventory of facility in the Oil and Natural Gas efficiency of these large sized plants was estimate by 76.74 MMtCO2e. The total source category where we would expect greater than 99.8 percent, we methane emissions from Petroleum and SO2 to be emitted directly, although H2S reevaluated the original data. Based on Natural Gas Systems, based on the 2009 contained in sour gas, when oxidized in the available cost information, it Inventory, adjusted for tight sand plays the atmosphere or combusted in boilers appears that a 99.9-percent efficiency is and the Marcellus, is 328.29 MMtCO2e. and heaters in the field, forms SO2 as a cost effective for facilities with a sulfur Although this proposed rule does not product of oxidation. These field boilers feed rate greater than 5 long tons per include standards for regulating the and heaters are not part of the Oil and day and H2S content equal to or greater GHG emissions discussed above, we Natural Gas source category and are than 50 percent. Based on our review, continue to assess these significant generally too small to be regulated by we are proposing that the maximum emissions and evaluate appropriate the NSPS covering boilers (i.e., they initial and continuous efficiency for actions for addressing these concerns. have a heat input of less than 10 million facilities with a sulfur feed rate greater Because many of the proposed British Thermal Units per hour). than 5 long tons per day and an H2S requirements for control of VOC However, we may consider addressing content equal to or greater than 50 emissions also control methane them as part of a future sector-based percent be raised to 99.9 percent. We are emissions as a co-benefit, the proposed strategy for the oil and natural gas not proposing to make changes to the VOC standards would also achieve sector. equations. significant reduction of methane In addition to VOC emissions from Our search of the RBLC database did emissions. gas processing plants, there are not uncover information regarding costs Significant emissions of oxides of numerous sources of VOC throughout and achievable emission reductions to nitrogen (NOX) also occur at oil and the oil and natural gas sector that are suggest that the emission limitations for natural gas sites due to the combustion not addressed by the current NSPS. As facilities with a sulfur feed rate less than of natural gas in reciprocating engines explained above in section V.A, 5 long tons per day or H2S content less and combustion turbines used to drive pursuant to CAA section 111(b), to the than 50 percent should be modified. the compressors that move natural gas extent necessary, we are modifying the Therefore, we are not proposing any through the system, and from listed category to include all segments changes to the emissions limitations for combustion of natural gas in heaters and of the oil and natural gas industry for facilities with sulfur feed rate and H2S boilers. While these engines, turbines, regulation. We are also proposing VOC content less than 5 long tons per day heaters and boilers are co-located with standards to cover additional processes and 50 percent, respectively. processes in the oil and natural gas at oil and natural gas operations. These sector, they are not in the Oil and include NSPS for VOC from gas well 2. What pollutants are being evaluated Natural Gas source category and are not completions, pneumatic controllers, in this Oil and Natural Gas NSPS being addressed in this action. The NO compressors and storage vessels. package? X emissions from engines and turbines are We believe that produced water The two current NSPS for the Oil and covered by the Standards of ponds are also a potentially significant Natural Gas source category address Performance for Stationary Spark source of emissions, but we have only emissions of VOC and SO2. In addition Internal Combustion Engines (40 CFR limited information. We, therefore, to these pollutants, sources in this part 60, subpart JJJJ) and Standards of solicit comments on produced water source category also emit a variety of Performance for Stationary Combustion ponds, particularly in the following other pollutants, most notably, air Turbines (40 CFR part 60, subpart subject areas: toxics. As discussed elsewhere in this KKKK), respectively. (a) We are requesting comments notice, there are NESHAP that address An additional source of NOX pertaining to methods for calculating air toxics from the oil and natural gas emissions would be pit flaring of VOC emissions. The State of Colorado sector. emissions from well completions during currently uses a mass balance that In addition, processes in the Oil and periods where REC is not feasible, as assumes 100 percent of the VOC content Natural Gas source category emit would be required under our proposed is emitted to the atmosphere. Water9, an significant amounts of methane. The operational standards for wellhead air emissions model, is another option 1990–2009 U.S. GHG Inventory affected facilities. As discussed below in that has some limitations, including estimates 2009 methane emissions from section VI.B.4 (well completion), pit poor methanol estimation. Petroleum and Natural Gas Systems (not flaring is the only way we identified of (b) We are requesting additional including petroleum refineries) to be controlling VOC emissions during these information on typical VOC content in 251.55 MMtCO2e (million metric tons of periods. Because there is no way of produced water and any available 11 CO2-equivalents (CO2e)). The directly measuring the NOX produced, chemical analyses, including data that emissions estimated from well nor is there any way of applying could help clarify seasonal variations or completions and recompletions exclude controls other than minimizing flaring, differences among gas fields. a significant number of wells completed we propose to allow flaring only when Additionally, we request data that in tight sand plays, such as the REC is not feasible. We have included increase our understanding of how Marcellus, due to availability of data our estimates of NOX formation from pit changing process variables or age of when the 2009 Inventory was flaring in our discussion of secondary wells affect produced water output and developed. The estimate in this impacts in section VI.B.4. VOC content. proposal includes an adjustment for (c) We solicit information on the size tight sand plays (being considered as a 3. What emission sources are being and throughput capacity of typical planned improvement in development evaluated in this Oil and Natural Gas evaporation pond facilities and request of the 2010 Inventory). This adjustment NSPS package? suggestions on parameters that could be The current NSPS only cover used to define affected facilities or 11 U.S. EPA. Inventory of U.S. Greenhouse Gas emissions of VOC and SO2 from one affected sources. We also seek Inventory and Sinks. 1990–2009. http:// www.epa.gov/climatechange/emissions/ type of facility in the oil and natural gas information on impacts of smaller downloads10/US-GHG-Inventory- sector, which is the natural gas evaporation pits that are co-located with 2010_ExecutiveSummary.pdf. processing plant. This is the only type drilling operations, whether those

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warrant control and, if so, how controls several days following fracturing of a EPA has based the NSPS impacts should be developed. new well or refracturing of an existing analysis on best available emission data. (d) An important factor is cost of well. Well completions include multiple However, we recognize that there is emission reduction technologies, steps after the well bore hole has uncertainty associated with our including recovery credits or cost reached the target depth. These steps estimates. For both new completions savings realized from recovered salable include inserting and cementing-in well and recompletions, there are a variety of product. We are seeking information on casing, perforating the casing at one or factors that will determine the length of these considerations as well. more producing horizons, and often the flowback period and actual volume (e) We are also seeking information on hydraulically fracturing one or more of emissions such as the number of any limitations for emission reduction zones in the reservoir to stimulate zones, depth, pressure of the reservoir, technologies such as availability of production. Well recompletions may gas composition, etc. This variability electricity, waste generation and also include hydraulic fracturing. means there will be some wells which disposal and throughput and Hydraulic fracturing is one technique emit more than the estimated emission concentration constraints. for improving gas production where the factor and some wells that emit less. (f) Finally, we solicit information on During our review, we examined reservoir rock is fractured with very separator technologies that are able to information from the Natural Gas STAR high pressure fluid, typically water improve the oil-water separation program and the Colorado and efficiency. emulsion with a proppant (generally Wyoming state rules covering well sand) that ‘‘props open’’ the fractures completions. We identified two 4. What are the rationales for the after fluid pressure is reduced. proposed NSPS? subcategories of fractured gas wells: (1) Emissions are a result of the backflow of Non-exploratory and non-delineation We have provided below our the fracture fluids and reservoir gas at wells; and (2) exploratory and rationales for the proposed BSER high volume and velocity necessary to delineation wells. An exploratory well determinations and performance lift excess proppant and fluids to the is the first well drilled to determine the standards for a number of VOC emission surface. This multi-phase mixture is presence of a producing reservoir and sources in the Oil and Natural Gas often directed to a surface the well’s commercial viability. A source category that are not covered by impoundment where natural gas and delineation well is a well drilled to the existing NSPS. Our general process VOC vapors escape to the atmosphere determine the boundary of a field or for evaluating systems of emission during the collection of water, sand and producing reservoir. Because reduction for the emission sources hydrocarbon liquids. As the fracture exploratory and delineation wells are discussed below included: (1) fluids are depleted, the backflow generally isolated from existing Identification of available control eventually contains more volume of producing wells, there are no gathering measures; (2) evaluation of these natural gas from the formation. Wells lines available for collection of gas measures to determine emission that are fractured generally have great recovered during completion reductions achieved, associated costs, amounts of emissions because of the operations. In contrast, non-exploratory nonair environmental impacts, energy extended length of the flowback period and non-delineation wells are located impacts and any limitations to their required to purge the well of the fluids where existing, producing wells are application; and (3) selection of the and sand that are associated with the connected to gathering lines and are, control techniques that represent BSER fracturing operation. Along with the therefore, able to be connected to a based on the information we fluids and sand from the fracturing gathering line to collect recovered considered. operation, the 3- to 10-day flowback salable natural gas product that would We identified the control options period also results in emissions of otherwise be vented to the atmosphere discussed in this package through our natural gas and VOC that would not or combusted. review of relevant state and local occur in large quantities at oil wells or For subcategory 1, we identified requirements and mitigation measures at natural gas wells that are not ‘‘green’’ completion, which we refer to developed and reported by the EPA’s as REC, as an option for reducing VOC fractured. Thus, we estimate that gas Natural Gas STAR program. The EPA’s emissions during well completions. REC well completions involving hydraulic Natural Gas STAR program has worked are performed by separating the fracturing vent substantially more VOC, with industry partners since 1993 to flowback water, sand, hydrocarbon approximately 200 times more, than identify cost effective measures to condensate and natural gas to reduce completions not involving hydraulic reduce emissions of methane and other the portion of natural gas and VOC pollutants from natural gas operations. fracturing. Specifically, we estimate that vented to the atmosphere, while We relied heavily on this wealth of uncontrolled well completion emissions maximizing recovery of salable natural information in conducting this review. for a hydraulically fractured gas well are gas and VOC condensate. In some cases, We also identified state regulations, approximately 23 tons of VOC, where for a portion of the completion emissions for a conventional gas well primarily in Colorado and Wyoming, operation, such as when CO2 or nitrogen which require mitigation measures for completion are around 0.12 tons VOC. is injected with the fracture water, some emission sources in the Oil and These estimates are explained in detail initial gas produced is not of suitable Natural Gas source category. in the TSD available in the docket. quality to introduce into the gathering Based on our review, we believe that line due to CO2 or nitrogen content or a. NSPS for Well Completions emissions from recompletions of other undesirable characteristic. In such Well completion activities are a previously completed wells that are cases, for a portion of the flowback significant source of VOC emissions, fractured or refractured to stimulate period, gas cannot be recovered, but which occur when natural gas and non- production or to begin production from must be either vented or combusted. In methane hydrocarbons are vented to the a new production horizon are of similar practice, REC are often combined with atmosphere during flowback of a magnitude and composition as combustion to minimize the amount of hydraulically fractured gas well. emissions from completions of new gas and condensate being vented. This Flowback emissions are short-term in wells that have been hydraulically combustion process is rather crude, nature and occur over a period of fractured. consisting of a horizontal pipe

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downstream of the REC equipment, reduction that would be achieved. Aside standard rather than a performance- fitted with a continuous ignition source from the potential hazards associated based standard (e.g., requiring that some and discharging over a pit near the with pit flaring, in some cases, we did percentage of emissions be flared or wellhead. Because of the nature of the not identify any nonair environmental captured), because we believe there are flowback (i.e., with periods of water, impacts, health or energy impacts no feasible ways for operators to condensate, and gas in slug flow), associated with REC combined with measure emissions with enough conveying the entire portion of this combustion. However, pit flaring would certainty to demonstrate compliance stream to a traditional flare control produce NOX emissions. Because we with a performance-based standard for device or other control device, such as believe that these emissions cannot be REC in combination with pit flaring. a vapor recovery unit, is not feasible. controlled or measured directly due to The EPA requests comment on this and These control devices are not designed the open combustion process seeks input on whether alternative to accommodate the multiphase flow characteristic of pit flaring, we used approaches to requiring REC for all consisting of water, sand and published emission factors (EPA operators with access to pipelines may hydrocarbon liquids, along with the gas Emission Guidelines AP–42) to estimate exist that would allow operators to meet and vapor being controlled. Although the NOX emissions for purposes of a performance-based standard if they ‘‘pit flaring’’ does not employ a assessing secondary impacts. For can demonstrate that an REC is not cost traditional flare control device, and is category 1 well completions, we effective. not capable of being tested or monitored estimated that 0.02 tons of NOX are We have discussed above certain for efficiency due to the multiphase slug produced per event. This is based on the situations where unrecoverable gas flow and intermittent nature of the assumption that 5 percent of the would be vented because pit flaring discharge of gas, water and sand over flowback gas is combusted by the would present a fire hazard or is the pit, it does provide a means of combustion device. The 1.2 tons of VOC infeasible because gas is minimizing vented gas and is preferable controlled during the pit flaring portion noncombustible due to high to venting. Because of the rather large of category 1 well completions is concentrations of nitrogen or CO2. We exposed flame, open pit flaring can approximately 57 times greater than the solicit comment on whether there are present a fire hazard or other NOX produced by pit flaring. Thus, we other such situations where flaring undesirable impacts in some situations believe that the benefit of the VOC would be unsafe or infeasible, and (e.g., dry, windy conditions, proximity reduction far outweighs the secondary potential criteria that would support to residences, etc.). As a result, we are impact of NOX formation during pit venting in lieu of pit flaring. In addition, aware that owners and operators may flaring. we learned that coalbed methane not be able to pit flare unrecoverable gas We believe that, based on the analysis reservoirs may have low pressure, safely in every case. In some cases, pit above, REC in combination with which would present a technical barrier flaring may be prohibited by local combustion is BSER for subcategory 1 for performing a REC because the well ordinance. wells. We considered setting a pressure may not be substantial enough Equipment required to conduct REC numerical performance standard for to overcome gathering line pressure. In may include tankage, special gas-liquid- subcategory 1 wells. However, it is not addition, we identified that coalbed sand separator traps and gas practicable to measure the emissions methane wells often have low to almost dehydration. Equipment costs during pit flaring or venting because the no VOC emissions, even following the associated with REC will vary from well gas is discharged over the pit along with hydraulic fracturing process. We solicit to well. Typical well completions last water and sand in multiphase slug flow. comment on criteria and thresholds that between 3 and 10 days and costs of Therefore, we believe it is not feasible could be used to exempt some well performing REC are projected to be to set a numerical performance completion operations occurring in between $700 and $6,500 per day, standard. Pursuant to section 111(h)(2) coalbed methane reservoirs from the including a cost of approximately of the CAA, we are proposing an requirements for subcategory 1 wells. $3,523 per completion event for the pit operational standard for subcategory 1 Of the 25,000 new and modified flaring equipment. However, there are wells that would require a combination fractured gas wells completed each year, savings associated with the use of REC of REC and pit flaring to minimize we estimate that approximately 3,000 to because the gas recovered can be venting of gas and condensate vapors to 4,000 currently employ reduced incorporated into the production stream the atmosphere, with provisions for emission completion. We expect this and sold. In fact, we estimate that REC venting in lieu of pit flaring for number to increase to over 21,000 REC will result in an overall net cost savings situations in which pit flaring would annually as operators comply with the in many cases. present safety hazards or for periods proposed NSPS. We estimate that The emission reductions for a when the flowback gas is approximately 9,300 new wells and hydraulically fractured well are noncombustible due to high 12,000 existing wells will be fractured estimated to be around 22 tons of VOC. concentrations of nitrogen or CO2. The or refractured annually that would be Based on an average incremental cost of proposed operational standard would be subject to subcategory 1 requirements $33,237 per completion, the cost accompanied by requirements for under the NSPS. We believe that there effectiveness of REC, without documentation of the overall duration of will be a sufficient supply of REC considering any cost savings, is around the completion event, duration of equipment available by the time the $1,516 per ton of VOC (which we have recovery using REC, duration of NSPS becomes effective. However, previously found to be cost effective on combustion, duration of venting, and energy availability could be affected if a average). When the value of the gas specific reasons for venting in lieu of shortage of REC equipment was allowed recovered (approximately 150 tons of combustion. to cause delays in well completions. We methane per completion) is considered, We recognize that there is request comment on whether sufficient the cost effectiveness is estimated as an heterogeneity in well operations and supply of this equipment and personnel average net savings of $99 per ton VOC costs, and that while RECs may be cost- to operate it will be available to reduced, using standard discount rates. effective on average, they may not be for accommodate the increased number of We believe that these costs are very all operators. Nonetheless, EPA is REC by the effective date of the NSPS. reasonable, given the emission proposing to require an operational We also request specific estimates of

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how much time would be required to effective REC that we have not sand in multiphase slug flow. It is, get enough equipment in operation to identified in our review. For example, therefore, not feasible to set a numerical accommodate the full number of REC some small regulated entities may have performance standard. performed annually. an increased source of revenue due to Pursuant to CAA section 111(h)(2), we In the event that public comments the captured product. On the other are proposing an operational standard indicate that available equipment would hand, some small regulated entities may for subcategory 2 wells that requires likely be insufficient to accommodate have less access to REC than larger minimization of venting of gas and the increase in number of REC regulated entities might have. We hydrocarbon vapors during the performed, we are considering phasing request information on such completion operation through the use of in requirements for well completions opportunities and barriers that we pit flaring, with provisions for venting that would achieve an overall should consider and suggestions for in lieu of pit flaring for situations in comparable level of environmental how we may take them into account in which flaring would present safety benefit. For example, operators structuring the NSPS. hazards or for periods when the performing completions of fractured or The second subcategory of fractured flowback gas is noncombustible due to refractured existing wells (i.e., modified gas wells includes exploratory wells or high concentrations of nitrogen or wells) could be allowed to control delineation wells. Because these types carbon dioxide. emissions through pit flaring instead of of wells generally are not in proximity Consistent with requirements for REC for some period of time. After some to existing gathering lines, REC is not an subcategory 1 wells, owners or operators date certain, all modified wells would option, since there is no infrastructure of subcategory 2 wells would be be subject to REC. We solicit comment in place to get the recovered gas to required to document completions and on the phasing of requirements for REC market or further processing. For these provide justification for periods when along with suggestions for other ways to wells, the only potential control option gas was vented in lieu of combustion. address a potential short-term REC we were able to identify is pit flaring, We solicit comment on whether there equipment shortage that may hinder described above. As explained above, are other such situations where flaring operators’ compliance with the because of the slug flow nature of the would be unsafe or infeasible and proposed NSPS, while also achieving a flowback gas, water and sand, control by potential criteria that would support comparable level of reduced emissions a traditional flare control device or other venting in lieu of pit flaring. to the air. control devices, such as vapor recovery For controlling completion emissions Although we have determined that, units, is infeasible, which leaves pit at oil wells and conventional (non- on average, reduced emission flaring as the only practicable control fractured) gas wells, we have identified completions are cost effective, well and system for subcategory 2 wells. As also and evaluated the following control reservoir characteristics could vary, discussed above, open pit flaring can options: REC in conjunction with pit such that some REC are more cost present a fire hazard or other flaring and pit flaring alone. Due to the effective than others. Unlike most undesirable impacts in some situations. low uncontrolled VOC emissions of stationary source controls, REC Aside from the potential hazards approximately 0.007 ton per completion equipment is used only for a 3 to 10 day associated with pit flaring, in some and, therefore, low potential emission period. Our review found that most cases, we did not identify any nonair reductions from these events, the cost operators contract with service environmental impacts, health or energy per ton of reduction based on REC companies to perform REC rather than impacts associated with pit flaring. would be extremely high (over $700,000 purchase the equipment themselves, However, pit flaring would produce per ton of VOC reduced). We evaluated which was reflected in our economic NOX emissions. As in the case of the use of pit flaring alone as a system analysis. It is also possible that the category 1 wells, we believe that these for controlling emissions from oil wells contracting costs of supplying and emissions cannot be controlled or and conventional gas wells and operating REC equipment may rise in measured directly due to the open determined that the cost cost- the short term with the increased combustion process characteristic of pit effectiveness would be approximately demand for those services. We request flaring. We again used published $520,000 per ton for oil wells and comment and any available technical emission factors to estimate the NOX approximately $32,000 per ton for information to judge whether our emissions for purposes of assessing conventional gas wells. In light of the assumption of $33,237 per well secondary impacts. For category 2 well high cost per ton of VOC reduction, we completion for this service given the completions, we estimated that 0.32 do not consider either of these control projected number of wells in 2015 tons of NOX are produced as secondary options to be BSER for oil wells and subject to this requirement is accurate. emissions per completion event. This is conventional wells. We believe that the proposed rule based on the assumption that 95 percent We propose that fracturing (or regulates only significant emission of flowback gas is combusted by the refracturing) and completion of an sources for which controls are cost- combustion device. The 22 tons of VOC existing well (i.e., a well existing prior effective. Nevertheless, we solicit reduced during the pit flaring used to to August 23, 2011) is considered a comment and supporting data on control category 2 well completions is modification under CAA section 111(a), appropriate thresholds (e.g., pressure, approximately 69 times greater than the because physical change occurs to the flowrate) that we should consider in NOX produced. Thus, we believe that existing well, which includes the specifying which well completions are the benefit of the VOC reduction far wellbore, casing and tubing, resulting in subject to the REC requirements for outweighs the secondary impact of NOX an emissions increase during the subcategory 1 wells. Comments formation during pit flaring. completion operation. The physical specifying thresholds should include an In light of the above, we propose to change, in this case, would be caused by analysis of why sources below these determine that BSER for subcategory 2 the reperforation of the casing and thresholds are not cost effective to wells would be pit flaring. As we tubing, along with the refracturing of the control. explained above, it is not practicable to wellbore. The increased VOC emissions In addition, there may be economic, measure the emissions during pit flaring would occur during the flowback period technical or other opportunities or or venting because the gas is discharged following the fracturing or refracturing barriers associated with performing cost during flowback mixed with water and operation. Therefore, the proposed

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standards for category 1 and category 2 to the atmosphere. We are not aware of compressors, air tanks and dryers, wells would apply to completions at any add-on controls that are or can be would be $11,090. A system of this size existing fractured or refractured wells. used to reduce VOC emissions from gas- is capable of serving 15 control loops EPA seeks comment on the 10 percent driven pneumatic devices. and reducing VOC emissions by 4.2 tpy, per year rate of refracturing for natural For an average high-bleed pneumatic for a cost effectiveness of $2,659 per ton gas wells assumed in the impacts controller located in production (where of VOC reduced. If the savings of the analysis found in the TSD. EPA has the content of VOC in the raw product salable natural gas that would have been received anecdotal information stream is relatively high), the difference emitted is considered, the value of the suggesting that refracturing could be in VOC emissions between a high-bleed gas not emitted would help offset the occurring much less frequently, while controller and a low-bleed controller is cost for this control, bringing the cost others suggest that the percent of wells around 1.8 tpy. For the transmission per ton of VOC down to $1,824. refractured in a given year could be and storage segment (where the content We also evaluated the use of low- greater. We seek comment and of VOC in the pipeline quality gas is bleed controllers in place of high-bleed comprehensive data and information on relatively low), the difference in VOC controllers at processing plants. We the rate of refracturing and key factors emissions between a high-bleed evaluated the impact of bleeding 6 that influence or determine refracturing controller and a low-bleed controller is standard cubic feet of natural gas per frequency. around 0.89 tpy. We have developed hour, which is the maximum bleed rate In addition to well completions, we projections that estimate that from low-bleed controllers, according to considered VOC emissions occurring at approximately 13,600 new gas-driven manufacturers of these devices. We the wellhead affected facility during units in the production segment and 67 chose natural gas as a surrogate for VOC, subsequent day-to-day operations new gas-driven units in the because manufacturers’ technical during well production. As discussed transmission and storage segment will specifications for pneumatic controllers below in section VI.B.1.e, VOC be installed each year, including are stated in terms of natural gas bleed emissions from wellheads are very small replacement of old units. Not all rate rather than VOC. The capital cost during production and account for pneumatic controllers are gas driven. difference between a new high-bleed about 2.6 tons VOC per year. We are not These ‘‘non-gas driven’’ pneumatic controller and a new low-bleed aware of any cost effective controls that controllers use sources of power other controller is estimated to be $165. can be used to address these relatively than pressurized natural gas, such as Without taking into account the savings small emissions. compressed ‘‘instrument air.’’ Because due to the natural gas losses avoided, b. NSPS for Pneumatic Controllers these devices are not gas driven, they do the annual costs are estimated to be not release natural gas or VOC around $23 per year, which is a cost of Pneumatic controllers are automated emissions, but they do have energy $13 per ton of VOC reduced for the instruments used for maintaining a impacts because electrical power is production segment. If the savings of the process condition, such as liquid level, required to drive the instrument air salable natural gas that would have been pressure, pressure differential and compressor system. Electrical service of emitted is considered, there is a net temperature. Pneumatic controllers are at least 13.3 kilowatts (kW) is required savings of $1,519 per ton of VOC widely used in the oil and natural gas to power a 10 horsepower (hp) reduced. sector. In many situations across all instrument air compressor, which is a Although the non-gas-driven segments of the oil and gas industry, relatively small capacity compressor. At controller system is more expensive pneumatic controllers make use of the sites without available electrical service than the low-bleed controller system, it available high-pressure natural gas to sufficient to power an instrument air is still reasonably cost-effective. operate. In these ‘‘gas-driven’’ compressor, only gas driven pneumatic Furthermore, the non-gas-driven pneumatic controllers, natural gas may devices can be used. During our review, controller system achieves a 100-percent be released with every valve movement we determined that gas processing VOC reduction in contrast to a 66- or continuously from the valve control plants are the only facilities in the oil percent reduction achieved by a low- pilot. The rate at which this release and natural gas sector highly likely to bleed controller. Moreover, we believe occurs is referred to as the device bleed have electrical service sufficient to the collateral emissions from electrical rate. Bleed rates are dependent on the power an instrument air system, and power generation needed to run the design of the device. Similar designs that approximately half of existing gas compressor are very low. Finally, non- will have similar steady-state rates processing plants are using non-gas gas-driven pneumatic controllers avoid when operated under similar driven devices. potentially explosive concentrations of conditions. Gas-driven pneumatic For devices at gas processing plants, natural gas which can occur as a result controllers are typically characterized as we evaluated the use of non-gas driven of normal bleeding from groups of gas- ‘‘high-bleed’’ or ‘‘low-bleed,’’ where a controllers and low-bleed controllers as driven pneumatic controllers located in high-bleed device releases more than 6 options for reducing VOC emissions, close proximity, as they often are at gas standard cubic feet per hour (scfh) of with high-bleed controllers being the processing plants. Based on our review gas, with 18 scfh bleed rate being what baseline. As mentioned above, non-gas described above, we believe that a non- we used in our analyses below. There driven devices themselves have zero gas-driven controller is BSER for are three basic designs: (1) Continuous emissions, but they do have energy reducing VOC emissions from bleed devices (high or low-bleed) are impacts because electrical power is pneumatic devices at gas processing used to modulate flow, liquid level or required to drive the instrument air plants. Accordingly, the proposed pressure and gas is vented at a steady- compressor system. In our cost analysis, standard for pneumatic devices at gas state rate; (2) actuating/intermittent we determined that the annualized cost processing plants is a zero VOC devices (high or low-bleed) perform of installing and operating a fully emission limit. quick control movements and only redundant 10 hp (13.3 kW) instrument For the production (other than release gas when they open or close a air system (systems generally are processing plants) and transmission and valve or as they throttle the gas flow; designed with redundancy to allow for storage segments, where electrical and (3) self-contained devices release system maintenance and failure without service sufficient to power an gas to a downstream pipeline instead of loss of air pressure), including duplicate instrument air system is likely

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unavailable and, therefore, only gas- would help assure that only appropriate the seal oil is commonly vented to the driven devices can be used, we exemptions are claimed. atmosphere. Degassing of the seal oil evaluated the use of low-bleed The proposed standards would apply emits an average of 47.7 scfm of gas, controllers in place of high-bleed to installation of a new pneumatic depending on the operating pressure of controllers. Just as in our analysis of device (including replacing an existing the compressor. An uncontrolled wet low-bleed controllers as an option for device with a new device). We consider seal system can emit, on average, gas processing plants, we evaluated the that a pneumatic device, an apparatus, approximately 20.5 tpy of VOC during impact of bleeding 6 standard cubic feet is an affected facility and each the venting process (production per minute (scfm) of natural gas per installation is construction subject to segment) or about 3.5 tpy (transmission hour contrasted with 18 scfm from a the proposed NSPS. See definitions of and storage segment). We identified two high-bleed unit. Again, the capital cost ‘‘affected facility’’ and ‘‘construction’’ at potential control techniques for difference between a new high-bleed 40 CFR 60.2. reducing emissions from degassing of controller and a new low-bleed c. NSPS for Compressors wet seal systems: (1) Routing the gas back to a low pressure fuel stream to be controller is estimated to be $165. There are many locations throughout Without taking into account the savings combusted as fuel gas and (2) routing the oil and natural gas sector where the gas to a flare. We know only of due to the natural gas losses avoided, compression of natural gas is required to anecdotal, undocumented information the annual costs are estimated to be move it along the pipeline. This is on routing of the gas back to a fuel around $23 per year, which is a cost of accomplished by compressors powered stream and, therefore, were unable to $13 per ton of VOC reduced for the by combustion turbines, reciprocating assess costs and cost effectiveness of the production segment. If the savings of the internal combustion engines or electric first option. Although we do not have salable natural gas that would have been motors. Turbine-powered compressors specific examples of routing emissions emitted is considered, there is a net use a small portion of the natural gas from wet seal degassing to a flare, we savings for this control. In the that they compress to fuel the turbine. were able to estimate the cost, emission transmission and storage segment, The turbine operates a centrifugal reductions and cost effectiveness of the where the VOC content of the vented compressor, which compresses the second option using uncontrolled wet gas is much lower than in the natural gas for transit through the seals as a baseline. production segment, the cost pipeline. Sometimes an electric motor is Based on the average uncontrolled effectiveness of a low-bleed pneumatic used to turn a centrifugal compressor. emissions of wet seal systems discussed device is estimated to be around $262 This type of compressor does not above and a flare efficiency of 95 per ton of VOC reduced. However, there require the use of any of the natural gas percent, we determined that VOC are no potential offsetting savings to be from the pipeline, but it does require a emission reductions from a wet seal realized in the transmission and storage substantial source of electricity. system would be an average of 19.5 tpy segment, since the operators of Reciprocating spark ignition engines are (production segment) or 3.3 tpy transmission and storage stations also used to power many compressors, (transmission and storage segment). typically do not own the gas they are referred to as reciprocating compressors, Using an annualized cost of flare handling. Based on our evaluation of the since they compress gas using pistons installation and operation of $103,373, emissions and costs, we believe that that are driven by the engine. Like we estimated the incremental cost low-bleed controllers represent BSER combustion turbines, these engines are effectiveness of this option (from for pneumatic controllers in the fueled by natural gas from the pipeline. uncontrolled wet seals to controlled wet production (other than processing Both centrifugal and reciprocating seals using a flare) to be approximately plants) and transmission and storage compressors are sources of VOC $5,300/ton and $31,000/ton for the segments. Therefore, for pneumatic emissions and were evaluated for production segment and transmission devices at these locations, we propose a coverage under the NSPS. and storage segment, respectively. With natural gas bleed rate limit of 6.0 scfh Centrifugal Compressors. Centrifugal this option, there would be secondary to reflect the VOC limit with the use of compressors require seals around the air impacts from combustion. However a low-bleed controller. rotating shaft to minimize gas leakage we did not identify any nonair quality and fugitive VOC emissions from where or energy impacts associated with this There may be situations where high- the shaft exits the compressor casing. control technique. bleed controllers and the attendant gas There are two types of seal systems: Wet Dry seal systems do not use any bleed rate greater than 6 cubic feet per seal systems and mechanical dry seal circulating seal oil. Dry seals operate hour, are necessary due to functional systems. mechanically under the opposing force requirements, such as positive actuation Wet seal systems use oil, which is created by hydrodynamic grooves and or rapid actuation. An example would circulated under high pressure between springs. Fugitive emissions occur from be controllers used on large emergency three or more rings around the dry seals around the compressor shaft. shutdown valves on pipelines entering compressor shaft, forming a barrier to Based on manufacturer studies and or exiting compression stations. For minimize compressed gas leakage. Very engineering design estimates, fugitive such situations, we have provided in the little gas escapes through the oil barrier, emissions from dry seal systems are proposed rule an exemption where but considerable gas is absorbed by the approximately 6 scfm of gas, depending pneumatic controllers meeting the oil. The amount of gas absorbed and on the operating pressure of the emission standards discussed above entrained by the oil barrier is affected by compressor. A dry seal system can have would pose a functional limitation due the operating pressure of the gas being fugitive emissions of, on average, to their actuation response time or other handled; higher operating pressures approximately 2.6 tpy of VOC operating characteristics. We are result in higher absorption of gas into (production segment) or about 0.4 tpy requesting comments on whether there the oil. Seal oil is purged of the (transmission and storage segment). We are other situations that should be absorbed and entrained gas (using did not identify any control device considered for this exemption. If you heaters, flash tanks and degassing suitable to capture and control the provide such comment, please specify techniques) and recirculated to the seal fugitive emissions from dry seals around the criteria for such situations that area for reuse. Gas that is purged from the compressor shaft.

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Using uncontrolled wet seals as a minute. This not only poses a likely dilute lubricating oil, causing premature baseline, we evaluated the reductions hazard that would destroy test failure of engine bearings, pose an and incremental cost effectiveness of equipment on contact, it poses a safety explosion hazard and eventually be dry seal systems. Based on the average hazard to personnel, as well. Therefore, vented from the crankcase breather, fugitive emissions, we determined that pursuant to section 111(h)(2) of the defeating the purpose of a control VOC emission reductions achieved by CAA, we are proposing an equipment device. dry seal systems compared to standard that would require the use of As mentioned above, as packing uncontrolled wet seal systems would be dry seals to limit the VOC emissions wears and deteriorates, leak rates can 18 tpy (production segment) and 3.1 tpy from new centrifugal compressors. We increase. We, therefore, evaluate (transmission and storage segment). consider that a centrifugal compressor, replacement of compressor rod packing Combined with an annualized cost of an apparatus, is an affected facility and systems as an option for reducing VOC dry seal systems of $10,678, the each installation is construction subject emissions. Conventional bronze- incremental cost effectiveness compared to the proposed NSPS. See definitions of metallic packing rings wear out and to uncontrolled wet seal systems would ‘‘affected facility’’ and ‘‘construction’’ at need to be replaced every 3 to 5 years, be $595/ton and $3,495/ton for the 40 CFR 60.2. Accordingly, the proposed depending on the compressor’s rate of production segment and transmission standard would apply to installation of usage (i.e., the percentage of time that a and storage segment, respectively. We new centrifugal compressors at new compressor is in pressurized mode). identified neither nonair quality nor any locations, as well as replacement of old Based on industry experience in the energy impacts associated with this compressors. Natural Gas STAR program and other option. Although we are proposing to sources, we evaluated the rod packing In performing our analysis, we determine dry seal systems to be BSER replacement costs for reciprocating estimated the incremental cost of a dry for centrifugal compressors, we are compressors at different segments of seal compressor over that of an soliciting comments on the emission this industry. Usage rates vary by equivalent wet seal compressor to be reduction potential, cost and any segment. Usage rates for compressors at $75,000. This value was obtained from limitations for the option of routing the wellheads, gathering/boosting stations, a vendor who represents a large share of gas back to a low pressure fuel stream processing plants, transmission stations the market for centrifugal compressors. to be combusted as fuel gas. In addition, and storage facilities are 100, 79, 90, 79 However, this number likely represents we solicit comments on whether there and 68 percent, respectively. a conservatively high value because wet are situations or applications where wet Reciprocating compressors at wellheads seal units have a significant amount of seal is the only option, because a dry are small and operate at lower ancillary equipment, namely the seal oil seal system is infeasible or otherwise pressures, which limit VOC emissions system and, thus, additional capital inappropriate. from these sources. Due to the low VOC expenses. Dry seal systems have some Reciprocating Compressors. emissions from these compressors, ancillary equipment (the seal gas Reciprocating compressors in the about 0.044 tpy, combined with an filtration system), but the costs are less natural gas industry leak natural gas annual cost of approximately $3,700, than the wet seal oil system. We were fugitive VOC during normal operation. the cost per ton of VOC reduction is not able to directly confirm this The highest volumes of gas loss and rather high. We estimated that the cost assumption with the vendor, however, a fugitive VOC emissions are associated effectiveness of controlling wellhead search of product literature showed that with piston rod packing systems. compressors is over $84,000 per ton of seal oil systems and seal gas filtration Packing systems are used to maintain a VOC reduced, which we believe to be systems are typically listed separate tight seal around the piston rod, too high and, therefore, not reasonable. from the basic compressor package. preventing the high pressure gas in the Because the cost effectiveness of Using available data on the cost of this compressor cylinder from leaking, while replacing packing wellhead compressor equipment, it is very likely that the cost allowing the rod to move freely. This rod systems is not reasonable, and of purchasing a dry seal compressor leakage rate is dependent on a variety of absent other emission reduction may actually be lower that a wet seal factors, including physical size of the measures, we did not find a BSER for compressor. We seek comment on compressor piston rod, operating speed reducing VOC emissions from reciprocal available cost data of a dry seal versus and operating pressure. Under the best compressors at wellheads. wet seal compressor, including all conditions, new packing systems For reciprocating compressors located ancillary equipment costs. properly installed on a smooth, well- at other oil and gas operations, we In light of the above analyses, we aligned shaft can be expected to leak a estimated that the cost effectiveness of propose to determine that dry seal minimum of 11.5 scfh. Higher leak rates controlling compressor VOC emissions systems are BSER for reducing VOC are a consequence of fit, alignment of by rod packing replacement would be emissions from centrifugal compressors. the packing parts and wear. $870 per ton of VOC for reciprocating We evaluated the possibility of setting a We evaluated the possibility of compressors at gathering and boosting performance standard that reflects the reducing VOC emissions from reciprocal stations, $270 per ton of VOC for emission limitation achievable through compressors through a control device. reciprocating compressors at processing the use of a dry seal system. However, However, VOC from reciprocating stations, $2,800 per ton of VOC for as mentioned above, VOC from compressors are fugitive emissions from reciprocating compressors at centrifugal compressors with dry seals around the compressor shafts. Although transmission stations and $3,700 per ton are fugitive emissions from around the it is possible to construct an enclosure of VOC for reciprocating compressors at compressor shafts. There is no device to around the rod packing area and vent underground storage facilities. We capture and control these fugitive the emissions outside for safety consider these costs to be reasonable. emissions, nor can reliable purposes, connection to a closed vent We did not identify any nonair quality measurement of these emissions be system and control device would create health or environmental impacts or conducted due to difficulty in accessing back pressure on the leaking gas. This energy impacts associated with rod the leakage area and danger of back pressure would cause the leaked packing replacement. In light of the contacting the shaft rotating at gas instead to be forced inside the above, we propose to determine that approximately 30,000 revolutions per crankcase of the engine, which would such control is the BSER for reducing

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VOC emission from compressors at d. NSPS for Storage Vessels depend on the amount of vapor these other oil and gas operations. Crude oil, condensate and produced produced by the storage vessels being Because VOC emitted from reciprocal water are typically stored in fixed-roof controlled. A VRU has a potential compressors are fugitive emissions, storage vessels. Some vessels used for advantage over flaring, in that it there is no device to capture and control storing produced water may be open-top recovers hydrocarbon vapors that the emissions. Therefore, pursuant to tanks. These vessels, which are operated potentially can be used as supplemental section 111(h) of the CAA, we are at or near atmospheric pressure burner fuel, or the vapors can be proposing an operational standard. conditions, are typically located as part condensed and collected as condensate Based on industry experience reported of a tank battery. A tank battery refers that can be sold. If natural gas is to the Natural Gas STAR program, we to the collection of process equipment recovered, it can be sold, as well, as determined that packing rods should be used to separate, treat and store crude long as a gathering line is available to replaced every 3 years of operation. oil, condensate, natural gas and convey the recovered salable gas However, to account for segments of the product to market or to further produced water. The extracted products industry in which reciprocating processing. A VRU also does not have from productions wells enter the tank compressors operate in pressurized secondary air impacts that flaring does, battery through the production header, mode a fraction of the calendar year as described below. However, a VRU which may collect product from many (ranging from approximately 68 percent cannot be used in all instances. Some up to approximately 90 percent), the wells. Emissions from storage vessels are a conditions that affect the feasibility of proposed rule expresses the result of working, breathing and flash VRU are: Availability of electrical replacement requirement in terms of service sufficient to power the VRU; losses. Working losses occur due to the hours of operation rather than on a fluctuations in vapor loading caused by emptying and filling of storage tanks. calendar year basis. One year of surges in throughput and flash Breathing losses are the release of gas continuous operation would be 8,760 emissions from the tank; potential for associated with daily temperature hours. Three years of continuous drawing air into condensate tanks fluctuations and other equilibrium operation would be 26,280 hours, or causing an explosion hazard; and lack of effects. Flash losses occur when a liquid rounded to the nearest thousand, 26,000 appropriate destination or use for the with dissolved gases is transferred from hours. Accordingly, the proposed rule vapor recovered. would require the replacement of the a vessel with higher pressure to a vessel Like a VRU, a flare control device can rod packing every 26,000 hours of with lower pressure, thus, allowing also achieve a control efficiency of 95 operation. The owner or operator would dissolved gases and a portion of the percent. There are no technical be required to monitor the hours of liquid to vaporize or flash. In the oil and limitations on the use of flares to control operation beginning with the natural gas production segment, flashing vapors from condensate and crude oil installation of the reciprocating losses occur when live crude oils or tanks. However, flaring has a secondary condensates flow into a storage tank compressor affected facility. Cumulative impact from emissions of NOX and other hours of operation would be reported from a processing vessel operated at a pollutants. In light of the technical each year in the facility’s annual report. higher pressure. Typically, the larger the limitations with the use of a VRU, we Once the hours of operation reached pressure drop, the more flash emissions are unable to conclude that a VRU is 26,000 hours, the owner or operator will occur in the storage stage. better than flaring. We, therefore, would be required to change the rod Temperature of the liquid also propose to determine that both a VRU packing immediately, although influences the amount of flash and flare are BSER for reducing VOC unexpected shutdowns could be emissions. The amount of liquid emission from storage vessels. We avoided by tracking hours of operation entering the tank during a given time, propose an NSPS of 95-percent and planning for packing replacement at commonly known as throughput, also reduction for storage vessels to reflect scheduled maintenance shutdowns affects the emission rate, with higher the level of emission reduction before the hours of operation reached throughput tanks having higher annual achievable by VRU and flares. 26,000. emissions, given that other parameters VOC emissions from storage vessels Some industry partners of the Natural are the same. vary significantly, depending on the rate Gas STAR program currently conduct In analyzing controls for storage of liquid entering and passing through periodic testing to determine the leakage vessels, we reviewed control techniques the vessel (i.e., its throughput), the rates that would identify economically identified in the Natural Gas STAR pressure of the liquid as it enters the beneficial replacement of rod packing program and state regulations. We atmospheric pressure storage vessel, the based on natural gas savings. Therefore, identified two ways of controlling liquid’s volatility and temperature of the we are soliciting comments on storage vessel emissions, both of which liquid. Some storage vessels have incorporating a method similar to that can reduce VOC emissions by 95 negligible emissions, such as those with in the Natural Gas STAR’s Lessons percent. One option would be to install very little throughput and/or handling Learned document entitled, Reducing a vapor recovery unit (VRU) and recover heavy liquids entering at atmospheric Methane Emissions from Compressor all the vapors from the tanks. The other pressure. We do not believe that it is Rod Packing Systems (http:// option would be to route the emissions cost effective to control these vessels. www.epa.gov/gasstar/documents/ from the tanks to a flare control device. We believe it is important to control ll_rodpack.pdf), to be incorporated in These devices could be ‘‘candlestick’’ tanks with significant VOC emissions the NSPS. We are soliciting comments flares that are found at gas processing under the proposed NSPS. on how to determine a suitable leak plants or other larger facilities or In our analysis, we evaluated storage threshold above which rod packing enclosed combustors which are tanks with varying condensate or crude replacement would be cost effective for commonly found at smaller field oil throughput. We used emission VOC emission reduction. We are also facilities. We estimated the total annual factors developed for the Texas soliciting comment on the appropriate cost for a VRU to be approximately Environmental Research Consortium in replacement frequency and other $18,900/yr and for a flare to be a study that evaluated VOC emissions considerations that would be associated approximately $8,900/yr. Cost from crude oil and condensate storage with regular replacement periods. effectiveness of these control options tanks by performing direct

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measurements. The study found that the shown that working losses (i.e., those and compressors are potential sources average VOC emission factor for crude emissions absent flash emission that can leak due to seal failure. Other oil storage tanks was 1.6 pounds (lb) conditions) are very low, approaching sources, such as open-ended lines and VOC per barrel of crude oil throughput. zero. During times of flash emissions, sampling connections may leak for The average VOC emission factor for tanks are designed such that the flash reasons other than faulty seals. In condensate tanks was determined to be emissions are released through a vent on addition, corrosion of welded 33.3 lb VOC per barrel of condensate the fixed roof of the tank when pressure connections, flanges, and valves may throughput. Applying these emission reaches just a few ounces to prevent also be a cause of equipment leak factors and evaluating condensate pressure buildup and resulting tank emissions. Because of the large number throughput rates of 0.5, 1, 2 and 5 damage. At those times, vapor readily of valves, pumps and other components barrels per day (bpd), we determined escapes through the vent to protect the within an oil and gas production, that VOC emissions at these condensate tank. Tests have shown that open processing and transmission facility, throughput rates would be hatches or leaking hatch gaskets have equipment leak volatile emissions from approximately 3, 6, 12 and 30 tpy, little effect on emissions from these components can be significant. respectively. Similarly, we evaluated uncontrolled tanks due to the Natural gas processing plants, especially crude oil throughput rates of 1, 5, 20 functioning roof vent. However, in the those using refrigerated absorption and and 50 bpd. Based on the Texas study, case of controlled tanks, the control transmission stations tend to have a these crude oil throughput rates would requirements include provisions for large number of components. result in VOC emissions of 0.3, 1.5, 5.8 maintaining integrity of the closed vent Equipment leaks from processing plants and 14.6 tpy, respectively. We believe system that conveys emissions to the are addressed in our review of 40 CFR that it is important to control tanks with control device, including hatches and part 60, subpart KKK, which is significant VOC emissions. other tank openings. As a result, hatches discussed above in section VI.B.1. Furthermore, we believe it would be are required to be kept closed and In addition to gas processing plants, easier and less costly for owners and gaskets kept in good repair to meet these types of equipment also exist at oil operators to determine applicability by control requirements of controlled and gas production sites and gas using a throughput threshold instead of storage vessels. Because the measures transmission and storage facilities. an emissions threshold. As a result of we evaluated, including maintenance of While the number of components at the above analyses, we believe that hatch integrity, do not provide individual transmission and storage storage vessels with at least 1 bpd of appreciable emission reductions for facilities is relatively smaller than at condensate or 20 bpd of crude oil storage vessels with throughputs under processing plants, collectively, there are should be controlled. These throughput 1 barrel of condensate per day and 21 many components that can result in rates are equivalent to VOC emissions of barrels of crude oil per day, we believe significant emissions. approximately 6 tpy. Based on an that the control options we evaluated do Therefore, we evaluated applying estimated annual cost of $18,900 for the not reflect BSER for the small NSPS for equipment leaks to facilities in control device, controlling storage throughput tanks and we are not the production segment of the industry, vessels with these condensate or crude proposing standards for these tanks. which includes everything from the oil throughputs would result in a cost As discussed in section VII of this wellhead to the point that the gas enters effectiveness of $3,150 per ton of VOC preamble, we are proposing to amend the processing plant, transmission reduced. the NESHAP for oil and natural gas pipeline or distribution pipeline. Based on our evaluation, we propose production facilities at 40 CFR part 63, Production facilities can vary to determine that both a VRU and flare subpart HH to require that all storage significantly in the operations are BSER for reducing VOC emission vessels at production facilities reduce performed and the processes, all of from storage vessels with throughput of HAP emissions by 95 percent. Because which impact the number of at least 1 barrel of condensate per day the controls used to achieve the 95- components and potential emissions or 20 barrels of crude oil per day. We percent HAP reduction are the same as from leaking equipment and, thus, propose an NSPS of 95-percent the proposed BSER for VOC reduction impact the annual costs related to reduction for these storage vessels to for storage vessels (i.e., VRU and flare), implementing a LDAR program. We reflect the level of emission reduction sources that are achieving the 95- used data collected by the Gas Research achievable by VRU and flare control percent HAP reduction would also be Institute to develop model production devices. meeting the proposed NSPS of 95- facilities. Baseline emissions, along with For storage vessels below the percent VOC reduction. In light of the emission reductions and costs of throughput levels described above above, and to avoid duplicate regulatory alternatives, were estimated (‘‘small throughput tanks’’), for which monitoring, recordkeeping and using these model production facilities. we do not consider flares or VRU to be reporting, we propose that storage We considered production facilities cost effective controls, we evaluated vessels subject to the requirements of where separation, storage, compression other measures to reduce VOC subpart HH are exempt from the and other processes occur. These emissions. Standard practices for such proposed NSPS for storage vessel in 40 facilities may not have a wellhead on- tanks include requiring a cover that is CFR part 60, subpart OOOO. site, but would be associated with a well designed, maintained in good wellhead. We also evaluated gathering condition and kept closed. Crude oil e. NSPS for VOC Equipment Leaks and boosting facilities, where gas and/ and condensate storage tanks in the oil Equipment leaks are fugitive or oil are collected from a number of and natural gas sector are designed to emissions emanating from valves, pump wells, then processed and transported operate at or just slightly above or below seals, flanges, compressor seals, downstream to processing plants or atmospheric pressure. Accordingly, they pressure relief valves, open-ended lines transmission stations. We evaluated the are provided with vents to prevent tank and other process and operation impacts at these production facilities destruction under rapid pressure components. There are several potential with varying number of operations and increases due to flash emissions reasons for equipment leak emissions. equipment. We also developed a model conditions. Studies by the Natural Gas Components such as pumps, valves, plant for the transmission and storage STAR program and by others have pressure relief valves, flanges, agitators segment using data from the Gas

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Research Institute. Details of these production sites associated with a 21 check (Option 2). As discussed in evaluations may be found in the TSD in wellhead.12 The cost-effectiveness for secton VI.B.1, we had previously the docket. valves was calculated to be $17,828 per determined that the VOC reductions For an average production site at or ton of VOC by reducing the monitoring achieved under this option would be the associated with a wellhead, we frequency from monthly to annually. same as for option 1 subpart VVa-level estimated annual VOC emissions from The cost-effectiveness for connectors LDAR. In our evaluation of Option 2, we equipment leaks of around 2.6 tpy. For was calculated to be $87,277 per ton of estimated that a single optical imaging an average gathering/boosting facility, VOC by reducing the monitoring instrument could be used for 160 well we estimated the annual VOC emissions frequency from every 4 years to every 8 sites and 13 gathering and boosting from equipment leaks to be around 9.8 years after the initial compliance period. stations, which means that the cost of tpy. The average transmission and We performed a similar facility-wide the purchase or rental of the camera storage facility emits 2.7 tpy of VOC. and component-specific analysis of would be spread across 173 facilities. For facilities in each non-gas option 1 LDAR for gathering and For production sites, gathering and processing plant segment, we evaluated boosting stations. For the subpart VVa boosting stations, and transmission and the same four options as we did for gas level of control at the average gathering storage facilities, we estimated that processing plants in section VI.B.1 and boosting station, facility-wide cost- option 2 monthly optical gas imaging above. These four options are as follows: effectiveness was estimated to be $9,344 with annual Method 21 check would (1) 40 CFR part 60, subpart VVa-level per ton of VOC. Component-specific have cost-effectiveness of $16,123, LDAR (which is based on conducting cost-effectiveness ranged from $6,079 $10,095, and $19,715 per ton of VOC, Method 21 monthly, defining ‘‘leak’’ at per ton of VOC (for valves) to $77,310 respectively.13 500 ppm threshold, and adding per ton of VOC (for open-ended lines), The annual costs for option 1 and connectors to the VV list of components with connectors and pressure relief option 2 leak detection and repair to be monitored); (2) monthly optical devices being $23,603 and $72,523 per programs for production sites associated gas imaging with annual Method 21 ton, respectively. For the modified with a wellhead, gathering and boosting check (the alternative work practice for subpart VVa level of control at gathering stations and transmission and storage monitoring equipment for leaks at 40 and boosting stations, cost-effectiveness facilities were higher than those CFR 60.18(g)); (3) monthly optical gas ranged from $5,221 per ton of VOC (for estimated for natural gas processing imaging alone; and (4) annual optical valves) to $77,310 per ton of VOC (for plants because natural gas processing gas imaging alone. open-ended lines), with connectors and plant annual costs are based on the For option 1, we evaluated subpart pressure relief devices being $27,274 incremental cost of implementing VVa-LDAR as a whole. We also and $72,523 per ton, respectively. The subpart VVa-level standards, whereas analyzed separately the individual types modified subpart VVa level controls the other facilities are not currently of components (valves, connectors, were more cost-effective than the regulated under an LDAR program. The pressure relief devices and open-ended subpart VVa level controls for valves, currently unregulated sites would be lines). Detailed discussions of these but not for connectors. This is due to the required to set up a new LDAR program; component by component analyses are low cost of monitoring connectors and perform initial monitoring, tagging, included in the TSD in the docket. the low VOC emissions from leaking Based on our evaluation, subpart VVa- logging and repairing of components; as connectors. well as planning and training personnel level LDAR (Option 1) results in more We also performed a similar analysis VOC reduction than the subpart VV- to implement the new LDAR program. of option 1 subpart VVa-level LDAR for In addition to options 1 and 2, we level LDAR currently required for gas gas transmission and storage facilities. processing plants, because more leaks evaluated a third option that consisted For the subpart VVa level of control at of monthly optical gas imaging without are found based on the lower definition the average transmission and storage of ‘‘leak’’ under subpart VVa (10,000 an annual Method 21 check. Because we facility, facility-wide cost-effectiveness were unable to estimate the VOC ppm for subpart VV and 500 ppm for was $20,215. Component-specific cost- emissions achieved by an optical subpart VVa). In addition, our effectiveness ranged from $24,762 per imaging program alone, we were unable evaluation shows that the cost per ton ton of VOC (for open-ended lines) to to estimate the cost-effectiveness of this of VOC reduced for subpart VVa level $243,525 per ton of VOC (for pressure option. However, we estimated the controls is less than the cost per ton of relief devices), with connectors and annual cost of the monthly optical gas VOC reduced for the less stringent valves being $36,527 and $43,111 per imaging LDAR program at production subpart VV level of control. Although ton of VOC, respectively. For the sites, gathering and boosting stations, the cost of repairing more leaks is modified subpart VVa level of control at and transmission and storage facilities higher, the increased VOC control transmission and storage facilities, cost- to be $37,049, $86,135, and $45,080, afforded by subpart VVa level controls effectiveness ranged from $24,762 per more than offsets the increased costs. ton of VOC (for open-ended lines) to respectively, based on camera purchase, For the subpart VVa level of control $243,525 per ton of VOC (for pressure or $32,693, $81,780, and $40,629, at the average production site associated relief devices), with connectors and respectively, based on camera rental. with a wellhead, average facility-wide valves being $42,140 and $40,593 per Finally, we evaluated a fourth option cost-effectiveness would be $16,084 per ton of VOC, respectively. Again, the similar to the third option except that ton of VOC. Component-specific cost- modified subpart VVa level controls the optical gas imaging would be effectiveness ranged from $15,063 per were more cost-effective for valves and performed annually rather than ton of VOC (for valves) to $211,992 per less cost effective for connectors than monthly. For this option, we estimated ton of VOC (for pressure relief devices), the subpart VVa level controls. This is the annual cost for production sites, with connectors and open-ended lines due to the low cost of monitoring gathering and boosting stations, and being $74,283 and $180,537 per ton of connectors and the low VOC emissions transmission and storage facilities to be VOC, respectively. We also looked at from leaking connectors. 13 Because optical gas imaging is used to view component costs for a modified subpart For each of the non-gas processing several pieces of equipment at a facility at once to VVa level of control with less frequent segments, we also evaluated monthly survey for leaks, options involving imaging are not monitoring for valves and connectors at optical gas imaging with annual Method amenable to a component by component analysis.

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$30,740, $64,416, and $24,031, should not be viewed as a distinct determine an appropriate response respectively, based on camera purchase, operating mode and, therefore, any based on, among other things, the good or $26,341, $60,017, and $19,493, emissions that occur at such times do faith efforts of the source to minimize respectively, based on camera rental. not need to be factored into emissions during malfunction periods, We request comment on the development of CAA section 111 including preventative and corrective applicability of a leak detection and standards. Further, nothing in CAA actions, as well as root cause analyses repair program based solely on the use section 111 or in case law requires that to ascertain and rectify excess of optical imaging or other technologies. the EPA anticipate and account for the emissions. The EPA would also Of most use to us would be information innumerable types of potential consider whether the source’s failure to on the effectiveness of advanced malfunction events in setting emission comply with the CAA section 111 measurement technologies to detect and standards. See, Weyerhaeuser v Costle, standard was, in fact, ‘‘sudden, repair small leaks on the same order or 590 F.2d 1011, 1058 (D.C. Cir. 1978) infrequent, not reasonably preventable’’ smaller as specified in the VVa (‘‘In the nature of things, no general and was not instead ‘‘caused in part by equipment leak requirements and the limit, individual permit, or even any poor maintenance or careless effects of increased frequency of and upset provision can anticipate all upset operation.’’ 40 CFR 60.2 (definition of associated leak detection, recording, and situations. After a certain point, the malfunction). repair practices. transgression of regulatory limits caused Finally, the EPA recognizes that even Based on the evaluation described by ‘uncontrollable acts of third parties,’ equipment that is properly designed and above, we believe that neither option 1 such as strikes, sabotage, operator maintained can sometimes fail. Such nor option 2 is cost effective for intoxication or insanity, and a variety of failure can sometimes cause an reducing fugitive VOC emissions from other eventualities, must be a matter for exceedance of the relevant emission equipment leaks at sites, gathering and the administrative exercise of case-by- standard (See, e.g., State boosting stations, and transmission and case enforcement discretion, not for storage facilities. For options 3 and 4, Implementation Plans: Policy Regarding specification in advance by Excessive Emissions During we were unable to estimate their cost regulation.’’), and, therefore, any effectiveness and, therefore, could not Malfunctions, Startup, and Shutdown emissions that occur at such times do (September 20, 1999); Policy on Excess identify either of these two options as not need to be factored into Emissions During Startup, Shutdown, BSER for addressing equipment leak of development of CAA section 111 Maintenance, and Malfunctions VOC at production facilities associated standards. with wellheads, at gathering and Further, it is reasonable to interpret (February 15, 1983)). The EPA is, boosting stations or at gas transmission CAA section 111 as not requiring the therefore, proposing to add an and storage facilities. We are, therefore, EPA to account for malfunctions in affirmative defense to civil penalties for not proposing NSPS for addressing VOC setting emissions standards. For exceedances of emission limits that are emissions from equipment leaks at these example, we note that CAA section 111 caused by malfunctions. See 40 CFR facilities. provides that the EPA set standards of 60.41Da (defining ‘‘affirmative defense’’ performance which reflect the degree of to mean, in the context of an 5. What are the SSM provisions? emission limitation achievable through enforcement proceeding, a response or The EPA is proposing standards in ‘‘the application of the best system of defense put forward by a defendant, this rule that apply at all times, emission reduction’’ that the EPA regarding which the defendant has the including during periods of startup or determines is adequately demonstrated. burden of proof and the merits of which shutdown, and periods of malfunction. Applying the concept of ‘‘the are independently and objectively In proposing the standards in this rule, application of the best system of evaluated in a judicial or administrative the EPA has taken into account startup emission reduction’’ to periods during proceeding). We also are proposing and shutdown periods. which a source is malfunctioning other regulatory provisions to specify The General Provisions in 40 CFR part presents difficulties. The ‘‘application of the elements that are necessary to 60 require facilities to keep records of the best system of emission reduction’’ establish this affirmative defense; the the occurrence and duration of any is more appropriately understood to source must prove by a preponderance startup, shutdown or malfunction (40 include operating units in such a way as of the evidence that it has met all of the CFR 60.7(b)) and either report to the to avoid malfunctions. elements set forth in 40 CFR 60.46Da. EPA any period of excess emissions that Moreover, even if malfunctions were (See 40 CFR 22.24). These criteria occurs during periods of SSM (40 CFR considered a distinct operating mode, ensure that the affirmative defense is 60.7(c)(2)) or report that no excess we believe it would be impracticable to available only where the event that emissions occurred (40 CFR 60.7(c)(4)). take malfunctions into account in causes an exceedance of the emission Thus, any comments that contend that setting CAA section 111 standards for limit meets the narrow definition of sources cannot meet the proposed affected facilities under 40 CFR part 60, malfunction in 40 CFR 60.2 (sudden, standard during startup and shutdown subpart OOOO. As noted above, by infrequent, not reasonably preventable periods should provide data and other definition, malfunctions are sudden and and not caused by poor maintenance specifics supporting their claim. unexpected events and it would be and or careless operation). For example, Periods of startup, normal operations difficult to set a standard that takes into to successfully assert the affirmative and shutdown are all predictable and account the myriad different types of defense, the source must prove by a routine aspects of a source’s operations. malfunctions that can occur across all preponderance of the evidence that However, by contrast, malfunction is sources in the category. Moreover, excess emissions ‘‘[w]ere caused by a defined as a ‘‘sudden, infrequent, and malfunctions can vary in frequency, sudden, infrequent, and unavoidable not reasonably preventable failure of air degree and duration, further failure of air pollution control and pollution control and monitoring complicating standard setting. monitoring equipment, process equipment, process equipment or a In the event that a source fails to equipment, or a process to operate in a process to operate in a normal or usual comply with the applicable CAA section normal or usual manner * * *’’ The manner * * *’’ (40 CFR 60.2.) The EPA 111 standards as a result of a criteria also are designed to ensure that has determined that malfunctions malfunction event, the EPA would steps are taken to correct the

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malfunction, to minimize emissions in To concentrate on only records The data in the ECHO database are accordance with 40 CFR 60.40Da and to pertaining to the oil and natural gas updated monthly. prevent future malfunctions. For industry sector, data were extracted We performed a query on the ECHO example, the source would have to using two criteria. First, we specified database requesting records for major prove by a preponderance of the that all facilities containing codes sources, with NAICS codes 211*, evidence that ‘‘[r]epairs were made as identifying the Oil and Natural Gas 221210, 4861* and 4862*, with expeditiously as possible when the Production and the Natural Gas information for MACT. The ECHO applicable emission limitations were Transmission and Storage MACT source database query identified records for a being exceeded * * *’’ and that ‘‘[a]ll categories (MACT codes 0501 and 0504, total of 555 facilities, 269 in the Oil and possible steps were taken to minimize respectively). Second, we extracted Natural Gas Production source category the impact of the excess emissions on facilities identified with the following (NAICS 211* and 221210) and 286 in ambient air quality, the environment NAICS codes: 211 * * * (Oil and Gas the Natural Gas Transmission and and human health * * *’’ In any Extraction), 221210 (Natural Gas Storage source category (NAICS 4861* judicial or administrative proceeding, Distribution), 4861 * * * (Pipeline and 4862*). This comparison leads us to the Administrator may challenge the Transportation of Crude Oil), and 4862 conclude that, for the Natural Gas assertion of the affirmative defense and, * * * (Pipeline Transportation of Transmission and Storage segment, the if the respondent has not met the Natural Gas). Once the data were NEI database is representative of the burden of proving all of the extracted, we reviewed the Source number of sources subject to the rule. requirements in the affirmative defense, Classification Codes (SCC) to assess For the Oil and Natural Gas Production appropriate penalties may be assessed whether there were any records source category, it confirms our in accordance with CAA section 113 included in the dataset that were clearly assumption that the NEI dataset (see also 40 CFR part 22.77). not a part of the oil and natural gas contains more facilities than are subject sector. Our review of the SCC also to the rule. However, this provides a VII. Rationale for Proposed Action for included assigning each SCC to an conservative overestimate of the number NESHAP ‘‘Emission Process Group’’ that of sources, which we believe is A. What data were used for the NESHAP represents emission point types within appropriate for our risk analyses. analyses? the oil and natural gas sector. We are requesting that the public provide a detailed review of the Since these MACT standards only To perform the technology review and information in this dataset and provide apply to major sources, only facilities residual risk analysis for the two comments and updated information designated as major sources in the NEI NESHAP, we created a comprehensive where appropriate. Section X of this were extracted. In the NEI, sources are dataset (i.e., the MACT dataset). This preamble provides an explanation of identified as major if the facility-wide dataset was based on the EPA’s 2005 how to provide updated information for emissions are greater than 10 tpy for any National Emissions Inventory (NEI). The these datasets. NEI database contains information about single HAP or 25 tpy for any sources that emit criteria air pollutants combination of HAP. We believe that B. What are the proposed decisions and their precursors and HAP. The this may overestimate the number of regarding certain unregulated emissions database includes estimates of annual major sources in the oil and natural gas sources? air pollutant emissions from point, sector because it does not take into In addition to actions relative to the nonpoint and mobile sources in the 50 account the limitations set forth in the technology review and risk reviews states, the District of Columbia, Puerto CAA regarding aggregation of emissions discussed below, we are proposing, Rico and the Virgin Islands. The EPA from wells and associated equipment in pursuant to CAA sections 112(d)(2) and collects information about sources and determining major source status. (3), MACT standards for glycol releases an updated version of the NEI The final dataset contained a total of dehydrators and storage vessels for database every 3 years. 1,311 major sources in the oil and which standards were not previously The NEI database is compiled from natural gas sector; 990 in Oil and developed. We are also proposing these primary sources: Natural Gas Production, and 321 in changes that affect the definition of • Natural Gas Transmission and Storage. ‘‘associated equipment’’ which could Emissions inventories compiled by To assess how representative this state and local environmental apply these MACT standards to number of facilities was, we obtained previously unregulated sources. agencies information on the number of subject • Databases related to the EPA’s MACT facilities for both MACT standards from 1. Glycol Dehydrators programs the Enforcement and Compliance Once natural gas has been separated • Toxics Release Inventory data History Online (ECHO) database. The from any liquid materials or products • For electric generating units, the ECHO database is a web-based tool (e.g., crude oil, condensate or produced EPA’s Emission Tracking System/ (http://www.epa-echo.gov/echo/ water), residual entrained water is CEM data and United States index.html) that provides public access removed from the natural gas by Department of Energy (DOE) fuel use to compliance and enforcement dehydration. Dehydration is necessary data information for approximately 800,000 because water vapor may form hydrates, • For onroad sources, the United States EPA-regulated facilities. The ECHO which are ice-like structures, and can Federal Highway Administration’s database allows users to find permit, cause corrosion in or plug equipment estimate of vehicle miles traveled and inspection, violation, enforcement lines. The most widely used natural gas emission factors from the EPA’s action and penalty information covering dehydration processes are glycol MOBILE computer model the past 3 years. The site includes dehydration and solid desiccant • For nonroad sources, the EPA’s facilities regulated as CAA stationary dehydration. Solid desiccant NONROAD computer model sources, as well as Clean Water Act dehydration, which is typically only • Emissions inventories from previous direct dischargers, and Resource used for lower throughputs, uses years, if states do not submit current Conservation and Recovery Act adsorption to remove water and is not data hazardous waste generators/handlers. a source of HAP emissions.

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Glycol dehydration is an absorption average benzene emissions greater than sources, we created an emission factor process in which a liquid absorbent, or equal to 0.90 Mg/yr (40 CFR in terms of grams BTEX/scm-ppmv for glycol, directly contacts the natural gas 63.765(a)). The EPA did not establish each facility. The emission factor stream and absorbs any entrained water standards for the other subcategory, reflects the facility’s emission level, vapor in a contact tower or absorption which consists of glycol dehydration taking into consideration its natural gas column. The majority of glycol units that are below the flowrate and throughput and inlet natural gas BTEX dehydration units use triethylene glycol emission thresholds specified in subpart concentration. To determine the MACT as the absorbent, but ethylene glycol HH. Similarly, under 40 CFR part 63, floor for the existing dehydrators, we and diethylene glycol are also used. The subpart HHH (the Natural Gas ranked each unit from lowest to highest, rich glycol, which has absorbed water Transmission and Storage NESHAP), the based on their emission factor, to vapor from the natural gas stream, EPA established MACT standards for determine the facilities in the top 12 leaves the bottom of the absorption the subcategory of glycol dehydration percent of the dataset. The MACT floor column and is directed either to (1) a units with an actual annual average was an emission factor of 1.10 × 10¥4 gas condensate glycol (GCG) separator natural gas flowrate greater than or grams BTEX/scm-ppmv. To meet this (flash tank) and then a reboiler or (2) equal to 283,000 scmd and actual level of emissions, we anticipate that directly to a reboiler where the water is average benzene emissions greater than sources will use a variety of options, boiled off of the rich glycol. The or equal to 0.90 Mg/yr, but did not including, but not limited to, routing regenerated glycol (lean glycol) is establish standards for the other emissions to a condenser or to a circulated, by pump, into the absorption subcategory, which consists of glycol combustion device. tower. The vapor generated in the dehydration units that are below the We also considered beyond-the-floor reboiler is directed to the reboiler vent. flowrate and emission thresholds options for the existing sources, as The reboiler vent is a source of HAP specified in subpart HHH. As required by section 112(d)(2) of the emissions. In the glycol contact tower, mentioned above, we refer to these CAA. To achieve further reductions glycol not only absorbs water, but also unregulated dehydration units in both beyond the MACT floor level of control, absorbs selected hydrocarbons, subparts HH and HHH as ‘‘small sources would have to install an including BTEX and n-hexane. The dehydrators’’ in this proposed rule. additional add-on control device, most hydrocarbons are boiled off along with The EPA is proposing emission likely a combustion device. Assuming the water in the reboiler and vented to standards for these subcategories of the MACT floor control device is a the atmosphere or to a control device. small dehydrators (i.e., those combustion device, which generally The most commonly used control dehydrators with an actual annual achieves at least a 95-percent HAP device is a condenser. Condensers not average natural gas flowrate less than reduction, then less than 5 percent of only reduce emissions, but also recover 85,000 scmd at production sites or the initial HAP emissions remain. condensable hydrocarbon vapors that 283,000 scmd at natural gas Installing a second device would can be recovered and sold. In addition, transmission and storage sites, or actual involve the same costs as the first the dry non-condensable off-gas from average benzene emissions less than 0.9 control, but would only achieve 1⁄20 of the condenser may be used as fuel or Mg/yr). Because we do not have any the reduction (i.e., reducing the recycled into the production process or new emissions data concerning these remaining 5 percent by another 95 directed to a flare, incinerator or other emission points, we evaluated the percent represents a 4.49-percent combustion device. dataset collected from industry during reduction of the initial, uncontrolled If present, the GCG separator (flash the development of the original MACT emissions, which is 1⁄20 of the 95- tank) is also a potential source of HAP standards (legacy docket A–94–04, item percent reduction achieved with the emissions. Some glycol dehydration II–B–01, disk 1 for oil and natural gas first control). Based on the $8,360/Mg units use flash tanks prior to the reboiler production facilities; and items IV–G– cost effectiveness of the floor level of to separate entrained gases, primarily 24, 26, 27, 30 and 31 for natural gas control, we estimate that the methane and ethane from the glycol. transmission and storage facilities). We incremental cost effectiveness of the The flash tank off-gases are typically believe this dataset is representative of second control to be $167,200/Mg. We recovered as fuel or recycled to the currently operating glycol dehydrators do not believe this cost to be reasonable natural gas production header. because it contains information for a given the level of emission reduction. However, the flash tank may also be varied group of sources (i.e., units We are, therefore, proposing an vented directly to the atmosphere. Flash owned by different companies, located emission standard for existing small tanks typically enhance the reboiler in different states, representing a range dehydrators that reflects the MACT condenser’s emission reduction of gas compositions and emission floor. efficiency by reducing the concentration controls) and that the processes have For new small glycol dehydrators in of non-condensable gases present in the not changed significantly since the data the Oil and Natural Gas Production stream prior to being introduced into were collected. source category, based on our the condenser. In the Oil and Natural Gas Production performance ranking, the best In the development of the MACT source category, there were 91 glycol performing source has an emission standards for the two oil and natural gas dehydration units with throughput and factor of 4.66 × 10¥6 grams BTEX/scm- source categories, the EPA created two emissions data identified that would be ppmv. To meet this level of emissions, subcategories of glycol dehydrators classified as small glycol dehydration we anticipate that sources will use a based on actual annual average natural units. We evaluated the possibility of variety of options, including, but not gas flowrate and actual average benzene establishing a MACT floor as a Mg/yr limited to, routing emissions to a emissions. Under 40 CFR part 63, limit. However, due to variability of gas condenser or to a combustion device. subpart HH, (the Oil and Natural Gas throughput and inlet gas composition, The consideration of beyond-the-floor Production NESHAP), the EPA we could not properly identify the best options for new small dehydrators established MACT standards for glycol performing units by only considering would be the same as for existing small dehydration units with an actual annual emissions. To allow us to normalize the dehydrators, and, as stated above, we do average natural gas flowrate greater than emissions for a more accurate not believe a cost of $167,200/Mg to be or equal to 85,000 scmd and actual determination of the best performing reasonable given the level of emission

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reduction. We are, therefore, proposing ppmv. To meet this level of emissions, with entrained gases is transferred from a MACT standard for new small we anticipate that sources will use a a vessel with higher pressure to a vessel dehydrators that reflects the MACT floor variety of options, including, but not with lower pressure, thus, allowing level of control. limited to, routing emissions to a entrained gases or a portion of the liquid Under our proposal, a small condenser or to a combustion device. to vaporize or flash. In the oil and dehydrator’s actual MACT emission The consideration of beyond-the-floor natural gas production segment, flashing limit would be determined by options for new small dehydrators losses occur when live crude oils or multiplying the MACT floor emission would be the same as for existing small condensates flow into a storage tank factor in g BTEX/scm-ppmv by its unit- dehydrators, and, as stated above, we do from a processing vessel operated at a specific incoming natural gas not believe a cost of $33,000/Mg to be higher pressure. Typically, the larger the throughput and BTEX concentration for reasonable given the level of emission pressure drop, the more flashing the dehydrator. A formula is provided reduction. We are, therefore, proposing emission will occur in the storage stage. in 40 CFR 63.765(b)(1)(iii) to calculate an emission standard for new sources Temperature of the liquid may also the MACT limit as an annual value. that reflects the MACT floor level of influence the amount of flash emissions. In the Natural Gas Transmission and control. In the Oil and Natural Gas Production Storage source category, there were 16 Under our proposal, a source’s actual NESHAP (40 CFR part 63, subpart HH), facilities for which throughput and MACT emissions limit would be the MACT standards for storage vessels emissions data were available that determined by multiplying this apply only to those with the PFE. would be classified as small glycol emission factor by their unit-specific Storage vessels with the PFE are defined dehydration units. Since the number of incoming natural gas throughput and as storage vessels that contain units was less than 30, the MACT floor BTEX concentration for the dehydrator. hydrocarbon liquids that meet the for existing sources was based on the A formula is provided in 40 CFR following criteria: top five performing units. Using the 63.1275(b)(1)(iii) to calculate the limit • A stock tank gas to oil ratio (GOR) same emission factor concept, we as an annual value. greater than or equal to 0.31 cubic determined that the MACT floor for As discussed below, we are proposing meters per liter (m3/liter); and existing sources is an emission factor that, with the removal of the 1-ton • An American Petroleum Institute ¥ equal to 6.42 × 10 5 grams BTEX/scm- alternative compliance option from the (API) gravity greater than or equal to 40 ppmv. To meet this level of emissions, existing standards for glycol degrees; and we anticipate that sources will use a dehydrators, the MACT for these two • An actual annual average variety of options, including, but not source categories would provide an hydrocarbon liquid throughput greater limited to, routing emissions to a ample margin of safety to protect public than or equal to 79,500 liters per day condenser or to a combustion device. health. We, therefore, maintain that, (liter/day). We also considered beyond-the-floor after the implementation of the small Accordingly, there is no emission options for the existing small dehydrator standards discussed above, limit in the existing MACT for storage dehydrators as required by section these MACT will continue to provide an vessels without the PFE. However, the 112(d)(2) of the CAA. To achieve further ample margin of safety to protect public MACT analysis performed at the time reductions beyond the MACT floor level health. Consequently, we do not believe indicates that the MACT floor was based of control, sources would have to install it will be necessary to conduct another on all storage vessels, not just those an additional add-on control device, residual risk review under CAA section vessels with flash emissions. See, most likely a combustion device. 112(f) for these two source categories 8 Recommendation of MACT Floor Levels Assuming the MACT floor control years following promulgation of the for HAP Emission Points at Major device is a combustion device, which small dehydrator standards merely due Sources in the Oil and Natural Gas generally achieves at least a 95-percent to the addition of these new MACT Production Source Category, (September HAP reduction, then less than 5 percent requirements. 23, 1997, Docket A–94–04, Item II–A– of the initial HAP emissions remain. 2. Storage Vessels 07). We, therefore, propose to apply the Installing a second device would existing MACT for storage vessels with involve the same costs as the first Crude oil, condensate and produced PFE to all storage vessels (i.e., storage control device, but would only achieve water are typically stored in fixed-roof vessels with the PFE, as well as those 1 ⁄20 of the reduction (i.e., reducing the storage vessels. Some vessels used for without the PFE). remaining 5 percent by another 95 storing produced water may be open-top percent represents a 4.49-percent tanks. These vessels, which are operated 3. Definition of Associated Equipment reduction of the initial, uncontrolled at or near atmospheric pressure CAA section 112(n)(4)(A) provides: emissions, which is 1⁄20 of the 95- conditions, are typically located at tank Notwithstanding the provisions of percent reduction achieved with the batteries. A tank battery refers to the subsection (a), emissions from any oil or gas first control). Based on the $1,650/Mg collection of process components used exploration or production well (with its cost effectiveness of the floor level of to separate, treat and store crude oil, associated equipment) and emission from control, we estimate that the condensate, natural gas and produced any pipeline compressor or pump station incremental cost effectiveness of the water. The extracted products from shall not be aggregated with emissions from second control to be $33,000/Mg. We do productions wells enter the tank battery other similar units, whether or not such units not believe this cost to be reasonable through the production header, which are in contiguous area or under common given the level of emission reduction. may collect product from many wells. control, to determine whether such units or We are, therefore, proposing an Emissions from storage vessels are a stations are major sources. emission standard for existing small result of working, breathing and flash As stated above, the CAA prevents dehydrators that reflects the MACT losses. Working losses occur due to the aggregation of HAP emissions from floor. emptying and filling of storage tanks. wells and associated equipment in For new small glycol dehydrators, Breathing losses are the release of gas making major source determinations. In based on our performance ranking, the associated with daily temperature the absence of clear guidance in the best performing source has an emission fluctuations and other equilibrium statute on what constitutes ‘‘associated factor of 1.10 × 10¥5 grams BTEX/scm- effects. Flash losses occur when a liquid equipment,’’ the EPA sought to define

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‘‘associated equipment’’ in a way that the distribution of cancer risks within We discussed the use of both MACT- recognizes the need to implement relief the exposed populations, cancer allowable and actual emissions in the for this industry as Congress intended incidence and an evaluation of the final Coke Oven Batteries residual risk and that also allow for the appropriate potential for adverse environmental rule (70 FR 19998–19999, April 15, regulation of significant emission effects for each source category. The risk 2005) and in the proposed and final points. 64 FR at 32619. Accordingly, in assessments consisted of seven primary Hazardous Organic NESHAP residual the existing Oil and Natural Gas steps, as discussed below. The docket risk rules (71 FR 34428, June 14, 2006, Production NESHAP (1998 and 1999 for this rulemaking contains the and 71 FR 76609, December 21, 2006, NESHAP), the EPA defined ‘‘associated following document which provides respectively). In those previous actions, equipment’’ to exclude glycol more information on the risk assessment we noted that assessing the risks at the dehydration units and storage vessels inputs and models: Draft Residual Risk MACT-allowable level is inherently with PFE (thus allowing their emissions Assessment for the Oil and Gas reasonable since these risks reflect the to be included in determining major Production and Natural Gas maximum level sources could emit and source status) because EPA identified Transmission and Storage Source still comply with national emission these sources as substantial contributors Categories. The methods used to assess standards. But we also explained that it to HAP emissions. Id. EPA explained in risks (as described in the seven primary is reasonable to consider actual that NESHAP that, because a single steps below) are consistent with those emissions, where such data are storage vessel with flash emissions may peer-reviewed by a panel of the EPA’s available, in both steps of the risk emit several Mg of HAP per year and Science Advisory Board (SAB) in 2009 analysis, in accordance with the individual glycol dehydrators may emit and described in their peer review Benzene NESHAP. (54 FR 38044, above the major source level, storage report issued in 2010 14; they are also September 14, 1989.) vessels with PFE and glycol dehydrators consistent with the key To estimate emissions at the MACT- are large individual sources of HAP, 63 recommendations contained in that allowable level, we developed a ratio of FR 6288, 6301 (1998). The EPA report. MACT-allowable to actual emissions for therefore considered these emission each emissions source type in each a. Establishing the Nature and source category, based on the level of sources substantial contributors to HAP Magnitude of Actual Emissions and emissions and excluded them from the control required by the MACT standards Identifying the Emissions Release compared to the level of reported actual definition of ‘‘associated equipment.’’ Characteristics 64 FR at 32619. We have recently emissions and available information on As discussed in section VII.A of this examined HAP emissions from storage the level of control achieved by the preamble, we used a dataset based on vessels without flash emissions and emissions controls in use. the 2005 NEI as the basis for the risk found that these emissions are assessment. In addition to the quality c. Conducting Dispersion Modeling, significant and comparable to those assurance (QA) of the facilities Determining Inhalation Exposures and vessels with flash emissions. For contained in the dataset, we also Estimating Individual and Population example, one storage vessel with an API checked the coordinates of every facility Inhalation Risks gravity of 30 degrees and a GOR of 2.09 in the dataset through visual Both long-term and short-term × 10¥3 m3/liter with a throughput of observations using tools such as inhalation exposure concentrations and 79,500 liter/day had HAP emissions of GoogleEarth and ArcView. Where health risks from each source in the 9.91 Mg/yr, including 9.45 Mg/yr of n- coordinates were found to be incorrect, source categories addressed in this hexane. we identified and corrected them to the proposal were estimated using the Because storage vessels without the extent possible. We also performed QA Human Exposure Model (HEM) PFE can have significant emissions at of the emissions data and release (Community and Sector HEM–3 version levels that are comparable to emissions characteristics to ensure there were no 1.1.0). The HEM–3 performs three from storage vessels with the PFE, there outliers. primary risk assessment activities: is no appreciable difference between (1) Conducting dispersion modeling to storage vessels with the PFE and those b. Establishing the Relationship estimate the concentrations of HAP in without the PFE for purposes of Between Actual Emissions and MACT- ambient air, (2) estimating long-term defining ‘‘associated equipment.’’ We Allowable Emissions Levels and short-term inhalation exposures to are, therefore, proposing to amend the The available emissions data in the individuals residing within 50 km of the associated equipment definition to MACT dataset represent the estimates of modeled sources and (3) estimating exclude all storage vessels and not just mass of emissions actually emitted individual and population-level storage vessels with the PFE. during the specified annual time period. inhalation risks using the exposure C. How did we perform the risk These ‘‘actual’’ emission levels are often estimates and quantitative dose- assessment and what are the results and lower than the emission levels that a response information. proposed decisions? facility might be allowed to emit and The dispersion model used by HEM– still comply with the MACT standards. 3 is AERMOD, which is one of the 1. How did we estimate risks posed by The emissions level allowed to be EPA’s preferred models for assessing the source categories? emitted by the MACT standards is pollutant concentrations from industrial The EPA conducted risk assessments referred to as the ‘‘MACT-allowable’’ facilities.15 To perform the dispersion that provided estimates for each source emissions level. This represents the modeling and to develop the in a category of the MIR posed by the highest emissions level that could be preliminary risk estimates, HEM–3 HAP emissions, the HI for chronic emitted by the facility without violating draws on three data libraries. The first exposures to HAP with the potential to the MACT standards. is a library of meteorological data, cause noncancer health effects, and the hazard quotient (HQ) for acute 14 U.S. EPA SAB. Risk and Technology Review 15 U.S. EPA. Revision to the Guideline on Air (RTR) Risk Assessment Methodologies: For Review Quality Models: Adoption of a Preferred General exposures to HAP with the potential to by the EPA’s Science Advisory Board with Case Purpose (Flat and Complex Terrain) Dispersion cause noncancer health effects. The Studies—MACT I Petroleum Refining Sources and Model and Other Revisions (70 FR 68218, assessments also provided estimates of Portland Cement Manufacturing, May 2010. November 9, 2005).

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which is used for dispersion a manner consistent with the EPA to Carcinogens 20 were applied. This calculations. This library includes guidelines and have undergone a peer adjustment has the effect of increasing 1 year of hourly surface and upper air review process similar to that used by the estimated lifetime risks for POM by observations for more than 158 the EPA, we may use such dose- a factor of 1.6. In addition, although meteorological stations, selected to response values in place of or in only a small fraction of the total POM provide coverage of the United States addition to other values, if appropriate. emissions were not reported as and Puerto Rico. A second library of Formaldehyde is a unique case. In individual compounds, the EPA United States Census Bureau census 2004, the EPA determined that the expresses carcinogenic potency for block 16 internal point locations and Chemical Industry Institute of compounds in this group in terms of populations provides the basis of Toxicology (CIIT) cancer dose-response benzo[a]pyrene equivalence, based on human exposure calculations (Census, value for formaldehyde (5.5 × 10¥9 per evidence that carcinogenic POM has the 2000). In addition, for each census μg/m3) was based on better science than same mutagenic mechanism of action as block, the census library includes the the IRIS cancer dose-response value benzo[a]pyrene. For this reason, the elevation and controlling hill height, (1.3 × 10¥5 per μg/m3) and we switched EPA’s Science Policy Council 21 which are also used in dispersion from using the IRIS value to the CIIT recommends applying the Supplemental calculations. A third library of pollutant value in risk assessments supporting Guidance to all carcinogenic polycyclic unit risk factors and other health regulatory actions. However, subsequent aromatic hydrocarbons for which risk benchmarks is used to estimate health research published by the EPA suggests estimates are based on relative potency. risks. These risk factors and health that the CIIT model was not appropriate Accordingly, we have applied the ADAF benchmarks are the latest values and in 2010 the EPA returned to using to the benzo[a]pyrene equivalent recommended by the EPA for HAP and the 1991 IRIS value, which is more portion of all POM mixtures. other toxic air pollutants. These values health protective.17 The EPA has been Incremental individual lifetime are available at http://www.epa.gov/ttn/ working on revising the formaldehyde cancer risks associated with emissions atw/toxsource/summary.html and are IRIS assessment and the National from the source category were estimated discussed in more detail later in this Academy of Sciences (NAS) completed as the sum of the risks for each of the section. its review of the EPA’s draft in May of carcinogenic HAP (including those In developing the risk assessment for 2011. EPA is reviewing the public classified as carcinogenic to humans, chronic exposures, we used the comments and the NAS independent likely to be carcinogenic to humans and estimated annual average ambient air scientific peer review, and the draft IRIS suggestive evidence of carcinogenic concentration of each of the HAP assessment will be revised and the final potential 22) emitted by the modeled emitted by each source for which we assessment will be posted on the IRIS source. Cancer incidence and the have emissions data in the source database. In the interim, we will present distribution of individual cancer risks category. The air concentrations at each findings using the 1991 IRIS value as a for the population within 50 km of any nearby census block centroid were used primary estimate, and may also consider source were also estimated for the as a surrogate for the chronic inhalation other information as the science source category as part of these exposure concentration for all the evolves. assessments by summing individual people who reside in that census block. In the case of benzene, the high end risks. A distance of 50 km is consistent We calculated the MIR for each facility of the reported cancer URE range was with both the analysis supporting the as the cancer risk associated with a used in our assessments to provide a 1989 Benzene NESHAP (54 FR 38044) continuous lifetime (24 hours per day, conservative estimate of potential and the limitations of Gaussian 7 days per week, and 52 weeks per year cancer risks. Use of the high end of the dispersion models, including AERMOD. for a 70-year period) exposure to the range provides risk estimates that are To assess risk of noncancer health maximum concentration at the centroid approximately 3.5 times higher than use effects from chronic exposures, we of an inhabited census block. Individual of the equally-plausible low end value. summed the HQ for each of the HAP cancer risks were calculated by We also evaluated the impact of using that affects a common target organ multiplying the estimated lifetime the low end of the URE range on our system to obtain the HI for that target exposure to the ambient concentration risk results. organ system (or target organ-specific of each of the HAP (in micrograms per We also note that polycyclic organic HI, TOSHI). The HQ for chronic cubic meter) by its unit risk estimate matter (POM), a carcinogenic HAP with exposures is the estimated chronic (URE), which is an upper bound a mutagenic mode of action, is emitted estimate of an individual’s probability by some of the facilities in these two 20 U.S. EPA. Supplemental Guidance for 18 Assessing Early-Life Exposure to Carcinogens. EPA/ of contracting cancer over a lifetime of categories. For this compound 630/R–03/003F, 2005. http://www.epa.gov/ttn/atw/ exposure to a concentration of 1 group,19 the age-dependent adjustment childrens_supplement_final.pdf. microgram of the pollutant per cubic factors (ADAF) described in the EPA’s 21 U.S. EPA. Science Policy Council Cancer meter of air. For residual risk Supplemental Guidance for Assessing Guidelines Implementation Workgroup assessments, we generally use URE Susceptibility from Early-Life Exposure Communication II: Memo from W.H. Farland, dated June 14, 2006. values from the EPA’s Integrated Risk 22 These classifications also coincide with the Information System (IRIS). For 17 For details on the justification for this decision, terms ‘‘known carcinogen, probable carcinogen and carcinogenic pollutants without the EPA see the memorandum in the docket from Peter possible carcinogen,’’ respectively, which are the IRIS values, we look to other reputable Preuss to Steve Page entitled, Recommendation for terms advocated in the EPA’s previous Guidelines Formaldehyde Inhalation Cancer Risk Values, for Carcinogen Risk Assessment, published in 1986 sources of cancer dose-response values, January 22, 2010. (51 FR 33992, September 24, 1986). Summing the often using California EPA (CalEPA) 18 U.S. EPA. Performing risk assessments that risks of these individual compounds to obtain the URE values, where available. In cases include carcinogens described in the Supplemental cumulative cancer risks is an approach that was where new, scientifically credible dose- Guidance as having a mutagenic mode of action. recommended by the EPA’s SAB in their 2002 peer Science Policy Council Cancer Guidelines review of EPA’s NATA entitled, NATA—Evaluating response values have been developed in Implementation Work Group Communication II: the National-scale Air Toxics Assessment 1996 Memo from W.H. Farland, dated October 4, 2005. Data—an SAB Advisory, available at: http:// 16 A census block is generally the smallest 19 See the Risk Assessment for Source Categories yosemite.epa.gov/sab/sabproduct.nsf/ geographic area for which census statistics are document available in the docket for a list of HAP 214C6E915BB04E14852570CA007A682C/$File/ tabulated. with a mutagenic mode of action. ecadv02001.pdf.

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exposure divided by the chronic exposure duration.’’ Acute REL values of a substance above which it is reference level, which is either the EPA are based on the most sensitive, predicted that the general population, reference concentration (RfC), defined relevant, adverse health effect reported including susceptible individuals, could as ‘‘an estimate (with uncertainty in the medical and toxicological experience notable discomfort, spanning perhaps an order of literature. Acute REL values are irritation, or certain asymptomatic magnitude) of a continuous inhalation designed to protect the most sensitive nonsensory effects. However, the effects exposure to the human population individuals in the population by the are not disabling and are transient and (including sensitive subgroups) that is inclusion of margins of safety. Since reversible upon cessation of exposure.’’ likely to be without an appreciable risk margins of safety are incorporated to The document also notes (page 3) that, of deleterious effects during a lifetime,’’ address data gaps and uncertainties, ‘‘Airborne concentrations below AEGL– or, in cases where an RfC from the exceeding the acute REL does not 1 represent exposure levels that can EPA’s IRIS database is not available, the automatically indicate an adverse health produce mild and progressively EPA will utilize the following impact. increasing but transient and prioritized sources for our chronic dose- AEGL values were derived in nondisabling odor, taste, and sensory response values: (1) The Agency for response to recommendations from the irritation or certain asymptomatic, Toxic Substances and Disease Registry National Research Council (NRC). As nonsensory effects.’’ Similarly, the Minimum Risk Level, which is defined described in Standing Operating document defines AEGL–2 values as as ‘‘an estimate of daily human Procedures (SOP) of the National ‘‘the airborne concentration (expressed exposure to a substance that is likely to Advisory Committee on Acute Exposure as ppm or mg/m3) of a substance above be without an appreciable risk of Guideline Levels for Hazardous which it is predicted that the general adverse effects (other than cancer) over Substances (http://www.epa.gov/ population, including susceptible a specified duration of exposure’’; (2) opptintr/aegl/pubs/sop.pdf),23 ‘‘the individuals, could experience the CalEPA Chronic Reference Exposure NRC’s previous name for acute exposure irreversible or other serious, long-lasting Level (REL), which is defined as ‘‘the levels—community emergency exposure adverse health effects or an impaired concentration level at or below which levels—was replaced by the term AEGL ability to escape.’’ no adverse health effects are anticipated to reflect the broad application of these ERPG values are derived for use in for a specified exposure duration’’; and values to planning, response, and emergency response, as described in the (3), as noted above, in cases where prevention in the community, the American Industrial Hygiene scientifically credible dose-response workplace, transportation, the military, Association’s document entitled, values have been developed in a manner and the remediation of Superfund Emergency Response Planning consistent with the EPA guidelines and sites.’’ This document also states that Guidelines (ERPG) Procedures and have undergone a peer review process AEGL values ‘‘represent threshold Responsibilities (http://www.aiha.org/ similar to that used by the EPA, we may exposure limits for the general public 1documents/committees/ use those dose-response values in place and are applicable to emergency ERPSOPs2006.pdf) which states that, of or in concert with other values. exposures ranging from 10 minutes to ‘‘Emergency Response Planning Screening estimates of acute eight hours.’’ The document lays out the Guidelines were developed for exposures and risks were also evaluated purpose and objectives of AEGL by emergency planning and are intended as for each of the HAP at the point of stating (page 21) that ‘‘the primary health based guideline concentrations highest off-site exposure for each facility purpose of the AEGL program and the for single exposures to chemicals.’’ 24 (i.e., not just the census block National Advisory Committee for Acute The ERPG–1 value is defined as ‘‘the centroids), assuming that a person is Exposure Guideline Levels for maximum airborne concentration below located at this spot at a time when both Hazardous Substances is to develop which it is believed that nearly all the peak (hourly) emission rate and guideline levels for once-in-a-lifetime, individuals could be exposed for up to worst-case dispersion conditions (1991 short-term exposures to airborne 1 hour without experiencing other than calendar year data) occur. The acute HQ concentrations of acutely toxic, high- mild transient adverse health effects or is the estimated acute exposure divided priority chemicals.’’ In detailing the without perceiving a clearly defined, by the acute dose-response value. In intended application of AEGL values, objectionable odor.’’ Similarly, the each case, acute HQ values were the document states (page 31) that ‘‘[i]t ERPG–2 value is defined as ‘‘the calculated using best available, short- is anticipated that the AEGL values will maximum airborne concentration below term dose-response values. These acute be used for regulatory and which it is believed that nearly all dose-response values, which are nonregulatory purposes by U.S. Federal individuals could be exposed for up to described below, include the acute REL, and state agencies and possibly the 1 hour without experiencing or acute exposure guideline levels (AEGL) international community in conjunction developing irreversible or other serious and emergency response planning with chemical emergency response, health effects or symptoms which could guidelines (ERPG) for 1-hour exposure planning, and prevention programs. impair an individual’s ability to take durations. As discussed below, we used More specifically, the AEGL values will protective action.’’ conservative assumptions for emission be used for conducting various risk rates, meteorology and exposure assessments to aid in the development As can be seen from the definitions location for our acute analysis. of emergency preparedness and above, the AEGL and ERPG values As described in the CalEPA’s Air prevention plans, as well as real-time include the similarly-defined severity Toxics Hot Spots Program Risk emergency response actions, for levels 1 and 2. For many chemicals, a Assessment Guidelines, Part I, The accidental chemical releases at fixed severity level 1 value AEGL or ERPG has Determination of Acute Reference facilities and from transport carriers.’’ not been developed; in these instances, Exposure Levels for Airborne Toxicants, The AEGL–1 value is then specifically higher severity level AEGL–2 or ERPG– an acute REL value (http:// defined as ‘‘the airborne concentration 2 values are compared to our modeled www.oehha.ca.gov/air/pdf/acuterel.pdf) is defined as ‘‘the concentration level at 23 NAS, 2001. Standing Operating Procedures for 24 ERP Committee Procedures and or below which no adverse health Developing Acute Exposure Levels for Hazardous Responsibilities. November 1, 2006. American effects are anticipated for a specified Chemicals, page 2. Industrial Hygiene Association.

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exposure levels to screen for potential 1, additional site-specific data were estimate does not exceed the AEGL–1, acute concerns. considered to develop a more refined we note here that it slightly exceeds Acute REL values for 1-hour exposure estimate of the potential for acute workplace ceiling level guidelines durations are typically lower than their impacts of concern. The data designed to protect the worker corresponding AEGL–1 and ERPG–1 refinements employed for these source population for short duration (<15 values. Even though their definitions are categories consisted of using the site- minute) increases in exposure to slightly different, AEGL–1 values are specific facility layout to distinguish benzene, as discussed below. The often the same as the corresponding facility property from an area where the occupational short-term exposure limit ERPG–1 values, and AEGL–2 values are public could be exposed. These (STEL) standard for benzene developed often equal to ERPG–2 values. refinements are discussed in the draft by the Occupational Safety and Health Maximum HQ values from our acute risk assessment document, which is Administration is 16 mg/m3, ‘‘as screening risk assessments typically available in the docket for each of these averaged over any 15-minute period.’’ 27 result when basing them on the acute source categories. Ideally, we would Occupational guideline STEL for REL value for a particular pollutant. In prefer to have continuous measurements exposures to benzene have also been cases where our maximum acute HQ over time to see how the emissions vary developed by the American Conference value exceeds 1, we also report the HQ by each hour over an entire year. Having of Governmental Industrial Hygienists value based on the next highest acute a frequency distribution of hourly (ACGIH) 28 for less than 15 minutes 29 dose-response value (usually the AEGL– emission rates over a year would allow (ACGIH threshold limit value (TLV)- 1 and/or the ERPG–1 value). us to perform a probabilistic analysis to STEL value of 8.0 mg/m3), and by the To develop screening estimates of estimate potential threshold National Institute for Occupational acute exposures, we developed exceedances and their frequency of Safety and Health (NIOSH) 30 ‘‘for any estimates of maximum hourly emission occurrence. Such an evaluation could 15 minute period in a work day’’ rates by multiplying the average actual include a more complete statistical (NIOSH REL–STEL of 3.2 mg/m3). These annual hourly emission rates by a factor treatment of the key parameters and shorter duration occupational values to cover routinely variable emissions. elements adopted in this screening indicate potential concerns regarding We chose the factor based on process analysis. However, we recognize that health effects at exposure levels below knowledge and engineering judgment having this level of data is rare, hence the 1-hour AEGL–1 value. We solicit and with awareness of a Texas study of our use of the multiplier approach. comment on the use of the occupational short-term emissions variability, which To better characterize the potential values described above in the showed that most peak emission events, health risks associated with estimated interpretation of these worst-case acute in a heavily-industrialized 4-county area acute exposures to HAP, and in screening exposure estimates. (Harris, Galveston, Chambers and response to a key recommendation from d. Conducting Multi-Pathway Exposure Brazoria Counties, Texas) were less than the SAB’s peer review of the EPA’s RTR and Risk Modeling twice the annual average hourly risk assessment methodologies,26 we emission rate. The highest peak generally examine a wider range of The potential for significant human emission event was 74 times the annual available acute health metrics than we health risks due to exposures via routes average hourly emission rate, and the do for our chronic risk assessments. other than inhalation (i.e., multi- 99th percentile ratio of peak hourly This is in response to the SAB’s pathway exposures) and the potential emission rate to the annual average acknowledgement that there are for adverse environmental impacts were hourly emission rate was 9.25 This generally more data gaps and evaluated in a three-step process. In the analysis is provided in Appendix 4 of inconsistencies in acute reference first step, we determined whether any the Draft Residual Risk Assessment for values than there are in chronic facilities emitted any HAP known to be the Oil and Gas Production and Natural reference values. Comparisons of the PB–HAP (HAP known to be persistent Gas Transmission and Storage Source estimated maximum off-site 1-hour and bio-accumulative) in the Categories, which is available in the exposure levels are not typically made environment. There are 14 PB–HAP docket for this action. Considering this to occupational levels for the purpose of compounds or compound classes analysis, unless specific process characterizing public health risks in identified for this screening in the EPA’s knowledge or data are available to RTR assessments. This is because they Air Toxics Risk Assessment Library provide an alternate value, to account are developed for working age adults (available at http://www.epa.gov/ttn/ for more than 99 percent of the peak and are not generally considered fera/risk_atra_vol1.html). They are hourly emissions, we apply a protective for the general public. We cadmium compounds, chlordane, conservative screening multiplication note that occupational ceiling values chlorinated dibenzodioxins and furans, factor of 10 to the average annual hourly are, for most chemicals, set at levels emission rate in these acute exposure higher than a 1-hour AEGL–1. 27 29 CFR 1910.1028, Benzene. Available online As discussed in section VII.C.2 of this at http://www.osha.gov/pls/oshaweb/owadisp. screening assessments. The factor of 10 show_document?p_table=STANDARDS&p_ was used for both the Oil and Natural preamble, the maximum estimated worst-case 1-hour exposure to benzene id=10042. Gas Production and the Natural Gas 28 ACGIH (2001) Benzene. In Documentation of Transmission and Storage source outside the facility fence line for a the TLVs® and BEIs® with Other Worldwide categories. facility in either source category is 12 Occupational Exposure Values. ACGIH, 1300 mg/m3. This estimated exposure Kemper Meadow Drive, Cincinnati, OH 45240 In cases where acute HQ values from (ISBN: 978–1–882417–74–2) and available online at the screening step were less than or exceeds the 6-hour REL by a factor of 9 (HQ = 9), but is significantly below http://www.acgih.org. equal to 1, acute impacts were deemed REL 29 The ACGIH definition of a TLV–STEL states negligible and no further analysis was the 1-hour AEGL–1 (HQAEGL–1 = 0.07). that ‘‘Exposures above the TLV–TWA up to the performed. In cases where an acute HQ Although this worst-case exposure TLV–STEL should be less than 15 minutes, should occur no more than four times per day, and there from the screening step was greater than 26 The SAB peer review of RTR Risk Assessment should be at least 60 minutes between successive Methodologies is available at: http://yosemite.epa. exposures in this range.’’ 25 See http://www.tceq.state.tx.us/compliance/ gov/sab/sabproduct.nsf/4AB3966E263D943A852 30 NIOSH. Occupational Safety and Health field_ops/eer/index.html or docket to access the 5771F00668381/$File/EPA-SAB-10-007- Guideline for Benzene; http://www.cdc.gov/niosh/ source of these data. unsigned.pdf. 74-137.html.

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dichlorodiphenyldichloroethylene, not locally available, multi-pathway g. Conducting Other Analyses: heptachlor, hexachlorobenzene, exposures and environmental risks were Demographic Analysis hexachlorocyclohexane, lead deemed negligible, and no further To examine the potential for any compounds, mercury compounds, analysis was performed. For further environmental justice (EJ) issues that methoxychlor, polychlorinated information on the multi-pathway might be associated with each source biphenyls, POM, toxaphene and analysis approach, see the residual risk category, we performed a demographic trifluralin. documentation. analysis of population risk. In this Since one or more of these PB–HAP analysis, we evaluated the distributions are emitted by at least one facility in e. Assessing Risks Considering of HAP-related cancer and noncancer both source categories, we proceeded to Emissions Control Options risks across different social, the second step of the evaluation. In this In addition to assessing baseline demographic and economic groups step, we determined whether the within the populations living near the facility-specific emission rates of each of inhalation risks and screening for facilities where these source categories the emitted PB–HAP were large enough potential multi-pathway risks, where are located. The development of to create the potential for significant appropriate, we also estimated risks demographic analyses to inform the non-inhalation human or environmental considering the potential emission consideration of EJ issues in the EPA risks under reasonable worst-case reductions that would be achieved by conditions. To facilitate this step, we the particular control options under rulemakings is an evolving science. The have developed emission rate consideration. In these cases, the EPA offers the demographic analyses in thresholds for each PB–HAP using a expected emissions reductions were this rulemaking to inform the hypothetical worst-case screening applied to the specific HAP and consideration of potential EJ issues and exposure scenario developed for use in emissions sources in the source category invites public comment on the conjunction with the EPA’s TRIM.FaTE dataset to develop corresponding approaches used and the interpretations model. The hypothetical screening estimates of risk reductions. made from the results, with the hope scenario was subjected to a sensitivity that this will support the refinement f. Conducting Other Risk-Related and improve the utility of such analyses analysis to ensure that its key design Analyses: Facility-Wide Assessments parameters were established such that for future rulemakings. environmental media concentrations For the demographic analyses, we To put the source category risks in focus on the populations within 50 km were not underestimated (i.e., to context, we also examined the risks minimize the occurrence of false of any facility estimated to have from the entire ‘‘facility,’’ where the exposures to HAP which result in negatives or results that suggest that facility includes all HAP-emitting risks might be acceptable when, in fact, cancer risks of 1-in-1 million or greater, operations within a contiguous area and or noncancer HI of 1 or greater (based actual risks are high) and to also under common control. In other words, minimize the occurrence of false on the emissions of the source category for each facility that includes one or or the facility, respectively). We positives for human health endpoints. more sources from one of the source We call this application of the examine the distributions of those risks categories under review, we examined across various demographic groups, TRIM.FaTE model TRIM–Screen. The the HAP emissions not only from the facility-specific emission rates of each of comparing the percentages of particular source category of interest, but also from demographic groups to the total number the PB–HAP in each source category all other emission sources at the facility. were compared to the TRIM–Screen of people in those demographic groups The emissions data for generating these nationwide. The results, including other emission threshold values for each of ‘‘facility-wide’’ risks were also obtained the PB–HAP identified in the source risk metrics, such as average risks for from the 2005 NEI. For every facility the exposed populations, are category datasets to assess the potential included in the MACT database, we also for significant human health risks or documented in source-category-specific retrieved emissions data and release environmental risks via non-inhalation technical reports in the docket for both characteristics for all other emission pathways. source categories covered in this There was only one facility in the sources at the same facility. We proposal. Natural Gas Transmission and Storage estimated the risks due to the inhalation The basis for the risk values used in source category with reported emissions of HAP that are emitted ‘‘facility-wide’’ these analyses were the modeling of PB–HAP, and the emission rates were for the populations residing within 50 results based on actual emissions levels less than the emission threshold values. km of each facility, consistent with the obtained from the HEM–3 model There were 29 facilities in the Oil and methods used for the source category described above. The risk values for Natural Gas Production source category analysis described above. For these each census block were linked to a with reported emissions of PB–HAP, facility-wide risk analyses, the modeled database of information from the 2000 and one of these had emission rates source category risks were compared to Decennial census that includes data on greater than the emission threshold the facility-wide risks to determine the race and ethnicity, age distributions, values. In this case, the emission portion of facility-wide risks that could poverty status, household incomes and threshold value for POM was exceeded be attributed to the source categories education level. The Census Department by a factor of 6. For POM, dairy, addressed in this proposal. We Landview® database was the source of vegetables and fruits were the three specifically examined the facilities the data on race and ethnicity and the most dominant exposure pathways associated with the highest estimates of data on age distributions, poverty status, driving human exposures in the risk and determined the percentage of household incomes and education level hypothetical screening exposure that risk attributable to the source were obtained from the 2000 Census of scenario. The single facility with category of interest. The risk Population and Housing Summary File emissions exceeding the emission documentation available through the 3 Long Form. While race and ethnicity threshold value for POM is located in a docket for this action provides the census data are available at the census highly industrialized area. Therefore, methodology and the results of the block level, the age and income census since the exposure pathways which facility-wide analyses for each source data are only available at the census would drive high human exposure are category. block group level (which includes an

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average of 26 blocks or an average of including those performed for the situations to overestimate or 1,350 people). Where census data are source categories addressed in this underestimate ambient impacts. For available at the block group level, but proposal. Although uncertainty exists, example, meteorological data were not the block level, we assumed that all we believe that our approach, which taken from a single year (1991) and census blocks within the block group used conservative tools and facility locations can be a significant have the same distribution of ages and assumptions, ensures that our decisions distance from the site where these data incomes as the block group. are health-protective. A brief discussion were taken. Despite these uncertainties, For each source category, we focused of the uncertainties in the emissions we believe that at off-site locations and on those census blocks where source datasets, dispersion modeling, census block centroids, the approach category risk results show estimated inhalation exposure estimates and dose- considered in the dispersion modeling lifetime inhalation cancer risks above response relationships follows below. A analysis should generally yield 1-in-1 million or chronic noncancer more thorough discussion of these overestimates of ambient HAP indices above 1 and determined the uncertainties is included in the risk concentrations. assessment documentation (referenced relative percentage of different racial iii. Uncertainties in Inhalation Exposure and ethnic groups, different age groups, earlier) available in the docket for this adults with and without a high school action. The effects of human mobility on diploma, people living in households exposures were not included in the i. Uncertainties in the Emissions assessment. Specifically, short-term below the national median income and Datasets for people living below the poverty line mobility and long-term mobility within those census blocks. The specific Although the development of the between census blocks in the modeling 31 census population categories studied MACT dataset involved QA/quality domain were not considered. The include: control processes, the accuracy of assumption of not considering short or • emissions values will vary depending long-term population mobility does not Total population on the source of the data, the degree to bias the estimate of the theoretical MIR, • White • which data are incomplete or missing, nor does it affect the estimate of cancer African American (or Black) the degree to which assumptions made incidence since the total population • Native Americans • to complete the datasets are inaccurate, number remains the same. It does, Other races and multiracial errors in estimating emissions values however, affect the shape of the • Hispanic or Latino • and other factors. The emission distribution of individual risks across Children 18 years of age and under estimates considered in this analysis the affected population, shifting it • Adults 19 to 64 years of age • generally are annual totals for certain toward higher estimated individual Adults 65 years of age and over years that do not reflect short-term risks at the upper end and reducing the • Adults without a high school diploma • fluctuations during the course of a year number of people estimated to be at Households earning under the or variations from year to year. lower risks, thereby increasing the national median income The estimates of peak hourly emission • estimated number of people at specific People living below the poverty line rates for the acute effects screening risk levels. It should be noted that these assessment were based on a In addition, the assessment predicted categories overlap in some instances, multiplication factor of 10 applied to the chronic exposures at the centroid of resulting in some populations being the average annual hourly emission rate, each populated census block as counted in more than one category (e.g., which is intended to account for surrogates for the exposure other races and multiracial and emission fluctuations due to normal concentrations for all people living in Hispanic). In addition, while not a facility operations. Additionally, that block. Using the census block specific census population category, we although we believe that we have data centroid to predict chronic exposures also examined risks to ‘‘Minorities,’’ a for most facilities in these two source tends to over-predict exposures for classification which is defined for these categories in our RTR dataset, our people in the census block who live purposes as all race population dataset may not include data for all further from the facility, and under- categories except white. existing facilities. Moreover, there are predict exposures for people in the For further information about risks to uncertainties with regard to the census block who live closer to the the populations located near the identification of sources as major or area facility. Thus, using the census block facilities in these source categories, we in the NEI for these source categories. centroid to predict chronic exposures also evaluated the estimated may lead to a potential understatement distribution of inhalation cancer and ii. Uncertainties in Dispersion Modeling or overstatement of the true maximum chronic noncancer risks associated with While the analysis employed the impact, but is an unbiased estimate of the HAP emissions from all the EPA’s recommended regulatory average risk and incidence. emissions sources at the facility (i.e., dispersion model, AERMOD, we The assessments evaluate the cancer facility-wide). This analysis used the recognize that there is uncertainty in inhalation risks associated with facility-wide RTR modeling results and ambient concentration estimates continuous pollutant exposures over a the census data described above. associated with any model, including 70-year period, which is the assumed The methodology and the results of AERMOD. In circumstances where we lifetime of an individual. In reality, both the demographic analyses for each had to choose between various model the length of time that modeled source category are included in a options, where possible, model options emissions sources at facilities actually source-category-specific technical report (e.g., rural/urban, plume depletion, operate (i.e., more or less than 70 years), for each of the categories, which are chemistry) were selected to provide an and the domestic growth or decline of available in the docket for this action. overestimate of ambient air the modeled industry (i.e., the increase concentrations of the HAP rather than h. Considering Uncertainties in Risk underestimates. However, because of 31 Short-term mobility is movement from one Assessment micro-environment to another over the course of practicality and data limitation reasons, hours or days. Long-term mobility is movement Uncertainty and the potential for bias some factors (e.g., meteorology, building from one residence to another over the course of a are inherent in all risk assessments, downwash) have the potential in some lifetime.

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or decrease in the number or size of quantitatively, and others generally are consideration of both uncertainty and United States facilities), will influence expressed in qualitative terms. We note variability. When there are gaps in the the risks posed by a given source as a preface to this discussion a point on available information, UF are applied to category. Depending on the dose-response uncertainty that is derive reference values that are characteristics of the industry, these brought out in the EPA 2005 Cancer intended to protect against appreciable factors will, in most cases, result in an Guidelines; namely, that ‘‘the primary risk of deleterious effects. The UF are overestimate both in individual risk goal of the EPA actions is protection of commonly default values,35 e.g., factors levels and in the total estimated number human health; accordingly, as an of 10 or 3, used in the absence of of cancer cases. However, in rare cases, Agency policy, risk assessment compound-specific data; where data are where a facility maintains or increases procedures, including default options available, UF may also be developed its emission levels beyond 70 years, that are used in the absence of scientific using compound-specific information. residents live beyond 70 years at the data to the contrary, should be health When data are limited, more same location, and the residents spend protective.’’ (EPA 2005 Cancer assumptions are needed and more UF most of their days at that location, then Guidelines, pages 1–7.) This is the are used. Thus, there may be a greater the risks could potentially be approach followed here as summarized tendency to overestimate risk in the underestimated. Annual cancer in the next several paragraphs. A sense that further study might support incidence estimates from exposures to complete detailed discussion of development of reference values that are emissions from these sources would not uncertainties and variability in dose- higher (i.e., less potent) because fewer be affected by uncertainty in the length response relationships is given in the default assumptions are needed. of time emissions sources operate. residual risk documentation, which is However, for some pollutants, it is The exposure estimates used in these available in the docket for this action. possible that risks may be analyses assume chronic exposures to Cancer URE values used in our risk underestimated. While collectively ambient levels of pollutants. Because assessments are those that have been termed ‘‘uncertainty factor,’’ these most people spend the majority of their developed to generally provide an upper factors account for a number of different time indoors, actual exposures may not bound estimate of risk. That is, they quantitative considerations when using be as high, depending on the represent a ‘‘plausible upper limit to the observed animal (usually rodent) or characteristics of the pollutants true value of a quantity’’ (although this human toxicity data in the development modeled. For many of the HAP, indoor is usually not a true statistical of the RfC. The UF are intended to levels are roughly equivalent to ambient confidence limit).33 In some account for: (1) Variation in levels, but for very reactive pollutants or circumstances, the true risk could be as susceptibility among the members of the larger particles, these levels are low as zero; however, in other human population (i.e., inter-individual typically lower. This factor has the circumstances, the risk could also be variability); (2) uncertainty in 34 potential to result in an overstatement of greater. When developing an upper extrapolating from experimental animal 25 to 30 percent of exposures.32 bound estimate of risk and to provide data to humans (i.e., interspecies In addition to the uncertainties risk values that do not underestimate differences); (3) uncertainty in highlighted above, there are several risk, health-protective default extrapolating from data obtained in a factors specific to the acute exposure approaches are generally used. To err on study with less-than-lifetime exposure assessment that should be highlighted. the side of ensuring adequate health- (i.e., extrapolating from sub-chronic to The accuracy of an acute inhalation protection, the EPA typically uses the chronic exposure); (4) uncertainty in exposure assessment depends on the upper bound estimates rather than extrapolating the observed data to simultaneous occurrence of lower bound or central tendency obtain an estimate of the exposure independent factors that may vary estimates in our risk assessments, an associated with no adverse effects; and greatly, such as hourly emissions rates, approach that may have limitations for (5) uncertainty when the database is meteorology, and human activity other uses (e.g., priority-setting or incomplete or there are problems with patterns. In this assessment, we assume expected benefits analysis). the applicability of available studies. that individuals remain for 1 hour at the Chronic noncancer reference (RfC and Many of the UF used to account for point of maximum ambient reference dose (RfD)) values represent variability and uncertainty in the chronic exposure levels that are concentration as determined by the co- development of acute reference values intended to be health-protective levels. occurrence of peak emissions and worst- Specifically, these values provide an case meteorological conditions. These 35 According to the NRC report, Science and estimate (with uncertainty spanning assumptions would tend to overestimate Judgment in Risk Assessment (NRC, 1994) perhaps an order of magnitude) of daily ‘‘[Default] options are generic approaches, based on actual exposures since it is unlikely that oral exposure (RfD) or of a continuous general scientific knowledge and policy judgment, a person would be located at the point inhalation exposure (RfC) to the human that are applied to various elements of the risk of maximum exposure during the time assessment process when the correct scientific population (including sensitive of worst-case impact. model is unknown or uncertain.’’ The 1983 NRC subgroups) that is likely to be without report, Risk Assessment in the Federal Government: iv. Uncertainties in Dose-Response an appreciable risk of deleterious effects Managing the Process, defined default option as Relationships during a lifetime. To derive values that ‘‘the option chosen on the basis of risk assessment policy that appears to be the best choice in the There are uncertainties inherent in are intended to be ‘‘without appreciable absence of data to the contrary’’ (NRC, 1983a, p. 63). the development of the dose-response risk,’’ the methodology relies upon an Therefore, default options are not rules that bind values used in our risk assessments for uncertainty factor (UF) approach (U.S. the Agency; rather, the Agency may depart from EPA, 1993, 1994) which includes them in evaluating the risks posed by a specific cancer effects from chronic exposures substance when it believes this to be appropriate. and noncancer effects from both chronic In keeping with EPA’s goal of protecting public and acute exposures. Some 33 IRIS glossary (http://www.epa.gov/NCEA/iris/ health and the environment, default assumptions help_gloss.htm). are used to ensure that risk to chemicals is not uncertainties may be considered 34 An exception to this is the URE for benzene, underestimated (although defaults are not intended which is considered to cover a range of values, each to overtly overestimate risk). See EPA, 2004, An 32 U.S. EPA. National-Scale Air Toxics end of which is considered to be equally plausible Examination of EPA Risk Assessment Principles Assessment for 1996. (EPA 453/R–01–003; January and which is based on maximum likelihood and Practices, EPA/100/B–04/001 available at: 2001; page 85.) estimates. http://www.epa.gov/osa/pdfs/ratf-final.pdf.

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are quite similar to those developed for understatement of risk for these for our source category risk assessments chronic durations, but they more often pollutants at environmental exposure apply to the facility-wide risk use individual UF values that may be levels is possible. For a group of assessments. Additionally, the degree of less than 10. UF are applied based on compounds that are either unspeciated uncertainty associated with facility- chemical-specific or health effect- or do not have reference values for every wide emissions and risks is likely specific information (e.g., simple individual compound (e.g., glycol greater because we generally have not irritation effects do not vary appreciably ethers), we conservatively use the most conducted a thorough engineering between human individuals, hence a protective reference value to estimate review of emissions data for source value of 3 is typically used), or based on risk from individual compounds in the categories not currently undergoing an the purpose for the reference value (see group of compounds. RTR review. the following paragraph). The UF Additionally, chronic reference values vii. Uncertainties in the Demographic applied in acute reference value for several of the compounds included Analysis derivation include: (1) Heterogeneity in this assessment are currently under among humans; (2) uncertainty in the EPA IRIS review and revised Our analysis of the distribution of extrapolating from animals to humans; assessments may determine that these risks across various demographic groups (3) uncertainty in lowest observed pollutants are more or less potent than is subject to the typical uncertainties adverse effect (exposure) level to no the current value. We may re-evaluate associated with census data (e.g., errors observed adverse effect (exposure) level residual risks for the final rulemaking if in filling out and transcribing census adjustments; and (4) uncertainty in these reviews are completed prior to our forms), as well as the additional accounting for an incomplete database taking final action for these source uncertainties associated with the on toxic effects of potential concern. categories and a dose-response metric extrapolation of census-block group data Additional adjustments are often changes enough to indicate that the risk (e.g., income level and education level) applied to account for uncertainty in assessment supporting this notice may down to the census block level. extrapolation from observations at one significantly understate human health 2. What are the results and proposed exposure duration (e.g., 4 hours) to risk. decisions from the risk review for the derive an acute reference value at v. Uncertainties in the Multi-Pathway Oil and Natural Gas Production source another exposure duration (e.g., 1 hour). and Environmental Effects Assessment category? Not all acute reference values are We generally assume that when developed for the same purpose and a. Results of the Risk Assessments and exposure levels are not anticipated to Analyses care must be taken when interpreting adversely affect human health, they also the results of an acute assessment of are not anticipated to adversely affect We conducted an inhalation risk human health effects relative to the the environment. For each source assessment for the Oil and Natural Gas reference value or values being category, we generally rely on the site- Production source category. We also exceeded. Where relevant to the specific levels of PB–HAP emissions to conducted an assessment of facility- estimated exposures, the lack of short- determine whether a full assessment of wide risk. Details of the risk term dose-response values at different the multi-pathway and environmental assessments and analyses can be found levels of severity should be factored into effects is necessary. As discussed above, in the residual risk documentation, the risk characterization as potential we conclude that the potential for these which is available in the docket for this uncertainties. types of impacts is low for these source action. For informational purposes and Although every effort is made to categories. to examine the potential for any EJ identify peer-reviewed reference values issues that might be associated with for cancer and noncancer effects for all vi. Uncertainties in the Facility-Wide each source category, we performed a pollutants emitted by the sources Risk Assessment demographic analysis of population included in this assessment, some HAP Given that the same general analytical risks. continue to have no reference values for approach and the same models were i. Inhalation Risk Assessment Results cancer or chronic noncancer or acute used to generate facility-wide risk effects. Since exposures to these results as were used to generate the Table 2 provides an overall summary pollutants cannot be included in a source category risk results, the same of the results of the inhalation risk quantitative risk estimate, an types of uncertainties discussed above assessment.

TABLE 2—OIL AND NATURAL GAS PRODUCTION INHALATION RISK ASSESSMENT RESULTS

Maximum individual cancer risk Estimated Maximum chronic noncancer (in 1 million) 2 Estimated pop- annual cancer TOSHI 4 Maximum Number of ulation at risk ≥ incidence off-site acute facilities 1 Actual emis- Allowable emis- 1-in-1 million (cases per Actual emis- Allowable emis- noncancer HQ 5 sions level sions level year) sions level sions level

3 3 3 990 40 100–400 160,000 0.007–0.02 0.1 0.7 HQREL = 9 (benzene) HQAEGL–1 = 0.07 (benzene) 1 Number of facilities evaluated in the risk analysis. 2 Estimated maximum individual excess lifetime cancer risk. 3 The EPA IRIS assessment for benzene provides a range of equally-plausible URE (2.2E–06 to 7.8E–06 per ug/m3), giving rise to ranges for the estimates of cancer MIR and cancer incidence. Estimated population values are not scalable with benzene URE range, but would be lower using the lower end of the URE range. 4 Maximum TOSHI. The target organ with the highest TOSHI for the Oil and Natural Gas Production source category is the respiratory system. 5 The maximum estimated acute exposure concentration was divided by available short-term dose-response values to develop an array of HQ values.

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As shown in Table 2, the results of the URE range would further reduce this as high as 400-in-1 million (100-in-1 inhalation risk assessment performed population estimate). The maximum million based on the lower end of the using actual emissions data indicate the chronic non-cancer TOSHI value for the benzene URE range) and the maximum maximum lifetime individual cancer source category could be up to 0.1 from chronic noncancer TOSHI value could risk could be as high as 40-in-1 million, emissions of naphthalene, indicating no be as high as 0.7 at the MACT-allowable with POM driving the highest risk, and significant potential for chronic emissions level. benzene driving risks overall. The total noncancer impacts. ii. Facility-Wide Risk Assessment estimated cancer incidence from this As explained above, our analysis of potential differences between actual Results source category is 0.02 excess cancer emission levels and emissions allowable cases per year (0.007 excess cancer cases under the oil and natural gas production A facility-wide risk analysis was also per year based on the lower end of the MACT standard indicate that MACT- conducted based on actual emissions benzene URE range), or one case in allowable emission levels may be up to levels. Table 3 displays the results of the every 50 years. Approximately 160,000 50 times greater than actual emission facility-wide risk assessment. For people are estimated to have cancer levels. Considering this difference, the detailed facility-specific results, see risks at or above 1-in-1 million as a risk results from the inhalation risk Table 2 of Appendix 6 of the risk result of the emissions from 89 facilities assessment indicate the maximum document in the docket for this (use of the lower end of the benzene lifetime individual cancer risk could be rulemaking.

TABLE 3—OIL AND NATURAL GAS PRODUCTION FACILITY-WIDE RISK ASSESSMENT RESULTS

Number of facilities analyzed ...... 990 Cancer Risk: Estimated maximum facility-wide individual cancer risk (in 1 million) ...... 100 Number of facilities with estimated facility-wide individual cancer risk of 100-in-1 million or more ...... 1 Number of facilities at which the Oil and Natural Gas Production source category contributes 50 percent or more to the facil- ity-wide individual cancer risks of 100-in-1 million or more ...... 0 Number of facilities with facility-wide individual cancer risk of 1-in-1 million or more ...... 140 Number of facilities at which the Oil and Natural Gas Production source category contributes 50 percent or more to the facil- ity-wide individual cancer risk of 1-in-1 million or more ...... 85 Chronic Noncancer Risk: Maximum facility-wide chronic noncancer TOSHI ...... 9 Number of facilities with facility-wide maximum noncancer TOSHI greater than 1 ...... 10 Number of facilities at which the Oil and Natural Gas Production source category contributes 50 percent or more to the facil- ity-wide maximum noncancer TOSHI of 1 or more ...... 0

The facility-wide MIR from all HAP wide MIR of 1-in-1 million or greater. Of values greater than 1. Of these facilities, emissions at a facility that contains these facilities, 85 have oil and natural none had oil and natural gas production sources subject to the oil and natural gas gas production operations that operations that contributed greater than production MACT standards is contribute greater than 50 percent to the 50 percent to these facility-wide risks. estimated to be 100-in-1 million, based facility-wide risks. As discussed above, The chronic noncancer risks at these 10 on actual emissions. Of the 990 facilities we are proposing MACT standards for facilities are primarily driven by included in this analysis, only one has BTEX emissions from small glycol acrolein emissions from RICE. a facility-wide MIR of 100-in-1 million. dehydrators in this action. These iii. Demographic Risk Analysis Results At this facility, oil and natural gas standards would reduce the risk from production accounts for less than 2 benzene emissions at facilities with oil The results of the demographic percent of the total facility-wide risk. and gas production. Formaldehyde analyses performed to investigate the Nickel emissions from oil-fired boilers emissions will be assessed under future distribution of cancer risks at or above and formaldehyde emissions from RTR for RICE. 1-in-1 million among the surrounding reciprocating internal combustion The facility-wide maximum population are summarized in Table 4 engines (RICE) contribute essentially all individual chronic noncancer TOSHI is below. These results, for various the facility-wide risks at this facility, estimated to be 9 based on actual demographic groups, are based on with over 80 percent of the risk emissions. Of the 990 facilities included actual emissions levels for the attributed to the nickel emissions.36 in this analysis, 10 have facility-wide population living within 50 km of the There are 140 facilities with facility- maximum chronic noncancer TOSHI facilities.

TABLE 4—OIL AND NATURAL GAS PRODUCTION DEMOGRAPHIC RISK ANALYSIS RESULTS

Population with cancer risk at or above 1-in-1 million due to Nationwide Source category Facility-wide HAP HAP emissions emissions

Total Population ...... 285,000,000 160,000 597,000

36 We note that there is an ongoing IRIS risk assessments will use the cancer potency for As a result, the current results may not match those reassessment for formaldehyde, and that future RTR formaldehyde that results from that reassessment. of future assessments.

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TABLE 4—OIL AND NATURAL GAS PRODUCTION DEMOGRAPHIC RISK ANALYSIS RESULTS—Continued

Population with cancer risk at or above 1-in-1 million due to Nationwide Source category Facility-wide HAP HAP emissions emissions

Race by Percent

White ...... 75 62 61 All Other Races ...... 25 38 39

Race by Percent

White ...... 75 62 61 African American ...... 12 12 8 Native American ...... 0.9 0.7 1.3 Other and Multiracial ...... 12 25 30

Ethnicity by Percent

Hispanic ...... 14 22 34 Non-Hispanic ...... 86 78 66

Income by Percent

Below Poverty Level ...... 13 14 19 Above Poverty Level ...... 87 86 81

Education by Percent

Over 25 and without High School Diploma ...... 13 10 16 Over 25 and with a High School Diploma ...... 87 90 84

The results of the Oil and Natural Gas demographic group, results which are URE range). While the 40-in-1 million Production source category 18, 2, 0.4 and 3 percentage points higher risk due to actual emissions is demographic analysis indicate that there than the percentages for these considerably less than 100-in-1 million, are approximately 160,000 people demographic groups across the United which is the presumptive limit of exposed to a cancer risk at or above 1- States, respectively. The percentages for acceptability, the 400-in-1 million risk in-1 million due to emissions from the the other demographic groups are lower due to allowable emissions is source category, including an estimated than their respective nationwide considerably higher and is considered 38 percent that are classified as minority percentages. unacceptable. We do note, however, that (listed as ‘‘All Other Races’’ in the table b. What are the proposed risk decisions the risk analysis shows low cancer above). Of the 160,000 people with for the Oil and Natural Gas Production incidence (1 case in every 50 years), low estimated cancer risks at or above 1-in- source category? potential for adverse environmental 1 million from the source category, 25 effects or human health multi-pathway percent are in the ‘‘Other and i. Risk Acceptability effects and that chronic noncancer Multiracial’’ demographic group, 22 In the risk analysis we performed for health impacts are unlikely. percent are in the ‘‘Hispanic or Latino’’ this source category, pursuant to CAA We also conclude that acute demographic group, and 14 percent are section 112(f)(2), we considered the noncancer health impacts are unlikely. in the ‘‘Below Poverty Level’’ available health information—the MIR; As discussed above, screening estimates demographic group, results which are the numbers of persons in various risk of acute exposures and risks were 13, 8 and 1 percentage points higher, ranges; cancer incidence; the maximum evaluated for each of the HAP at the respectively, than the respective noncancer HI; the maximum acute point of highest off-site exposure for percentages for these demographic noncancer hazard; the extent of each facility (i.e., not just the census groups across the United States. The noncancer risks; the potential for block centroids) assuming that a person percentages for the other demographic adverse environmental effects; and is located at this spot at a time when groups are lower than their respective distribution of risks in the exposed both the peak emission rate and worst- nationwide percentages. The table also population; and risk estimation case dispersion conditions occur. Under shows that there are approximately uncertainty (54 FR 38044, September these worst-case conditions, we estimate 597,000 people exposed to an estimated 14, 1989). benzene acute HQ values (based on the cancer risk at or above 1-in-1 million For the Oil and Natural Gas REL) could be as high as 9. Although the due to facility-wide emissions, Production source category, the risk REL (which indicates the level below including 30 percent in the ‘‘Other and analysis we performed indicates that the which adverse effects are not Multiracial’’ demographic group, 34 cancer risks to the individual most anticipated) is exceeded in this case, we percent in the ‘‘Hispanic or Latino’’ exposed could be as high as 40-in-1 believe the potential for acute effects is demographic group, 1.3 percent in the million due to actual emissions and as low for several reasons. First, the acute ‘‘Native American’’ demographic group high as 400-in-1 million due to MACT- modeling scenario is worst-case because and 16 percent in the ‘‘Over 25 and allowable emissions (100-in-1 million, of the confluence of peak emission rates without High School Diploma’’ based on the lower end of the benzene and worst-case dispersion conditions.

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Second, the benzene REL is based on a effective date. We are requesting $5,170/Mg ($4,700/ton) for control of 6-hour exposure duration because a comment on whether or not this is VOC for the options evaluated. A LDAR 1-hour exposure duration value was sufficient time for the large dehydrators program to control HAP would involve unavailable. An REL based on a 6-hour that have been relying on this similar costs for equipment, labor, etc., exposure duration is generally lower compliance alternative to come into to those considered in the NSPS than an REL based on a 1-hour exposure compliance with the 95-percent control assessment, but since there is duration and, consequently, easier to requirement or if additional time is approximately 20 times less HAP than exceed. Also, although there are needed. See CAA section 112(f)(4)(A). VOC present in material handled in exceedances of the REL, the highest We recognize that our proposal to regulated equipment, the cost estimated 1-hour exposure is less than remove the 0.9 Mg/yr compliance effectiveness to control HAP would be 10 percent of the AEGL–1 value, which alternative for the 95-percent control approximately 20 times greater (i.e., is a level at which effects could be glycol dehydrator MACT standard could $100,000/Mg) for HAP, which we experienced. Finally, the generally have negative impacts on some sources believe is not reasonable. that have come to rely on the flexibility sparse populations near these facilities In accordance with the approach this alternative provides. We solicit make it less likely that a person would established in the Benzene NESHAP, comment on any such impacts and be near the plant to be exposed. For the EPA weighed all health risk example, in the two cases where the whether such impacts warrant adding a measures and information considered in acute HQ value is as high as 9, there are different compliance alternative that the risk acceptability determination, only 30 people associated with the would result in less risk than the 0.9 along with the costs and economic census blocks within 2 miles of the two Mg/yr benzene limit compliance option. impacts of emissions controls, facilities. If a commenter suggests a different While our additional analysis of compliance alternative, the commenter technological feasibility, uncertainties facility-wide risks showed that there is should explain, in detail, what that and other relevant factors in making our one facility with maximum facility-wide alternative would be, how it would ample margin of safety determination. cancer risk of 100-in-1 million or greater work and how it would reduce risk. Considering the health risk information and 10 facilities with a maximum and the high cost effectiveness of the ii. Ample Margin of Safety chronic noncancer TOSHI greater than options identified, we propose that the 1, it also showed that oil and natural gas We next considered whether this existing MACT standards, with the production operations did not drive revised standard (existing MACT plus removal of the 1 tpy benzene limit these risks. removal of 0.9 Mg/yr benzene compliance option from the glycol In determining whether risk is compliance option) provides an ample dehydrator standards, provide an ample acceptable, we considered the available margin of safety. In this analysis, we margin of safety to protect public health. health information, as described above. investigated available emissions control While we are proposing that the oil In this case, although a number of options that might reduce the risk and natural gas production MACT factors we considered indicate relatively associated with emissions from the standards (with the removal of the low risk concern, we are proposing to source category and considered this alternative compliance option of 1 tpy determine that the risks are information along with all of the health benzene limit) provide an ample margin unacceptable, in large part, because the risks and other health information of safety to protect public health, we are MIR is 400-in-1 million due to MACT- considered in the risk acceptability concerned about the estimated facility- allowable emissions, which greatly determination. wide risks identified through these exceeds the ‘‘presumptive limit on For glycol dehydrators, we considered screening analyses. As described maximum individual lifetime risk of the addition of a second control device previously, the highest estimated approximately 1-in-10 thousand [100-in- in the same manner that was discussed facility-wide cancer risks are mostly due 1 million] recognized in the Benzene in the floor evaluation in section VII.B.1 to emissions from oil fired boilers and NESHAP (54 FR 38045).’’ The MIR, above. The cost effectiveness associated RICE. Both of these sources are based on MACT-allowable emissions, is with that option would be $167,200/Mg, regulated under other source categories driven by the allowable emissions of 0.9 which we believe is too high to require and we anticipate that emission Mg/yr benzene under the MACT as a additional controls on glycol reductions from those sources will compliance option. We are, therefore, dehydrators. occur as standards for those source proposing to eliminate the alternative Similarly, we considered the addition categories are implemented. compliance option of 0.9 Mg/yr benzene of a second control device to the from the existing glycol dehydrator required MACT floor control device 3. What are the results and proposed MACT requirements. With this change, (cost effectiveness of $18,300/Mg). decisions from the risk review for the the source category MIR, based on Similar to our discussion of beyond-the- Natural Gas Transmission and Storage MACT-allowable emissions, would be MACT-floor controls for glycol source category? reduced to 40-in-1 million, which we dehydrators in section VII.B.1 of this a. Results of the Risk Assessments and find acceptable in light of all the other preamble, the incremental cost to add a Analyses factors considered. Thus, we are second control device for storage vessels proposing that the risks from the Oil would be approximately 20 times higher We conducted an inhalation risk and Natural Gas Production source than the MACT floor cost effectiveness, assessment for the Natural Gas category are acceptable, with the or $366,000/Mg. We do not believe this Transmission and Storage source removal of the alternative compliance cost effectiveness is reasonable. category. We also conducted an option of 0.9 Mg/yr benzene limit from For leak detection, we considered assessment of facility-wide risk and the current glycol dehydrator MACT implementation of LDAR programs that performed a demographic analysis of requirements. are more stringent than the current population risks. Details of the risk Pursuant to CAA section 112(f)(4), we standards. An assessment performed for assessments and analyses can be found are proposing that this change (i.e., various LDAR options under the NSPS in the residual risk documentation, removal of the 0.9 Mg/yr compliance in section VI.B.4.b of this preamble which is available in the docket for this alternative) apply 90 days after its yielded the lowest cost effectiveness of action.

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i. Inhalation Risk Assessment Results assessment. For informational purposes each source category, we performed a Table 5 provides an overall summary and to examine the potential for any EJ demographic analysis of population of the results of the inhalation risk issues that might be associated with risks.

TABLE 5—NATURAL GAS TRANSMISSION AND STORAGE INHALATION RISK ASSESSMENT RESULTS

Maximum individual cancer risk Estimated Estimated Maximum chronic noncancer (in 1 million) 2 annual cancer TOSHI 4 Maximum Number of population at incidence off-site acute Facilities 1 risk ≥ 1-in-1 Actual Allowable emis- (cases per Actual Allowable emis- noncancer HQ 5 emissions level sions level million year) emissions level sions level

3 3 3 3 321 30–90 30–90 2,500 0.0003–0.001 0.4 0.8 HQREL = 5 (benzene) HQAEGL–1 = 0.2 (chlorobenzene) 1 Number of facilities evaluated in the risk analysis. 2 Estimated maximum individual excess lifetime cancer risk. 3 The EPA IRIS assessment for benzene provides a range of equally-plausible URE (2.2E–06 to 7.8E–06 per ug/m3), giving rise to ranges for the estimates of cancer MIR and cancer incidence. Estimated population values are not scalable with benzene URE range, but would be lower using the lower end of the URE range. 4 Maximum TOSHI. The target organ with the highest TOSHI for the Natural Gas Transmission and Storage source category is the immune system. 5 The maximum estimated acute exposure concentration was divided by available short-term dose-response values to develop an array of HQ values.

As shown in Table 5 above, the would further reduce this population maximum lifetime individual cancer results of the inhalation risk assessment estimate). The maximum chronic risk would still be 90-in-1 million (30- performed using actual emissions data noncancer TOSHI value for the source in-1 million based on the lower end of indicate the maximum lifetime category could be up to 0.4 from the benzene URE range), based on both individual cancer risk could be as high emissions of benzene, indicating no actual and allowable emission levels, as 90-in-1 million, (30-in-1 million significant potential for chronic and the maximum chronic noncancer based on the lower end of the benzene noncancer impacts. TOSHI value could be as high as 0.8 at URE range), with benzene as the major As explained above in section the MACT-allowable emissions level. contributor to the risk. The total VII.C.1.b, our analysis of potential estimated cancer incidence from the differences between actual emission ii. Facility-Wide Risk Assessment source category is 0.001 excess cancer levels and emissions allowable under Results cases per year (0.0003 excess cancer the natural gas transmission and storage cases per year based on the lower end MACT standard indicate that MACT- A facility-wide risk analysis was also of the benzene URE range), or one case allowable emission levels may be up to conducted based on actual emissions in every polycyclic organic matter 1,000 50 times greater than actual emission levels. Table 6 below displays the years. Approximately 2,500 people are levels at some sources. However, results of the facility-wide risk estimated to have cancer risks at or because some sources are emitting at the assessment. For detailed facility-specific above 1-in-1 million as a result of the level allowed under the current results, see Table 2 of Appendix 6 of the emissions from 15 facilities (use of the NESHAP, the risk results from the risk document in the docket for this lower end of the benzene URE range inhalation risk assessment indicate the rulemaking.

TABLE 6—NATURAL GAS TRANSMISSION AND STORAGE FACILITY-WIDE RISK ASSESSMENT RESULTS

Number of Facilities Analyzed ...... 321

Cancer Risk: Estimated maximum facility-wide individual cancer risk (in 1 million) ...... 1 200 Number of facilities with estimated facility-wide individual cancer risk of 100-in-1 million or more ...... 3 Number of facilities at which the Natural Gas Transmission and Storage source category contributes 50 percent or more to the facility-wide individual cancer risks of 100-in-1 million or more ...... 1 Number of facilities with facility-wide individual cancer risk of 1-in-1 million or more ...... 74 Number of facilities at which the Natural Gas Transmission and Storage source category contributes 50 percent or more to the facility-wide individual cancer risk of 1-in-1 million or more ...... 10 Chronic Noncancer Risk: Maximum facility-wide chronic noncancer TOSHI ...... 80 Number of facilities with facility-wide maximum noncancer TOSHI greater than 1 ...... 30 Number of facilities at which the Natural Gas Transmission and Storage source category contributes 50 percent or more to the facility-wide maximum noncancer TOSHI of 1 or more ...... 0 1 We note that the MIR would be 100-in-1 million if the CIIT URE for formaldehyde were used instead of the IRIS URE.

The facility-wide MIR from all HAP standards is estimated to be 200-in-1 100-in-1 million or greater. The facility- emissions at any facility that contains million, based on actual emissions. Of wide MIR is 200-in-1 million at two of sources subject to the natural gas the 321 facilities included in this these facilities, driven by formaldehyde transmission and storage MACT analysis, three have facility-wide MIR of

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from RICE.37 Another facility has a operations. The facility-wide cancer wide risks. The chronic noncancer risks facility-wide risk of 100-in-1 million, risks at the facilities with risks of 1-in- at these facilities are primarily driven by with 90 percent of the risk attributed to 1 million or more are primarily driven acrolein emissions from RICE. natural gas transmission and storage. by formaldehyde emissions from RICE, There are 74 facilities with facility-wide which will be assessed in a future RTR iii. Demographic Risk Analysis Results MIR of 1-in-1 million or greater. Of for that category. The results of the demographic these facilities, 10 have natural gas The facility-wide maximum analyses performed to investigate the transmission and storage operations that individual chronic noncancer TOSHI is distribution of cancer risks at or above contribute greater than 50 percent to the estimated to be 80, based on actual facility-wide risks. As discussed above, emissions. Of the 321 facilities included 1-in-1 million among the surrounding we are proposing MACT standards for in this analysis, 30 have facility-wide population are summarized in Table 7 benzene emissions from small glycol maximum chronic noncancer TOSHI below. These results, for various dehydrators in this action. These values greater than 1. Of these facilities, demographic groups, are based on standards would reduce the risk from none had natural gas transmission and actual emissions levels for the benzene emissions at facilities with storage operations that contributed population living within 50 km of the natural gas transmission and storage greater than 50 percent to these facility- facilities.

TABLE 7—NATURAL GAS TRANSMISSION AND STORAGE DEMOGRAPHIC RISK ANALYSIS RESULTS

Population with cancer risk at or above 1-in-1 million due to . . . Nationwide Source category Facility-wide HAP HAP emissions emissions

Total Population ...... 285,000,000 2,500 99,000

Race by Percent

White ...... 75 92 58 All Other Races ...... 25 8 42

Race by Percent

White ...... 75 92 58 African American ...... 12 6 40 Native American ...... 0.9 0.1 0.2 Other and Multiracial ...... 12 1 2

Ethnicity by Percent

Hispanic ...... 14 1 2 Non-Hispanic ...... 86 99 98

Income by Percent

Below Poverty Level ...... 13 17 20 Above poverty level ...... 87 83 80

Education by Percent

Over 25 and without High School Diploma ...... 13 20 15 Over 25 and with a High School Diploma ...... 87 80 85

The results of the Natural Gas High School Diploma’’ demographic the 99,000 people with estimated cancer Transmission and Storage source group, results which are 4 and 7 risk at or above 1-in-1 million from category demographic analysis indicate percentage points higher, respectively, facility-wide emissions, 40 percent are that there are approximately 2,500 than the percentages for these in the ‘‘African American’’ demographic people exposed to a cancer risk at or demographic groups across the United group, 20 percent are in the ‘‘Below above 1-in-1 million due to emissions States. The percentages for the other Poverty Level’’ demographic group, and from the source category, including an demographic groups are lower than 15 percent are in the ‘‘Over 25 and estimated 8 percent that are classified as their respective nationwide percentages. without High School Diploma’’ minority (listed as ‘‘All Other Races’’ in The table also shows that there are demographic group, results which are Table 7 above). Of the 2,500 people with approximately 99,000 people exposed to 28, 7 and 2 percentage points higher, estimated cancer risks at or above 1-in- an estimated cancer risk at or above 1- respectively, than the percentages for 1 million from the source category, 17 in-1 million due to facility-wide these demographic groups across the percent are in the ‘‘Below Poverty emissions, including an estimated 42 Level’’ demographic group, and 20 percent that are classified as minority United States. The percentages for the percent are in the ‘‘Over 25 and without (‘‘All Other Races’’ in Table 7 above). Of other demographic groups are equal to

37 We note that there is an ongoing IRIS risk assessments will use the cancer potency for As a result, the current results may not match those reassessment for formaldehyde, and that future RTR formaldehyde that results from that reassessment. of future assessments.

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or lower than their respective proposing to determine that the risks are the risk acceptability determination, nationwide percentages. acceptable. along with the costs and economic impacts of emissions controls, b. What are the proposed risk decisions ii. Ample Margin of Safety technological feasibility, uncertainties for the Natural Gas Transmission and We next considered whether the Storage source category? and other relevant factors in making our existing MACT standard provides an ample margin of safety determination. i. Risk Acceptability ample margin of safety. In this analysis, Considering the health risk information we investigated available emissions and the reasonable cost effectiveness of In the risk analysis we performed for control options that might reduce the this source category, pursuant to CAA the option identified, we propose that risk associated with emissions from the the existing MACT standards, with the section 112(f)(2), we considered the source category and considered this removal of the 0.9 Mg benzene limit available health information—the MIR; information, along with all of the health compliance option from the glycol the numbers of persons in various risk risks and other health information dehydrator standards, provide an ample ranges; cancer incidence; the maximum considered in the risk acceptability noncancer HI; the maximum acute determination. The estimated MIR of 90- margin of safety to protect public health. noncancer hazard; the extent of in-1 million discussed above is driven Pursuant to CAA section 112(f)(4), we noncancer risks; the potential for by the 0.9 Mg/year benzene limit are proposing that this change (i.e., adverse environmental effects; compliance alternative for the glycol removal of the 0.9 Mg/yr compliance distribution of risks in the exposed dehydrator MACT standard in the alternative) apply 90 days after its population; and risk estimation current NESHAP. Removal of this effective date. We are requesting uncertainty (54 FR 38044, September compliance alternative would lower the comment on whether or not there is 14, 1989). MIR for the source category to 20-in-1 sufficient time for the large dehydrators For the Natural Gas Transmission and million. We, therefore, considered that have been relying on this Storage source category, the risk removing this compliance alternative as compliance alternative to come into analysis we performed indicates that the an option for reducing risk and assessed compliance with the 95-percent control cancer risks to the individual most the cost of such alternative. Without the requirement or if additional time is exposed could be as high as 90-in-1 compliance alternative, affected glycol needed. See CAA section 112(f)(4)(A). million due to actual and allowable dehydrators (i.e., those units with annual average benzene emissions of 0.9 We recognize that our proposal to emissions (30-in-1 million, based on the remove the one-ton compliance lower end of the benzene URE range). Mg/yr or greater and an annual average natural gas throughput of 283,000 scmd alternative for the 95-percent control These risks are near 100-in-1 million, glycol dehydrator MACT standard could which is the presumptive limit of or greater) must demonstrate compliance with the 95-percent control have negative impacts on some sources acceptability. On the other hand, the that have come to rely on the flexibility risk analysis shows low cancer requirement, which we believe can be this alternative provides. We solicit incidence (1 case in every 1,000 years), shown with their existing control comment on any such impacts and low potential for adverse environmental devices in most cases, although, in some whether such impacts warrant adding a effects or human health multi-pathway instances, installation of a different or different compliance alternative that effects and that chronic and acute an additional control may be necessary. would result in less risk than the 0.9 noncancer health impacts are unlikely. In section VII.B.1 above, we discuss We conclude that acute noncancer the costs for requiring controls on Mg/yr benzene limit compliance option. health impacts are unlikely for reasons currently unregulated ‘‘small glycol If a commenter suggests a different similar to those described in section dehydrators,’’ which are similar, in compliance alternative, the commenter VII.C.2.b.i of this preamble. operation and type of emission controls, should explain, in detail, what that to the dehydrators subject to the current alternative would be, how it would Our additional analysis of facility- MACT (‘‘large dehydrators’’). The HAP work, and how it would reduce risk. wide risks showed that, among three cost effectiveness determined for small As described above, we are proposing facilities with maximum facility-wide dehydrators at the floor level of control that the natural gas transmission and cancer risk of 100-in-1 million or was $1,650/Mg. Although control storage MACT standards (with the greater, one facility has a facility-wide methodologies are similar for large and removal of the 0.9 Mg/yr benzene limit cancer risk of 100-in-1 million, with 90 small dehydrators, we expect that the compliance option) provide an ample percent of the risk attributed to natural costs for controls on large units could be gas and transmission and storage. There as much as twice as high as for small margin of safety to protect public health. are 30 facilities with a maximum units because of the large gas flow being We recognize that one facility has a chronic noncancer TOSHI greater than processed. However, we also expect that facility-wide cancer risk of 100-in-1 1, but natural gas transmission and the amount of HAP emission reduction million, with 90 percent of the risk storage operations did not drive this for the large dehydrators, in general, to attributed to natural gas transmission risk. be as much as, or more than, the amount and storage. This risk is driven by In determining whether risk is achieved by small dehydrators. In light benzene emissions from glycol acceptable, we considered the available of the above, we do not expect the cost dehydrators and is being addressed by health information, as described above. effectiveness of the control device our proposed revision to the Natural Gas In this case, because the MIR is needed to meet the 95-percent control Transmission and Storage NESHAP approaching, but still less than 100-in- requirement for large dehydrators to (removal of the 0.9 Mg/yr benzene limit 1 million risk, and because a number of exceed $3,300/Mg (i.e., twice the cost compliance option). As previously other factors indicate relatively low risk effectiveness for small dehydrators), mentioned, two facilities have facility- concern (e.g., low cancer incidence, low which we consider to be reasonable. wide MIR of 200-in-1 million, driven by potential for adverse environmental In accordance with the approach formaldehyde from RICE. Emissions effects or human health multi-pathway established in the Benzene NESHAP, from RICE are regulated under another effects, chronic and acute noncancer the EPA weighed all health risk source category and will be assessed health impacts unlikely), we are measures and information considered in under a future RTR for that category.

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D. How did we perform the technology emission sources in the source addressed by both 40 CFR part 63, review and what are the results and categories under this current RTR subpart HH and 40 CFR part 63, subpart proposed decisions? review. HHH, while equipment leaks and We also consulted the EPA’s RBLC. storage vessels with the PFE are only 1. What was the methodology for the The terms ‘‘RACT,’’ ‘‘BACT,’’ and covered by subpart HH. technology review? ‘‘LAER’’ are acronyms for different Since the promulgation of 40 CFR part Our technology review is focused on program requirements under the CAA 63, subpart HH, which established the identification and evaluation of provisions addressing the NAAQS. MACT standards to address HAP ‘‘developments in practices, processes, Control technologies classified as RACT, emissions from equipment leaks at gas and control technologies’’ since the BACT or LAER apply to stationary processing plants, the EPA has promulgation of the MACT standards sources depending on whether the developed LDAR programs that are for the two oil and gas source categories. source exists or is new and on the size, more stringent than what is required in If a review of available information age and location of the facility. The subpart HH. The most prevalent identifies such developments, then we BACT and LAER (and sometimes RACT) differences between these more conduct an analysis of the technical are determined on a case-by-case basis, stringent programs and subpart HH feasibility of requiring the usually by state or local permitting relate to the frequency of monitoring implementation of these developments, agencies. The EPA established the RBLC and the concentration which constitutes along with the impacts (costs, emission to provide a central database of air a ‘‘leak.’’ We do consider these reductions, risk reductions, etc.). We pollution technology information programs to represent a development in then make a decision on whether it is (including technologies required in practices and evaluated whether to necessary to amend the regulation to source-specific permits) to promote the revise the MACT standards for require these developments. sharing of information among equipment leaks at natural gas Based on specific knowledge of each permitting agencies and to aid in processing plants under subpart HH in source category, we began by identifying identifying future possible control light of this development. known developments in practices, technology options that might apply An analysis was performed above in processes and control technologies. For broadly to numerous sources within a section VI.B.1 to assess the VOC the purpose of this exercise, we category or apply only on a source-by- reduction, costs and other impacts considered any of the following to be a source basis. The RBLC contains over associated with these more stringent ‘‘development’’: 5,000 air pollution control permit LDAR program options at natural gas • Any add-on control technology or determinations that can help identify processing plants. One option other equipment that was not identified appropriate technologies to mitigate considered was to require compliance and considered during MACT many air pollutant emission streams. with 40 CFR part 60, subpart VVa development; We searched this database to determine • instead of 40 CFR part 60, subpart VV Any improvements in add-on whether any practices, processes or (the current NSPS requirement for control technology or other equipment control technologies are included for the equipment leaks of VOC at natural gas (that was identified and considered types of processes used for emission processing plants), which changes the during MACT development) that could sources (e.g., spray booths) in the source leak definition (based on methane) from result in significant additional emission categories under consideration in this 10,000 ppm to 500 ppm and requires reduction; proposal. monitoring of connectors. Because the • Any work practice or operational We also consulted information from current leak definition under NESHAP procedure that was not identified and the Natural Gas STAR program. The 40 CFR part 63, subpart HH is the same considered during MACT development; Natural Gas STAR program is a flexible, as that in NSPS subpart VV, and the and voluntary partnership that encourages ratio of VOC to HAP is approximately • Any process change or pollution oil and natural gas companies to adopt prevention alternative that could be 20 to 1, we expect that the HAP cost effective technologies and practices reduction would be 1/20th of the VOC broadly applied that was not identified that improve operational efficiency and and considered during MACT reduction under subpart VVa. The reduce pollutant emissions. The estimated incremental cost for that development. program provides the oil and gas In addition to looking back at option was determined to be $3,340 per industry with information on new ton of VOC. Based on the 20-to-1 ratio, practices, processes or control techniques and developments to reduce technologies reviewed at the time we we estimate the incremental cost to pollutant emissions from the various control HAP at the subpart VVa level developed the MACT standards, we processes. reviewed a variety of sources of data to would be approximately $66,800 per ton aid in our evaluation of whether there 2. What are the results and proposed of HAP ($73,480/Mg). Other options were additional practices, processes or decisions from the technology review? considered in section VI.B.1 of this controls to consider. One of these There are three types of emission preamble (and the incremental cost of sources of data was subsequent air sources covered by the two oil and gas each option for reducing HAP) are as toxics rules. Since the promulgation of NESHAP. These sources and the control follows: The use of an optical gas the MACT standards for the source technologies (including add-on control imaging camera monthly with an annual categories addressed in this proposal, devices and process modifications) EPA Method 21 check ($129,000 per ton the EPA has developed air toxics considered during the development of of HAP/$143,600 per Mg, if purchasing regulations for a number of additional the MACT standards are: Glycol the camera; $93,000 per ton of HAP/ source categories. We reviewed the dehydrators (combustion devices, $103,300 per Mg, if renting the camera); regulatory requirements and/or recovery devices, process monthly optical gas imagining alone; 38 technical analyses associated with these modifications), storage vessels with the and annual optical gas imaging. In subsequent regulatory actions to PFE (combustion devices, recovery 38 As stated above in section VI.B.1, emissions for identify any practices, processes and devices) and equipment leaks (LDAR the two options using the optical gas imaging control technologies considered in these programs, specific equipment camera alone cannot be quantified and, therefore, efforts that could possibly be applied to modifications). Dehydrators are no cost effectiveness values were determined.

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light of the above, we do not believe that Our review of the RBLC did not clearance above the flame zone. Such the additional costs of these programs identify any practices, processes and extensions can more easily be are justified. control technologies applicable to the configured by the manufacturer of the In addition to the plant-wide emission sources in these categories that control device rather than having to evaluations, a component analysis was were not identified and evaluated modify an extension in the field to fit also evaluated at gas processing plants during the original MACT development. devices at every site. Issues related to for the 40 CFR part 60, subpart VVa- In light of the above, we are not transporting, installing and supporting level of control (option 1 considered in proposing any revisions to the existing the extension in the field are also section VI.B.1).39 That assessment MACT standards for storage vessels eliminated through manufacturer shows that the subpart VVa-level of pursuant to section 112(d)(6) of the testing. Another concern is that the pitot control for connectors has an CAA. tube used to measure flow can be incremental cost effectiveness of $4,360 altered by radiant heat from the flame E. What other actions are we proposing? per ton for VOC for connectors and $144 such that gas flow rates are not accurate. per ton for VOC for valves. This means 1. Combustion Control Device Testing This issue is best overcome by having the incremental cost to control HAP As explained below in section VII.E.2, the manufacturer select and use the would be approximately $87,200 per ton under our proposal, performance testing pitot tube best suited to their specific ($96,900/Mg) for connectors and $2,880 would be required initially and every 5 unit. For these reasons, we believe the manufacturers’ test is appropriate for per ton ($3,200/Mg) for valves. We do years for non-condenser control devices. these control devices with ongoing not believe the additional cost for the However, for certain enclosed performance ensured by periodic more stringent requirement for combustion control devices, we are inspection and maintenance. connectors is justified, but the proposing to allow, as an alternative to additional cost for valves is justified. This proposed alternative does not on-site testing, a performance test apply to flares, as defined in 40 CFR Therefore, we are proposing to revise conducted by a control device the equipment leak requirements in 40 63.761 and 40 CFR 63.1271, which must manufacturer in accordance with the demonstrate compliance by meeting the CFR part 63, subpart HH to lower the procedures provided in this proposal. leak definition for valves to an design and operation requirements in 40 We propose to allow a unit whose CFR 63.11(b), 40 CFR 63.772(e)(2) and instrument reading of at least 500 ppm model meets the proposed performance as a result of our technology review. 40 CFR 63.1282(d)(2). It also would not criteria to claim a BTEX or HAP apply to thermal oxidizers having a Some of the practices, processes or destruction efficiency of 98 percent at control technologies listed by the combustion chamber/firebox where the facility. This value is lower than the combustion temperature and residence Natural Gas STAR program applicable 99.9-percent destruction efficiency to the emission sources in these time can be measured during an on-site required in the manufacturers’ test due performance test and are valid categories were not identified and to variations between the test fuel evaluated during the original MACT indicators of performance. These specified and the gas streams combusted thermal oxidizers do not present the development. While the Natural Gas at the actual facility. A source subject to STAR program does contain information issues described above relative to on- the small dehydrator BTEX limit would site performance testing and, therefore, regarding new innovative techniques use the 98-percent destruction that are available to reduce HAP do not need an alternative testing efficiency to calculate their dehydrator’s option. The proposed alternative would, emissions, they are not considered to BTEX emissions for the purpose of have emission reductions higher than therefore, apply to enclosed combustion demonstrating compliance. For the control devices except for these thermal what is set by the original MACT. One 95-percent control MACT standard, a control technology identified in the oxidizers. control device matching the tested In conjunction with the proposed Natural Gas STAR program that would model would be considered to meet that manufacturer testing alternative, we are result in no HAP emissions from glycol requirement. Once a device has been proposing to add a definition for flare to dehydration units would be the demonstrated to meet the proposed clarify that flares, as referenced in the replacement of a glycol dehydration performance criteria (and, therefore, is NESHAP (and to which the proposed unit with a desiccant dehydrator. This assigned a 98-percent destruction testing alternative does not apply), technology cannot be used for natural efficiency), installation of a unit refers to a thermal oxidation system gas operations with gas streams having matching the tested model at a facility with an open flame (i.e., without high temperature, high volume, and low would require no further performance enclosure). Accordingly, any thermal pressure. Due to the limitations posed testing (i.e., periodic tests would not be oxidation system that does not meet the by these conditions, we do not consider required every 5 years). proposed flare definition would be desiccant dehydrators as MACT. We are proposing this alternative to considered an enclosed combustion For storage vessels, the applicable minimize issues associated with control device. technologies identified by the Gas STAR performance testing of certain We estimate that there are many program, which are evaluated above for combustion control devices. We believe existing facilities currently using proposal under NSPS in section VI.B.4, that testing units that are not configured enclosed combustion control devices are similar to the cover and control with a distinct combustion chamber that would be required to either conduct technologies currently required for present several technical issues that are an on-site performance test or install storage vessels under the existing more optimally addressed through and operate a control device tested by MACT. Therefore, these technologies manufacturer testing, and once these the manufacturer under our proposal. would not result in any further units are installed at a facility, through Given the estimated number of these emissions reductions than what is periodic inspection and maintenance in combustion control devices in use, the achieved by the original MACT. accordance with manufacturers’ time required for manufacturers to test recommendations. One issue is that an and manufacture such units, we are 39 Because optical gas imaging is used to view extension above certain existing proposing that existing sources have up several pieces of equipment at a facility at once to survey for leaks, options involving imaging are not combustion control device enclosures to 3 years from the date of the final amenable to a component by component analysis. will be necessary to get adequate rules’ publication date to comply with

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the initial performance testing There are variables (e.g., air to fuel minimum temperature of 760 degrees requirements. ratios and waste constituents for Celsius. We are proposing to remove the combustion; varying organic residence time requirement. The 2. Monitoring, Recordkeeping and concentrations, constituents and residence time requirement is not Reporting capacity issues, including break-through needed because the compliance We are proposing to make changes to for carbon adsorption) that make demonstration made during the the monitoring requirements described theoretical predictions less reliable. The performance test is sufficient to ensure below to address issues we have effects of these site-specific variables on that the combustion device has adequate identified through a monitoring emissions are not easily predictable and residence time to ensure the needed sufficiency review performed during the establishing monitoring conditions (e.g., destruction efficiency. Therefore, we are RTR process. First, we are including combustion temperature, vacuum proposing to remove the residence time calibration procedures associated with regeneration) based on vendor data will requirement. parametric monitoring requirements in likely not account for those variables. We are also clarifying at 40 CFR the existing NESHAP. The NESHAP Therefore, we propose to eliminate the 63.773(d)(3)(i) and 40 CFR require parametric monitoring of control design evaluation alternative for non- 63.1283(d)(3)(i) for thermal vapor device parameters (e.g., temperatures or condenser controls. incinerators, boilers and process flowrate monitoring), but did not For non-condenser controls (and heaters, that the temperature sensor include information on calibration or condensers not using the design shall be installed at a location included inadequate information on analysis option), in addition to the representative of the combustion zone calibration of monitoring devices. initial compliance testing, we are temperature. Currently, the regulation Therefore, we are specifying the proposing that performance tests be requires that the temperature sensor be calibration requirements for temperature conducted at least once every 5 years installed at a location ‘‘downstream of and flow monitors that the NESHAP and whenever sources desire to the combustion zone’’ because we had currently lacks. establish new operating limits. Under thought that the temperature In addition, under the current the current NESHAP, a performance test downstream would be representative of NESHAP, a design analysis can be used is only conducted in two instances: (1) combustion zone temperature. We have in lieu of performance testing to As an alternative to a design analysis for now learned that may or may not be the demonstrate compliance and establish their compliance demonstration and case. We are, therefore, proposing to operating parameter limits. We are identification of operating parameter amend this provision to more accurately proposing to allow the use of the design ranges and (2) as a requirement to reflect the intended requirement. evaluation alternative only when the resolve a disagreement between the EPA Next, consistent with revisions for and the owner or operator regarding the control device being used is a SSM, we’ve revised 40 CFR design analysis. The current NESHAP condenser. The design evaluation 63.771(d)(4)(i) and 40 CFR do not require additional performance option is appropriate for condensers 63.1281(d)(4)(i), except when testing beyond these two cases (i.e., because their emissions can be maintenance or repair on a unit cannot there is no periodic testing accurately predicted using readily be completed without a shutdown of the requirement). As mentioned above, we available physical property information control device. (e.g., vapor pressure data and are proposing to remove the design evaluation option for non-condenser Also, we’ve updated the criteria for condensation calculations). In those prior performance test results that can cases, one would not need to conduct controls. For non-condenser controls (and condensers not using the design be used to demonstrate compliance in emissions testing to determine actual lieu of conducting a performance test. emissions to demonstrate compliance analysis option), the proposed periodic testing would ensure compliance with These updates ensure that data for with the MACT standard. For example, determining compliance are accurate, a requirement that ‘‘the temperature at the emission standards by verifying that the control device is meeting the up-to-date, and truly representative of the outlet of the condenser shall be actual operating conditions. ° necessary HAP destruction efficiency maintained at 50 Fahrenheit below the In addition, we are proposing to condensation temperature calculated for determined in the initial performance test. As discussed above in section revise the temperature monitoring the compound of interest using the device minimum accuracy criteria in 40 reference equation’’ (e.g., National VII.E.1, we are proposing that combustion control devices tested under CFR 63.773(d)(3)(i) to better reflect the Institute of Standards and Technology the manufacturers’ procedure are not level of performance that is required of Chemistry WebBook at http:// required to conduct periodic testing. In the temperature monitoring devices. We webbook.nist.gov/chemistry/) is addition, we are also proposing that believe that temperature monitoring adequate to assure proper operation of combustion control devices that can devices currently used to meet the the condenser and, therefore, demonstrate a uniform combustion zone requirements of the NESHAP can meet compliance with the required emission temperature meeting the required the proposed revised criteria without standard. control efficiency during the initial modification. For other types of control performance test are exempt from Also, we are proposing to revise the technologies, such as carbon adsorption periodic testing. The requirement for calibration gas concentration for the no systems and enclosed combustion detectable emissions procedure 40 continuous monitoring of combustion devices, the ability to predict zone temperature is an accurate applicable to closed vent systems in 40 emissions depends on data developed indicator of control device performance CFR 63.772(c)(4)(ii) from 10,000 ppmv by the vendor and such data may not and eliminates the need for future to 500 ppmv methane to be consistent reliably result in an accurate prediction testing. with the leak threshold of 500 ppmv in of emissions from a specific facility. The current NESHAP (40 CFR 40 CFR part 63, subpart HH. The current 63.771(d) and 40 CFR 63.1281(d)) calibration level is inconsistent with 40 The design analysis alternative in the existing MACT does not apply to flares. As previously require operating an enclosed achieving accurate readings at the level mentioned, the existing MACT provides separate combustion device at a minimum necessary to demonstrate there are no design and operation requirements for flares. residence time of 0.5 seconds at a detectable emissions.

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Also, we are proposing recordkeeping exempt sources from the requirement to the innumerable types of potential and reporting requirements for carbon comply with the otherwise applicable malfunction events in setting emission adsorption systems. The current CAA section 112(d) emission standard standards. See Weyerhaeuser v. Costle, NESHAP require the replacement of all during periods of SSM. 590 F.2d 1011, 1058 (D.C. Cir. 1978), carbon in the carbon adsorption system We are proposing the elimination of (‘‘In the nature of things, no general with fresh carbon on a regular, the SSM exemption in the two oil and limit, individual permit, or even any predetermined time interval that is no gas NESHAP. Consistent with Sierra upset provision can anticipate all upset longer than the carbon service life Club v. EPA, the EPA is proposing to situations. After a certain point, the established for the carbon system, but apply the standards in these NESHAP at transgression of regulatory limits caused provide no recordkeeping or reporting all times. In addition, we are proposing by ‘‘uncontrollable acts of third parties,’’ requirement to document and assure to revise 40 CFR 63.771(d)(4)(i) and 40 such as strikes, sabotage, operator compliance with this standard. We CFR 63.1281(d)(4)(i) to remove the intoxication or insanity, and a variety of believe that maintaining some sort of log provision allowing shutdown of the other eventualities, must be a matter for book is a reasonable alternative control device during maintenance or the administrative exercise of case-by- combined with a requirement to report repair. We are also proposing several case enforcement discretion, not for instances when specified practices are revisions to the General Provisions specification in advance by not followed. Therefore, the proposed applicability table for the MACT regulation.’’). rule adds reporting and recordkeeping standard. For example, we are Further, it is reasonable to interpret requirements for establishing a schedule proposing to eliminate the incorporation CAA section 112(d) as not requiring the and maintaining logs of carbon of the General Provisions’ requirement EPA to account for malfunctions in replacement. that the source develop a SSM plan. We setting emissions standards. For Finally, as noted above in section are also proposing to eliminate or revise example, we note that CAA section 112 VII.B.1, we are proposing a BTEX certain recordkeeping and reporting uses the concept of ‘‘best performing’’ emissions limit for small glycol requirements related to the SSM sources in defining MACT, the level of dehydration unit process vents. For the exemption. The EPA has attempted to stringency that major source standards compliance demonstration, we propose ensure that we have not included in the must meet. Applying the concept of that parametric monitoring of the proposed regulatory language any ‘‘best performing’’ to a source that is control device be performed. We believe provisions that are inappropriate, malfunctioning presents significant that parametric monitoring is adequate unnecessary or redundant in the difficulties. The goal of best performing for glycol dehydrators in these two absence of the SSM exemption. We are sources is to operate in such a way as source categories because temperature specifically seeking comment on to avoid malfunctions of their units. monitoring, whether it be to verify whether there are any such provisions Moreover, even if malfunctions were proper condenser or combustion device that we have inadvertently incorporated considered a distinct operating mode, operation, is a reliable indicator of or overlooked. we believe it would be impracticable to performance for reducing organic HAP In proposing the MACT standards in emissions. We also considered the use these rules, the EPA has taken into take malfunctions into account in of a continuous emissions monitoring account startup and shutdown periods. setting CAA section 112(d) standards for system (CEMS) to monitor compliance. We believe that operations and oil and natural gas production facility However, for glycol dehydrators in the emissions do not differ from normal and natural gas transmission and storage oil and natural gas sector, the necessary operations during these periods such operations. As noted above, by electricity, weather-protective that it warrants a separate standard. definition, malfunctions are sudden and enclosures and daily staffing are not Therefore, we have not proposed unexpected events, and it would be usually available. We, therefore, different standards for these periods. difficult to set a standard that takes into question the technical feasibility of Periods of startup, normal operations account the myriad different types of operating a CEMS correctly in this and shutdown are all predictable and malfunctions that can occur across all sector. We request comment on the routine aspects of a source’s operations. sources in each source category. practicality of including provisions in However, by contrast, malfunction is Moreover, malfunctions can also vary in the final rule for a CEMS to monitor defined as a ‘‘sudden, infrequent and frequency, degree and duration, further BTEX emissions for small glycol not reasonably preventable failure of air complicating standard setting. dehydration units. pollution control and monitoring In the event that a source fails to equipment, process equipment or a comply with the applicable CAA section 3. Startup, Shutdown, Malfunction process to operate in a normal or usual 112(d) standards as a result of a The United States Court of Appeals manner * * *’’ (40 CFR 63.2). The EPA malfunction event, the EPA would for the District of Columbia Circuit has determined that malfunctions determine an appropriate response vacated portions of two provisions in should not be viewed as a distinct based on, among other things, the good the EPA’s CAA section 112 regulations operating mode and, therefore, any faith efforts of the source to minimize governing the emissions of HAP during emissions that occur at such times do emissions during malfunction periods, periods of SSM. Sierra Club v. EPA, 551 not need to be factored into including preventative and corrective F.3d 1019 (D.C. Cir. 2008), cert. denied, development of CAA section 112(d) actions, as well as root cause analyses 130 S. Ct. 1735 (U.S. 2010). Specifically, standards, which, once promulgated, to ascertain and rectify excess the Court vacated the SSM exemption apply at all times. In Mossville emissions. The EPA would also contained in 40 CFR 63.6(f)(1) and 40 Environmental Action Now v. EPA, 370 consider whether the source’s failure to CFR 63.6(h)(1), that is part of a F.3d 1232, 1242 (D.C. Cir. 2004), the comply with the CAA section 112(d) regulation, commonly referred to as the Court upheld as reasonable, standards standard was, in fact, ‘‘sudden, General Provisions Rule, that the EPA that had factored in variability of infrequent, not reasonably preventable’’ promulgated under section 112 of the emissions under all operating and was not instead ‘‘caused in part by CAA. When incorporated into CAA conditions. However, nothing in CAA poor maintenance or careless section 112(d) regulations for specific section 112(d) or in case law requires operation.’’ 40 CFR 63.2 (definition of source categories, these two provisions that the EPA anticipate and account for malfunction).

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Finally, the EPA recognizes that even accordance with 40 CFR 63.762 for this occurrence and data demonstrating equipment that is properly designed and sources subject to the oil and natural gas the circumstances where it occurs. In maintained can sometimes fail and that production facilities MACT standards or light of the potential issue, we are such failure can sometimes cause or 40 CFR 63.1272 for sources subject to asking for comment regarding the contribute to an exceedance of the the natural gas transmission and storage addition of provisions in the NESHAP relevant emission standard. (See, e.g., facilities MACT standards and to to require area sources to recalculate State Implementation Plans: Policy prevent future malfunctions. For their PTE to confirm that they are Regarding Excessive Emissions During example, the source must prove by a indeed area sources and whether that Malfunctions, Startup, and Shutdown preponderance of evidence that calculation should be performed on an (September 20, 1999); Policy on Excess ‘‘[r]epairs were made as expeditiously as annual or biannual basis to verify that Emissions During Startup, Shutdown, possible when the applicable emission changes in gas composition have not Maintenance, and Malfunctions limitations were being exceeded * * *’’ increased their emissions. (February 15, 1983)). The EPA is, and that ‘‘[a]ll possible steps were taken b. Definition of Facility and therefore, proposing to add to the final to minimize the impact of the excess Applicability Criteria rule an affirmative defense to civil emissions on ambient air quality, the Subpart HH of 40 CFR part 63 (section penalties for exceedances of emission environment and human health * * *.’’ 63.760(a)(2)) currently defines facilities limits that are caused by malfunctions In any judicial or administrative as those where hydrocarbon liquids are in both of the MACT standards proceeding, the Administrator may challenge the assertion of the affirmative processed, upgraded or stored prior to addressed in this proposal. See 40 CFR the point of custody transfer or where 63.761 for sources subject to the oil and defense and, if the respondent has not met its burden of proving all of the natural gas is processed, upgraded or natural gas production MACT stored prior to entering the Natural Gas standards, or 40 CFR 63.1271 for requirements in the affirmative defense, appropriate penalties may be assessed Transmission and Storage source sources subject to the natural gas category. We are proposing to remove transmission and storage MACT in accordance with section 113 of the CAA (see also 40 CFR 22.77). the references to ‘‘point of custody standards (defining ‘‘affirmative transfer’’ and ‘‘transmission and storage defense’’ to mean, in the context of an 4. Applicability and Compliance source categories’’ from the definition enforcement proceeding, a response or a. Calculating Potential To Emit (PTE) because the operations performed at a defense put forward by a defendant, site sufficiently define a facility and the regarding which the defendant has the We are proposing to amend section 40 scope of the subpart is specified already burden of proof and the merits of which CFR 63.760(a)(1)(iii) to clarify that under 40 CFR 63.760. In addition, we are independently and objectively sources must use a glycol circulation are removing the custody transfer evaluated in a judicial or administrative rate consistent with the definition of reference from the applicability criteria proceeding). We also are proposing PTE in 40 CFR 63.2 in calculating in 40 CFR 63.760(a)(2). Since other regulatory provisions to specify emissions for purposes of determining hydrocarbon liquids can pass through the elements that are necessary to PTE. Affected parties have several custody transfer points between establish this affirmative defense; a misinterpreted the current language the well and the final destination, the source subject to the oil and natural gas concerning measured values or annual custody transfer criteria is not clear production facilities or natural gas average to apply to a broader range of enough. We are, therefore, proposing to transmission MACT standards must parameters than was intended. Those replace the reference to ‘‘point of prove by a preponderance of the qualifiers were meant to apply to gas custody transfer’’ with a more specific evidence that it has met all of the characteristics that are measured, such description of the point up to which the elements set forth in 40 CFR 63.762 and as inlet gas composition, pressure and subpart applies (i.e., the point where a source subject to the natural gas temperature rather than process hydrocarbon liquids enter either the transmission and storage facilities equipment settings. That means that the organic liquids distribution or MACT standards must prove by a circulation rate used in PTE petroleum refineries source categories) preponderance of the evidence that it determinations shall be the maximum and exclude custody transfer from that has met all of the elements set forth in under its physical and operational criteria. We believe this change 40 CFR 63.1272. (See 40 CFR 22.24.) design. eliminates ambiguity and is consistent The criteria ensure that the affirmative In addition to the proposed changes with the oil and natural gas production- defense is available only where the described above, we are seeking specific provisions in the organic event that causes an exceedance of the comment on several PTE related issues. liquids distribution MACT. emission limit meets the narrow According to the data available to the definition of malfunction in 40 CFR 63.2 Administrator, when 40 CFR part 63, 5. Other Proposed Changes To Clarify (sudden, infrequent, not reasonably subpart HH was promulgated, the level These Rules preventable and not caused by poor of HAP emissions was predominantly The following lists additional changes maintenance and or careless operation). driven by natural gas throughput (i.e., to the NESHAP we are proposing. This For example, to successfully assert the HAP emissions went up or down in list includes proposed rule changes that affirmative defense, the source must concert with natural gas throughput). address editorial corrections and plain prove by a preponderance of evidence Since promulgation, we have learned language revisions: that excess emissions ‘‘[w]ere caused by that there is not always a direct • Revise 40 CFR 63.769(b) to clarify a sudden, infrequent, and unavoidable correlation between HAP emissions and that the equipment leak provisions in 40 failure of air pollution control and natural gas throughput. We have CFR part 63, subpart HH do not apply monitoring equipment, process received information suggesting that, in to a source if that source is required to equipment, or a process to operate in a some cases, HAP emissions can increase control equipment leaks under either 40 normal or usual manner * * *.’’ The despite decreasing natural gas CFR part 63, subpart H or 40 CFR part criteria also are designed to ensure that throughput due to changes in gas 60, subpart KKK. The current 40 CFR steps are taken to correct the composition. We are asking for 63.769(b), which states that subpart HH malfunction, to minimize emissions in comment regarding the likelihood of does not apply if a source meets the

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requirements in either of the subparts A. What are the affected sources? B. How are the impacts for this proposal mentioned above, does not clearly evaluated? We expect that by 2015, the year express our intent that such source must For these proposed Oil and Natural be implementing the LDAR provisions when all existing sources will be required to come into compliance in the Gas Production and Natural Gas in the other 40 CFR part 60 or 40 CFR Transmission and Storage NESHAP United States, there will be 97 oil and part 63 subparts to qualify for the amendments and NSPS, the EPA used natural gas production facilities and 15 exemption. two models to evaluate the impacts of • Revise 40 CFR 63.760(a)(1) to natural gas transmission and storage the regulation on the industry and the clarify that an existing area source that facilities with one or more existing economy. Typically, in a regulatory increases its emissions to major source glycol dehydration units. We also analysis, the EPA determines the levels has up to the first substantive estimate that there will be an additional regulatory options suitable to meet compliance date to either reduce its 329 (there are 47 facilities that already statutory obligations under the CAA. emissions below major source levels by have an affected glycol dehydration Based on the stringency of those obtaining a practically enforceable unit) existing oil and natural gas permit or comply with the applicable options, the EPA then determines the production facilities with existing control technologies and monitoring major source provisions of 40 CFR part storage vessels that we expect to be 63, subpart HH. We have revised the requirements that sources might affected by these final amendments. second to last sentence in 40 CFR rationally select to comply with the 63.760(a)(1) by removing the These facilities operate approximately regulation. This analysis is documented parenthetical statement because it 134 glycol dehydration units (115 in in an engineering analysis. The selected simply reiterates the last sentence of production and 19 in transmission and control technologies and monitoring this section and is, therefore, storage) and 1,970 storage vessels. requirements are then evaluated in a unnecessary. Approximately 10 oil and natural gas cost model to determine the total • Revise 40 CFR 63.771(d)(1)(ii) and production and two transmission and annualized control costs. The 40 CFR 63.1281(d)(1)(ii) to clarify that storage facilities would have new glycol annualized control costs serve as inputs the vapor recovery device and ‘‘other dehydration units and 38 production to an Economic Impact Analysis model control device’’ described in those facilities would have new dehydration that evaluates the impacts of those costs provisions refer to non-destructive units. We expect new production on the industry and society as a whole. control devices only. facilities would operate approximately The Economic Impact Analysis used • Revise the last sentence of 40 CFR 12 production glycol dehydration units the National Energy Modeling System (NEMS) to estimate the impacts of the 63.764(i) and 40 CFR 63.1274(g) to and 197 storage vessels and new proposed NSPS on the United States clarify the requirements following an transmission and storage would operate energy system. The NEMS is a unsuccessful attempt to repair a leak. approximately two glycol dehydration • Updated the e-mail and physical publically-available model of the United units. address for area source reporting in 40 States energy economy developed and CFR 63.775(c)(1). Based on data provided by the United maintained by the Energy Information States Energy Information Administration of the United States VIII. What are the cost, environmental, Administration, we anticipate that by DOE and is used to produce the Annual energy and economic impacts of the 2015 there will be approximately 21,800 Energy Outlook, a reference publication proposed 40 CFR part 60, subpart gas wellhead facilities, 790 that provides detailed forecasts of the OOOO and amendments to subparts HH reciprocating compressors, 30 energy economy from the current year to and HHH of 40 CFR part 63? centrifugal compressors, 14,000 2035. The impacts we estimated We are presenting a combined pneumatic devices and 300 storage included changes in drilling activity, discussion of the estimates of the vessels subject to the new NSPS for price and quantity changes in the impacts for the proposed 40 CFR part VOC. Some of these affected facilities production and consumption of crude 60, subpart OOOO and proposed will be built at existing facilities and oil and natural gas and changes in amendments to 40 CFR part 63, subpart some at new greenfield facilities. Based international trade of crude oil and HH and 40 CFR part 63, subpart HHH. on data limitations, we assume impacts natural gas. We evaluated whether and The cost, environmental and economic are equal regardless of location. to what extent the increased production impacts presented in this section are costs imposed by the NSPS might alter expressed as incremental differences There are about 21 glycol dehydration the mix of fuels consumed at a national between the impacts of an oil and units with high enough HAP emissions level. Additionally, we combined natural gas facility complying with the that we believe cannot meet the estimated emissions co-reductions of amendments to subparts HH and HHH emissions limit without using more than methane from the engineering analysis and new standards under 40 CFR 60, one control technique. In developing the with NEMS analysis to estimate the net subpart OOOO and the baseline, i.e., the cost impacts, we assume that they change in CO2e GHG from energy- standards before these amendments. would require multiple controls. The related sources. The impacts are presented for the year controls for which we have detailed cost C. What are the air quality impacts? 2015, which will be the year that all data are condensers and VRU, so we existing oil and natural gas facilities developed costs for both controls to For the oil and natural gas sector will have to be in compliance, and also develop what we consider to be a NESHAP and NSPS, we estimated the the year that will represent reasonable cost estimate for these emission reductions that will occur due approximately 5 years of construction of facilities. This does not imply that we to the implementation of the final new oil and natural gas facilities subject believe these facilities will specifically emission limits. The EPA estimated to the NSPS emissions limits. The use a combination of a condenser and emission reductions based on the analyses and the documents referenced control technologies selected by the vapor recovery limit, but we do believe below can be found in Docket ID engineering analysis. These emission the combination of these control results Numbers EPA–HQ–OAR–2007–0877 reductions associated with the proposed and EPA–HQ–OAR–2002–0051. is a reasonable estimate of cost. amendments to 40 CFR part 63, subpart

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HH and 40 CFR part 63, subpart HHH impacts from the implementation of the the recovery of salable natural gas and are based on the estimated population proposed NESHAP amendments and the condensate. Thus, the final standards in 2008. Under the proposed limits for proposed NSPS. have a positive impact associated with glycol dehydration units and storage the recovery of non-renewable energy E. What are the secondary impacts? vessels, we have estimated that the HAP resources. emissions reductions will be 1,400 tpy Indirect or secondary air quality G. What are the cost impacts? for existing units subject to the impacts include impacts that will result proposed emissions limits. from the increased electricity usage The estimated total capital cost to For the NSPS, we estimated the associated with the operation of control comply with the proposed amendments emission reductions that will occur due devices, as well as water quality and to 40 CFR part 63, subpart HH for major to the implementation of the final solid waste impacts (which were just sources in the Oil and Natural Gas emission limits. The EPA estimated discussed) that might occur as a result Production source category is emission reductions based on the of these proposed actions. We estimate approximately $51.5 million. The total control technologies selected by the the proposed amendments to 40 CFR capital cost for the proposed engineering analysis. These emission part 63, subpart HH and 40 CFR part 63, amendments to 40 CFR part 63, subpart reductions are based on the estimated subpart HHH will increase emissions of HHH for major sources in the Natural population in 2015. Under the proposed criteria pollutants due to the potential Gas Transmission and Storage source NSPS, we have estimated that the use of flares for the control of storage category is estimated to be emissions reductions will be 540,000 vessels. We do not estimate an increased approximately $370 thousand. All costs tpy VOC for affected facilities subject to energy demand associated with the are in 2008 dollars. the NSPS. installation of condensers, VRU or The total estimated net annual cost to The control strategies likely adopted flares. The increases in criteria pollutant industry to comply with the proposed to meet the proposed NESHAP emissions associated with the use of amendments to 40 CFR part 63, subpart amendments and the proposed NSPS flares to control storage vessels subject HH for major sources in the Oil and will result in concurrent control of HAP, to existing source standards are Natural Gas Production source category methane and VOC emissions. We estimated to be 5,500 tpy of CO2, 16 tpy is approximately $16 million. The total estimate that direct reductions in HAP, of carbon monoxide (CO), 3 tpy of NOX, net annual cost for proposed methane and VOC for the proposed less than 1 tpy of particulate matter amendments to 40 CFR part 63, subpart rules combined total about 38,000 tpy, (PM) and 6 tpy total hydrocarbons. For HHH for major sources in the Natural 3.4 million tpy and 540,000 tpy, storage vessels subject to new source Gas Transmission and Storage source respectively. standards, increases in secondary air category is estimated to be Under the final standards, new pollutants are estimated to be less than approximately $360,000. These monitoring requirements are being 900 tpy of CO2, 3 tpy of CO, 1 tpy of estimated annual costs include: (1) The added. NOX, 1 tpy of PM and 1 tpy total cost of capital, (2) operating and hydrocarbons. maintenance costs, (3) the cost of D. What are the water quality and solid In addition, we estimate that the monitoring, inspection, recordkeeping waste impacts? secondary impacts associated with the and reporting (MIRR) and (4) any We estimated minimal water quality pneumatic controller requirements to associated product recovery credits. All impacts for the proposed amendments comply with the proposed NSPS would costs are in 2008 dollars. and proposed NSPS. For the proposed be about 22 tpy of CO2, 1 tpy of NOX The estimated total capital cost to amendments to the NESHAP, we and 3 tpy PM. For gas wellhead affected comply with the proposed NSPS is anticipate that the water impacts facilities, we estimate that the use of approximately $740 million in 2008 associated with the installation of a flares would result in increases in dollars. The total estimated net annual condenser system for the glycol criteria pollutant emissions of about cost to industry to comply with the dehydration unit process vent would be 990,000 tons of CO2, 2,800 tpy of CO, proposed NSPS is approximately $740 minimal. This is because the condensed 500 tpy of NOX, 5 tpy of PM and 1,000 million in 2008 dollars. This annual water collected with the hydrocarbon tpy total hydrocarbons. cost estimate includes: (1) The cost of condensate can be directed back into the capital, (2) operating and maintenance system for reprocessing with the F. What are the energy impacts? costs and (3) the cost of MIRR. This hydrocarbon condensate or, if separated, Energy impacts in this section are estimated annual cost does not take into combined with produced water for those energy requirements associated account any producer revenues disposal, usually by reinjection. with the operation of emission control associated with the recovery of salable Similarly, the water impacts devices. Potential impacts on the natural gas and hydrocarbon associated with installation of a vapor national energy economy from the rule condensates. control system either on a glycol are discussed in the economic impacts When revenues from additional dehydration unit or a storage vessel section. There would be little national product recovery are considered, the would be minimal. This is because the energy demand increase from the proposed NSPS is estimated to result in water vapor collected along with the operation of any of the control options a net annual engineering cost savings hydrocarbon vapors in the vapor analyzed under the proposed NESHAP overall. When including the additional collection and redirect system can be amendments and proposed NSPS. natural gas recovery in the engineering directed back into the system for The proposed NESHAP amendments cost analysis, we assume that producers reprocessing with the hydrocarbon and proposed NSPS encourage the use are paid $4 per thousand cubic feet condensate or, if separated, combined of emission controls that recover (Mcf) for the recovered gas at the with the produced water for disposal for hydrocarbon products, such as methane wellhead. The engineering analysis cost reinjection. and condensate that can be used on-site analysis assumes the value of recovered There would be no water impacts as fuel or reprocessed within the condensate is $70 per barrel. Based on expected for facilities subject to the production process for sale. We the engineering analysis, about proposed NSPS. Further, we do not estimated that the proposed standards 180,000,000 Mcf (180 billion cubic feet) anticipate any adverse solid waste will result in a net cost savings due to of natural gas and 730,000 barrels of

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condensate are estimated to be change, while average crude oil prices associated with exposure to HAP, ozone recovered by control requirements in are estimated to decrease slightly and PM2.5 in the RIA for this rule. These 2015. Using the price assumptions, the ($0.02/barrel in 2008 dollars or less than qualitative effects are briefly estimated revenues from natural gas 0.1 percent at the wellhead for onshore summarized below, but for more product recovery are approximately producers in the lower 48 states) in the detailed information, please refer to the $780 million in 2008 dollars. This year of analysis, 2015. The NEMS-based RIA, which is available in the docket. savings is estimated at $45 million in analysis estimates in the year of One of the HAP of concern from the oil 2008 dollars. analysis, 2015, that net imports of and natural gas sector is benzene, which Using the engineering cost estimates, natural gas and crude will not change is a known human carcinogen, and estimated natural gas product recovery, significantly. formaldehyde, which is a probable and natural gas product price Total CO2e emissions from energy- human carcinogen. VOC emissions are assumptions, the net annual engineering related sources are expected to increase precursors to both PM2.5 and ozone cost savings is estimated for the about 2.0 million metric tons CO2e or formation. As documented in previous proposed NSPS at about $45 million in 0.04 percent under the proposed NSPS, analyses (U.S. EPA, 2006 41 and U.S. 42 2008 dollars. Totals may not sum due to according to the NEMS analysis. This EPA, 2010 ), exposure to PM2.5 and independent rounding. increase is attributable largely to natural ozone is associated with significant As the price assumption is very gas consumption increases. This public health effects. PM2.5 is associated influential on estimated annualized estimate does not include CO2e with health effects such as premature engineering costs, we performed a reductions from the implementation of mortality for adults and infants, simple sensitivity analysis of the the controls; these reductions are cardiovascular morbidity, such as heart influence of the assumed wellhead price discussed in more detail in the benefits attacks, hospital admissions and paid to natural gas producers on the section that follows. respiratory morbidity such as asthma overall engineering annualized costs We did not estimate the energy attacks, acute and chronic bronchitis, estimate of the proposed NSPS. At economy impacts of the proposed hospital and emergency room visits, $4.22/Mcf, the price forecast reported in NESHAP amendments using NEMS, as work loss days, restricted activity days the 2011 Annual Energy Outlook in the expected costs of the rule are not and respiratory symptoms, as well as 2008 dollars, the annualized costs are likely to have estimable impacts on the visibility impairment.43 Ozone is estimated at about ¥$90 million, which national energy economy. associated with health effects such as would approximately double the I. What are the benefits? respiratory morbidity such as asthma estimate of net cost savings of the attacks, hospital and emergency proposed NSPS. As indicated by this The proposed Oil and Natural Gas department visits, school loss days and difference, EPA has chosen a relatively NSPS and NESHAP amendments are premature mortality, as well as injury to conservative assumption (leading to an expected to result in significant vegetation and climate effects.44 estimate of few savings and higher net reductions in existing emissions and In addition to the improvements in air costs) for the engineering costs analysis. prevent new emissions from expansions quality and resulting benefits to human The natural gas price at which the of the industry. These proposed rules health and non-climate welfare effects proposed NSPS breaks-even from an combined are anticipated to reduce previously discussed, this proposed rule estimated engineering costs perspective 38,000 tons of HAP, 540,000 tons of is expected to result in significant is around $3.77/Mcf. A $1/Mcf change VOC and 3.4 million tons of methane. climate co-benefits due to anticipated in the wellhead natural gas price leads These pollutants are associated with methane reductions. Methane is a to about a $180 million change in the substantial health effects, welfare effects potent GHG that, once emitted into the annualized engineering costs of the and climate effects. With the data atmosphere, absorbs terrestrial infrared proposed NSPS. Consequently, available, we are not able to provide radiation, which contributes to annualized engineering costs estimates credible health benefit estimates for the increased global warming and would increase to about $140 million reduction in exposure to HAP, ozone continuing climate change. Methane under a $3/Mcf price or decrease to and PM (2.5 microns and less) (PM2.5) reacts in the atmosphere to form ozone about ¥$230 million under a $5/Mcf for these rules, due to the differences in and ozone also impacts global price. For further details on this the locations of oil and natural gas temperatures. According to the sensitivity analysis, please refer the emission points relative to existing regulatory impact analysis (RIA) for this information and the highly localized 41 U.S. EPA. RIA. National Ambient Air Quality rulemaking located in the docket. nature of air quality responses Standards for Particulate Matter, Chapter 5. Office associated with HAP and VOC of Air Quality Planning and Standards, Research H. What are the economic impacts? Triangle Park, NC. October 2006. Available on the reductions. Internet at http://www.epa.gov/ttn/ecas/regdata/ The NEMS analysis of energy system This is not to imply that there are no RIAs/Chapter%205-Benefits.pdf. impacts for the proposed NSPS option benefits of the rules; rather, it is a 42 U.S. EPA. RIA. National Ambient Air Quality estimates that domestic natural gas reflection of the difficulties in modeling Standards for Ozone. Office of Air Quality Planning production is likely to increase slightly the direct and indirect impacts of the and Standards, Research Triangle Park, NC. January 2010. Available on the Internet at http:// (about 20 billion cubic feet or 0.1 reductions in emissions for this www.epa.gov/ttn/ecas/regdata/RIAs/s1- percent) and average natural gas prices industrial sector with the data currently supplemental_analysis_full.pdf. to decrease slightly ($0.04 per Mcf in available. In addition to health 43 U.S. EPA. Integrated Science Assessment for 2008 dollars or 0.9 percent at the improvements, there will be Particulate Matter (Final Report). EPA–600–R–08– wellhead for onshore producers in the improvements in visibility effects, 139F. National Center for Environmental Assessment—RTP Division. December 2009. lower 48 states) for 2015, the year of ecosystem effects and climate effects, as Available at http://cfpub.epa.gov/ncea/cfm/ analysis. This increase in production well as additional product recovery. recordisplay.cfm?deid=216546. and decrease in wellhead price is Although we do not have sufficient 44 U.S. EPA. Air Quality Criteria for Ozone and largely a result of the increased natural information or modeling available to Related Photochemical Oxidants (Final). EPA/600/ R–05/004aF–cF. Washington, DC: U.S. EPA. gas and condensate recovery as a result provide quantitative estimates for this February 2006. Available on the Internet at http:// of complying with the NSPS. Domestic rulemaking, we include a qualitative cfpub.epa.gov/ncea/CFM/ crude oil production is not expected to assessment of the health effects recordisplay.cfm?deid=149923.

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Intergovernmental Panel on Climate climate benefits of taking approximately Alternatively, if the fraction of GDP lost Change (IPCC) 4th Assessment Report 11 million typical passenger cars off the due to climate change is assumed to be (2007), methane is the second leading road or eliminating electricity use from similar across countries, the domestic long-lived climate forcer after CO2 about 7 million typical homes each benefit would be proportional to the globally. Total methane emissions from year.46 U.S. share of global GDP, which is the oil and gas industry represent about The EPA recognizes that the methane currently about 23 percent. On the basis 40 percent of the total methane reductions proposed in this rule will of this evidence, values from 7 to 23 emissions from all sources and account provide for significant economic climate percent should be used to adjust the for about 5 percent of all CO2e benefits to society just described. global SCC to calculate domestic effects. emissions in the United States, with However, there is no interagency- It is recognized that these values are natural gas systems being the single accepted methodology to place approximate, provisional and highly largest contributor to United States monetary values on these benefits. A speculative. There is no a priori reason anthropogenic methane emissions.45 ‘global warming potential (GWP) why domestic benefits should be a Methane, in addition to other GHG approach’ of converting methane to constant fraction of net global damages emissions, contributes to warming of the CO2e using the GWP of methane over time.49 atmosphere, which, over time, leads to provides an approximation method for These co-benefits equate to a range of increased air and ocean temperatures, estimating the monetized value of the approximately $110 to $1,400 per short changes in precipitation patterns, methane reductions anticipated from ton of methane reduced, depending melting and thawing of global glaciers this rule. This calculation uses the GWP upon the discount rate assumed with a and ice, increasingly severe weather of the non-CO2 gas to estimate CO2 per ton estimate of $480 at the 3-percent events, such as hurricanes of greater equivalents and then multiplies these discount rate. Methane climate co- intensity and sea level rise, among other CO2 equivalent emission reductions by benefit estimates for additional impacts. the social cost of carbon developed by regulatory alternatives are included in This rulemaking proposes emission the Interagency Social Cost of Carbon the RIA for this proposed rule. These control technologies and regulatory Work Group to generate monetized social cost of methane benefit estimates alternatives that will significantly estimates of the benefits. are not the same as would be derived decrease methane emissions from the oil The social cost of carbon is an from direct computations (using the and natural gas sector in the United estimate of the net present value of the integrated assessment models employed States. The regulatory alternatives flow of monetized damages from a 1- to develop the Interagency Social Cost proposed for the NESHAP and the NSPS metric ton increase in CO2 emissions in of Carbon estimates) for a variety of are expected to reduce methane a given year (or from the alternative reasons, including the shorter emissions annually by about 3.4 million perspective, the benefit to society of atmospheric lifetime of methane relative reducing CO emissions by 1 ton). For short tons or 65 million metric tons 2 to CO2 (about 12 years compared to CO2 more information about the social cost CO e. After considering the secondary whose concentrations in the atmosphere 2 of carbon, see the Support Document: impacts of this proposal previously decay on timescales of decades to Social Cost of Carbon for Regulatory discussed, such as increased CO millennia). The climate impacts also 2 Impact Analysis Under Executive Order emissions from well completion differ between the pollutants for reasons 12866 47 and RIA for the Light-Duty combustion and decreased CO e other than the radiative forcing profiles 2 Vehicle GHG rule.48 Applying this emissions because of fuel-switching by and atmospheric lifetimes of these approach to the methane reductions consumers, the methane reductions gases. estimated for the proposed NESHAP become about 62 million metric tons Methane is a precursor to ozone and and NSPS of the oil and gas rule, the ozone is a short-lived climate forcer that CO2e. These reductions represent about 2015 climate co-benefits vary by 26 percent of the baseline methane contributes to global warming. The use discount rate and range from about $370 of the IPCC Second Assessment Report emissions for this sector reported in the million to approximately $4.7 billion; EPA’s U.S. Greenhouse Gas Inventory GWP to approximate co-benefits may the mean social cost of carbon at the 3- underestimate the direct radiative Report for 2009 (251.55 million metric percent discount rate results in an tons CO2e when petroleum refineries forcing benefits of reduced ozone levels estimate of about $1.6 billion in 2015. and does not capture any secondary and petroleum transportation are The ratio of domestic to global excluded because these sources are not climate co-benefits involved with benefits of emission reductions varies ozone-ecosystem interactions. In examined in this proposal). After with key parameter assumptions. For addition, a recent EPA National Center considering the secondary impacts of example, with a 2.5 or 3 percent of Environmental Economics working this proposal, such as increased CO2 discount rate, the U.S. benefit is about paper suggests that this quick ‘GWP emissions from well completion 7–10 percent of the global benefit, on approach’ to benefits estimation will combustion and decreased CO2 average, across the scenarios analyzed. emissions because of fuel-switching by likely understate the climate benefits of methane reductions in most cases.50 consumers, the CO2e GHG reductions 46 U.S. EPA. Greenhouse Gas Equivalency are reduced to about 62 million metric Calculator available at: http://www.epa.gov/ This conclusion is reached using the cleanenergy/energy-resources/calculator.html tons CO2e. However, it is important to 100-year GWP for methane of 25 as put note that the emission reductions are accessed 07/19/11. forth in the IPCC Fourth Assessment 47 Interagency Working Group on Social Cost of Report (AR 4), as opposed to the lower based upon predicted activities in 2015; Carbon (IWGSC). 2010. Technical Support the EPA did not forecast sector-level Document: Social Cost of Carbon for Regulatory emissions in 2015 for this rulemaking. Impact Analysis Under Executive Order 12866. 49 Interagency Working Group on Social Cost of Docket ID EPA–HQ–OAR–2009–0472–114577. Carbon (IWGSC). 2010. Technical Support These emission reductions equate to the http://www.epa.gov/otaq/climate/regulations/scc- Document: Social Cost of Carbon for Regulatory tsd.pdf; Accessed March 30, 2011. Impact Analysis Under Executive Order 12866. 45 U.S. EPA (2011), 2011 U.S. Greenhouse Gas 48 U.S. EPA. Final Rulemaking: Light-Duty 50 Marten and Newbold (2011), Estimating the Inventory Report Executive Summary available on Vehicle Greenhouse Gas Emissions Standards and Social Cost of Non-CO2 GHG Emissions: Methane the internet at http://www.epa.gov/ Corporate Average Fuel Economy Standards. May and Nitrous Oxide, NCEE Working Paper Series climateexchange/emissions/downloads11/US-GHG- 2010. Available on the Internet at http:// #11–01. http://yosemite.epa.gov/EE/epa/eed.nsf/ Inventory-2011-Executive Summary.pdf. www.epa.gov/otaq/climate/regulations.htm#finalR. WPNumber/2011-01?OpenDocument.

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value of 21 used in this analysis. Using For the proposed NESHAP actions, we are also interested in any the higher GWP estimate of 25 would amendments, a break-even analysis additional data that may help to reduce increase these reported methane climate suggests that HAP emissions would the uncertainties inherent in the risk co-benefit estimates by about 19 need to be valued at $12,000 per ton for assessments. We are specifically percent. Although the IPCC Assessment the benefits to exceed the costs if the interested in receiving corrections to the Report (AR4) suggested a GWP of 25 for health, ecosystem and climate benefits datasets used for MACT analyses and methane, the EPA has used GWP of 21 from the reductions in VOC and risk modeling. Such data should include to estimate the methane climate co- methane emissions are assumed to be supporting documentation in sufficient benefits for this oil and gas proposal in zero. Even though emission reductions detail to allow characterization of the order to provide estimates more of VOC and methane are co-benefits for quality and representativeness of the consistent with global GHG inventories, the proposed NESHAP amendments, data or information. Please see the which currently use GWP from the IPCC they are legitimate components of the following section for more information Second Assessment Report. total benefit-cost comparison. If we on submitting data. assume the health benefits from HAP Due to the uncertainties involved X. Submitting Data Corrections emission reductions are zero, the VOC with the ‘GWP approach’ estimates emissions would need to be valued at The facility-specific data used in the presented and methane climate co- $1,700 per ton or the methane emissions source category risk analyses, facility- benefits estimates available in the would need to be valued at $3,300 per wide analyses and demographic literature, the EPA chooses not to ton for the co-benefits to exceed the analyses for each source category compare these co-benefit estimates to costs. All estimates are in 2008 dollars. subject to this action are available for the costs of the rule for this proposal. For the proposed NSPS, the revenue download on the RTR Web page at Rather, the EPA presents the ‘GWP from additional product recovery http://www.epa.gov/ttn/atw/rrisk/ approach’ climate co-benefit estimates exceeds the costs, which renders a rtrpg.html. These data files include as an interim method to produce these break-even analysis unnecessary when detailed information for each HAP estimates until the Interagency Social these revenues are included in the emissions release point at each facility Cost of Carbon Work Group develops analysis. Based on the methodology included in the source category and all values for non-CO2 GHG. The EPA from Fann, Fulcher, and Hubbell other HAP emissions sources at these requests comments from interested (2009),51 ranges of benefit-per-ton facilities (facility-wide emissions parties and the public about this interim estimates for emissions of VOC indicate sources). However, it is important to approach specifically and more broadly that on average in the United States, note that the source category risk about appropriate methods to monetize VOC emissions are valued from $1,200 analysis included only those emissions the climate benefits of methane to $3,000 per ton as a PM2.5 precursor, tagged with the MACT code associated reductions. In particular, the EPA seeks but emission reductions in specific with the source category subject to the public comments to this proposed areas are valued from $280 to $7,000 per risk analysis. rulemaking regarding social cost of ton in 2008 dollars. As a result, even if If you believe the data are not methane estimates that may be used to VOC emissions from oil and natural gas representative or are inaccurate, please value the co-benefits of methane operations result in monetized benefits identify the data in question, provide emission reductions anticipated for the that are substantially below the national your reason for concern and provide any oil and gas industry from this rule. average, there is a reasonable chance ‘‘improved’’ data that you have, if Comments specific to whether GWP is that the benefits of the rule would available. When you submit data, we an acceptable method for generating a exceed the costs, especially if we were request that you provide documentation placeholder value for the social cost of able to monetize all of the additional of the basis for the revised values to methane until interagency-modeled benefits associated with ozone support your suggested changes. To estimates become available are formation, visibility, HAP and methane. submit comments on the data welcome. Public comments may be downloaded from the RTR Web page, provided in the official docket for this IX. Request for Comments complete the following steps: proposed rulemaking in accordance We are soliciting comments on all 1. Within this downloaded file, enter with the process outlined earlier in this aspects of this proposed action. All suggested revisions to the data fields notice. These comments will be comments received during the comment appropriate for that information. The considered in developing the final rule period will be considered. In addition to data fields that may be revised include for this rulemaking. general comments on the proposed the following:

Data element Definition

Control Measure ...... Are control measures in place? (yes or no). Control Measure Comment ...... Select control measure from list provided and briefly describe the control measure. Delete ...... Indicate here if the facility or record should be deleted. Delete Comment ...... Describes the reason for deletion. Emission Calculation Method Code for Revised Emis- Code description of the method used to derive emissions. For example, CEM, mate- sions. rial balance, stack test, etc. Emission Process Group ...... Enter the general type of emission process associated with the specified emission point. Fugitive Angle ...... Enter release angle (clockwise from true North); orientation of the y-dimension rel- ative to true North, measured positive for clockwise starting at 0 degrees (max- imum 89 degrees). Fugitive Length ...... Enter dimension of the source in the east-west (x-) direction, commonly referred to as length (ft).

51 Fann, N., C.M. Fulcher, B.J. Hubbell. The estimates of the human health benefits of reducing a ton of air pollution. Air Qual Atmos Health (2009) influence of location, source, and emission type in 2:169–176.

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Data element Definition

Fugitive Width ...... Enter dimension of the source in the north-south (y-) direction, commonly referred to as width (ft). Malfunction Emissions ...... Enter total annual emissions due to malfunctions (TPY). Malfunction Emissions Max Hourly ...... Enter maximum hourly malfunction emissions here (lb/hr). North American Datum ...... Enter datum for latitude/longitude coordinates (NAD27 or NAD83); if left blank, NAD83 is assumed. Process Comment ...... Enter general comments about process sources of emissions. REVISED Address ...... Enter revised physical street address for MACT facility here. REVISED City ...... Enter revised city name here. REVISED County Name ...... Enter revised county name here. REVISED Emission Release Point Type ...... Enter revised Emission Release Point Type here. REVISED End Date ...... Enter revised End Date here. REVISED Exit Gas Flow Rate ...... Enter revised Exit Gas Flowrate here (ft3/sec). REVISED Exit Gas Temperature ...... Enter revised Exit Gas Temperature here (OF). REVISED Exit Gas Velocity ...... Enter revised Exit Gas Velocity here (ft/sec). REVISED Facility Category Code ...... Enter revised Facility Category Code here, which indicates whether facility is a major or area source. REVISED Facility Name ...... Enter revised Facility Name here. REVISED Facility Registry Identifier ...... Enter revised Facility Registry Identifier here, which is an ID assigned by the EPA Facility Registry System. REVISED HAP Emissions Performance Level Code ...... Enter revised HAP Emissions Performance Level here. REVISED Latitude ...... Enter revised Latitude here (decimal degrees). REVISED Longitude ...... Enter revised Longitude here (decimal degrees). REVISED MACT Code ...... Enter revised MACT Code here. REVISED Pollutant Code ...... Enter revised Pollutant Code here. REVISED Routine Emissions ...... Enter revised routine emissions value here (TPY). REVISED SCC Code ...... Enter revised SCC Code here. REVISED Stack Diameter ...... Enter revised Stack Diameter here (ft). REVISED Stack Height ...... Enter revised Stack Height here (Ft). REVISED Start Date ...... Enter revised Start Date here. REVISED State ...... Enter revised state here. REVISED Tribal Code ...... Enter revised Tribal Code here. REVISED Zip Code ...... Enter revised Zip Code here. Shutdown Emissions ...... Enter total annual emissions due to shutdown events (TPY). Shutdown Emissions Max Hourly ...... Enter maximum hourly shutdown emissions here (lb/hr). Stack Comment ...... Enter general comments about emission release points. Startup Emissions ...... Enter total annual emissions due to startup events (TPY). Startup Emissions Max Hourly ...... Enter maximum hourly startup emissions here (lb/hr). Year Closed ...... Enter date facility stopped operations.

2. Fill in the commenter information categories, you need only submit one under Executive Order 12866 and fields for each suggested revision (i.e., file for that facility, which should Executive Order 13563 (76 FR 3821, commenter name, commenter contain all suggested changes for all January 21, 2011) and any changes made organization, commenter e-mail address, source categories at that facility. We in response to OMB recommendations commenter phone number and revision request that all data revision comments have been documented in the docket for comments). be submitted in the form of updated this action. 3. Gather documentation for any Microsoft® Access files, which are In addition, the EPA prepared a RIA suggested emissions revisions (e.g., provided on the http://www.epa.gov/ttn/ performance test reports, material atw/rrisk/rtrpg.html Web page. of the potential costs and benefits balance calculations, etc.). associated with this action. The RIA 4. Send the entire downloaded file XI. Statutory and Executive Order available in the docket describes in with suggested revisions in Microsoft® Reviews detail the empirical basis for the EPA’s Access format and all accompanying A. Executive Order 12866: Regulatory assumptions and characterizes the documentation to Docket ID Number Planning and Review and Executive various sources of uncertainties EPA–HQ–OAR–2010–0505 (through one Order 13563: Improving Regulation and affecting the estimates below. Table 8 of the methods described in the Regulatory Review shows the results of the cost and ADDRESSES section of this preamble). To benefits analysis for these proposed expedite review of the revisions, it Under Executive Order 12866 (58 FR rules. For more information on the would also be helpful if you submitted 51735, October 4, 1993), this action is benefit and cost analysis, as well as a copy of your revisions to the EPA an ‘‘economically significant regulatory details on the regulatory options directly at [email protected] in addition to action’’ because it is likely to have an considered, please refer to the RIA for annual effect on the economy of $100 submitting them to the docket. this rulemaking, which is available in 5. If you are providing comments on million or more. Accordingly, the EPA the docket. a facility with multiple source submitted this action to OMB for review

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TABLE 8—SUMMARY OF THE MONETIZED BENEFITS, COSTS AND NET BENEFITS FOR THE PROPOSED OIL AND NATURAL GAS NSPS AND NEHSAP AMENDMENTS IN 2015 [Millions of 2008$] 1

Proposed NSPS and Proposed NSPS Proposed NESHAP NESHAP amendments amendments combined

Total Monetized Benefits 2 ...... N/A N/A N/A. Total Costs 3 ...... ¥$45 million $16 million ¥$29 million. Net Benefits ...... N/A N/A N/A. Non-monetized Benefits 45 ...... 37,000 tons of HAP 1,400 tons of HAP 38,000 tons of HAP. 540,000 tons of VOC 9,200 tons of VOC 540,000 tons of VOC. 3.4 million tons of methane 4,900 tons of methane 3.4 million tons of meth- ane.

Health effects of HAP exposure. Health effects of PM2.5 and ozone exposure. Visibility impairment. Vegetation effects. Climate effects. 1 All estimates are for the implementation year (2015). 2 While we expect that these avoided emissions will result in improvements in air quality and reductions in health effects associated with HAP, ozone and PM, as well as climate effects associated with methane, we have determined that quantification of those benefits cannot be accom- plished for this rule in a defensible way. This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the data currently available. 3 The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the proposed NSPS reflects the in- clusion of revenues from additional natural gas and hydrocarbon condensate recovery that are estimated as a result of the proposed NSPS. 4 For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co-benefits. 5 The specific control technologies for these proposed rules are anticipated to have minor secondary disbenefits. The net CO2-equivalent emis- sion reductions are 93,000 metric tons for the NESHAP and 62 million metric tons for the NSPS.

B. Paperwork Reduction Act only the specific information needed to the cost of reporting, including reading determine compliance. instructions and information gathering. The information collection For sources subject to the proposed Recordkeeping cost estimates include requirements in this proposed action NSPS, burden changes associated with reading instructions, planning activities have been submitted for approval to these amendments result from the and conducting compliance monitoring. OMB under the Paperwork Reduction respondents’ annual reporting and The average hours and cost per Act, 44 U.S.C. 3501, et seq. The ICR recordkeeping burden associated with regulated entity subject to the Oil and document prepared by the EPA has been this proposed rule for this collection Natural Gas Production NESHAP would assigned EPA ICR Numbers 1716.07 (40 (averaged over the first 3 years after the be 72 hours per year and $2,500 per CFR part 60, subpart OOOO), 1788.10 effective date of the standards). The year, based on an average of 846 (40 CFR part 63, subpart HH), 1789.07 burden is estimated to be 560,000 labor facilities per year and three responses (40 CFR part 63, subpart HHH) and hours at a cost of $18 million per year. per facility. For the Natural Gas 1086.10 (40 CFR part 60, subparts KKK This includes the burden previously Transmission and Storage NESHAP, the and subpart LLL). estimated for sources subject to 40 CFR average hours and cost per regulated The information to be collected for part 60, subpart KKK (which is being entity would be 50 hours per year and the proposed NSPS and the proposed incorporated into 40 CFR part 60, $1,600 per year, based on an average of NESHAP amendments are based on subpart OOOO). The average hours and 53 facilities per year and three notification, recordkeeping and cost per regulated entity subject to the responses per facility. Burden is defined reporting requirements in the NESHAP NSPS for oil and natural gas production at 5 CFR 1320.3(b). General Provisions (40 CFR part 63, and natural gas transmissions and An agency may not conduct or subpart A), which are mandatory for all distribution facilities would be 110 sponsor, and a person is not required to operators subject to national emission hours per response and $3,693 per respond to, a collection of information standards. These recordkeeping and response, based on an average of 1,459 unless it displays a currently valid OMB reporting requirements are specifically operators responding per year and 16 control number. The OMB control authorized by section 114 of the CAA responses per year. numbers for the EPA’s regulations in 40 (42 U.S.C. 7414). All information The estimated recordkeeping and CFR are listed in 40 CFR part 9. submitted to the EPA pursuant to the reporting burden after the effective date To comment on the Agency’s need for recordkeeping and reporting of the proposed amendments is this information, the accuracy of the requirements for which a claim of estimated for all affected major and area provided burden estimates and any confidentiality is made is safeguarded sources subject to the Oil and Natural suggested methods for minimizing according to Agency policies set forth in Gas Production NESHAP to be respondent burden, the EPA has 40 CFR part 2, subpart B. approximately 63,000 labor hours per established a public docket for this rule, These proposed rules would require year at a cost of $2.1 million per year. which includes this ICR, under Docket maintenance inspections of the control For the Natural Gas Transmission and ID Number EPA–HQ–OAR–2010–0505. devices, but would not require any Storage NESHAP, the recordkeeping and Submit any comments related to the ICR notifications or reports beyond those reporting burden is estimated to be to the EPA and OMB. See the ADDRESSES required by the General Provisions. The 2,500 labor hours per year at a cost of section at the beginning of this notice recordkeeping requirements require $86,800 per year. This estimate includes for where to submit comments to the

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EPA. Send comments to OMB at the the impact on well-related compliance this proposed rule is not subject to the Office of Information and Regulatory costs to be significantly mitigated. This requirements of sections 202 or 205 of Affairs, Office of Management and conclusion is enhanced because the UMRA. This proposed rule is also not Budget, 725 17th Street, NW., returns to REC activities occur without subject to the requirements of section Washington, DC 20503, Attention: Desk a significant time lag between 203 of UMRA because it contains no Office for the EPA. Since OMB is implementing the control and obtaining regulatory requirements that might required to make a decision concerning the recovered product, unlike many significantly or uniquely affect small the ICR between 30 and 60 days after control options where the emissions governments. This action contains no August 23, 2011, a comment to OMB is reductions accumulate over long requirements that apply to such best assured of having its full effect if periods of time; the reduced emission governments nor does it impose OMB receives it by September 22, 2011. completions and recompletions occur obligations upon them. The final rule will respond to any OMB over a short span of time, during which or public comments on the information the additional product recovery is also E. Executive Order 13132: Federalism collection requirements contained in accomplished. This proposed rule does not have this proposal. Proposed NESHAP Amendments federalism implications. It will not have C. Regulatory Flexibility Act substantial direct effects on the states, After considering the economic on the relationship between the national The Regulatory Flexibility Act impact of the proposed NESHAP government and the states, or on the generally requires an agency to prepare amendments on small entities, I certify distribution of power and a regulatory flexibility analysis of any that this action will not have a responsibilities among the various rule subject to notice and comment SISNOSE. Based upon the analysis in levels of government, as specified in rulemaking requirements under the the RIA, which is in the Docket, we Executive Order 13132. Thus, Executive Administrative Procedure Act or any estimate that 62 of the 118 firms (53 Order 13132 does not apply to this other statute, unless the agency certifies percent) that own potentially affected proposed rule. In the spirit of Executive that the rule will not have a significant facilities are small entities. The EPA Order 13132 and consistent with the economic impact on a substantial performed a screening analysis for EPA policy to promote communications number of small entities (SISNOSE). impacts on all expected affected small between the EPA and state and local Small entities include small businesses, entities by comparing compliance costs governments, the EPA specifically small organizations, and small to entity revenues. Among the small solicits comment on this proposed rule governmental jurisdictions. For firms, 52 of the 62 (84 percent) are likely from state and local officials. purposes of assessing the impact of this to have impacts of less than 1 percent rule on small entities, a small entity is in terms of the ratio of annualized F. Executive Order 13175: Consultation defined as: (1) A small business whose compliance costs to revenues. and Coordination With Indian Tribal parent company has no more than 500 Meanwhile, 10 firms (16 percent) are Governments employees (or revenues of less than $7 likely to have impacts greater than 1 This action does not have tribal million for firms that transport natural percent. Four of these 10 firms are likely implications, as specified in Executive gas via pipeline); (2) a small to have impacts greater than 3 percent. Order 13175 (65 FR 67249, November 9, governmental jurisdiction that is a While these 10 firms might receive 2000). It will not have substantial direct government of a city, county, town, significant impacts from the proposed effect on tribal governments, on the school district, or special district with a NESHAP amendments, they represent a relationship between the Federal population of less than 50,000; and (3) very small slice of the oil and gas government and Indian tribes or on the a small organization that is any not-for- industry in its entirety, less than 0.2 distribution of power and profit enterprise which is independently percent of the estimated 6,427 small responsibilities between the Federal owned and operated and is not firms in NAICS 211. Although this final government and Indian tribes, as dominant in its field. rule will not impact a substantial specified in Executive Order 13175. number of small entities, the EPA, Proposed NSPS Thus, Executive Order 13175 does not nonetheless, has tried to reduce the apply to this action. After considering the economic impact of this rule on small entities by impact of the proposed NSPS on small setting the final emissions limits at the The EPA specifically solicits entities, I certify that this action will not MACT floor, the least stringent level additional comment on this proposed have a SISNOSE. The EPA performed a allowed by law. action from tribal officials. screening analysis for impacts on a We continue to be interested in the G. Executive Order 13045: Protection of sample of expected affected small potential impacts of the proposed rule Children From Environmental Health entities by comparing compliance costs on small entities and welcome Risks and Safety Risks to entity revenues. Based upon the comments on issues related to such analysis in the RIA, which is in the impacts. This proposed rule is not subject to Docket, EPA concludes the number of Executive Order 13045 (62 FR 19885, impacted small businesses is unlikely to D. Unfunded Mandates Reform Act April 23, 1997) because the Agency does be sufficiently large to declare a This action contains no Federal not believe the environmental health SISNOSE. Our judgment in this mandates under the provisions of title II risks or safety risks addressed by this determination is informed by the fact of the Unfunded Mandates Reform Act action present a disproportionate risk to that many affected firms are expected to of 1995 (UMRA), 2 U.S.C. 1531–1538 for children. This actions’ health and risk receive revenues from the additional state, local or tribal governments or the assessments are contained in section natural gas and condensate recovery private sector. This proposed rule does VII.C of this preamble. engendered by the implementation of not contain a Federal mandate that may The public is invited to submit the controls evaluated in this RIA. As result in expenditures of $100 million or comments or identify peer-reviewed much of the additional natural gas more for state, local and tribal studies and data that assess effects of recovery is estimated to arise from governments, in the aggregate, or to the early life exposure to HAP from oil and completion-related activities, we expect private sector in any one year. Thus, natural gas sector activities.

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H. Executive Order 13211: Actions directed into natural gas production the American Society of Mechanical Concerning Regulations That streams and sold. One pollution control Engineers (ASME), Three Park Avenue, Significantly Affect Energy Supply, requirement of the proposed NSPS also New York, NY 10016–5990. Also, we Distribution or Use captures saleable condensates. The are proposing to revise subpart HHH to Executive Order 13211, (66 FR 28,355, revenues from additional natural gas allow ASTM D6420–99 (2004), Test May 22, 2001), provides that agencies and condensate recovery are expected to Method for Determination of Gaseous shall prepare and submit to the offset the costs of implementing the Organic Compounds by Direct Interface Administrator of the Office of proposed NSPS. Gas Chromatography/Mass The analysis of energy impacts for the Information and Regulatory Affairs, Spectrometry, to be used in lieu of EPA proposed NSPS that includes the Method 18. For a detailed discussion of OMB, a Statement of Energy Effects for additional product recovery shows that this VCS, and its appropriateness as a certain actions identified as significant domestic natural gas production is substitute for Method 18, see the final energy actions. Section 4(b) of Executive estimated to increase (20 billion cubic Oil and Natural Gas Production Order 13211 defines ‘‘significant energy feet or 0.1 percent) and natural gas NESHAP (Area Sources) (72 FR 36, actions’’ as ‘‘any action by an agency prices to decrease ($0.04/Mcf or 0.9 January 3, 2007). (normally published in the Federal percent at the wellhead for producers in As a result, the EPA is proposing Register) that promulgates or is the lower 48 states) in 2015, the year of ASTM D6420–99 (2004) for use in 40 expected to lead to the promulgation of analysis. Domestic crude oil production CFR part 63, subpart HHH. The EPA a final rule or regulation, including is not estimated to change, while crude also proposes to allow Method 18 as an notices of inquiry, advance notices of oil prices are estimated to decrease option in addition to ASTM D6420–99 proposed rulemaking, and notices of slightly ($0.02/barrel or less than 0.1 (2004). This would allow the continued proposed rulemaking: (1)(i) That is a percent at the wellhead for producers in use of gas chromatography significant regulatory action under the lower 48 states) in 2015, the year of configurations other than gas Executive Order 12866 or any successor analysis. All prices are in 2008 dollars. chromatography/mass spectrometry. order and (ii) is likely to have a Additionally, the NSPS establishes The EPA welcomes comments on this significant adverse effect on the supply, several performance standards that give aspect of the proposed rulemaking and, distribution, or use of energy; or (2) that regulated entities flexibility in specifically, invites the public to is designated by the Administrator of determining how to best comply with identify potentially-applicable VCS and the Office of Information and Regulatory the regulation. In an industry that is to explain why such standards should Affairs as a significant energy action.’’ geographically and economically be used in this regulation. The proposed rules will result in the heterogeneous, this flexibility is an J. Executive Order 12898: Federal addition of control equipment and important factor in reducing regulatory Actions To Address Environmental monitoring systems for existing and new burden. sources within the oil and natural gas For more information on the Justice in Minority Populations and industry. The proposed NESHAP estimated energy effects, please refer to Low-Income Populations amendments are unlikely to have a the economic impact analysis for this Executive Order 12898 (59 FR 7629, significant adverse effect on the supply, proposed rule. The analysis is available February 16, 1994) establishes Federal distribution or use of energy. As such, in the RIA, which is in the public executive policy on EJ. Its main the proposed NESHAP amendments are docket. provision directs Federal agencies, to not ‘‘significant energy actions’’ as the greatest extent practicable and defined in Executive Order 13211 (66 I. National Technology Transfer and permitted by law, to make EJ part of FR 28355, May 22, 2001). Advancement Act their mission by identifying and The proposed NSPS is also unlikely to Section 12(d) of the National addressing, as appropriate, have a significant effect on the supply, Technology Transfer and Advancement disproportionately high and adverse distribution or use of energy. As such, Act of 1995 (NTTAA), Public Law No. human health or environmental effects the proposed NSPS is not a ‘‘significant 104–113 (15 U.S.C. 272 note) directs the of their programs, policies and activities energy action’’ as defined in Executive EPA to use voluntary consensus on minority populations and low- Order 13211 (66 FR 28355, May 22, standards (VCS) in its regulatory income populations in the United 2001). The basis for the determination is activities unless to do so would be States. as follows. inconsistent with applicable law or The EPA has determined that this As discussed in the impacts section of otherwise impractical. VCS are proposed rule will not have the Preamble, we use the NEMS to technical standards (e.g., materials disproportionately high and adverse estimate the impacts of the proposed specifications, test methods, sampling human health or environmental effects NSPS on the United States energy procedures, and business practices) that on minority or low-income populations system. The NEMS is a publically are developed or adopted by VCS because it increases the level of available model of the United States bodies. NTTAA directs the EPA to environmental protection for all affected energy economy developed and provide Congress, through OMB, populations without having any maintained by the Energy Information explanations when the Agency decides disproportionately high and adverse Administration of the United States not to use available and applicable VCS. human health or environmental effects DOE and is used to produce the Annual The proposed rule involves technical on any population, including any Energy Outlook, a reference publication standards. Therefore, the requirements minority or low-income population. that provides detailed forecasts of the of the NTTAA apply to this action. We To examine the potential for any EJ United States energy economy. are proposing to revise 40 CFR part 63, issues that might be associated with Proposed emission controls for the subpart HH and 40 CFR part 63, subpart each source category, we evaluated the NSPS capture VOC emissions that HHH to allow ANSI/ASME PTC 19.10– distributions of HAP-related cancer and otherwise would be vented to the 1981, Flue and Exhaust Gas Analyses noncancer risks across different social, atmosphere. Since methane is co- (Part 10, Instruments and Apparatus) to demographic and economic groups emitted with VOC, a large proportion of be used in lieu of EPA Methods 3B, 6 within the populations living near the the averted methane emissions can be and 16A. This standard is available from facilities where these source categories

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are located. The methods used to 40 CFR Part 63 Subpart LLL—Standards of conduct demographic analyses for this Environmental protection, Air Performance for SO2 Emissions From rule are described in section VII.C of the pollution control, Reporting and Onshore Natural Gas Processing for preamble for this rule. The development recordkeeping requirements, Volatile Which Construction, Reconstruction, of demographic analyses to inform the organic compounds. or Modification Commenced After consideration of EJ issues in EPA January 20, 1984, and on or Before Dated: July 28, 2011. rulemakings is an evolving science. The August 23, 2011 EPA offers the demographic analyses in Lisa P. Jackson, Administrator. 5. The heading for Subpart LLL is this proposed rulemaking as examples revised to read as set out above. of how such analyses might be For the reasons set out in the 6. Section 60.640 is amended by developed to inform such consideration, preamble, title 40, chapter I of the Code revising paragraph (d) to read as and invites public comment on the of Federal Regulations is proposed to be follows: approaches used and the interpretations amended as follows: made from the results, with the hope § 60.640 Applicability and designation of PART 60—[AMENDED] that this will support the refinement affected facilities. and improve utility of such analyses for 1. The authority citation for part 60 * * * * * future rulemakings. continues to read as follows: (d) The provisions of this subpart apply to each affected facility identified For the demographic analyses, we Authority: 42 U.S.C. 7401, et seq. in paragraph (a) of this section which focused on the populations within 50 2. Section 60.17 is amended by: commences construction or km of any facility estimated to have a. Revising paragraph (a)(7); and modification after January 20, 1984, and exposures to HAP which result in b. Revising paragraphs (a)(91) and on or before August 23, 2011. cancer risks of 1-in-1 million or greater, (a)(92) to read as follows: * * * * * or noncancer HI of 1 or greater (based § 60.17 Incorporations by reference. 7. Add subpart OOOO to part 60 to on the emissions of the source category read as follows: or the facility, respectively). We * * * * * examined the distributions of those (a) * * * Subpart OOOO—Standards of Performance (7) ASTM D86–78, 82, 90, 93, 95, 96, for Crude Oil and Natural Gas Production, risks across various demographic Transmission, and Distribution groups, comparing the percentages of Distillation of Petroleum Products, IBR Sec. particular demographic groups to the approved for §§ 60.562–2(d), 60.593(d), 60.593a(d), 60.633(h) and 60.5401(h). 60.5360 What is the purpose of this total number of people in those subpart? demographic groups nationwide. The * * * * * 60.5365 Am I subject to this subpart? results, including other risk metrics, (91) ASTM E169–63, 77, 93, General 60.5370 When must I comply with this such as average risks for the exposed Techniques of Ultraviolet Quantitative subpart? populations, are documented in source Analysis, IBR approved for 60.5375 What standards apply to gas category-specific technical reports in the §§ 60.485a(d)(1), 60.593(b)(2), wellhead affected facilities? 60.593a(b)(2), 60.632(f) and 60.5400(f). 60.5380 What standards apply to docket for both source categories (92) ASTM E260–73, 91, 96, General centrifugal compressor affected covered in this proposal. Gas Chromatography Procedures, IBR facilities? As described in the preamble, our risk approved for §§ 60.485a(d)(1), 60.5385 What standards apply to assessments demonstrate that the reciprocating compressor affected 60.593(b)(2), 60.593a(b)(2), 60.632(f), facilities? regulations for the oil and natural gas 60.5400(f) and 60.5406(b). 60.5390 What standards apply to pneumatic production and natural gas transmission * * * * * controller affected facilities? and storage source categories, are 60.5395 What standards apply to storage associated with an acceptable level of Subpart KKK—Standards of vessel affected facilities? risk and that the proposed additional Performance for Equipment Leaks of 60.5400 What VOC standards apply to requirements will provide an ample VOC From Onshore Natural Gas affected facilities at an onshore natural margin of safety to protect public health. Processing Plants for Which gas processing plant? Construction, Reconstruction, or 60.5401 What are the exceptions to the VOC Our analyses also show that, for these standards for affected facilities at source categories, there is no potential Modification Commenced After onshore natural gas processing plants? for an adverse environmental effect or January 20, 1984, and on or Before 60.5402 What are the alternative emission human health multi-pathway effects, August 23, 2011 limitations for equipment leaks from and that acute and chronic noncancer onshore natural gas processing plants? 3. The heading for Subpart KKK is 60.5405 What standards apply to health impacts are unlikely. The EPA revised to read as set out above. has determined that, although there may sweetening units at onshore natural gas 4. Section 60.630 is amended by processing plants? be an existing disparity in HAP risks revising paragraph (b) to read as follows: 60.5406 What test methods and procedures from these sources between some must I use for my sweetening units demographic groups, no demographic § 60.630 Applicability and designation of affected facilities at onshore natural gas group is exposed to an unacceptable affected facility. processing plants? level of risk. * * * * * 60.5407 What are the requirements for (b) Any affected facility under monitoring of emissions and operations List of Subjects paragraph (a) of this section that from my sweetening unit affected facilities at onshore natural gas 40 CFR Part 60 commences construction, reconstruction, or modification after processing plants? January 20, 1984, and on or before 60.5408 What is an optional procedure for Environmental protection, Air measuring hydrogen sulfide in acid gas— pollution control, Reporting and August 23, 2011, is subject to the Tutwiler Procedure? recordkeeping requirements, Volatile requirements of this subpart. 60.5410 How do I demonstrate initial organic compounds. * * * * * compliance with the standards for my

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gas wellhead affected facility, my following hydraulic fracturing or located at the onshore natural gas centrifugal compressor affected facility, refracturing that occurs at a gas processing plant site is exempt from the my reciprocating compressor affected wellhead facility that commenced provisions of §§ 60.5400, 60.5401, facility, my pneumatic controller construction, modification, or 60.5402, 60.5421 and 60.5422 of this affected facility, my storage vessel affected facility, and my affected reconstruction on or before August 23, subpart. facilities at onshore natural gas 2011 is considered a modification of the (5) Affected facilities located at processing plants? gas wellhead facility, but does not affect onshore natural gas processing plants 60.5415 How do I demonstrate continuous other equipment, process units, storage and described in paragraphs (f)(1) and compliance with the standards for my vessels, or pneumatic devices located at (f)(2) of this section are exempt from gas wellhead affected facility, my the well site. this subpart if they are subject to and centrifugal compressor affected facility, (a) A gas wellhead affected facility, is controlled according to subparts VVa, my stationary reciprocating compressor a single natural gas well. GGG or GGGa of this part. affected facility, my pneumatic (b) A centrifugal compressor affected controller affected facility, my storage (g) Sweetening units located onshore vessel affected facility, and my affected facility, which is defined as a single that process natural gas produced from facilities at onshore natural gas centrifugal compressor located between either onshore or offshore wells. processing plants? the wellhead and the city gate (as (1) Each sweetening unit that 60.5420 What are my notification, defined in § 60.5430), except that a processes natural gas is an affected reporting, and recordkeeping centrifugal compressor located at a well facility; and requirements? site (as defined in § 60.5430) is not an (2) Each sweetening unit that 60.5421 What are my additional affected facility under this subpart. For processes natural gas followed by a recordkeeping requirements for my the purposes of this subpart, your sulfur recovery unit is an affected affected facility subject to VOC requirements for onshore natural gas centrifugal compressor is considered to facility. processing plants? have commenced construction on the (3) Facilities that have a design 60.5422 What are my additional reporting date the compressor is installed at the capacity less than 2 long tons per day requirements for my affected facility facility. (LT/D) of hydrogen sulfide (H2S) in the subject to VOC requirements for onshore (c) A reciprocating compressor acid gas (expressed as sulfur) are natural gas processing plants? affected facility, which is defined as a required to comply with recordkeeping 60.5423 What additional recordkeeping and single reciprocating compressor located and reporting requirements specified in reporting requirements apply to my between the wellhead and the city gate § 60.5423(c) but are not required to sweetening unit affected facilities at (as defined in § 60.5430), except that a comply with §§ 60.5405 through onshore natural gas processing plants? reciprocating compressor located at a 60.5425 What part of the General Provisions 60.5407 and paragraphs 60.5410(g) and apply to me? well site (as defined in § 60.5430) is not 60.5415(g) of this subpart. 60.5430 What definitions apply to this an affected facility under this subpart. (4) Sweetening facilities producing subpart? For the purposes of this subpart, your acid gas that is completely reinjected Table 1 to Subpart OOOO of Part 60— reciprocating compressor is considered into oil-or-gas-bearing geologic strata or Required Minimum Initial SO2 Emission to have commenced construction on the that is otherwise not released to the Reduction Efficiency (Zi) date the compressor is installed at the atmosphere are not subject to §§ 60.5405 Table 2 to Subpart OOOO of Part 60— facility. through 60.5407, and §§ 60.5410(g), Required Minimum SO2 Emission (d) A pneumatic controller affected 60.5415(g), and § 60.5423 of this Reduction Efficiency (Z ) c facility, which is defined as a single subpart. Table 3 to Subpart OOOO of Part 60— pneumatic controller. Applicability of General Provisions to (e) A storage vessel affected facility, § 60.5370 When must I comply with this Subpart OOOO which is defined as a single storage subpart? Subpart OOOO—Standards of vessel. (a) You must be in compliance with Performance for Crude Oil and Natural (f) Compressors and equipment (as the standards of this subpart no later Gas Production, Transmission, and defined in § 60.5430) located at onshore than the date of publication of the final Distribution natural gas processing plants. rule in the Federal Register or upon (1) Each compressor in VOC service or startup, whichever is later. § 60.5360 What is the purpose of this in wet gas service is an affected facility. (b) The provisions for exemption from subpart? (2) The group of all equipment, except compliance during periods of startup, This subpart establishes emission compressors, within a process unit is an shutdown, and malfunctions provided standards and compliance schedules for affected facility. for in 40 CFR 60.8(c) do not apply to the control of volatile organic (3) Addition or replacement of this subpart. compounds (VOC) and sulfur dioxide equipment, as defined in § 60.5430, for (c) You are exempt from the (SO2) emissions from affected facilities the purpose of process improvement obligation to obtain a permit under 40 that commenced construction, that is accomplished without a capital CFR part 70 or 40 CFR part 71, provided modification or reconstruction after expenditure shall not by itself be you are not otherwise required by law August 23, 2011. considered a modification under this to obtain a permit under 40 CFR 70.3(a) subpart. or 40 CFR 71.3(a). Notwithstanding the § 60.5365 Am I subject to this subpart? (4) Equipment (as defined in previous sentence, you must continue to If you are the owner or operator of one § 60.5430) associated with a compressor comply with the provisions of this or more of the affected facilities listed station, dehydration unit, sweetening subpart. in paragraphs (a) through (g) of this unit, underground storage tank, field gas section that commenced construction, gathering system, or liquefied natural § 60.5375 What standards apply to gas modification, or reconstruction after gas unit is covered by §§ 60.5400, wellhead affected facilities? August 23, 2011 your affected facility is 60.5401, 60.5402, 60.5421 and 60.5422 If you are the owner or operator of a subject to the applicable provisions of of this subpart if it is located at an gas wellhead affected facility, you must this subpart. For the purposes of this onshore natural gas processing plant. comply with paragraphs (a) through (g) subpart, a well completion operation Equipment (as defined in § 60.5430) not of this section.

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(a) Except as provided in paragraph (f) (b) You must demonstrate initial emissions no greater than 6 standard of this section, for each well completion compliance with the standards that cubic feet per hour. operation with hydraulic fracturing, as apply to centrifugal compressor affected (d) You must demonstrate initial defined in § 60.5430, you must control facilities as required by § 60.5410. compliance with standards that apply to emissions by the operational procedures (c) You must demonstrate continuous pneumatic controller affected facilities found in paragraphs (a)(1) through (a)(3) compliance with the standards that as required by § 60.5410. of this section. apply to centrifugal compressor affected (e) You must demonstrate continuous (1) You must minimize the emissions facilities as required by § 60.5415. compliance with standards that apply to associated with venting of hydrocarbon (d) You must perform the required pneumatic controller affected facilities fluids and gas over the duration of notification, recordkeeping, and as required by § 60.5415. flowback by routing the recovered reporting as required by § 60.5420. (f) You must perform the required liquids into storage vessels and routing notification, recordkeeping, and the recovered gas into a gas gathering § 60.5385 What standards apply to reciprocating compressor affected reporting as required by § 60.5420, line or collection system. facilities? except that you are not required to (2) You must employ sand traps, surge You must comply with the standards submit the notifications specified in vessels, separators, and tanks during § 60.5420(a). flowback and cleanout operations to in paragraphs (a) through (d) of this safely maximize resource recovery and section for each reciprocating § 60.5395 What standards apply to storage minimize releases to the environment. compressor affected facility. vessel affected facilities? All salable quality gas must be routed to (a) You must replace the reciprocating You must comply with the standards the gas gathering line as soon as compressor rod packing before the in paragraphs (a) through (e) of this practicable. compressor has operated for 26,000 section for each storage vessel affected (3) You must capture and direct hours. The number of hours of operation facility. must be continuously monitored flowback emissions that cannot be (a) You must comply with the beginning upon initial startup of your directed to the gathering line to a standards for storage vessels specified in reciprocating compressor affected completion combustion device, except § 63.766(b) and (c) of this chapter, facility, or the date of publication of the in conditions that may result in a fire except as specified in paragraph (b) of final rule in the Federal Register, or the hazard or explosion. Completion this section. Storage vessels that meet date of the previous reciprocating combustion devices must be equipped either one or both of the throughput compressor rod packing replacement, with a reliable continuous ignition conditions specified in paragraphs (a)(1) whichever is later. source over the duration of flowback. or (a)(2) of this section are not subject (b) You must demonstrate initial (b) You must maintain a log for each to the standards of this section. well completion operation at each gas compliance with standards that apply to reciprocating compressor affected (1) The annual average condensate wellhead affected facility. The log must throughput is less than 1 barrel per day be completed on a daily basis and must facilities as required by § 60.5410. (c) You must demonstrate continuous per storage vessel. contain the records specified in (2) The annual average crude oil § 60.5420(c)(1)(iii). compliance with standards that apply to reciprocating compressor affected throughput is less than 20 barrels per (c) You must demonstrate initial day per storage vessel. compliance with the standards that facilities as required by § 60.5415. (b) This standard does not apply to apply to gas wellhead affected facilities (d) You must perform the required storage vessels already subject to and as required by § 60.5410. notification, recordkeeping, and (d) You must demonstrate continuous reporting as required by § 60.5420. controlled in accordance with the compliance with the standards that requirements for storage vessels in § 60.5390 What standards apply to § 63.766(b)(1) or (2) of this chapter. apply to gas wellhead affected facilities pneumatic controller affected facilities? as required by § 60.5415. (c) You must demonstrate initial (e) You must perform the required For each pneumatic controller compliance with standards that apply to notification, recordkeeping, and affected facility you must comply with storage vessel affected facilities as reporting as required by § 60.5420. the VOC standards, based on natural gas required by § 60.5410. (f) For wells meeting the criteria for as a surrogate for VOC, in either (d) You must demonstrate continuous wildcat or delineation wells, each well paragraph (b) or (c) of this section, as compliance with standards that apply to completion operation with hydraulic applicable. Pneumatic controllers storage vessel affected facilities as fracturing at a gas wellhead affected meeting the conditions in paragraph (a) required by § 60.5415. facility must reduce emissions by using are exempt from this requirement. (e) You must perform the required a completion combustion device (a) The requirements of paragraph (b) notification, recordkeeping, and meeting the requirements of paragraph or (c) of this section are not required if reporting as required by § 60.5420. (a)(3) of this section. You must also you demonstrate, to the Administrator’s § 60.5400 What VOC standards apply to maintain records specified in satisfaction, that the use of a high bleed device is predicated. The demonstration affected facilities at an onshore natural gas § 60.5420(c)(1)(iii) for wildcat or processing plant? delineation wells. may include, but is not limited to, response time, safety and actuation. This section applies to each § 60.5380 What standards apply to (b) Each pneumatic controller affected compressor in VOC service or in wet gas centrifugal compressor affected facilities? facility located at a natural gas service and the group of all equipment You must comply with the standards processing plant (as defined in (as defined in § 60.5430), except in paragraphs (a) through (d) of this § 60.5430) must have zero emissions of compressors, within a process unit. section, as applicable for each natural gas. (a) You must comply with the centrifugal compressor affected facility. (c) Each pneumatic controller affected requirements of § 60.482–1a(a), (b), and (a) You must equip each rotating facility not located at a natural gas (d), § 60.482–2a, and § 60.482–4a compressor shaft with a dry seal system processing plant (as defined in through 60.482–11a, except as provided upon initial startup. § 60.5430) must have natural gas in § 60.5401.

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(b) You may elect to comply with the detected, except as provided in reduction in VOC emissions at least requirements of §§ 60.483–1a and § 60.482–9a. equivalent to the reduction in VOC 60.483–2a, as an alternative. (ii) A first attempt at repair must be emissions achieved under any design, (c) You may apply to the made no later than 5 calendar days after equipment, work practice or operational Administrator for permission to use an each leak is detected. standard, the Administrator will alternative means of emission limitation (4)(i) Any pressure relief device that publish, in the Federal Register, a that achieves a reduction in emissions is located in a nonfractionating plant notice permitting the use of that of VOC at least equivalent to that that is monitored only by non-plant alternative means for the purpose of achieved by the controls required in this personnel may be monitored after a compliance with that standard. The subpart according to the requirements of pressure release the next time the notice may condition permission on § 60.5402 of this subpart. monitoring personnel are on-site, requirements related to the operation (d) You must comply with the instead of within 5 days as specified in and maintenance of the alternative provisions of § 60.485a of this part paragraph (b)(1) of this section and means. except as provided in paragraph (f) of § 60.482–4a(b)(1) of subpart VVa. (b) Any notice under paragraph (a) of this section. (ii) No pressure relief device this section must be published only after notice and an opportunity for a (e) You must comply with the described in paragraph (b)(4)(i) of this public hearing. provisions of §§ 60.486a and 60.487a of section must be allowed to operate for (c) The Administrator will consider this part except as provided in more than 30 days after a pressure release without monitoring. applications under this section from §§ 60.5401, 60.5421, and 60.5422 of this either owners or operators of affected part. (c) Sampling connection systems are exempt from the requirements of facilities, or manufacturers of control (f) You must use the following equipment. provision instead of § 60.485a(d)(1): § 60.482–5a. (d) Pumps in light liquid service, (d) The Administrator will treat Each piece of equipment is presumed to valves in gas/vapor and light liquid applications under this section be in VOC service or in wet gas service service, and pressure relief devices in according to the following criteria, unless an owner or operator gas/vapor service that are located at a except in cases where the Administrator demonstrates that the piece of nonfractionating plant with a design concludes that other criteria are equipment is not in VOC service or in capacity to process 283,200 standard appropriate: wet gas service. For a piece of cubic meters per day (scmd) (10 million (1) The applicant must collect, verify equipment to be considered not in VOC standard cubic feet per day) or more of and submit test data, covering a period service, it must be determined that the field gas are exempt from the routine of at least 12 months, necessary to VOC content can be reasonably monitoring requirements of §§ 60.482– support the finding in paragraph (a) of expected never to exceed 10.0 percent 2a(a)(1) and 60.482–7a(a), and this section. by weight. For a piece of equipment to (2) If the applicant is an owner or paragraph (b)(1) of this section. be considered in wet gas service, it must (e) Pumps in light liquid service, operator of an affected facility, the be determined that it contains or valves in gas/vapor and light liquid applicant must commit in writing to contacts the field gas before the service, and pressure relief devices in operate and maintain the alternative extraction step in the process. For gas/vapor service within a process unit means so as to achieve a reduction in purposes of determining the percent that is located in the Alaskan North VOC emissions at least equivalent to the VOC content of the process fluid that is Slope are exempt from the routine reduction in VOC emissions achieved contained in or contacts a piece of monitoring requirements of §§ 60.482– under the design, equipment, work equipment, procedures that conform to 2a(a)(1), 60.482–7a(a), and paragraph practice or operational standard. the methods described in ASTM E169– (b)(1) of this section. 63, 77, or 93, E168–67, 77, or 92, or § 60.5405 What standards apply to (f) Flares used to comply with this sweetening units at onshore natural gas E260–73, 91, or 96 (incorporated by subpart must comply with the processing plants? reference as specified in § 60.17) must requirements of § 60.18. be used. (a) During the initial performance test (g) An owner or operator may use the required by § 60.8(b), you must achieve § 60.5401 What are the exceptions to the following provisions instead of at a minimum, an SO2 emission VOC standards for affected facilities at § 60.485a(e): reduction efficiency (Zi) to be onshore natural gas processing plants? (1) Equipment is in heavy liquid determined from Table 1 of this subpart (a) You may comply with the service if the weight percent evaporated based on the sulfur feed rate (X) and the ° ° following exceptions to the provisions is 10 percent or less at 150 C (302 F) sulfur content of the acid gas (Y) of the of subpart VVa of this part. as determined by ASTM Method D86– affected facility. (b)(1) Each pressure relief device in 78, 82, 90, 95, or 96 (incorporated by (b) After demonstrating compliance gas/vapor service may be monitored reference as specified in § 60.17). with the provisions of paragraph (a) of quarterly and within 5 days after each (2) Equipment is in light liquid this section, you must achieve at a service if the weight percent evaporated minimum, an SO2 emission reduction pressure release to detect leaks by the ° is greater than 10 percent at 150 C (302 efficiency (Zc) to be determined from methods specified in § 60.485a(b) except ° as provided in § 60.5400(c) and in F) as determined by ASTM Method Table 2 of this subpart based on the paragraph (b)(4) of this section, and D86–78, 82, 90, 95, or 96 (incorporated sulfur feed rate (X) and the sulfur § 60.482–4a(a) through (c) of subpart by reference as specified in § 60.17). content of the acid gas (Y) of the affected facility. VVa. § 60.5402 What are the alternative (2) If an instrument reading of 5000 emission limitations for equipment leaks 60.5406 What test methods and ppm or greater is measured, a leak is from onshore natural gas processing procedures must I use for my sweetening detected. plants? units affected facilities at onshore natural (3)(i) When a leak is detected, it must (a) If, in the Administrator’s gas processing plants? be repaired as soon as practicable, but judgment, an alternative means of (a) In conducting the performance no later than 15 calendar days after it is emission limitation will achieve a tests required in § 60.8, you must use

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the test methods in Appendix A of this product storage tanks. You must use content of the effluent gas is greater than part or other methods and procedures as readings taken at the beginning and end 1.0 percent by volume. You must take specified in this section, except as of each run, the tank geometry, sulfur eight samples of 20 minutes each at 30- provided in paragraph § 60.8(b). density at the storage temperature, and minute intervals. The arithmetic average (b) During a performance test required sample duration to determine the sulfur must be the concentration for the run. by § 60.8, you must determine the production rate (S) in kg/hr (lb/hr) for The concentration in ppm reduced minimum required reduction each run. sulfur as sulfur must be multiplied by ¥ efficiencies (Z) of SO2 emissions as (3) You must compute the emission 1.333 × 10 3 to convert the results to required in § 60.5405(a) and (b) as rate of sulfur for each run as follows: sulfur equivalent. follows: (iv) You must use Method 2 of (1) The average sulfur feed rate (X) appendix A to part 60 of this chapter to must be computed as follows: determine the volumetric flow rate of X ¥ KQ g the effluent gas. A velocity traverse a Where: Where: must be conducted at the beginning and E = emission rate of sulfur per run, kg/hr. end of each run. The arithmetic average X = average sulfur feed rate, Mg/D (LT/D). Ce = concentration of sulfur equivalent (SO2 of the two measurements must be used Qa = average volumetric flow rate of acid gas + reduced sulfur), g/dscm (lb/dscf). to calculate the volumetric flow rate from sweetening unit, dscm/day (dscf/ Qsd = volumetric flow rate of effluent gas, day). dscm/hr (dscf/hr). (Qsd) for the run. For the determination Y = average H2S concentration in acid gas K1 = conversion factor, 1000 g/kg of the effluent gas molecular weight, a feed from sweetening unit, percent by (7000 gr/lb). single integrated sample over the 4-hour volume, expressed as a decimal. (4) The concentration (C ) of sulfur period may be taken and analyzed or K = (32 kg S/kg-mole) / ((24.04 dscm/kg- e grab samples at 1-hour intervals may be mole) (1000 kg S/Mg)) equivalent must be the sum of the SO2 ¥ taken, analyzed, and averaged. For the = 1.331 × 10 3 Mg/dscm, for metric units and TRS concentrations, after being = (32 lb S/lb-mole) / ((385.36 dscf/lb-mole) converted to sulfur equivalents. For moisture content, you must take two (2240 lb S/long ton)) each run and each of the test methods samples of at least 0.10 dscm (3.5 dscf) ¥ = 3.707 × 10 5 long ton/dscf, for English specified in this paragraph (c) of this and 10 minutes at the beginning of the units. section, you must use a sampling time 4-hour run and near the end of the time (2) You must use the continuous of at least 4 hours. You must use period. The arithmetic average of the readings from the process flowmeter to Method 1 of Appendix A to part 60 of two runs must be the moisture content determine the average volumetric flow this chapter to select the sampling site. for the run. rate (Qa) in dscm/day (dscf/day) of the The sampling point in the duct must be § 60.5407 What are the requirements for acid gas from the sweetening unit for at the centroid of the cross-section if the monitoring of emissions and operations each run. area is less than 5 m2 (54 ft2) or at a from my sweetening unit affected facilities (3) You must use the Tutwiler point no closer to the walls than at onshore natural gas processing plants? procedure in § 60.5408 or a 1 m (39 in) if the cross-sectional area is (a) If your sweetening unit affected chromatographic procedure following 5 m2 or more, and the centroid is more facility is located at an onshore natural ASTM E–260 (incorporated by than 1 m (39 in.) from the wall. gas processing plant and is subject to reference—see § 60.17) to determine the (i) You must use Method 6 of the provisions of § 60.5405(a) or (b) you H2S concentration in the acid gas feed Appendix A to part 60 of this chapter must install, calibrate, maintain, and from the sweetening unit (Y). At least to determine the SO2 concentration. You operate monitoring devices or perform one sample per hour (at equally spaced must take eight samples of 20 minutes measurements to determine the intervals) must be taken during each each at 30-minute intervals. The following operations information on a 4-hour run. The arithmetic mean of all arithmetic average must be the daily basis: samples must be the average H2S concentration for the run. The (1) The accumulation of sulfur concentration (Y) on a dry basis for the concentration must be multiplied by product over each 24-hour period. The run. By multiplying the result from the 0.5 × 10¥3 to convert the results to monitoring method may incorporate the Tutwiler procedure by 1.62 × 10¥3, the sulfur equivalent. use of an instrument to measure and units gr/100 scf are converted to volume (ii) You must use Method 15 of record the liquid sulfur production rate, percent. appendix A to part 60 of this chapter to or may be a procedure for measuring (4) Using the information from determine the TRS concentration from and recording the sulfur liquid levels in paragraphs (b)(1) and (b)(3) of this reduction-type devices or where the the storage tanks with a level indicator section, Tables 1 and 2 of this subpart oxygen content of the effluent gas is less or by manual soundings, with must be used to determine the required than 1.0 percent by volume. The subsequent calculation of the sulfur initial (Zi) and continuous (Zc) sampling rate must be at least 3 liters/ production rate based on the tank reduction efficiencies of SO2 emissions. min (0.1 ft3/min) to insure minimum geometry, stored sulfur density, and (c) You must determine compliance residence time in the sample line. You elapsed time between readings. The with the SO2 standards in § 60.5405(a) must take sixteen samples at 15-minute method must be designed to be accurate or (b) as follows: intervals. The arithmetic average of all within ± 2 percent of the 24-hour sulfur (1) You must compute the emission the samples must be the concentration accumulation. reduction efficiency (R) achieved by the for the run. The concentration in ppm (2) The H2S concentration in the acid sulfur recovery technology for each run reduced sulfur as sulfur must be gas from the sweetening unit for each using the following equation: multiplied by 1.333 × 10¥3 to convert 24-hour period. At least one sample per the results to sulfur equivalent. 24-hour period must be collected and (iii) You must use Method 16A or analyzed using the equation specified in Method 15 of appendix A to part 60 of § 60.5406(b)(1). The Administrator may (2) You must use the level indicators this chapter to determine the reduced require you to demonstrate that the H2S or manual soundings to measure the sulfur concentration from oxidation- concentration obtained from one or liquid sulfur accumulation rate in the type devices or where the oxygen more samples over a 24-hour period is

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within ± 20 percent of the average of 12 determined using the monitoring internal. The 24-hour interval may begin samples collected at equally spaced device. If the volumetric ratio of sulfur and end at any selected clock time, but intervals during the 24-hour period. In dioxide to sulfur dioxide plus total must be consistent. You must compute instances where the H2S concentration reduced sulfur (expressed as SO2) in the the 24-hour average reduction efficiency of a single sample is not within ± 20 gas leaving the incinerator is equal to or (R) based on the 24-hour average sulfur percent of the average of the 12 equally less than 0.98, then temperature production rate (S) and sulfur emission spaced samples, the Administrator may monitoring may be used to demonstrate rate (E), using the equation in require a more frequent sampling that sulfur dioxide emission monitoring § 60.5406(c)(1). schedule. is sufficient to determine total sulfur (1) You must use data obtained from (3) The average acid gas flow rate emissions. At all times during the from the sweetening unit. You must operation of the facility, you must the sulfur production rate monitoring install and operate a monitoring device maintain the average temperature of the device specified in paragraph (a) of this to continuously measure the flow rate of gas leaving the combustion zone of the section to determine S. acid gas. The monitoring device reading incinerator at or above the appropriate (2) You must use data obtained from must be recorded at least once per hour level determined during the most recent the sulfur emission rate monitoring during each 24-hour period. The average performance test to ensure the sulfur systems specified in paragraphs (b) or acid gas flow rate must be computed compound oxidation criteria are met. (c) of this section to calculate a 24-hour from the individual readings. Operation at lower average temperatures average for the sulfur emission rate (E). (4) The sulfur feed rate (X). For each may be considered by the Administrator The monitoring system must provide at 24-hour period, you must compute X to be unacceptable operation and least one data point in each successive using the equation specified in maintenance of the affected facility. You 15-minute interval. You must use at § 60.5406(b)(3). may request that the minimum least two data points to calculate each (5) The required sulfur dioxide incinerator temperature be reestablished 1-hour average. You must use a emission reduction efficiency for the by conducting new performance tests minimum of 18 1-hour averages to 24-hour period. You must use the sulfur under § 60.8. compute each 24-hour average. feed rate and the H2S concentration in (4) Upon promulgation of a the acid gas for the 24-hour period, as performance specification of continuous (e) In lieu of complying with applicable, to determine the required monitoring systems for total reduced paragraphs (b) or (c) of this section, reduction efficiency in accordance with sulfur compounds at sulfur recovery those sources with a design capacity of the provisions of § 60.5405(b). plants, you may, as an alternative to less than 152 Mg/D (150 LT/D) of H2S (b) Where compliance is achieved paragraph (b)(2) of this section, install, expressed as sulfur may calculate the through the use of an oxidation control calibrate, maintain, and operate a sulfur emission reduction efficiency system or a reduction control system continuous emission monitoring system achieved for each 24-hour period by: followed by a continually operated for total reduced sulfur compounds as incineration device, you must install, required in paragraph (d) of this section calibrate, maintain, and operate in addition to a sulfur dioxide emission monitoring devices and continuous monitoring system. The sum of the emission monitors as follows: equivalent sulfur mass emission rates (1) A continuous monitoring system to from the two monitoring systems must Where: measure the total sulfur emission rate be used to compute the total sulfur R = The sulfur dioxide removal efficiency (E) of SO2 in the gases discharged to the emission rate (E). achieved during the 24-hour period, atmosphere. The SO2 emission rate (c) Where compliance is achieved percent. must be expressed in terms of through the use of a reduction control K = Conversion factor, 0.02400 Mg/D per kg/ equivalent sulfur mass flow rates (kg/hr system not followed by a continually 2 hr (0.01071 LT/D per lb/hr). (lb/hr)). The span of this monitoring operated incineration device, you must S = The sulfur production rate during the 24- system must be set so that the install, calibrate, maintain, and operate hour period, kg/hr (lb/hr). equivalent emission limit of a continuous monitoring system to X = The sulfur feed rate in the acid gas, Mg/ § 60.5405(b) will be between 30 percent measure the emission rate of reduced D (LT/D). and 70 percent of the measurement sulfur compounds as SO2 equivalent in range of the instrument system. the gases discharged to the atmosphere. (f) The monitoring devices required in (2) Except as provided in paragraph The SO2 equivalent compound emission paragraphs (b)(1), (b)(3) and (c) of this (b)(3) of this section: A monitoring rate must be expressed in terms of section must be calibrated at least device to measure the temperature of equivalent sulfur mass flow rates (kg/hr annually according to the the gas leaving the combustion zone of (lb/hr)). The span of this monitoring manufacturer’s specifications, as the incinerator, if compliance with system must be set so that the required by § 60.13(b). § 60.5405(a) is achieved through the use equivalent emission limit of of an oxidation control system or a § 60.5405(b) will be between 30 and 70 (g) The continuous emission reduction control system followed by a percent of the measurement range of the monitoring systems required in continually operated incineration system. This requirement becomes paragraphs (b)(1), (b)(3), and (c) of this device. The monitoring device must be effective upon promulgation of a section must be subject to the emission certified by the manufacturer to be performance specification for monitoring requirements of § 60.13 of accurate to within ± 1 percent of the continuous monitoring systems for total the General Provisions. For conducting temperature being measured. reduced sulfur compounds at sulfur the continuous emission monitoring (3) When performance tests are recovery plants. system performance evaluation required conducted under the provision of § 60.8 (d) For those sources required to by § 60.13(c), Performance Specification to demonstrate compliance with the comply with paragraph (b) or (c) of this 2 of appendix B to part 60 of this standards under § 60.5405, the section, you must calculate the average chapter must apply, and Method 6 must temperature of the gas leaving the sulfur emission reduction efficiency be used for systems required by incinerator combustion zone must be achieved (R) for each 24-hour clock paragraph (b) of this section.

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§ 60.5408 What is an optional procedure proper volume, and store in glass- disconnect it from burette. Rinse for measuring hydrogen sulfide in acid stoppered brown glass bottle. graduated cylinder with a standard 1 gas—Tutwiler Procedure? (2) Standard iodine solution, 1 ml = iodine solution (0.00171 g I per ml); fill (a) When an instantaneous sample is 0.001771 g I. Transfer 33.7 ml of above cylinder and record reading. Introduce desired and H2S concentration is ten 0.1N stock solution into a 250 ml successive small amounts of iodine thru grains per 1000 cubic foot or more, a volumetric flask; add water to mark and (F); shake well after each addition; 100 ml Tutwiler burette is used. For mix well. Then, for 100 ml sample of continue until a faint permanent blue concentrations less than ten grains, a gas, 1 ml of standard iodine solution is color is obtained. Record reading; 500 ml Tutwiler burette and more dilute equivalent to 100 grains H2S per cubic subtract from previous reading, and call solutions are used. In principle, this feet of gas. difference D. method consists of titrating hydrogen (3) Starch solution. Rub into a thin (e) With every fresh stock of starch sulfide in a gas sample directly with a paste about one teaspoonful of wheat solution perform a blank test as follows: standard solution of iodine. starch with a little water; pour into Introduce fresh starch solution into (b) Apparatus. (See Figure 1 of this about a pint of boiling water; stir; let burette up to 100 ml mark. Close (F) and subpart) A 100 or 500 ml capacity cool and decant off clear solution. Make (G). Lower (L) and open (G). When Tutwiler burette, with two-way glass fresh solution every few days. liquid level reaches the 10 ml mark, stopcock at bottom and three-way (d) Procedure. Fill leveling bulb with close (G). With air in burette, titrate as stopcock at top which connect either starch solution. Raise (L), open cock (G), during a test and up to same end point. with inlet tubulature or glass-stoppered open (F) to (A), and close (F) when Call ml of iodine used C. Then, cylinder, 10 ml capacity, graduated in solutions starts to run out of gas inlet. Grains H2S per 100 cubic foot of gas = 0.1 ml subdivision; rubber tubing Close (G). Purge gas sampling line and 100 (D¥C) connecting burette with leveling bottle. connect with (A). Lower (L) and open (f) Greater sensitivity can be attained (c) Reagents. (1) Iodine stock solution, (F) and (G). When liquid level is several if a 500 ml capacity Tutwiler burette is 0.1N. Weight 12.7 g iodine, and 20 to 25 ml past the 100 ml mark, close (G) and used with a more dilute (0.001N) iodine g cp potassium iodide for each liter of (F), and disconnect sampling tube. Open solution. Concentrations less than 1.0 solution. Dissolve KI in as little water as (G) and bring starch solution to 100 ml grains per 100 cubic foot can be necessary; dissolve iodine in mark by raising (L); then close (G). Open determined in this way. Usually, the concentrated KI solution, make up to (F) momentarily, to bring gas in burette starch-iodine end point is much less to atmospheric pressure, and close (F). distinct, and a blank determination of 1 Gas Engineers Handbook, Fuel Gas Engineering end point, with H S-free gas or air, is practices, The Industrial Press, 93 Worth Street, Open (G), bring liquid level down to 10 2 New York, NY, 1966, First Edition, Second Printing, ml mark by lowering (L). Close (G), required. page 6/25 (Docket A–80–20–A, Entry II–I–67). clamp rubber tubing near (E) and BILLING CODE 6560–50–P

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BILLING CODE 6560–50–C begins on the date of publication of the commencement of the well completion § 60.5410 How do I demonstrate initial final rule in the Federal Register or operation, the date of the compliance with the standards for my gas upon initial startup, whichever is later, commencement of the well completion wellhead affected facility, my centrifugal and ends on the date the first annual operation, the latitude and longitude compressor affected facility, my report is due as specified in coordinates of the well in decimal reciprocating compressor affected facility, § 60.5420(b). degrees to an accuracy and precision of my pneumatic controller affected facility, my storage vessel affected facility, and my (a) You have achieved initial five (5) decimals of a degree using the affected facilities at onshore natural gas compliance with standards for each well North American Datum (NAD) of 1983. processing plants? completion operation conducted at your (2) You have maintained a log of You must determine initial gas wellhead affected facility if you records as specified in § 60.5375(b) or (f) compliance with the standards for each have complied with paragraphs (a)(1) for each well completion operation affected facility using the requirements and (a)(2) of this section. conducted during the initial compliance in paragraphs (a) through (g) of this (1) You have notified the period. section. The initial compliance period Administrator within 30 days of the

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(3) You have submitted the initial publication of the final rule in the (3) You have submitted the results of annual report for your wellhead affected Federal Register and have conducted paragraphs (g)(1) and (g)(2) of this facility as required in § 60.5420(b). the compliance demonstration in section in the initial annual report (b) You have achieved initial § 63.772(f). submitted for your sweetening unit compliance with standards for your (3) You have conducted the initial affected facilities at onshore natural gas centrifugal compressor affected facility inspections required in § 63.773(c) of processing plants. if the centrifugal compressor is fitted this chapter. with a dry seal system upon initial (4) You have installed and operated § 60.5415 How do I demonstrate startup as required by § 60.5380. continuous compliance with the standards continuous parameter monitoring for my gas wellhead affected facility, my (c) You have achieved initial systems in accordance with § 63.773(d) centrifugal compressor affected facility, my compliance with standards for each of this chapter. stationary reciprocating compressor reciprocating compressor affected (5) If you are exempt from the affected facility, my pneumatic controller facility if you have complied with standards of § 60.5395 according to affected facility, my storage vessel affected paragraphs (c)(1) and (c)(2) of this § 60.5395(a)(1) or (a)(2), you have facility, and my affected facilities at onshore section. determined the condensate or crude oil natural gas processing plants? (1) During the initial compliance throughput, as applicable, according to (a) For each gas wellhead affected period, you have continuously paragraphs (e)(5)(i) or (e)(5)(ii) of this facility, you must demonstrate monitored the number of hours of section and demonstrated to the continuous compliance by maintaining operation. Administrator’s satisfaction that your the records for each completion (2) You have included the cumulative annual average condensate throughput operation (as defined in § 60.5430) number of hours of operation for your is less than 1 barrel per day per tank and specified in § 60.5420. reciprocating compressor affected your annual average crude oil (b) For each centrifugal compressor facility during the initial compliance throughput is less than 20 barrels per affected facility, continuous compliance period in your initial annual report day per tank. is demonstrated if the rotating required in § 60.5420(b). (i) You have installed and operated a compressor shaft is equipped with a dry (d) You have achieved initial flow meter to measure condensate or seal. compliance with emission standards for crude oil throughput in accordance with (c) For each reciprocating compressor your pneumatic controller affected the manufacturer’s procedures or affected facility, you have demonstrated facility if you comply with the specifications. continuous compliance according to requirements specified in paragraphs (ii) You have used any other method paragraphs (c)(1) and (2) of this section (d)(1) through (d)(4) of this section. approved by the Administrator to (1) You have continuously monitored (1) You have demonstrated, to the determine annual average condensate or the number of hours of operation for Administrator’s satisfaction, the use of a crude oil throughput. each reciprocating compressor affected high bleed device is predicated as (6) You have submitted the facility since initial startup, or the date specified in § 60.5490(a). (2) You own or operate a pneumatic information in paragraphs (e)(1) through of publication of the final rule in the controller affected facility located at a (e)(5) of this section in the initial annual Federal Register, or the date of the natural gas processing plant and your report for your storage vessel affected previous reciprocating compressor rod pneumatic controller is driven other facility as required in § 60.5420(b). packing replacement, whichever is later. than by use of natural gas and therefore (f) For affected facilities at onshore The cumulative number of hours of emits zero natural gas. natural gas processing plants, initial operation must be included in the (3) You own or operate a pneumatic compliance with the VOC requirements annual report as required in controller affected facility not located at is demonstrated if you are in § 60.5420(b)(4). a natural gas processing plant and the compliance with the requirements of (2) You have replaced the manufacturer’s design specifications § 60.5400. reciprocating compressor rod packing guarantee the controller emits less than (g) For sweetening unit affected before the total number of hours of or equal to 6.0 standard cubic feet of gas facilities at onshore natural gas operation reaches 26,000 hours. per hour. processing plants, initial compliance is (d) For each pneumatic controller (4) You have included the information demonstrated according to paragraphs affected facility, continuous compliance in paragraphs (d)(1) through (d)(3) of (g)(1) through (g)(3) of this section. is demonstrated by maintaining the this section in the initial annual report (1) To determine compliance with the records demonstrating that you have submitted for your pneumatic controller standards for SO2 specified in installed and operated the pneumatic affected facilities according to the § 60.5405(a), during the initial controllers as required in § 60.5390(a), requirements of § 60.5420(b). performance test as required by § 60.8, (b) or (c). (e) You have demonstrated initial the minimum required sulfur dioxide (e) For each storage vessel affected compliance with emission standards for emission reduction efficiency (Zi) is facility, continuous compliance is your storage vessel affected facility if compared to the emission reduction demonstrated according to § 63.772(f) of you are complying with paragraphs efficiency (R) achieved by the sulfur this chapter. (e)(1) through (e)(7) of this section. recovery technology as specified in (f) For affected facilities at onshore (1) You have equipped the storage paragraphs (g)(1)(i) and (g)(1)(ii) of this natural gas processing plants, vessel with a closed vent system that section. continuous compliance with VOC meets the requirements of § 63.771(c) of (i) If R ≥ Zi, your affected facility is requirements is demonstrated if you are this chapter connected to a control in compliance. in compliance with the requirements of device that meets the conditions (ii) If R < Zi, your affected facility is § 60.5400. specified in § 63.771(d). not in compliance. (g) For each sweetening unit affected (2) You have conducted an initial (2) The emission reduction efficiency facility at onshore natural gas performance test as required in (R) achieved by the sulfur reduction processing plants, you must § 63.772(e) of this chapter within 180 technology must be determined using demonstrate continuous compliance days after initial startup or the date of the procedures in § 60.5406(c)(1). with the standards for SO2 specified in

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§ 60.5405(b) according to paragraphs personal injury, or severe property operate one or more of the affected (g)(1) and (g)(2) of this section. damage; and facilities specified in § 60.5365. For the (1) The minimum required SO2 (v) All possible steps were taken to purposes of this subpart, a workover emission reduction efficiency (Zc) is minimize the impact of the excess that occurs after August 23, 2011 at each compared to the emission reduction emissions on ambient air quality, the affected facility for which construction, efficiency (R) achieved by the sulfur environment and human health; and reconstruction, or modification recovery technology. (vi) All emissions monitoring and commenced on or before August 23, (i) If R ≥ Zc, your affected facility is control systems were kept in operation 2011 is considered a modification for in compliance. if at all possible, consistent with safety which a notification must be submitted (ii) If R < Zc, your affected facility is and good air pollution control practices; under § 60.7(a)(4). not in compliance. and (1) If you own or operate a pneumatic (2) The emission reduction efficiency (vii) All of the actions in response to controller affected facility you are not (R) achieved by the sulfur reduction the excess emissions were documented required to submit the notifications technology must be determined using by properly signed, contemporaneous required in § 60.7(a)(1), (a)(3) and (a)(4). the procedures in § 60.5406(c)(1). operating logs; and (2) If you own or operate a gas (h) Affirmative defense for (viii) At all times, the facility was wellhead affected facility, you must exceedance of emission limit during operated in a manner consistent with submit a notification to the malfunction. In response to an action to good practices for minimizing Administrator within 30 days of the enforce the standards set forth in emissions; and commencement of the well completion §§ 60.5375, 60.5380, 60.5385, 60.5390, (ix) A written root cause analysis has operation. The notification must include 60.5395, 60.5400, and 60.5405, you may been prepared, the purpose of which is the date of commencement of the well assert an affirmative defense to a claim to determine, correct, and eliminate the completion operation, the latitude and for civil penalties for exceedances of primary causes of the malfunction and longitude coordinates of the well in such standards that are caused by the excess emissions resulting from the decimal degrees to an accuracy and malfunction, as defined at § 60.2. malfunction event at issue. The analysis precision of five (5) decimals of a degree Appropriate penalties may be assessed, shall also specify, using best monitoring using the North American Datum of however, if you fail to meet your burden methods and engineering judgment, the 1983. of proving all of the requirements in the amount of excess emissions that were (b) Reporting requirements. You must affirmative defense. The affirmative the result of the malfunction. submit annual reports containing the defense shall not be available for claims (2) The owner or operator of the information specified in paragraphs for injunctive relief. facility experiencing an exceedance of (b)(1) through (b)(6) of this section to the (1) To establish the affirmative its emission limit(s) during a Administrator. The initial annual report defense in any action to enforce such a malfunction shall notify the is due 1 year after the initial startup date limit, you must timely meet the Administrator by telephone or facsimile for your affected facility or 1 year after notification requirements in (FAX) transmission as soon as possible, the date of publication of the final rule § 60.5420(a), and must prove by a but no later than 2 business days after in the Federal Register, whichever is preponderance of evidence that: the initial occurrence of the later. Subsequent annual reports are due (i) The excess emissions: malfunction, if it wishes to avail itself on the same date each year as the initial (A) Were caused by a sudden, of an affirmative defense to civil annual report. If you own or operate infrequent, and unavoidable failure of penalties for that malfunction. The more than one affected facility, you may air pollution control and monitoring owner or operator seeking to assert an submit one report for multiple affected equipment, process equipment, or a affirmative defense shall also submit a facilities provided the report contains process to operate in a normal or usual written report to the Administrator all of the information required as manner, and within 45 days of the initial occurrence specified in paragraphs (b)(1) through (B) Could not have been prevented of the exceedance of the standards in through careful planning, proper design (b)(6) of this section. §§ 60.5375, 60.5380, 60.5385, 60.5390, (1) The general information specified or better operation and maintenance 60.5395, and 60.5400 to demonstrate, practices; and in paragraphs (b)(1)(i) through (b)(1)(iii) with all necessary supporting of this section. (C) Did not stem from any activity or documentation, that it has met the (i) The company name and address of event that could have been foreseen and requirements set forth in paragraph (a) the affected facility. avoided, or planned for; and of this section. The owner or operator (ii) An identification of each affected (D) Were not part of a recurring may seek an extension of this deadline facility being included in the annual pattern indicative of inadequate design, for up to 30 additional days by report. operation, or maintenance; and submitting a written request to the (iii) Beginning and ending dates of the (ii) Repairs were made as Administrator before the expiration of reporting period. expeditiously as possible when the the 45-day period. Until a request for an (2) For each gas wellhead affected applicable emission limitations were extension has been approved by the facility, the information in paragraphs being exceeded. Off-shift and overtime Administrator, the owner or operator is (b)(2)(i) through (b)(2)(iii) of this labor were used, to the extent subject to the requirement to submit section. practicable to make these repairs; and such report within 45 days of the initial (i) An identification of each well (iii) The frequency, amount and occurrence of the exceedance. duration of the excess emissions completion operation, as defined in (including any bypass) were minimized § 60.5420 What are my notification, § 60.5430, for each gas wellhead affected to the maximum extent practicable reporting, and recordkeeping facility conducted during the reporting during periods of such emissions; and requirements? period; (iv) If the excess emissions resulted (a) You must submit the notifications (ii) A record of deviations in cases from a bypass of control equipment or required in § 60.7(a)(1), (a)(3) and (a)(4), where well completion operations with a process, then the bypass was and according to paragraphs (a)(1) and hydraulic fracturing were not performed unavoidable to prevent loss of life, (a)(2) of this section, if you own or in compliance with the requirements

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specified in § 60.5375 for each gas well wellhead affected facility conducted emissions are less than 6 standard cubic affected facility. during the reporting period; feet per hour. (iii) Records specified in § 60.5375(b) (ii) Record of deviations in cases (iv) If the pneumatic controller for each well completion operation that where well completion operations with affected facility is located at a natural occurred during the reporting period. hydraulic fracturing were not performed gas processing plant, records of the (3) For each centrifugal compressor in compliance with the requirements documentation that only instrument air affected facility installed during the specified in § 60.5375. controllers are used. reporting period, documentation that (iii) Records required in § 60.5375(b) (5) For each storage vessel affected the centrifugal compressor is equipped or (f) for each well completion operation facility, you must maintain the records with dry seals. conducted for each gas wellhead identified in paragraphs (c)(5)(i) and (4) For each reciprocating compressor affected facility that occurred during the (c)(5)(ii) of this section. affected facility, the information reporting period. You must maintain the (i) If required to reduce emissions by specified in paragraphs (b)(4)(i) and records specified in paragraphs complying with § 63.766, the records (b)(4)(ii) of this section. (c)(1)(iii)(A) and (c)(1)(iii)(B) of this specified in § 63.774(b)(2) through (8) of (i) The cumulative number of hours or section. this chapter. (ii) Records of the determination that operation since initial startup, the date (A) For each gas wellheads affected the annual average condensate of publication of the final rule in the facility required to comply with the throughput is less than 1 barrel per day Federal Register, or since the previous requirements of § 60.5375(a), you must per storage vessel and crude oil reciprocating compressor rod packing record: The location of the well; the throughput is less than 21 barrels per replacement, whichever is later. duration of flowback; duration of day per storage vessel for the exemption (ii) Documentation that the recovery to the sales line; duration of under § 60.5395(a)(1) and (a)(2). reciprocating compressor rod packing combustion; duration of venting; and was replaced before the cumulative specific reasons for venting in lieu of § 60.5421 What are my additional number of hours of operation reached capture or combustion. The duration recordkeeping requirements for my affected 24,000 hours. must be specified in hours of time. facility subject to VOC requirements for (5) For each pneumatic controller (B) For each gas wellhead affected onshore natural gas processing plants? affected facility, the information facility required to comply with the (a) You must comply with the specified in paragraphs (b)(5)(i) through requirements of § 60.5375(f), you must requirements of paragraph (b) of this (b)(5)(iv) of this section. maintain the records specified in section in addition to the requirements (i) The date, location and paragraph (c)(1)(iii)(A) of this section of § 60.486a. manufacturer specifications for each except that you do not have to record (b) The following recordkeeping pneumatic controller installed. the duration of recovery to the sales requirements apply to pressure relief (ii) If applicable, documentation that line. In addition, you must record the devices subject to the requirements of the use of high bleed pneumatic devices distance, in miles, of the nearest § 60.5401(b)(1) of this subpart. is predicated and the reasons why. gathering line. (1) When each leak is detected as (iii) For pneumatic controllers not (2) For each centrifugal compressor specified in § 60.5401(b)(2), a installed at a natural gas processing affected facility, you must maintain weatherproof and readily visible plant, the manufacturer’s guarantee that records on the type of seal system identification, marked with the the device is designed such that natural installed. equipment identification number, must gas emissions are less than 6 standard be attached to the leaking equipment. cubic feet per hour. (3) For each reciprocating compressors affected facility, you must The identification on the pressure relief (iv) For pneumatic controllers device may be removed after it has been installed at a natural gas processing maintain the records in paragraphs (c)(3)(i) and (c)(3)(ii) of this section. repaired. plant, documentation that each (2) When each leak is detected as (i) Records of the cumulative number controllers has zero natural gas specified in § 60.5401(b)(2), the of hours of operation since initial emissions. following information must be recorded startup or the date of publication of the (6) For each storage vessel affected in a log and shall be kept for 2 years in final rule in the Federal Register, or the facility, the information in paragraphs a readily accessible location: previous replacement of the (b)(6)(i) and (b)(6)(ii) of this section. (i) The instrument and operator reciprocating compressor rod packing, (i) If required to reduce emissions by identification numbers and the whichever is later. complying with § 60.5395(a)(1), the equipment identification number. records specified in § 63.774(b)(2) (ii) Records of the date and time of (ii) The date the leak was detected through (b)(8) of this chapter. each reciprocating compressor rod and the dates of each attempt to repair (ii) Documentation that the annual packing replacement. the leak. average condensate throughput is less (4) For each pneumatic controller (iii) Repair methods applied in each than 1 barrel per day per storage vessel affected facility, you must maintain the attempt to repair the leak. and crude oil throughput is less than 21 records identified in paragraphs (c)(4)(i) (iv) ‘‘Above 500 ppm’’ if the barrels per day per storage for meeting through (c)(4)(iv) of this section. maximum instrument reading measured the requirements in § 60.5395(a)(1) or (i) Records of the date, location and by the methods specified in paragraph (a)(2). manufacturer specifications for each (a) of this section after each repair (c) Recordkeeping requirements. You pneumatic controller installed. attempt is 500 ppm or greater. must maintain the records identified as (ii) Records of the determination that (v) ‘‘Repair delayed’’ and the reason specified in § 60.7(f) and in paragraphs the use of high bleed pneumatic devices for the delay if a leak is not repaired (c)(1) through (c)(5) of this section is predicated and the reasons why. within 15 calendar days after discovery (1) The records for each gas wellhead (iii) If the pneumatic controller of the leak. affected facility as specified in affected facility is not located at a (vi) The signature of the owner or paragraphs (c)(1)(i) through (c)(1)(iii). natural gas processing plant, records of operator (or designate) whose decision it (i) Records identifying each well the manufacturer’s guarantee that the was that repair could not be effected completion operation for each gas device is designed such that natural gas without a process shutdown.

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(vii) The expected date of successful (2) For any affected facility electing to Centrifugal compressor means a piece repair of the leak if a leak is not repaired comply with the provisions of of equipment that compresses a process within 15 days. § 60.5407(b)(2), any 24-hour period gas by means of mechanical rotating (viii) Dates of process unit shutdowns during which the average temperature of vanes or impellers. that occur while the equipment is the gases leaving the combustion zone City gate means the delivery point at unrepaired. of an incinerator is less than the which natural gas is transferred from a (ix) The date of successful repair of appropriate operating temperature as transmission pipeline to the local gas the leak. determined during the most recent utility. (x) A list of identification numbers for performance test in accordance with the Completion combustion device means equipment that are designated for no provisions of § 60.5407(b)(2). Each 24- any ignition device, installed detectable emissions under the hour period must consist of at least 96 horizontally or vertically, used in provisions of § 60.482–4a(a). The temperature measurements equally exploration and production operations designation of equipment subject to the spaced over the 24 hours. to combust otherwise vented emissions provisions of § 60.482–4a(a) must be (c) To certify that a facility is exempt from completions or workovers. signed by the owner or operator. from the control requirements of these Compressor means a piece of standards, for each facility with a design equipment that compresses process gas § 60.5422 What are my additional reporting capacity less that 2 LT/D of H2S in the and is usually a centrifugal compressor requirements for my affected facility subject to VOC requirements for onshore natural acid gas (expressed as sulfur) you must or a reciprocating compressor. gas processing plants? keep, for the life of the facility, an Compressor station means any permanent combination of compressors (a) You must comply with the analysis demonstrating that the facility’s design capacity is less than 2 LT/D of that move natural gas at increased requirements of paragraphs (b) and (c) of H2S expressed as sulfur. pressure from fields, in transmission this section in addition to the (d) If you elect to comply with pipelines, or into storage. requirements of § 60.487a(a), (b), (c)(2)(i) § 60.5407(e) you must keep, for the life Condensate means a hydrocarbon through (iv), and (c)(2)(vii) through of the facility, a record demonstrating liquid separated from natural gas that (viii). that the facility’s design capacity is less (b) An owner or operator must condenses due to changes in the than 150 LT/D of H S expressed as include the following information in the 2 temperature, pressure, or both, and sulfur. remains liquid at standard conditions, initial semiannual report in addition to (e) The requirements of paragraph (b) the information required in as specified in § 60.2. For the purposes of this section remain in force until and of this subpart, a hydrocarbon liquid § 60.487a(b)(1) through (4): Number of unless the EPA, in delegating pressure relief devices subject to the with an API gravity equal to or greater enforcement authority to a state under than 40 degrees is considered requirements of § 60.5401(b) except for section 111(c) of the Act, approves those pressure relief devices designated condensate. reporting requirements or an alternative Crude oil means crude petroleum oil for no detectable emissions under the means of compliance surveillance or any other hydrocarbon liquid, which provisions of § 60.482–4a(a) and those adopted by such state. In that event, are produced at the well in liquid form pressure relief devices complying with affected sources within the state will be by ordinary production methods, and § 60.482–4a(c). relieved of obligation to comply with which are not the result of condensation (c) An owner or operator must include paragraph (b) of this section, provided the following information in all of gas before or after it leaves the that they comply with the requirements reservoir. For the purposes of this semiannual reports in addition to the established by the state. information required in subpart, a hydrocarbon liquid with an § 60.487a(c)(2)(i) through (vi): § 60.5425 What part of the General API gravity less than 40 degrees is (1) Number of pressure relief devices Provisions apply to me? considered crude oil. for which leaks were detected as Table 3 to this subpart shows which Dehydrator means a device in which required in § 60.5401(b)(2); and parts of the General Provisions in an absorbent directly contacts a natural (2) Number of pressure relief devices §§ 60.1 through 60.19 apply to you. gas stream and absorbs water in a for which leaks were not repaired as contact tower or absorption column required in § 60.5401(b)(3). § 60.5430 What definitions apply to this (absorber). subpart? Delineation well means a well drilled § 60.5423 What additional recordkeeping As used in this subpart, all terms not in order to determine the boundary of a and reporting requirements apply to my defined herein shall have the meaning field or producing reservoir. sweetening unit affected facilities at given them in the Act, in subpart A or Equipment means each pump, onshore natural gas processing plants? subpart VVa of part 60; and the pressure relief device, open-ended valve (a) You must retain records of the following terms shall have the specific or line, valve, compressor, and flange or calculations and measurements required meanings given them. other connector that is in VOC service in § 60.5405(a) and (b) and § 60.5407(a) Acid gas means a gas stream of or in wet gas service, and any device or through (g) for at least 2 years following hydrogen sulfide (H2S) and carbon system required by this subpart. the date of the measurements. This dioxide (CO2) that has been separated Field gas means feedstock gas requirement is included under § 60.7(d) from sour natural gas by a sweetening entering the natural gas processing of the General Provisions. unit. plant. (b) You must submit a written report Alaskan North Slope means the Field gas gathering means the system of excess emissions to the Administrator approximately 69,000 square-mile area used to transport field gas from a field semiannually. For the purpose of these extending from the Brooks Range to the to the main pipeline in the area. reports, excess emissions are defined as: Arctic Ocean. Flare means a thermal oxidation (1) Any 24-hour period (at consistent API Gravity means the weight per unit system using an open (without intervals) during which the average volume of hydrocarbon liquids as enclosure) flame. sulfur emission reduction efficiency (R) measured by a system recommended by Flowback means the process of is less than the minimum required the American Petroleum Institute (API) allowing fluids to flow from the well efficiency (Z). and is expressed in degrees. following a treatment, either in

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preparation for a subsequent phase of at a rate equal to or less than six Reciprocating compressor rod packing treatment or in preparation for cleanup standard cubic feet per hour. means a series of flexible rings in and returning the well to production. Modification means any physical machined metal cups that fit around the Flow line means surface pipe through change in, or change in the method of reciprocating compressor piston rod to which oil and/or natural gas travels operation of, an affected facility which create a seal limiting the amount of from the well. increases the amount of VOC or natural compressed natural gas that escapes to Gas-driven pneumatic controller gas emitted into the atmosphere by that the atmosphere. means a pneumatic controller powered facility or which results in the emission Reduced emissions completion means by pressurized natural gas. of VOC or natural gas into the a well completion where gas flowback Gas processing plant process unit atmosphere not previously emitted. For that is otherwise vented is captured, means equipment assembled for the the purposes of this subpart, each cleaned, and routed to the sales line. extraction of natural gas liquids from recompletion of a fractured or Reduced emissions recompletion field gas, the fractionation of the liquids refractured existing gas well is means a well completion following into natural gas products, or other considered to be a modification. refracturing of a gas well where gas operations associated with the Natural gas liquids means the flowback that is otherwise vented is processing of natural gas products. A hydrocarbons, such as ethane, propane, captured, cleaned, and routed to the process unit can operate independently butane, and pentane that are extracted sales line. if supplied with sufficient feed or raw from field gas. Reduced sulfur compounds means materials and sufficient storage facilities Natural gas processing plant (gas H2S, carbonyl sulfide (COS), and carbon for the products. plant) means any processing site disulfide (CS2). Gas well means a well, the principal engaged in the extraction of natural gas Routed to a process or route to a production of which at the mouth of the liquids from field gas, fractionation of process means the emissions are well is gas. mixed natural gas liquids to natural gas conveyed to any enclosed portion of a High-bleed pneumatic devices means products, or both. process unit where the emissions are automated, continuous bleed flow Nonfractionating plant means any gas predominantly recycled and/or control devices powered by pressurized plant that does not fractionate mixed consumed in the same manner as a natural gas and used for maintaining a natural gas liquids into natural gas material that fulfills the same function process condition such as liquid level, products. in the process and/or transformed by pressure, delta-pressure and Non gas-driven pneumatic device chemical reaction into materials that are temperature. Part of the gas power means an instrument that is actuated not regulated materials and/or stream which is regulated by the process using other sources of power than incorporated into a product; and/or condition flows to a valve actuator pressurized natural gas; examples recovered. controller where it vents continuously include solar, electric, and instrument Salable quality gas means natural gas (bleeds) to the atmosphere at a rate in air. that meets the composition, moisture, or excess of six standard cubic feet per Onshore means all facilities except other limits set by the purchaser of the hour. those that are located in the territorial natural gas. Hydraulic fracturing means the seas or on the outer continental shelf. Sales line means pipeline, generally process of directing pressurized liquids, Plunger lift system means an small in diameter, used to transport oil containing water, proppant, and any intermittent gas lift that uses gas or gas from the well to a processing added chemicals, to penetrate tight pressure buildup in the casing-tubing facility or a mainline pipeline. sand, shale, or coal formations that annulus to push a steel plunger, and the Storage vessel means a stationary involve high rate, extended back flow to column of fluid ahead of it, up the well vessel or series of stationary vessels that expel fracture fluids and sand during tubing to the surface. are either manifolded together or are completions and well workovers. Pneumatic controller means an located at a single well site and that In light liquid service means that the automated instrument used for have potential for VOC emissions equal piece of equipment contains a liquid maintaining a process condition such as to or greater than 10 tpy. that meets the conditions specified in liquid level, pressure, delta-pressure Sulfur production rate means the rate § 60.485a(e) or § 60.5401(h)(2) of this and temperature. of liquid sulfur accumulation from the part. Pneumatic pump means a pump that sulfur recovery unit. In wet gas service means that a uses pressurized natural gas to move a Sulfur recovery unit means a process compressor or piece of equipment piston or diaphragm, which pumps device that recovers element sulfur from contains or contacts the field gas before liquids on the opposite side of the acid gas. the extraction step at a gas processing piston or diaphragm. Surface site means any combination plant process unit. Process unit means components of one or more graded pad sites, gravel Liquefied natural gas unit means a assembled for the extraction of natural pad sites, foundations, platforms, or the unit used to cool natural gas to the point gas liquids from field gas, the immediate physical location upon at which it is condensed into a liquid fractionation of the liquids into natural which equipment is physically affixed. which is colorless, odorless, non- gas products, or other operations Sweetening unit means a process corrosive and non-toxic. associated with the processing of device that removes hydrogen sulfide Low-bleed pneumatic controller natural gas products. A process unit can and/or carbon dioxide from the natural means automated flow control devices operate independently if supplied with gas stream. powered by pressurized natural gas and sufficient feed or raw materials and Total Reduced Sulfur (TRS) means the used for maintaining a process sufficient storage facilities for the sum of the sulfur compounds hydrogen condition such as liquid level, pressure, products. sulfide, methyl mercaptan, dimethyl delta-pressure and temperature. Part of Reciprocating compressor means a sulfide, and dimethyl disulfide as the gas power stream which is regulated piece of equipment that increases the measured by Method 16 of appendix A by the process condition flows to a pressure of a process gas by positive to part 60 of this chapter. valve actuator controller where it vents displacement, employing linear Total SO2 equivalents means the sum continuously (bleeds) to the atmosphere movement of the driveshaft. of volumetric or mass concentrations of

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the sulfur compounds obtained by tests the reservoir flow characteristics, associated with any oil well, gas well, adding the quantity existing as SO2 to steps which may vent produced gas to or injection well and its associated well the quantity of SO2 that would be the atmosphere via an open pit or tank. pad. obtained if all reduced sulfur Well completion also involves Wellhead means the piping, casing, compounds were converted to SO2 connecting the well bore to the tubing and connected valves protruding (ppmv or kg/dscm (lb/dscf)). reservoir, which may include treating above the earth’s surface for an oil and/ Underground storage tank means a the formation or installing tubing, or natural gas well. The wellhead ends storage tank stored below ground. packer(s), or lifting equipment. where the flow line connects to a Well means an oil or gas well, a hole Well completion operation means any wellhead valve. The wellhead does not drilled for the purpose of producing oil well completion or well workover include other equipment at the well site or gas, or a well into which fluids are occurring at a gas wellhead affected except for any conveyance through injected. facility. which gas is vented to the atmosphere. Well completion means the process Well site means the areas that are Wildcat well means a well outside that allows for the flow of petroleum or directly disturbed during the drilling known fields or the first well drilled in natural gas from newly drilled wells to and subsequent operation of, or affected an oil or gas field where no other oil and expel drilling and reservoir fluids and by, production facilities directly gas production exists.

TABLE 1 TO SUBPART OOOO OF PART 60—REQUIRED MINIMUM INITIAL SO2 EMISSION REDUCTION EFFICIENCY (Zi)

Sulfur feed rate (X), LT/D H2S content of acid gas (Y), % 2.0 ≤ X ≤ 5.0 5.0 < X ≤ 15.0 15.0 < X ≤ 300.0 X > 300.0

Y ≥ 50 ...... 79.0 88.51X0.0101Y0.0125 or 99.9, whichever is smaller

20 ≤ Y < 50 ...... 79.0 88.5X0.0101Y0.0125 or 97.9, whichever is smaller 97.9

10 ≤ Y < 20 ...... 79.0 88.5X0.0101Y0.0125 ...... 93.5 93.5 or 97.9, whichever is smaller ...

Y < 10 ...... 79.0 79.0 79.0 79.0

TABLE 2 TO SUBPART OOOO OF PART 60—REQUIRED MINIMUM SO2 EMISSION REDUCTION EFFICIENCY (Zc)

Sulfur feed rate (X), LT/D H2S content of acid gas (Y), % 2.0 ≤ X ≤ 5.0 5.0 < X ≤ 15.0 15.0 < X ≤ 300.0 X > 300.0

Y ≥ 50 ...... 74.0 85.35X0.0144Y0.0128 or 99.9, whichever is smaller

20 ≤ Y < 50 ...... 74.0 85.35X0.0144Y0.0128 or 97.9, whichever is smaller 97.5

10 ≤ Y < 20 ...... 74.0 85.35X0.0144Y0.0128 ...... 90.8 90.8 or 90.8, whichever is smaller ...

Y < 10 ...... 74.0 74.0 74.0 74.0

E = The sulfur emission rate expressed as X = The sulfur feed rate from the sweetening expressed as percent carried to one elemental sulfur, kilograms per hour (kg/ unit (i.e., the H2S in the acid gas), decimal place. Zi refers to the reduction hr) [pounds per hour (lb/hr)], rounded to expressed as sulfur, Mg/D(LT/D), efficiency required at the initial one decimal place. rounded to one decimal place. performance test. Zc refers to the R = The sulfur emission reduction efficiency Y = The sulfur content of the acid gas from reduction efficiency required on a achieved in percent, carried to one the sweetening unit, expressed as mole continuous basis after compliance with decimal place. percent H2S (dry basis) rounded to one S = The sulfur production rate, kilograms per decimal place. Zi has been demonstrated. hour (kg/hr) [pounds per hour (lb/hr)], Z = The minimum required sulfur dioxide rounded to one decimal place. (SO2) emission reduction efficiency,

TABLE 3 TO SUBPART OOOO OF PART 60—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART OOOO [As stated in § 60.5425, you must comply with the following applicable General Provisions]

General provisions Applies to citation Subject of citation subpart? Explanation

§ 60.1 ...... General applicability of the General Provisions ... Yes. § 60.2 ...... Definitions ...... Yes...... Additional terms defined in § 60.5430. § 60.3 ...... Units and abbreviations ...... Yes. § 60.4 ...... Address ...... Yes. § 60.5 ...... Determination of construction or modification ...... Yes. § 60.6 ...... Review of plans ...... Yes. § 60.7 ...... Notification and record keeping ...... Yes ...... Except that § 60.7 only applies as specified in § 60.5420(a).

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TABLE 3 TO SUBPART OOOO OF PART 60—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART OOOO—Continued [As stated in § 60.5425, you must comply with the following applicable General Provisions]

General provisions Applies to citation Subject of citation subpart? Explanation

§ 60.8 ...... Performance tests ...... No ...... Performance testing is required for storage ves- sels as specified in 40 CFR part 63, subpart HH. § 60.9 ...... Availability of information ...... Yes. § 60.10 ...... State authority ...... Yes. § 60.11 ...... Compliance with standards and maintenance re- No ...... Requirements are specified in subpart OOOO. quirements. § 60.12 ...... Circumvention ...... Yes. § 60.13 ...... Monitoring requirements ...... Yes ...... Continuous monitors are required for storage vessels. § 60.14 ...... Modification ...... Yes. § 60.15 ...... Reconstruction ...... Yes. § 60.16 ...... Priority list ...... Yes. § 60.17 ...... Incorporations by reference ...... Yes. § 60.18 ...... General control device requirements ...... Yes. § 60.19 ...... General notification and reporting requirement ... Yes.

PART 63—[AMENDED] 63.4965(a)(3), 63.5160(d)(1)(iii), information is documented and 63.9307(c)(2), 63.9323(a)(3), recorded to the Administrator’s 8. The authority citation for part 63 63.11148(e)(3)(iii), 63.11155(e)(3), satisfaction in accordance with continues to read as follows: 63.11162(f)(3)(iii) and (f)(4), § 63.10(b)(3). A facility that is Authority: 42 U.S.C. 7401, et seq. 63.11163(g)(1)(iii) and (g)(2), determined to be an area source, but 9. Section 63.14 is amended by: 63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), subsequently increases its emissions or a. Adding paragraphs (b)(69), (b)(70), 63.11646(a)(1)(iii), table 5 to subpart its potential to emit above the major (b)(71) and (b)(72); and DDDDD of this part, and table 1 to source levels, and becomes a major b. Revising paragraph (i)(1) to read as subpart ZZZZZ of this part. source, must comply thereafter with all follows: * * * * * provisions of this subpart applicable to a major source starting on the applicable § 63.14 Incorporations by reference. Subpart HH—[Amended] compliance date specified in paragraph * * * * * (f) of this section. Nothing in this 10. Section 63.760 is amended by: (b) * * * paragraph is intended to preclude a a. Revising paragraph (a)(1) * * * * * source from limiting its potential to emit (69) ASTM D1945–03(2010) Standard introductory text; b. Revising paragraph (a)(1)(iii); through other appropriate mechanisms Test Method for Analysis of Natural Gas c. Revising paragraph (a)(2); that may be available through the by Gas Chromatography, IBR approved d. Revising paragraph (b)(1)(ii); permitting authority. for §§ 63.772 and 63.1282. e. Revising paragraph (f) introductory * * * * * (70) ASTM D5504–08 Standard Test text; (iii) The owner or operator shall Method for Determination of Sulfur f. Revising paragraph (f)(1); determine the maximum values for Compounds in Natural Gas and Gaseous g. Revising paragraph (f)(2); and other parameters used to calculate Fuels by Gas Chromatography and h. Adding paragraphs (f)(7), (f)(8), emissions as the maximum for the Chemiluminescence, IBR approved for (f)(9) and (f)(10) to read as follows: period over which the maximum natural §§ 63.772 and 63.1282. (71) ASTM D3588–98(2003) Standard § 63.760 Applicability and designation of gas or hydrocarbon liquid throughput is Practice for Calculating Heat Value, affected source. determined in accordance with Compressibility Factor, and Relative (a) * * * paragraph (a)(1)(i)(A) or (B) of this Density of Gaseous Fuels, IBR approved (1) Facilities that are major or area section. Parameters, other than glycol for §§ 63.772 and 63.1282. sources of hazardous air pollutants circulation rate, shall be based on either (72) ASTM D4891–89(2006) Standard (HAP) as defined in § 63.761. Emissions highest measured values or annual Test Method for Heating Value of Gases for major source determination purposes average. For estimating maximum in Natural Gas Range by Stoichiometric can be estimated using the maximum potential emissions from glycol Combustion, IBR approved for §§ 63.772 natural gas or hydrocarbon liquid dehydration units, the glycol circulation and 63.1282. throughput, as appropriate, calculated rate used in the calculation shall be the unit’s maximum rate under its physical * * * * * in paragraphs (a)(1)(i) through (iii) of (i) * * * this section. As an alternative to and operational design consistent with (1) ANSI/ASME PTC 19.10–1981, calculating the maximum natural gas or the definition of potential to emit in Flue and Exhaust Gas Analyses [Part 10, hydrocarbon liquid throughput, the § 63.2. Instruments and Apparatus], issued owner or operator of a new or existing (2) Facilities that process, upgrade, or August 31, 1981 IBR approved for source may use the facility’s design store hydrocarbon liquids prior to the §§ 63.309(k)(1)(iii), 63.771(e), 63.865(b), maximum natural gas or hydrocarbon point where hydrocarbon liquids enter 63.1281(d), 63.3166(a)(3), liquid throughput to estimate the either the Organic Liquids Distribution 63.3360(e)(1)(iii), 63.3545(a)(3), maximum potential emissions. Other (Non-gasoline) or Petroleum Refineries 63.3555(a)(3), 63.4166(a)(3), means to determine the facility’s major source categories. 63.4362(a)(3), 63.4766(a)(3), source status are allowed, provided the * * * * *

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(b) * * * or after August 23, 2011 must achieve Facility means any grouping of (1) * * * compliance immediately upon initial equipment where hydrocarbon liquids (ii) Each storage vessel; startup or the date of publication of the are processed, upgraded (i.e., remove * * * * * final rule in the Federal Register, impurities or other constituents to meet (f) The owner or operator of an whichever is later. contract specifications), or stored; or affected major source shall achieve (9) A production field facility, as where natural gas is processed, compliance with the provisions of this defined in § 63.761, constructed before upgraded, or stored. For the purpose of subpart by the dates specified in August 23, 2011 that was previously a major source determination, facility paragraphs (f)(1), (f)(2), and (f)(7) determined to be an area source but (including a building, structure, or through (f)(10) of this section. The becomes a major source (as defined in installation) means oil and natural gas owner or operator of an affected area paragraph 3 of the major source production and processing equipment source shall achieve compliance with definition in § 63.761) on the date of that is located within the boundaries of the provisions of this subpart by the publication of the final rule in the an individual surface site as defined in dates specified in paragraphs (f)(3) Federal Register must achieve this section. Equipment that is part of a through (f)(6) of this section. compliance no later than 3 years after facility will typically be located within (1) Except as specified in paragraphs the date of publication of the final rule close proximity to other equipment (f)(7) through (10) of this section, the in the Federal Register, except as located at the same facility. Pieces of owner or operator of an affected major provided in § 63.6(i). production equipment or groupings of source, the construction or (10) Each large glycol dehydration equipment located on different oil and reconstruction of which commenced unit, as defined in § 63.761, that has gas leases, mineral fee tracts, lease before February 6, 1998, shall achieve complied with the provisions of this tracts, subsurface or surface unit areas, compliance with the applicable subpart prior to August 23, 2011 by surface fee tracts, surface lease tracts, or provisions of this subpart no later than reducing its benzene emissions to less separate surface sites, whether or not June 17, 2002, except as provided for in than 0.9 megagrams per year must connected by a road, waterway, power § 63.6(i). The owner or operator of an achieve compliance no later than 90 line or pipeline, shall not be considered area source, the construction or days after the date of publication of the part of the same facility. Examples of reconstruction of which commenced final rule in the Federal Register, except facilities in the oil and natural gas before February 6, 1998, that increases as provided in § 63.6(i). production source category include, but its emissions of (or its potential to emit) * * * * * are not limited to, well sites, satellite HAP such that the source becomes a 11. Section 63.761 is amended by: tank batteries, central tank batteries, a major source that is subject to this a. Adding, in alphabetical order, new compressor station that transports subpart shall comply with this subpart definitions for the terms ‘‘affirmative natural gas to a natural gas processing 3 years after becoming a major source. defense,’’ ‘‘BTEX,’’ ‘‘flare,’’ ‘‘large glycol plant, and natural gas processing plants. (2) Except as specified in paragraphs dehydration units’’ and ‘‘small glycol * * * * * (f)(7) through (10) of this section, the dehydration units’’; owner or operator of an affected major b. Revising the definitions for Flare means a thermal oxidation source, the construction or ‘‘associated equipment,’’ ‘‘facility,’’ system using an open flame (i.e., reconstruction of which commences on ‘‘glycol dehydration unit baseline without enclosure). or after February 6, 1998, shall achieve operations,’’ and ‘‘temperature * * * * * compliance with the applicable monitoring device’’; and Glycol dehydration unit baseline provisions of this subpart immediately c. Revising paragraph (3) of the operations means operations upon initial startup or June 17, 1999, definition for ‘‘major source’’ to read as representative of the large glycol whichever date is later. Area sources, follows: dehydration unit operations as of June other than production field facilities § 63.761 Definitions. 17, 1999 and the small glycol identified in (f)(9) of this section, the dehydrator unit operations as of August construction or reconstruction of which * * * * * 23, 2011. For the purposes of this commences on or after February 6, 1998, Affirmative defense means, in the subpart, for determining the percentage that become major sources shall comply context of an enforcement proceeding, a of overall HAP emission reduction with the provisions of this standard response or defense put forward by a attributable to process modifications, immediately upon becoming a major defendant, regarding which the baseline operations shall be parameter source. defendant has the burden of proof, and the merits of which are independently values (including, but not limited to, * * * * * and objectively evaluated in a judicial glycol circulation rate or glycol-HAP (7) Each affected small glycol or administrative proceeding. absorbency) that represent actual long- dehydration unit and each storage * * * * * term conditions (i.e., at least 1 year). vessel that is not a storage vessel with Glycol dehydration units in operation the potential for flash emissions located Associated equipment, as used in this subpart and as referred to in section for less than 1 year shall document that at a major source, that commenced the parameter values represent expected construction before August 23, 2011 112(n)(4) of the Act, means equipment associated with an oil or natural gas long-term operating conditions had must achieve compliance no later than process modifications not been made. 3 years after the date of publication of exploration or production well, and the final rule in the Federal Register, includes all equipment from the * * * * * except as provided in § 63.6(i). wellbore to the point of custody Large glycol dehydration unit means a (8) Each affected small glycol transfer, except glycol dehydration units glycol dehydration unit with an actual dehydration unit and each storage and storage vessels. annual average natural gas flowrate vessel that is not a storage vessel with * * * * * equal to or greater than 85 thousand the potential for flash emissions, both as BTEX means benzene, toluene, ethyl standard cubic meters per day and defined in § 63.761, located at a major benzene and xylene. actual annual average benzene source, that commenced construction on * * * * * emissions equal to or greater than 0.90

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Mg/yr, determined according to requirements in the affirmative defense. excess emissions that were the result of § 63.772(b). The affirmative defense shall not be the malfunction. * * * * * available for claims for injunctive relief. (2) Notification. The owner or Major source *** (1) To establish the affirmative operator of the affected source (3) For facilities that are production defense in any action to enforce such a experiencing exceedance of its emission field facilities, only HAP emissions from limit, you must timely meet the limit(s) during a malfunction shall glycol dehydration units and storage notification requirements in paragraph notify the Administrator by telephone or vessels shall be aggregated for a major (d)(2) of this section, and must prove by facsimile transmission as soon as source determination. For facilities that a preponderance of evidence that: possible, but no later than two business are not production field facilities, HAP (i) The excess emissions: days after the initial occurrence of the emissions from all HAP emission units (A) Were caused by a sudden, malfunction, if it wishes to avail itself shall be aggregated for a major source infrequent, and unavoidable failure of of an affirmative defense to civil determination. air pollution control and monitoring penalties for that malfunction. The * * * * * equipment, process equipment, or a owner or operator seeking to assert an Small glycol dehydration unit means process to operate in a normal or usual affirmative defense shall also submit a a glycol dehydration unit, located at a manner; and written report to the Administrator major source, with an actual annual (B) Could not have been prevented within 45 days of the initial occurrence average natural gas flowrate less than 85 through careful planning, proper design of the exceedance of the standard in this thousand standard cubic meters per day or better operation and maintenance subpart to demonstrate, with all or actual annual average benzene practices; and necessary supporting documentation, emissions less than 0.90 Mg/yr, (C) Did not stem from any activity or that it has met the requirements set forth determined according to § 63.772(b). event that could have been foreseen and in paragraph (d)(1) of this section. The owner or operator may seek an * * * * * avoided, or planned for; and Temperature monitoring device (D) Were not part of a recurring extension of this deadline for up to 30 means an instrument used to monitor pattern indicative of inadequate design, additional days by submitting a written temperature and having a minimum operation, or maintenance; and request to the Administrator before the accuracy of ± 1 percent of the (ii) Repairs were made as expiration of the 45 day period. Until a temperature being monitored expressed expeditiously as possible when the request for an extension has been in °C, or ± 2.5 °C, whichever is greater. applicable emission limitations were approved by the Administrator, the The temperature monitoring device may being exceeded. Off-shift and overtime owner or operator is subject to the measure temperature in degrees labor were used, to the extent requirement to submit such report Fahrenheit or degrees Celsius, or both. practicable to make these repairs; and within 45 days of the initial occurrence (iii) The frequency, amount and of the exceedance. * * * * * duration of the excess emissions 13. Section 63.764 is amended by: 12. Section 63.762 is revised to read a. Revising paragraph (c)(2) as follows: (including any bypass) were minimized to the maximum extent practicable introductory text; § 63.762 Startups and shutdowns. during periods of such emissions; and b. Revising paragraph (e)(1) (a) The provisions set forth in this (iv) If the excess emissions resulted introductory text; subpart shall apply at all times. from a bypass of control equipment or c. Revising paragraph (i); and (b) The owner or operator shall not a process, then the bypass was d. Adding paragraph (j) to read as shut down items of equipment that are unavoidable to prevent loss of life, follows: required or utilized for compliance with personal injury, or severe property § 63.764 General standards. the provisions of this subpart during damage; and * * * * * times when emissions are being routed (v) All possible steps were taken to (c) * * * to such items of equipment, if the minimize the impact of the excess (2) For each storage vessel subject to shutdown would contravene emissions on ambient air quality, the this subpart, the owner or operator shall requirements of this subpart applicable environment, and human health; and comply with the requirements specified to such items of equipment. This (vi) All emissions monitoring and in paragraphs (c)(2)(i) through (iii) of paragraph does not apply if the owner control systems were kept in operation this section. or operator must shut down the if at all possible, consistent with safety equipment to avoid damage due to a and good air pollution control practices; * * * * * contemporaneous startup or shutdown, and (e) Exemptions. (1) The owner or of the affected source or a portion (vii) All of the actions in response to operator of an area source is exempt thereof. the excess emissions were documented from the requirements of paragraph (d) (c) During startups and shutdowns, by properly signed, contemporaneous of this section if the criteria listed in the owner or operator shall implement operating logs; and paragraph (e)(1)(i) or (ii) of this section measures to prevent or minimize excess (viii) At all times, the affected source are met, except that the records of the emissions to the maximum extent was operated in a manner consistent determination of these criteria must be practical. with good practices for minimizing maintained as required in § 63.774(d)(1). (d) In response to an action to enforce emissions; and * * * * * the standards set forth in this subpart, (ix) A written root cause analysis has (i) In all cases where the provisions of you may assert an affirmative defense to been prepared to determine, correct, and this subpart require an owner or a claim for civil penalties for eliminate the primary causes of the operator to repair leaks by a specified exceedances of such standards that are malfunction and the excess emissions time after the leak is detected, it is a caused by malfunction, as defined in 40 resulting from the malfunction event at violation of this standard to fail to take CFR 63.2. Appropriate penalties may be issue. The analysis shall also specify, action to repair the leak(s) within the assessed, however, if you fail to meet using best monitoring methods and specified time. If action is taken to your burden of proving all the engineering judgment, the amount of repair the leak(s) within the specified

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time, failure of that action to c. Revising paragraph (c)(2); and (ii) The owner or operator of a glycol successfully repair the leak(s) is not a d. Revising paragraph (c)(3) to read as dehydration unit located at an area violation of this standard. However, if follows: source, that must be controlled as the repairs are unsuccessful, and a leak § 63.765 Glycol dehydration unit process specified in § 63.764(d)(1)(i), shall is detected, the owner or operator shall vent standards. connect the process vent to a control take further action as required by the (a) This section applies to each glycol device or combination of control applicable provisions of this subpart. dehydration unit subject to this subpart devices through a closed-vent system (j) At all times the owner or operator that must be controlled for air emissions and the outlet benzene emissions from must operate and maintain any affected as specified in either paragraph (c)(1)(i) the control device(s) shall be reduced to source, including associated air or paragraph (d)(1)(i) of § 63.764. a level less than 0.90 megagrams per pollution control equipment and (b) * * * year. The closed-vent system shall be monitoring equipment, in a manner (1) For each glycol dehydration unit designed and operated in accordance consistent with safety and good air process vent, the owner or operator with the requirements of § 63.771(c). pollution control practices for shall control air emissions by either The control device(s) shall be designed minimizing emissions. Determination of paragraph (b)(1)(i), (ii), or (iii) of this and operated in accordance with the whether such operation and section. requirements of § 63.771(d), except that maintenance procedures are being used (i) The owner or operator of a large the performance levels specified in will be based on information available glycol dehydration unit, as defined in § 63.771(d)(1)(i) and (ii) do not apply. to the Administrator which may § 63.761, shall connect the process vent include, but is not limited to, to a control device or a combination of (iii) You must limit BTEX emissions monitoring results, review of operation control devices through a closed-vent from each small glycol dehydration unit and maintenance procedures, review of system. The closed-vent system shall be process vent, as defined in § 63.761, to operation and maintenance records, and designed and operated in accordance the limit determined in Equation 1 of inspection of the source. with the requirements of § 63.771(c). this section. The limit must be met in 14. Section 63.765 is amended by: The control device(s) shall be designed accordance with one of the alternatives a. Revising paragraph (a); and operated in accordance with the specified in paragraphs (b)(1)(iii)(A) b. Revising paragraph (b)(1); requirements of § 63.771(d). through (D) of this section.

Where: requirements specified in § 63.771(e) (iii) For each small glycol dehydration ELBTEX = Unit-specific BTEX emission limit, and emissions in accordance with the unit, BTEX emissions are reduced to a megagrams per year; requirements specified in § 63.772(b)(2). level less than the limit calculated by × ¥4 1.10 10 = BTEX emission limit, grams * * * * * paragraph (b)(1)(iii) of this section. BTEX/standard cubic meter = ppmv; 15. Section 63.766 is amended by: Throughput = Annual average daily natural (c) * * * a. Revising paragraph (a); gas throughput, standard cubic meters (2) The owner or operator shall b. Revising paragraph (b) introductory per day; demonstrate, to the Administrator’s text; Ci,BTEX = BTEX concentration of the natural satisfaction, that the total HAP c. Revising paragraph (b)(1); and gas at the inlet to the glycol dehydration emissions to the atmosphere from the d. Revising paragraph (d) to read as unit, ppmv. large glycol dehydration unit process follows: (A) Connect the process vent to a vent are reduced by 95.0 percent § 63.766 Storage vessel standards. control device or combination of control through process modifications, or a devices through a closed-vent system. combination of process modifications (a) This section applies to each The closed vent system shall be and one or more control devices, in storage vessel (as defined in § 63.761) designed and operated in accordance accordance with the requirements subject to this subpart. with the requirements of § 63.771(c). specified in § 63.771(e). (b) The owner or operator of a storage vessel (as defined in § 63.761) shall The control device(s) shall be designed (3) Control of HAP emissions from a and operated in accordance with the comply with one of the control GCG separator (flash tank) vent is not requirements specified in paragraphs requirements of § 63.771(f). required if the owner or operator (B) Meet the emissions limit through (b)(1) and (2) of this section. demonstrates, to the Administrator’s process modifications in accordance (1) The owner or operator shall equip satisfaction, that total emissions to the with the requirements specified in the affected storage vessel with a cover atmosphere from the glycol dehydration § 63.771(e). that is connected, through a closed-vent unit process vent are reduced by one of (C) Meet the emissions limit for each system that meets the conditions the levels specified in paragraph small glycol dehydration unit using a specified in § 63.771(c), to a control (c)(3)(i), (ii), or (iii) of this section, combination of process modifications device or a combination of control through the installation and operation of and one or more control devices through devices that meets any of the conditions controls as specified in paragraph (b)(1) the requirements specified in specified in § 63.771(d). The cover shall of this section. paragraphs (b)(1)(iii)(A) and (B) of this be designed and operated in accordance section. (i) For any large glycol dehydration with the requirements of § 63.771(b). (D) Demonstrate that the emissions unit, HAP emissions are reduced by * * * * * limit is met through actual uncontrolled 95.0 percent or more. (d) This section does not apply to operation of the small glycol (ii) For area source dehydration units, storage vessels for which the owner or dehydration unit. Document operational benzene emissions are reduced to a operator is subject to and controlled parameters in accordance with the level less than 0.90 megagrams per year. under the requirements specified in 40

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CFR part 60, subpart Kb; or the units. Owners and operators of small glycol dehydration unit baseline requirements specified under 40 CFR glycol dehydration units, shall comply operations shall be modified to achieve part 63 subparts G or CC. with the control device requirements in the 95.0 percent overall HAP emission 16. Section 63.769 is amended by: paragraph (f) of this section. reduction, or BTEX limit determined in a. Revising paragraph (b); (1) * * * § 63.765(b)(1)(iii), as applicable, either b. Revising paragraph (c) introductory (i) An enclosed combustion device through process modifications or text; and (e.g., thermal vapor incinerator, catalytic through a combination of process b. Revising paragraph (c)(8) to read as vapor incinerator, boiler, or process modifications and one or more control follows: heater) that is designed and operated in devices. If a combination of process accordance with one of the following § 63.769 Equipment leak standards. modifications and one or more control performance requirements: devices are used, the owner or operator * * * * * * * * * * shall also establish the emission (b) This section does not apply to (C) For a control device that can reduction to be achieved by the control ancillary equipment and compressors demonstrate a uniform combustion zone device to achieve an overall HAP for which the owner or operator is temperature during the performance test emission reduction of 95.0 percent for subject to and controlled under the conducted under § 63.772(e), operates at the glycol dehydration unit process vent requirements specified in subpart H of a minimum temperature of 760 degrees or, if applicable, the BTEX limit this part; or the requirements specified C. determined in § 63.765(b)(1)(iii) for the in 40 CFR part 60, subpart KKK. small glycol dehydration unit process (c) For each piece of ancillary * * * * * (ii) A vapor recovery device (e.g., vent. Only modifications in glycol equipment and each compressor subject carbon adsorption system or condenser) dehydration unit operations directly to this section located at an existing or or other non-destructive control device related to process changes, including new source, the owner or operator shall that is designed and operated to reduce but not limited to changes in glycol meet the requirements specified in 40 the mass content of either TOC or total circulation rate or glycol-HAP CFR part 61, subpart V, §§ 61.241 HAP in the gases vented to the device absorbency, shall be allowed. Changes through 61.247, except as specified in by 95.0 percent by weight or greater as in the inlet gas characteristics or natural paragraphs (c)(1) through (8) of this determined in accordance with the gas throughput rate shall not be section, except for valves subject to requirements of § 63.772(e). considered in determining the overall § 61.247–2(b) a leak is detected if an (iii) A flare, as defined in § 63.761, emission reduction due to process instrument reading of 500 ppm or that is designed and operated in modifications. greater is measured. accordance with the requirements of (3) The owner or operator that * * * * * § 63.11(b). achieves a 95.0 percent HAP emission (8) Flares, as defined in § 63.761, used * * * * * reduction or meets the BTEX limit to comply with this subpart shall (4) * * * determined in § 63.765(b)(1)(iii), as comply with the requirements of (i) Each control device used to comply applicable, using process modifications § 63.11(b). with this subpart shall be operating at alone shall comply with paragraph 17. Section 63.771 is amended by: all times when gases, vapors, and fumes (e)(3)(i) of this section. The owner or a. Revising paragraph (c)(1) are vented from the HAP emissions unit operator that achieves a 95.0 percent introductory text; or units through the closed-vent system HAP emission reduction or meets the b. Revising the heading of paragraph to the control device, as required under BTEX limit determined in (d); § 63.765, § 63.766, and § 63.769. An § 63.765(b)(1)(iii), as applicable, using a c. Adding paragraph (d) introductory owner or operator may vent more than combination of process modifications text; one unit to a control device used to and one or more control devices shall d. Revising paragraph (d)(1)(i) comply with this subpart. comply with paragraphs (e)(3)(i) and introductory text; (e)(3)(ii) of this section. e. Revising paragraph (d)(1)(i)(C); * * * * * f. Revising paragraph (d)(1)(ii); (5) * * * * * * * * g. Revising paragraph (d)(1)(iii); (i) Following the initial startup of the (ii) The owner or operator shall h. Revising paragraph (d)(4)(i); control device, all carbon in the control comply with the control device i. Revising paragraph (d)(5)(i); device shall be replaced with fresh requirements specified in paragraph (d) j. Revising paragraph (e)(2); carbon on a regular, predetermined time or (f) of this section, as applicable, k. Revising paragraph (e)(3) interval that is no longer than the except that the emission reduction or introductory text; carbon service life established for the limit achieved shall be the emission l. Revising paragraph (e)(3)(ii); and carbon adsorption system. Records reduction or limit specified for the m. Adding paragraph (f) to read as identifying the schedule for replacement control device(s) in paragraph (e)(2) of follows: and records of each carbon replacement this section. shall be maintained as required in (f) Control device requirements for § 63.771 Control equipment requirements. § 63.774(b)(7)(ix). The schedule for small glycol dehydration units. (1) The * * * * * replacement shall be submitted with the control device used to meet BTEX the (c) Closed-vent system requirements. Notification of Compliance Status emission limit calculated in (1) The closed-vent system shall route Report as specified in § 63.775(d)(5)(iv). § 63.765(b)(1)(iii) shall be one of the all gases, vapors, and fumes emitted Each carbon replacement must be control devices specified in paragraphs from the material in an emissions unit reported in the Periodic Reports as (f)(1)(i) through (iii) of this section. to a control device that meets the specified in § 63.772(e)(2)(xii). (i) An enclosed combustion device requirements specified in paragraph (d) * * * * * (e.g., thermal vapor incinerator, catalytic of this section. (e) * * * vapor incinerator, boiler, or process * * * * * (2) The owner or operator shall heater) that is designed and operated to (d) Control device requirements for document, to the Administrator’s reduce the mass content of BTEX in the sources except small glycol dehydration satisfaction, the conditions for which gases vented to the device as

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determined in accordance with the s. Revising paragraph (g)(2)(iii); requirements of paragraph (e) of this requirements of § 63.772(e). If a boiler or t. Revising paragraph (g)(3); section apply. Compliance is process heater is used as the control u. Adding paragraph (h); and demonstrated using the methods device, then the vent stream shall be v. Adding paragraph (i) to read as specified in paragraph (f) of this section. introduced into the flame zone of the follows: (2) If no control device is used to comply with the emission limit in boiler or process heater; or § 63.772 Test methods, compliance (ii) A vapor recovery device (e.g., procedures, and compliance § 63.765(b)(1)(iii), the owner or operator carbon adsorption system or condenser) demonstrations. must determine the glycol dehydration or other non-destructive control device unit BTEX emissions as specified in * * * * * paragraphs (d)(2)(i) through (iii) of this that is designed and operated to reduce (b) Determination of glycol section. Compliance is demonstrated if the mass content of BTEX in the gases dehydration unit flowrate, benzene the BTEX emissions determined as vented to the device as determined in emissions, or BTEX emissions. The accordance with the requirements of specified in paragraphs (d)(2)(i) through procedures of this paragraph shall be (iii) are less than the emission limit § 63.772(e); or used by an owner or operator to (iii) A flare, as defined in § 63.761, calculated using the equation in determine glycol dehydration unit that is designed and operated in § 63.765(b)(1)(iii). natural gas flowrate, benzene emissions, accordance with the requirements of (i) Method 1 or 1A, 40 CFR part 60, or BTEX emissions. § 63.11(b). appendix A, as appropriate, shall be (1) * * * (2) The owner or operator shall used for selection of the sampling sites (ii) The owner or operator shall operate each control device in at the outlet of the glycol dehydration document, to the Administrator’s accordance with the requirements unit process vent. Any references to satisfaction, the actual annual average specified in paragraphs (f)(2)(i) and (ii) particulate mentioned in Methods 1 and natural gas flowrate to the glycol of this section. 1A do not apply to this section. (i) Each control device used to comply dehydration unit. (ii) The gas volumetric flowrate shall (2) The determination of actual with this subpart shall be operating at be determined using Method 2, 2A, 2C, average benzene or BTEX emissions all times. An owner or operator may or 2D, 40 CFR part 60, appendix A, as from a glycol dehydration unit shall be vent more than one unit to a control appropriate. made using the procedures of either device used to comply with this (iii) The BTEX emissions from the paragraph (b)(2)(i) or (b)(2)(ii) of this subpart. outlet of the glycol dehydration unit (ii) For each control device monitored section. Emissions shall be determined process vent shall be determined using in accordance with the requirements of either uncontrolled, or with federally the procedures specified in paragraph § 63.773(d), the owner or operator shall enforceable controls in place. (e)(3)(v) of this section. As an demonstrate compliance according to (i) The owner or operator shall alternative, the mass rate of BTEX at the the requirements of either § 63.772(f) or determine actual average benzene or outlet of the glycol dehydration unit BTEX emissions using the model GRI– process vent may be calculated using (h). TM (3) For each carbon adsorption system GLYCalc , Version 3.0 or higher, and the model GRI–GLYCalcTM, Version 3.0 used as a control device to meet the the procedures presented in the or higher, and the procedures presented TM requirements of paragraph (f)(1)(ii) of associated GRI–GLYCalc Technical in the associated GRI–GLYCalcTM this section, the owner or operator shall Reference Manual. Inputs to the model Technical Reference Manual. Inputs to manage the carbon as required under shall be representative of actual the model shall be representative of (d)(5)(i) and (ii) of this section. operating conditions of the glycol actual operating conditions of the glycol 18. Section 63.772 is amended by: dehydration unit and may be dehydration unit and shall be a. Revising paragraph (b) introductory determined using the procedures determined using the procedures text; documented in the Gas Research documented in the Gas Research b. Revising paragraph (b)(1)(ii); Institute (GRI) report entitled Institute (GRI) report entitled c. Revising paragraph (b)(2); ‘‘Atmospheric Rich/Lean Method for ‘‘Atmospheric Rich/Lean Method for d. Adding paragraph (d); Determining Glycol Dehydrator Determining Glycol Dehydrator e. Revising paragraph (e) introductory Emissions’’ (GRI–95/0368.1); or Emissions’’ (GRI–95/0368.1). When the text; (ii) The owner or operator shall BTEX mass rate is calculated for glycol f. Revising paragraphs (e)(1)(i) determine an average mass rate of dehydration units using the model GRI– through (v); benzene or BTEX emissions in GLYCalcTM, all BTEX measured by g. Revising paragraph (e)(2); kilograms per hour through direct Method 18, 40 CFR part 60, appendix A, h. Revising paragraph (e)(3) measurement using the methods in shall be summed. introductory text; § 63.772(a)(1)(i) or (ii), or an alternative (e) Control device performance test i. Revising paragraph (e)(3)(i)(B); method according to § 63.7(f). Annual procedures. This paragraph applies to j. Revising paragraph (e)(3)(iv)(C)(1); emissions in kilograms per year shall be the performance testing of control k. Adding paragraphs (e)(3)(v) and determined by multiplying the mass rate devices. The owners or operators shall (vi); by the number of hours the unit is l. Revising paragraph (e)(4) demonstrate that a control device operated per year. This result shall be introductory text; achieves the performance requirements m. Revising paragraph (e)(4)(i); converted to megagrams per year. of § 63.771(d)(1), (e)(3)(ii) or (f)(1) using n. Revising paragraph (e)(5); * * * * * a performance test as specified in o. Revising paragraph (f) introductory (d) Test procedures and compliance paragraph (e)(3) of this section. Owners text; demonstrations for small glycol or operators using a condenser have the p. Adding paragraphs (f)(2) through dehydration units. This paragraph option to use a design analysis as (f)(6); applies to the test procedures for small specified in paragraph (e)(4) of this q. Revising paragraph (g) introductory dehydration units. section. The owner or operator may text; (1) If the owner or operator is using elect to use the alternative procedures in r. Revising paragraph (g)(1) and a control device to comply with the paragraph (e)(5) of this section for paragraph (g)(2) introductory text; emission limit in § 63.765(b)(1)(iii), the performance testing of a condenser used

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to control emissions from a glycol (i) * * * where standard temperature (gram-mole dehydration unit process vent. As an (B) To determine compliance with the per standard cubic meter) is 20 degrees alternative to conducting a performance enclosed combustion device total HAP C. test under this section for combustion concentration limit specified in n = Number of components in sample. control devices, a control device that § 63.765(b)(1)(iii), or the BTEX emission (2) When the BTEX mass rate is can be demonstrated to meet the limit specified in § 63.771(f)(1) the calculated, only BTEX compounds performance requirements of sampling site shall be located at the measured by Method 18, 40 CFR part § 63.771(d)(1), (e)(3)(ii) or (f)(1) through outlet of the combustion device. 60, appendix A, or ASTM D6420–99 a performance test conducted by the * * * * * (2004) as specified in § 63.772(a)(1)(ii), manufacturer, as specified in paragraph (iv) * * * shall be summed using the equations in (h) of this section can be used. (C) * * * paragraph (e)(3)(v)(B)(1) of this section. (vi) The owner or operator shall (1) * * * (1) The emission rate correction factor conduct performance tests according to (i) Except as specified in paragraph for excess air, integrated sampling and the schedule specified in paragraphs (e)(2) of this section, a flare, as defined analysis procedures of Method 3A or (e)(3)(vi)(A) and (B) of this section. in § 63.761, that is designed and 3B, 40 CFR part 60, appendix A, shall operated in accordance with § 63.11(b); (A) An initial performance test shall be used to determine the oxygen be conducted within 180 days after the (ii) Except for control devices used for concentration. The samples shall be small glycol dehydration units, a boiler compliance date that is specified for taken during the same time that the each affected source in § 63.760(f)(7) or process heater with a design heat samples are taken for determining TOC input capacity of 44 megawatts or through (8), except that the initial concentration or total HAP performance test for existing greater; concentration. (iii) Except for control devices used combustion control devices at existing * * * * * major sources shall be conducted no for small glycol dehydration units, a (v) To determine compliance with the later than 3 years after the date of boiler or process heater into which the BTEX emission limit specified in publication of the final rule in the vent stream is introduced with the § 63.771(f)(1) the owner or operator Federal Register. If the owner or primary fuel or is used as the primary shall use one of the following methods: operator of an existing combustion fuel; Method 18, 40 CFR part 60, appendix A; control device at an existing major (iv) Except for control devices used ASTM D6420–99 (2004), as specified in source chooses to replace such device for small glycol dehydration units, a § 63.772(a)(1)(ii); or any other method or with a control device whose model is boiler or process heater burning data that have been validated according tested under § 63.772(h), then the newly hazardous waste for which the owner or to the applicable procedures in Method installed device shall comply with all operator has either been issued a final 301, 40 CFR part 63, appendix A. The provisions of this subpart no later than permit under 40 CFR part 270 and following procedures shall be used to 3 years after the date of publication of complies with the requirements of 40 calculate BTEX emissions: the final rule in the Federal Register. CFR part 266, subpart H; or has certified (A) The minimum sampling time for The performance test results shall be compliance with the interim status each run shall be 1 hour in which either submitted in the Notification of requirements of 40 CFR part 266, an integrated sample or a minimum of Compliance Status Report as required in subpart H; four grab samples shall be taken. If grab § 63.775(d)(1)(ii). (v) Except for control devices used for sampling is used, then the samples shall (B) Periodic performance tests shall be small glycol dehydration units, a be taken at approximately equal conducted for all control devices hazardous waste incinerator for which intervals in time, such as 15-minute required to conduct initial performance the owner or operator has been issued intervals during the run. tests except as specified in paragraphs a final permit under 40 CFR part 270 (B) The mass rate of BTEX (Eo) shall (e)(3)(vi)(B)(1) and (2) of this section. and complies with the requirements of be computed using the equations and The first periodic performance test shall 40 CFR part 264, subpart O; or has procedures specified in paragraphs be conducted no later than 60 months certified compliance with the interim (e)(3)(v)(B)(1) and (2) of this section. after the initial performance test status requirements of 40 CFR part 265, (1) The following equation shall be required in paragraph (e)(3)(vi)(A) of subpart O. used: this section. Subsequent periodic * * * * * performance tests shall be conducted at (2) An owner or operator shall design intervals no longer than 60 months and operate each flare, as defined in following the previous periodic § 63.761, in accordance with the performance test or whenever a source requirements specified in § 63.11(b) and Where: desires to establish a new operating the compliance determination shall be limit. The periodic performance test Eo= Mass rate of BTEX at the outlet of the conducted using Method 22 of 40 CFR control device, dry basis, kilogram per results must be submitted in the next part 60, appendix A, to determine hour. Periodic Report as specified in visible emissions. Coj= Concentration of sample component j of § 63.775(e)(2)(xi). Combustion control (3) For a performance test conducted the gas stream at the outlet of the control devices meeting the criteria in either to demonstrate that a control device device, dry basis, parts per million by paragraph (e)(3)(vi)(B)(1) or (2) of this meets the requirements of volume. section are not required to conduct § 63.771(d)(1), (e)(3)(ii) or (f)(1), the Moj= Molecular weight of sample component periodic performance tests. owner or operator shall use the test j of the gas stream at the outlet of the (1) A control device whose model is control device, gram/gram-mole. methods and procedures specified in tested under, and meets the criteria of, Qo= Flowrate of gas stream at the outlet of paragraphs (e)(3)(i) through (v) of this the control device, dry standard cubic § 63.772(h), or section. The initial and periodic meter per minute. (2) A combustion control device ¥6 performance tests shall be conducted K2= Constant, 2.494 × 10 (parts per tested under § 63.772(e) that meets the according to the schedule specified in million) (gram-mole per standard cubic outlet TOC or HAP performance level paragraph (e)(3)(vi) of this section. meter) (kilogram/gram) (minute/hour), specified in § 63.771(d)(1)(i)(B) and that

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establishes a correlation between firebox Report, as required in § 63.775(e), performance requirements—condensers. or combustion chamber temperature and following the change. This paragraph applies to the the TOC or HAP performance level. * * * * * demonstration of compliance with the (4) For a condenser design analysis (2) The owner or operator shall performance requirements specified in conducted to meet the requirements of calculate the daily average of the § 63.771(d)(1)(ii),(e)(3) or (f)(1) for § 63.771(d)(1), (e)(3)(ii), or (f)(1), the applicable monitored parameter in condensers. Compliance shall be owner or operator shall meet the accordance with § 63.773(d)(4) except demonstrated using the procedures in requirements specified in paragraphs that the inlet gas flow rate to the control paragraphs (g)(1) through (3) of this (e)(4)(i) and (e)(4)(ii) of this section. device shall not be averaged. section. (1) The owner or operator shall Documentation of the design analysis (3) Compliance with the operating establish a site-specific condenser shall be submitted as a part of the parameter limit is achieved when the performance curve according to Notification of Compliance Status daily average of the monitoring § 63.773(d)(5)(ii). For sources required Report as required in § 63.775(d)(1)(i). parameter value calculated under paragraph (f)(2) of this section is either to meet the BTEX limit in accordance (i) The condenser design analysis equal to or greater than the minimum or with § 63.771(e) or (f)(1) the owner or shall include an analysis of the vent equal to or less than the maximum operator shall identify the minimum stream composition, constituent monitoring value established under percent reduction necessary to meet the concentrations, flowrate, relative paragraph (f)(1) of this section. For inlet BTEX limit. humidity, and temperature, and shall gas flow rate, compliance with the (2) Compliance with the requirements establish the design outlet organic operating parameter limit is achieved in § 63.771(d)(1)(ii),(e)(3) or (f)(1) shall compound concentration level, design when the value is equal to or less than be demonstrated by the procedures in average temperature of the condenser the value established under § 63.772(h). paragraphs (g)(2)(i) through (iii) of this exhaust vent stream, and the design (4) Except for periods of monitoring section. average temperatures of the coolant system malfunctions, repairs associated * * * * * fluid at the condenser inlet and outlet. with monitoring system malfunctions, (iii) Except as provided in paragraphs As an alternative to the condenser and required monitoring system quality (g)(2)(iii)(A) and (B) of this section, at design analysis, an owner or operator assurance or quality control activities the end of each operating day, the may elect to use the procedures (including, as applicable, system owner or operator shall calculate the specified in paragraph (e)(5) of this accuracy audits and required zero and 365-day average HAP, or BTEX, section. span adjustments), the CMS required in emission reduction, as appropriate, from * * * * * § 63.773(d) must be operated at all times the condenser efficiencies as (5) As an alternative to the procedures the affected source is operating. A determined in paragraph (g)(2)(ii) of this in paragraph (e)(4)(i) of this section, an monitoring system malfunction is any section for the preceding 365 operating owner or operator may elect to use the sudden, infrequent, not reasonably days. If the owner or operator uses a procedures documented in the GRI preventable failure of the monitoring combination of process modifications report entitled, ‘‘Atmospheric Rich/Lean system to provide valid data. and a condenser in accordance with the Method for Determining Glycol Monitoring system failures that are requirements of § 63.771(e), the 365-day Dehydrator Emissions’’ (GRI–95/0368.1) caused in part by poor maintenance or average HAP, or BTEX, emission as inputs for the model GRI– careless operation are not malfunctions. reduction shall be calculated using the GLYCalcTM, Version 3.0 or higher, to Monitoring system repairs are required emission reduction achieved through generate a condenser performance to be completed in response to process modifications and the condenser efficiency as determined in curve. monitoring system malfunctions and to return the monitoring system to paragraph (g)(2)(ii) of this section, both (f) Compliance demonstration for operation as expeditiously as for the previous 365 operating days. control device performance practicable. (A) After the compliance dates requirements. This paragraph applies to (5) Data recorded during monitoring specified in § 63.760(f), an owner or the demonstration of compliance with system malfunctions, repairs associated operator with less than 120 days of data the control device performance with monitoring system malfunctions, for determining average HAP, or BTEX, requirements specified in or required monitoring system quality emission reduction, as appropriate, § 63.771(d)(1)(i), (e)(3) and (f)(1). assurance or control activities may not shall calculate the average HAP, or Compliance shall be demonstrated using be used in calculations used to report BTEX emission reduction, as the requirements in paragraphs (f)(1) emissions or operating levels. All the appropriate, for the first 120 days of through (3) of this section. As an data collected during all other required operation after the compliance dates. alternative, an owner or operator that data collection periods must be used in For sources required to meet the overall installs a condenser as the control assessing the operation of the control 95.0 percent reduction requirement, device to achieve the requirements device and associated control system. compliance is achieved if the 120-day specified in § 63.771(d)(1)(ii), (e)(3) or (6) Except for periods of monitoring average HAP emission reduction is (f)(1) may demonstrate compliance system malfunctions, repairs associated equal to or greater than 90.0 percent. For according to paragraph (g) of this with monitoring system malfunctions, sources required to meet the BTEX limit section. An owner or operator may and required quality monitoring system under § 63.765(b)(1)(iii), compliance is switch between compliance with quality assurance or quality control achieved if the average BTEX emission paragraph (f) of this section and activities (including, as applicable, reduction is at least 95.0 percent of the compliance with paragraph (g) of this system accuracy audits and required required 365-day value identified under section only after at least 1 year of zero and span adjustments), failure to paragraph (g)(1) of this section (i.e., at operation in compliance with the collect required data is a deviation of least 76.0 percent if the 365-day design selected approach. Notification of such the monitoring requirements. value is 80.0 percent). a change in the compliance method (g) Compliance demonstration with (B) After 120 days and no more than shall be reported in the next Periodic percent reduction or emission limit 364 days of operation after the

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compliance dates specified in of the maximum design rate. Within the coated stainless steel evacuated canister § 63.760(f), the owner or operator shall first 5 minutes, ramp the firing rate to fitted with a flow controller sufficient to calculate the average HAP emission 100 percent of the maximum design fill the canister over a 1 hour period. reduction as the HAP emission rate. Hold at 100 percent for 5 minutes. Filling shall be conducted as specified reduction averaged over the number of In the 10–15 minute time range, ramp in the following: days between the current day and the back down to 70 percent of the (1) Open the canister sampling valve applicable compliance date. For sources maximum design rate. Repeat three at the beginning of the total required to meet the overall 95.0- more times for a total of 60 minutes of hydrocarbon (THC) test, and close the percent reduction requirement, sampling. canister at the end of the THC test. compliance with the performance (iii) 30–70–30 percent (ramp up, ramp (2) Fill one canister for each THC test requirements is achieved if the average down). Begin the test at 30 percent of run. HAP emission reduction is equal to or the maximum design rate. Within the (3) Label the canisters individually greater than 90.0 percent. For sources first 5 minutes, ramp the firing rate to and record on a chain of custody form. required to meet the BTEX limit under 70 percent of the maximum design rate. (B) Each fuel sample shall be analyzed § 63.765(b)(1)(iii), compliance is Hold at 70 percent for 5 minutes. In the using the following methods. The achieved if the average BTEX emission 10–15 minute time range, ramp back results shall be included in the test reduction is at least 95.0 percent of the down to 30 percent of the maximum report. required 365-day value identified under design rate. Repeat three more times for (1) Hydrocarbon compounds paragraph (g)(1) of this section (i.e., at a total of 60 minutes of sampling. containing between one and five atoms least 76.0 percent if the 365-day design (iv) 0–30–0 percent (ramp up, ramp of carbon plus benzene using ASTM value is 80.0 percent). down). Begin the test at 0 percent of the D1945–03. (3) If the owner or operator has data maximum design rate. Within the first 5 (2) Hydrogen (H2), carbon monoxide for 365 days or more of operation, minutes, ramp the firing rate to 100 (CO), carbon dioxide (CO2), nitrogen compliance is achieved based on the percent of the maximum design rate. (N2), oxygen (O2) using ASTM D1945– applicable criteria in paragraphs (g)(3)(i) Hold at 30 percent for 5 minutes. In the 03. or (ii) of this section. 10–15 minute time range, ramp back (3) Carbonyl sulfide, carbon disulfide (i) For sources meeting the HAP down to 0 percent of the maximum plus mercaptans using ASTM D5504. emission reduction specified in design rate. Repeat three more times for (4) Higher heating value using ASTM § 63.771(d)(1)(ii) or (e)(3) the average a total of 60 minutes of sampling. D3588–98 or ASTM D4891–89. (5) Outlet testing shall be conducted HAP emission reduction calculated in (3) All models employing multiple in accordance with the criteria in paragraph (g)(2)(iii) of this section is enclosures shall be tested paragraphs (h)(5)(i) through (v) of this equal to or greater than 95.0 percent. simultaneously and with all burners section. (ii) For sources required to meet the operational. Results shall be reported for (i) Sampling and flowrate measured in BTEX limit under § 63.771(e)(3) or (f)(1), the each enclosure individually and for the average of the emissions from all accordance with the following: compliance is achieved if the average (A) The outlet sampling location shall BTEX emission reduction calculated in interconnected combustion enclosures/ chambers. Control device operating data be a minimum of 4 equivalent stack paragraph (g)(2)(iii) of this section is diameters downstream from the highest equal to or greater than the minimum shall be collected continuously throughout the performance test using peak flame or any other flow percent reduction identified in disturbance, and a minimum of one paragraph (g)(1) of this section. an electronic Data Acquisition System and strip chart. Data shall be submitted equivalent stack diameter upstream of * * * * * with the test report in accordance with the exit or any other flow disturbance. (h) Performance testing for paragraph (8)(iii) of this section. A minimum of two sample ports shall combustion control devices— (4) Inlet testing shall be conducted as be used. manufacturers’ performance test. (1) specified in paragraphs (h)(4)(i) through (B) Flow rate shall be measured using This paragraph applies to the (iii) of this section. Method 1, 40 CFR part 60, Appendix 1, performance testing of a combustion (i) The fuel flow metering system for determining flow measurement control device conducted by the device shall be located in accordance with traverse point location; and Method 2, manufacturer. The manufacturer shall Method 2A, 40 CFR part 60, appendix 40 CFR part 60, Appendix 1, shall be demonstrate that a specific model of A–1, (or other approved procedure) to used to measure duct velocity. If low control device achieves the performance measure fuel flow rate at the control flow conditions are encountered (i.e., requirements in (h)(7) of this section by device inlet location. The fitting for velocity pressure differentials less than conducting a performance test as filling fuel sample containers shall be 0.05 inches of water) during the specified in paragraphs (h)(2) through located a minimum of 8 pipe diameters performance test, a more sensitive (6) of this section. upstream of any inlet fuel flow manometer shall be used to obtain an (2) Performance testing shall consist monitoring meter. accurate flow profile. of three one-hour (or longer) test runs (ii) Inlet flow rate shall be determined (ii) Molecular weight shall be for each of the four following firing rate using Method 2A, 40 CFR part 60, determined as specified in paragraphs settings making a total of 12 test runs appendix A–1. Record the start and stop (h)(4)(iii)(B), (h)(5)(ii)(A), and per test. Propene (propylene) gas shall reading for each 60-minute THC test. (h)(5)(ii)(B) of this section. be used for the testing fuel. All fuel Record the gas pressure and temperature (A) An integrated bag sample shall be analyses shall be performed by an at 5-minute intervals throughout each collected during the Method 4, 40 CFR independent third-party laboratory (not 60-minute THC test. part 60, Appendix A, moisture test. affiliated with the control device (iii) Inlet fuel sampling shall be Analyze the bag sample using a gas manufacturer or fuel supplier). conducted in accordance with the chromatograph-thermal conductivity (i) 90–100 percent of maximum criteria in paragraphs (h)(4)(iii)(A) and detector (GC–TCD) analysis meeting the design rate (fixed rate). (B) of this section. following criteria: (ii) 70–100–70 percent (ramp up, (A) At the inlet fuel sampling (1) Collect the integrated sample ramp down). Begin the test at 70 percent location, securely connect a Silonite- throughout the entire test, and collect

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representative volumes from each (iii) A 0–10 parts per million by this section, as applicable for the tested traverse location. volume-wet (ppmvw) (as propane) model. (2) The sampling line shall be purged measurement range is preferred; as an (A) Fuel gas delivery pressure and with stack gas before opening the valve alternative a 0–30 ppmvw (as carbon) temperature. and beginning to fill the bag. measurement range may be used. (B) Fuel gas moisture range. (3) The bag contents shall be kneaded (iv) Calibration gases will be propane (C) Purge gas usage range. or otherwise vigorously mixed prior to in air and be certified through EPA (D) Condensate (liquid fuel) the GC analysis. Protocol 1—‘‘EPA Traceability Protocol separation range. (4) The GC–TCD calibration for Assay and Certification of Gaseous (E) Combustion zone temperature procedure in Method 3C, 40 CFR part Calibration Standards,’’ September range. This is required for all devices 60, Appendix A, shall be modified by 1997, as amended August 25, 1999, that measure this parameter. using EPAAlt–045 as follows: For the EPA–600/R–97/121 (or more recent if (F) Excess combustion air range. initial calibration, triplicate injections of updated since 1999). (G) Flame arrestor(s). any single concentration must agree (v) THC measurements shall be (H) Burner manifold pressure. within 5 percent of their mean to be reported in terms of ppmvw as propane. (I) Pilot flame sensor. valid. The calibration response factor for (vi) THC results shall be corrected to (J) Pilot flame design fuel and fuel a single concentration re-check must be 3 percent CO2, as measured by Method usage. within 10 percent of the original 3C, 40 CFR part 60, Appendix A. (K) Tip velocity range. calibration response factor for that (vii) Subtraction of methane/ethane (L) Momentum flux ratio. concentration. If this criterion is not from the THC data is not allowed in (M) Exit temperature range. met, the initial calibration using at least determining results. (N) Exit flow rate. three concentration levels shall be (7) Performance test criteria: (O) Wind velocity and direction. repeated. (i) The control device model tested (vi) The test report shall include all (B) Report the molecular weight of: must meet the criteria in paragraphs calibration quality assurance/quality O2, CO2, methane (CH4), and N2 and (h)(7)(i)(A) through (C) of this section: control data, calibration gas values, gas include in the test report submitted (A) Method 22, 40 CFR part 60, cylinder certification, and strip charts under § 63.775(d)(iii). Moisture shall be Appendix A, results under paragraph annotated with test times and determined using Method 4, 40 CFR (h)(5)(v) of this section with no calibration values. part 60, Appendix A. Traverse both indication of visible emissions, and (i) Compliance demonstration for ports with the Method 4, 40 CFR part (B) Average Method 25A, 40 CFR part combustion control devices— 60, Appendix A, sampling train during 60, Appendix A, results under manufacturers’ performance test. This each test run. Ambient air shall not be paragraph (h)(6) of this section equal to paragraph applies to the demonstration introduced into the Method 3C, 40 CFR or less than 10.0 ppmvw THC as of compliance for a combustion control part 60, Appendix A, integrated bag propane corrected to 3.0 percent CO2, device tested under the provisions in sample during the port change. and paragraph (h) of this section. Owners or (iii) Carbon monoxide shall be (C) Average CO emissions determined operators shall demonstrate that a determined using Method 10, 40 CFR under paragraph (h)(5)(iv) of this section control device achieves the performance part 60, Appendix A. The test shall be equal to or less than 10 parts ppmvd, requirements of § 63.771(d)(1), (e)(3)(ii) run at the same time and with the corrected to 3.0 percent CO2. or (f)(1), by installing a device tested sample points used for the EPA Method (ii) The manufacturer shall determine under paragraph (h) of this section and 25A, 40 CFR part 60, Appendix A, a maximum inlet gas flow rate which complying with the following criteria: testing. An instrument range of 0–10 per shall not be exceeded for each control (1) The inlet gas flow rate shall meet million by volume-dry (ppmvd) shall be device model to achieve the criteria in the range specified by the manufacturer. used. paragraph (h)(7)(i) of this section. Flow rate shall be measured as specified (iv) Visible emissions shall be (iii) A control device meeting the in § 63.773(d)(3)(i)(H)(1). determined using Method 22, 40 CFR criteria in paragraphs (h)(7)(i)(A) (2) A pilot flame shall be present at all part 60, Appendix A. The test shall be through (C) of this section will have times of operation. The pilot flame shall performed continuously during each demonstrated a destruction efficiency of be monitored in accordance with test run. A digital color photograph of 98.0 percent for HAP regulated under § 63.773(d)(3)(i)(H)(2). the exhaust point, taken from the this subpart. (3) Devices shall be operated with no position of the observer and annotated (8) The owner or operator of a visible emissions, except for periods not with date and time, will be taken once combustion control device model tested to exceed a total of 5 minutes during per test run and the four photos under this section shall submit the any 2 consecutive hours. A visible included in the test report. information listed in paragraphs (h)(8)(i) emissions test using Method 22, 40 CFR (6) Total hydrocarbons (THC) shall be through (iii) of this section in the test part 60, Appendix A, shall be performed determined as specified by the report required under § 63.775(d)(1)(iii). monthly. The observation period shall following criteria: (i) Full schematic of the control be 2 hours and shall be used according (i) Conduct THC sampling using device and dimensions of the device to Method 22. Method 25A, 40 CFR part 60, Appendix components. (4) Compliance with the operating A, except the option for locating the (ii) Design net heating value parameter limit is achieved when the probe in the center 10 percent of the (minimum and maximum) of the device. following criteria are met: stack shall not be allowed. The THC (iii) Test fuel gas flow range (in both (i) The inlet gas flow rate monitored probe must be traversed to 16.7 percent, mass and volume). Include the under paragraph (i)(1) of this section is 50 percent, and 83.3 percent of the stack minimum and maximum allowable inlet equal to or below the maximum diameter during the testing. gas flow rate. established by the manufacturer; and (ii) A valid test shall consist of three (iv) Air/stream injection/assist ranges, (ii) The pilot flame is present at all Method 25A, 40 CFR part 60, Appendix if used. times; and A, tests, each no less than 60 minutes (v) The test parameter ranges listed in (iii) During the visible emissions test in duration. paragraphs (h)(8)(v)(A) through (O) of performed under paragraph (i)(3) of this

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section the duration of visible emissions operate a continuous parameter (i) Except for control devices for small does not exceed a total of 5 minutes monitoring system in accordance with glycol dehydration units, a boiler or during the observation period. Devices the requirements of paragraphs (d)(3) process heater in which all vent streams failing the visible emissions test shall through (9) of this section. Owners or are introduced with the primary fuel or follow the requirements in paragraphs operators that install and operate a flare is used as the primary fuel; or (i)(4)(iii)(A) and (B) of this section. in accordance with § 63.771(d)(1)(iii) or (ii) Except for control devices for (A) Following the first failure, the fuel (f)(1)(iii) are exempt from the small glycol dehydration units, a boiler nozzle(s) and burner tubes shall be requirements of paragraphs (d)(4) and or process heater with a design heat replaced. (5) of this section. The continuous input capacity equal to or greater than (B) If, following replacement of the monitoring system shall be designed 44 megawatts. fuel nozzle(s) and burner tubes as and operated so that a determination (3) * * * specified in paragraph (i)(4)(iii)(A), the can be made on whether the control (i) * * * visible emissions test is not passed in device is achieving the applicable (A) For a thermal vapor incinerator the next scheduled test, either a performance requirements of that demonstrates during the performance test shall be performed § 63.771(d), (e)(3) or (f)(1). Each performance test conducted under under paragraph (e) of this section, or continuous parameter monitoring § 63.772(e) that the combustion zone the device shall be replaced with system shall meet the following temperature is an accurate indicator of another control device whose model specifications and requirements: performance, a temperature monitoring was tested, and meets, the requirements * * * * * device equipped with a continuous in paragraph (h) of this section. (ii) A site-specific monitoring plan recorder. The monitoring device shall 19. Section 63.773 is amended by: must be prepared that addresses the have a minimum accuracy of ± 1 percent a. Adding paragraph (b); monitoring system design, data of the temperature being monitored in b. Revising paragraph (d)(1) collection, and the quality assurance degrees C, or ± 2.5 degrees C, whichever introductory text; and quality control elements outlined in value is greater. The temperature sensor c. Revising paragraph (d)(1)(ii) and paragraph (d) of this section and in shall be installed at a location adding paragraphs (d)(1)(iii) and (iv); § 63.8(d). Each CPMS must be installed, representative of the combustion zone d. Revising paragraphs (d)(2)(i) and calibrated, operated, and maintained in temperature. (d)(2)(ii); accordance with the procedures in your (B) For a catalytic vapor incinerator, e. Revising paragraphs (d)(3)(i)(A) and approved site-specific monitoring plan. a temperature monitoring device (B); Using the process described in equipped with a continuous recorder. f. Revising paragraphs (d)(3)(i)(D) and § 63.8(f)(4), you may request approval of The device shall be capable of (E); monitoring system quality assurance monitoring temperature at two locations g. Revising paragraphs (d)(3)(i)(F)(1) and have a minimum accuracy of ± 1 and (2); and quality control procedures alternative to those specified in percent of the temperature being h. Revising paragraph (d)(3)(i)(G); monitored in degrees C, or ± 2.5 degrees i. Adding paragraph (d)(3)(i)(H); paragraphs (d)(1)(ii)(A) through (E) of this section in your site-specific C, whichever value is greater. One j. Revising paragraph (d)(4); temperature sensor shall be installed in k. Revising paragraph (d)(5)(i); monitoring plan. the vent stream at the nearest feasible l. Revising paragraphs (d)(5)(ii)(A) (A) The performance criteria and point to the catalyst bed inlet and a through (C); design specifications for the monitoring second temperature sensor shall be m. Revising paragraphs (d)(6)(ii) and system equipment, including the sample installed in the vent stream at the (iii); interface, detector signal analyzer, and n. Adding paragraph (d)(6)(vi); data acquisition and calculations; nearest feasible point to the catalyst bed o. Revising paragraph (d)(8)(i)(A); and (B) Sampling interface (e.g., outlet. p. Revising paragraph (d)(8)(ii) to read thermocouple) location such that the * * * * * as follows: monitoring system will provide (D) For a boiler or process heater a representative measurements; temperature monitoring device § 63.773 Inspection and monitoring (C) Equipment performance checks, equipped with a continuous recorder. requirements. system accuracy audits, or other audit The temperature monitoring device * * * * * procedures; shall have a minimum accuracy of ± 1 (b) The owner or operator of a control (D) Ongoing operation and percent of the temperature being device whose model was tested under maintenance procedures in accordance monitored in degrees C, or ± 2.5 degrees § 63.772(h) shall develop an inspection with provisions in § 63.8(c)(1) and C, whichever value is greater. The and maintenance plan for each control (c)(3); and temperature sensor shall be installed at device. At a minimum, the plan shall (E) Ongoing reporting and a location representative of the contain the control device recordkeeping procedures in accordance combustion zone temperature. manufacturer’s recommendations for with provisions in § 63.10(c), (e)(1), and (E) For a condenser, a temperature ensuring proper operation of the device. (e)(2)(i). monitoring device equipped with a Semi-annual inspections shall be (iii) The owner or operator must continuous recorder. The temperature conducted for each control device with conduct the CPMS equipment monitoring device shall have a maintenance and replacement of control performance checks, system accuracy minimum accuracy of ± 1 percent of the device components made in accordance audits, or other audit procedures temperature being monitored in degrees with the plan. specified in the site-specific monitoring C, or ± 2.8 degrees C, whichever value * * * * * plan at least once every 12 months. is greater. The temperature sensor shall (d) Control device monitoring (iv) The owner or operator must be installed at a location in the exhaust requirements. (1) For each control conduct a performance evaluation of vent stream from the condenser. device, except as provided for in each CPMS in accordance with the site- (F) * * * paragraph (d)(2) of this section, the specific monitoring plan. (1) A continuous parameter owner or operator shall install and (2) * * * monitoring system to measure and

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record the average total regeneration (i) The owner or operator shall accordance with the requirements of stream mass flow or volumetric flow establish a minimum operating § 63.772(e)(4)(i) to demonstrate that the during each carbon bed regeneration parameter value or a maximum condenser achieves the applicable cycle. The flow sensor must have a operating parameter value, as performance requirements specified in measurement sensitivity of 5 percent of appropriate for the control device, to § 63.771(d)(1), (e)(3)(ii) or (f)(1), then the the flow rate or 10 cubic feet per define the conditions at which the condenser performance curve shall be minute, whichever is greater. The control device must be operated to based on the condenser design analysis mechanical connections for leakage continuously achieve the applicable and may be supplemented by the must be checked at least every month, performance requirements of control device manufacturer’s and a visual inspection must be § 63.771(d)(1), (e)(3)(ii) or (f)(1). Each recommendations. performed at least every 3 months of all minimum or maximum operating (C) As an alternative to paragraph components of the flow CPMS for parameter value shall be established as (d)(5)(ii)(B) of this section, the owner or physical and operational integrity and follows: operator may elect to use the procedures all electrical connections for oxidation (A) If the owner or operator conducts documented in the GRI report entitled, and galvanic corrosion if your flow performance tests in accordance with ‘‘Atmospheric Rich/Lean Method for CPMS is not equipped with a redundant the requirements of § 63.772(e)(3) to Determining Glycol Dehydrator flow sensor; and demonstrate that the control device Emissions’’ (GRI–95/0368.1) as inputs (2) A continuous parameter achieves the applicable performance for the model GRI–GLYCalcTM, Version monitoring system to measure and requirements specified in § 63.771(d)(1), 3.0 or higher, to generate a condenser record the average carbon bed (e)(3)(ii) or (f)(1), then the minimum performance curve. operating parameter value or the temperature for the duration of the * * * * * carbon bed steaming cycle and to maximum operating parameter value (6) * * * measure the actual carbon bed shall be established based on values temperature after regeneration and measured during the performance test (ii) For sources meeting within 15 minutes of completing the and supplemented, as necessary, by a § 63.771(d)(1)(ii), an excursion occurs cooling cycle. The temperature condenser design analysis or control when the 365-day average condenser monitoring device shall have a device manufacturer recommendations efficiency calculated according to the minimum accuracy of ± 1 percent of the or a combination of both. requirements specified in temperature being monitored in degrees (B) If the owner or operator uses a § 63.772(g)(2)(iii) is less than 95.0 C, or ± 2.5 degrees C, whichever value condenser design analysis in accordance percent. For sources meeting is greater. with the requirements of § 63.772(e)(4) § 63.771(f)(1), an excursion occurs when to demonstrate that the control device (G) For a nonregenerative-type carbon the 365-day average condenser achieves the applicable performance adsorption system, the owner or efficiency calculated according to the requirements specified in § 63.771(d)(1), operator shall monitor the design carbon requirements specified in (e)(3)(ii) or (f)(1), then the minimum replacement interval established using a § 63.772(g)(2)(iii) is less than 95.0 operating parameter value or the performance test performed in percent of the identified 365-day maximum operating parameter value accordance with § 63.772(e)(3) shall be required percent reduction. shall be established based on the based on the total carbon working (iii) For sources meeting condenser design analysis and may be capacity of the control device and § 63.771(d)(1)(ii), if an owner or supplemented by the condenser source operating schedule. operator has less than 365 days of data, manufacturer’s recommendations. (H) For a control device model whose an excursion occurs when the average (C) If the owner or operator operates condenser efficiency calculated model is tested under § 63.772(h): a control device where the performance (1) A continuous monitoring system according to the procedures specified in test requirement was met under § 63.772(g)(2)(iii)(A) or (B) is less than that measures gas flow rate at the inlet § 63.772(h) to demonstrate that the to the control device. The monitoring 90.0 percent. For sources meeting control device achieves the applicable § 63.771(d)(1)(ii), an excursion occurs instrument shall have an accuracy of performance requirements specified in plus or minus 2 percent or better. when the 365-day average condenser § 63.771(d)(1), (e)(3)(ii) or (f)(1), then the efficiency calculated according to the (2) A heat sensing monitoring device maximum inlet gas flow rate shall be equipped with a continuous recorder requirements specified in established based on the performance § 63.772(g)(2)(iii) is less than the that indicates the continuous ignition of test and supplemented, as necessary, by the pilot flame. identified 365-day required percent the manufacturer recommendations. reduction. * * * * * (ii) * * * (4) Using the data recorded by the (A) If the owner or operator conducts * * * * * monitoring system, except for inlet gas a performance test in accordance with (vi) For control device whose model flow rate, the owner or operator must the requirements of § 63.772(e)(3) to is tested under § 63.772(h) an excursion calculate the daily average value for demonstrate that the condenser achieves occurs when: each monitored operating parameter for the applicable performance (A) The inlet gas flow rate exceeds the each operating day. If the emissions unit requirements in § 63.771(d)(1), (e)(3)(ii) maximum established during the test operation is continuous, the operating or (f)(1), then the condenser conducted under § 63.772(h). day is a 24-hour period. If the emissions performance curve shall be based on (B) Failure of the monthly visible unit operation is not continuous, the values measured during the emissions test conducted under operating day is the total number of performance test and supplemented as § 63.772(i)(3) occurs. hours of control device operation per necessary by control device design * * * * * 24-hour period. Valid data points must analysis, or control device be available for 75 percent of the manufacturer’s recommendations, or a (8) * * * operating hours in an operating day to combination or both. (i) * * * compute the daily average. (B) If the owner or operator uses a (A) During a malfunction when the (5) * * * control device design analysis in affected facility is operated during such

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period in accordance with § 63.6(e)(1); (g) The owner or operator of an shall be submitted by 1 year after an or affected source subject to this subpart affected source becomes subject to the * * * * * shall maintain records of the occurrence provisions of this subpart or by June 17, (ii) For each control device, or and duration of each malfunction of 2000, whichever is later. Affected combinations of control devices operation (i.e., process equipment) or sources that are major sources on or installed on the same emissions unit, the air pollution control equipment and before June 17, 2000 and plan to be area one excused excursion is allowed per monitoring equipment. The owner or sources by June 17, 2002 shall include semiannual period for any reason. The operator shall maintain records of in this notification a brief, nonbinding initial semiannual period is the 6-month actions taken during periods of description of a schedule for the reporting period addressed by the first malfunction to minimize emissions in action(s) that are planned to achieve Periodic Report submitted by the owner accordance with § 63.764(a), including area source status. or operator in accordance with corrective actions to restore (ii) An affected source identified § 63.775(e) of this subpart. malfunctioning process and air under § 63.760(f)(7) or (9) shall submit * * * * * pollution control and monitoring an initial notification required for 20. Section 63.774 is amended by: equipment to its normal or usual existing affected sources under a. Revising paragraph (b)(3) manner of operation. § 63.9(b)(2) within 1 year after the introductory text; (h) Record the following when using affected source becomes subject to the b. Removing and reserving paragraph a control device whose model is tested provisions of this subpart or by one year (b)(3)(ii); under § 63.772(h) to comply with after publication of the final rule in the c. Revising paragraph (b)(4)(ii) § 63.771(d), (e)(3)(ii) and (f)(1): Federal Register, whichever is later. An introductory text; (1) All visible emission readings and affected source identified under d. Adding paragraph (b)(4)(ii)(C); flowrate measurements made during the § 63.760(f)(7) or (9) that plans to be an e. Adding paragraph (b)(7)(ix); and compliance determination required by area source by three years after f. Adding paragraphs (g) through (i) to § 63.772(i); and publication of the final rule in the read as follows: (2) All hourly records and other Federal Register, shall include in this recorded periods when the pilot flame notification a brief, nonbinding § 63.774 Recordkeeping requirements. is absent. description of a schedule for the * * * * * (i) The date the semi-annual action(s) that are planned to achieve (b) * * * maintenance inspection required under area source status. (3) Records specified in § 63.10(c) for § 63.773(b) is performed. Include a list each monitoring system operated by the * * * * * of any modifications or repairs made to (6) If there was a malfunction during owner or operator in accordance with the control device during the inspection the reporting period, the Periodic Report the requirements of § 63.773(d). and other maintenance performed such specified in paragraph (e) of this section Notwithstanding the requirements of as cleaning of the fuel nozzles. shall include the number, duration, and § 63.10(c), monitoring data recorded 21. Section 63.775 is amended by: a brief description for each type of during periods identified in paragraphs a. Revising paragraph (b)(1); malfunction which occurred during the (b)(3)(i) through (b)(3)(iv) of this section b. Revising paragraph (b)(6); reporting period and which caused or shall not be included in any average or c. Removing and reserving paragraph may have caused any applicable percent leak rate computed under this (b)(7); emission limitation to be exceeded. The subpart. Records shall be kept of the d. Revising paragraph (c)(1); report must also include a description of times and durations of all such periods e. Revising paragraph (c)(6); actions taken by an owner or operator and any other periods during process or f. Revising paragraph (c)(7)(i); during a malfunction of an affected control device operation when monitors g. Revising paragraph (d)(1)(i); source to minimize emissions in are not operating or failed to collect h. Revising paragraph (d)(1)(ii) accordance with § 63.764(j), including required data. introductory text; actions taken to correct a malfunction. * * * * * i. Revising paragraph (d)(5)(ii); (7) [Reserved] (ii) [Reserved] j. Adding paragraph (d)(5)(iv); * * * * * * * * * * k. Revising paragraph (d)(11); l. Adding paragraphs (d)(13) and (c) * * * (4) * * * (1) The initial notifications required (d)(14); (ii) Records of the daily average value under § 63.9(b)(2) not later than January m. Revising paragraphs (e)(2) of each continuously monitored 3, 2008. In addition to submitting your introductory text, (e)(2)(ii)(B) and (C); parameter for each operating day initial notification to the addressees determined according to the procedures n. Adding paragraphs (e)(2)(ii)(E) and (F); specified under § 63.9(a), you must also specified in § 63.773(d)(4) of this submit a copy of the initial notification subpart, except as specified in o. Adding paragraphs (e)(2)(xi) through (xiii); and to the EPA’s Office of Air Quality paragraphs (b)(4)(ii)(A) through (C) of Planning and Standards. Send your this section. p. Adding paragraph (g) to read as follows: notification via e-mail to Oil and Gas * * * * * [email protected] or via U.S. mail or other (C) For control device whose model is § 63.775 Reporting requirements. mail delivery service to U.S. EPA, tested under § 63.772(h), the records * * * * * Sector Policies and Programs Division/ required in paragraph (h) of this section. (b) * * * Fuels and Incineration Group (E143– * * * * * (1) The initial notifications required 01), Attn: Oil and Gas Project Leader, (7) * * * for existing affected sources under Research Triangle Park, NC 27711. (ix) Records identifying the carbon § 63.9(b)(2) shall be submitted as * * * * * replacement schedule under provided in paragraphs (b)(1)(i) and (ii) (6) If there was a malfunction during § 63.771(d)(5) and records of each of this section. the reporting period, the Periodic Report carbon replacement. (i) Except as otherwise provided in specified in paragraph (e) of this section * * * * * paragraph (ii), the initial notifications shall include the number, duration, and

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a brief description for each type of applicable requirements of (E) For each excursion caused when malfunction which occurred during the § 63.771(d)(1), (e)(3)(ii) or (f)(1). the maximum inlet gas flow rate reporting period and which caused or * * * * * identified under § 63.772(h) is may have caused any applicable (iv) For each carbon adsorber, the exceeded, the report must include the emission limitation to be exceeded. The predetermined carbon replacement values of the inlet gas identified and the report must also include a description of schedule as required in § 63.771(d)(5)(i). date and duration of the period that the actions taken by an owner or operator * * * * * excursion occurred. during a malfunction of an affected (11) The owner or operator shall (F) For each excursion caused when source to minimize emissions in submit the analysis prepared under visible emissions determined under accordance with § 63.764(j), including § 63.771(e)(2) to demonstrate the § 63.772(i) exceed the maximum actions taken to correct a malfunction. conditions by which the facility will be allowable duration, the report must (7) * * * operated to achieve the HAP emission include the date and duration of the (i) Documentation of the source’s period that the excursion occurred. location relative to the nearest UA plus reduction of 95.0 percent, or the BTEX offset and UC boundaries. This limit in § 63.765(b)(1)(iii), through * * * * * information shall include the latitude process modifications or a combination (xi) The results of any periodic test as and longitude of the affected source; of process modifications and one or required in § 63.772(e)(3) conducted whether the source is located in an more control devices. during the reporting period. urban cluster with 10,000 people or * * * * * (xii) For each carbon adsorber used to more; the distance in miles to the (13) If the owner or operator installs meet the control device requirements of nearest urbanized area boundary if the a combustion control device model § 63.771(d)(1), records of each carbon source is not located in an urban cluster tested under the procedures in replacement that occurred during the with 10,000 people or more; and the § 63.772(h), the data listed under reporting period. name of the nearest urban cluster with § 63.772(h)(8). (xiii) For combustion control device 10,000 people or more and nearest (14) For each combustion control inspections conducted in accordance urbanized area. device model tested under § 63.772(h), with § 63.773(b) the records specified in * * * * * the information listed in paragraphs § 63.774(i). (d)(14)(i) through (vi) of this section. (d) * * * * * * * * (1) * * * (i) Name, address and telephone (i) The condenser design analysis number of the control device (g) Electronic reporting. (1) As of documentation specified in manufacturer. January 1, 2012 and within 60 days after § 63.772(e)(4) of this subpart, if the (ii) Control device model number. the date of completing each owner or operator elects to prepare a (iii) Control device serial number. performance test, as defined in § 63.2 design analysis. (iv) Date of control device and as required in this subpart, you (ii) If the owner or operator is certification test. must submit performance test data, required to conduct a performance test, (v) Manufacturer’s HAP destruction except opacity data, electronically to the the performance test results including efficiency rating. EPA’s Central Data Exchange (CDX) by the information specified in paragraphs (vi) Control device operating using the Electronic Reporting Tool (d)(1)(ii)(A) and (B) of this section. parameters, maximum allowable inlet (ERT) (see http://www.epa.gov/ttn/chief/ Results of a performance test conducted gas flowrate. ert/ert tool.html/). Only data collected prior to the compliance date of this (e) * * * using test methods compatible with ERT subpart can be used provided that the (2) The owner or operator shall are subject to this requirement to be test was conducted using the methods include the information specified in submitted electronically into the EPA’s specified in § 63.772(e)(3) and that the paragraphs (e)(2)(i) through (xiii) of this WebFIRE database. test conditions are representative of section, as applicable. (2) All reports required by this current operating conditions. If the * * * * * subpart not subject to the requirements owner or operator operates a (ii) * * * in paragraphs (g)(1) of this section must combustion control device model tested (B) For each excursion caused when be sent to the Administrator at the under § 63.772(h), an electronic copy of the 365-day average condenser control appropriate address listed in § 63.13. If the performance test results shall be efficiency is less than the value acceptable to both the Administrator submitted via e-mail to Oil and Gas specified in § 63.773(d)(6)(ii), the report and the owner or operator of a source, [email protected]. must include the 365-day average values these reports may be submitted on * * * * * of the condenser control efficiency, and electronic media. The Administrator (5) * * * the date and duration of the period that retains the right to require submittal of (ii) An explanation of the rationale for the excursion occurred. reports subject to paragraph (g)(1) of this why the owner or operator selected each (C) For each excursion caused when section in paper format. of the operating parameter values condenser control efficiency is less than 22. Appendix to subpart HH of part 63 established in § 63.773(d)(5). This the value specified in § 63.773(d)(6)(iii), is amended by revising Table 2 to read explanation shall include any data and the report must include the average as follows: calculations used to develop the value values of the condenser control and a description of why the chosen efficiency, and the date and duration of Appendix to Subpart HH of Part 63— value indicates that the control device is the period that the excursion occurred. Tables operating in accordance with the * * * * * * * * * *

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TABLE 2 TO SUBPART HH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH

Applicable to General provisions reference subpart HH Explanation

§ 63.1(a)(1) ...... Yes. § 63.1(a)(2) ...... Yes. § 63.1(a)(3) ...... Yes. § 63.1(a)(4) ...... Yes. § 63.1(a)(5) ...... No ...... Section reserved. § 63.1(a)(6) ...... Yes. § 63.1(a)(7) through (a)(9) ...... No ...... Section reserved. § 63.1(a)(10) ...... Yes. § 63.1(a)(11) ...... Yes. § 63.1(a)(12) ...... Yes. § 63.1(b)(1) ...... No ...... Subpart HH specifies applicability. § 63.1(b)(2) ...... No ...... Section reserved. § 63.1(b)(3) ...... Yes. § 63.1(c)(1) ...... No ...... Subpart HH specifies applicability. § 63.1(c)(2) ...... Yes ...... Subpart HH exempts area sources from the requirement to obtain a Title V permit unless otherwise required by law as specified in § 63.760(h). § 63.1(c)(3) and (c)(4) ...... No ...... Section reserved. § 63.1(c)(5) ...... Yes. § 63.1(d) ...... No ...... Section reserved. § 63.1(e) ...... Yes. § 63.2 ...... Yes ...... Except definition of major source is unique for this source category and there are additional definitions in subpart HH. § 63.3(a) through (c) ...... Yes. § 63.4(a)(1) through (a)(2) ...... Yes. § 63.4(a)(3) through (a)(5) ...... No ...... Section reserved. § 63.4(b) ...... Yes. § 63.4(c) ...... Yes. § 63.5(a)(1) ...... Yes. § 63.5(a)(2) ...... Yes. § 63.5(b)(1) ...... Yes. § 63.5(b)(2) ...... No ...... Section reserved. § 63.5(b)(3) ...... Yes. § 63.5(b)(4) ...... Yes. § 63.5(b)(5) ...... No ...... Section reserved. § 63.5(b)(6) ...... Yes. § 63.5(c) ...... No ...... Section reserved. § 63.5(d)(1) ...... Yes. § 63.5(d)(2) ...... Yes. § 63.5(d)(3) ...... Yes. § 63.5(d)(4) ...... Yes. § 63.5(e) ...... Yes. § 63.5(f)(1) ...... Yes. § 63.5(f)(2) ...... Yes. § 63.6(a) ...... Yes. § 63.6(b)(1) ...... Yes. § 63.6(b)(2) ...... Yes. § 63.6(b)(3) ...... Yes. § 63.6(b)(4) ...... Yes. § 63.6(b)(5) ...... Yes. § 63.6(b)(6) ...... No ...... Section reserved. § 63.6(b)(7) ...... Yes. § 63.6(c)(1) ...... Yes. § 63.6(c)(2) ...... Yes. § 63.6(c)(3) through (c)(4) ...... No ...... Section reserved. § 63.6(c)(5) ...... Yes. § 63.6(d) ...... No ...... Section reserved. § 63.6(e) ...... Yes. § 63.6(e)(1)(i) ...... No ...... See § 63.764(j) for general duty requirement. § 63.6(e)(1)(ii) ...... No. § 63.6(e)(1)(iii) ...... Yes. § 63.6(e)(2) ...... No ...... Section reserved. § 63.6(e)(3) ...... No. § 63.6(f)(1) ...... No. § 63.6(f)(2) ...... Yes. § 63.6(f)(3) ...... Yes. § 63.6(g) ...... Yes. § 63.6(h) ...... No ...... Subpart HH does not contain opacity or visible emission standards. § 63.6(i)(1) through (i)(14) ...... Yes. § 63.6(i)(15) ...... No ...... Section reserved. § 63.6(i)(16) ...... Yes. § 63.6(j) ...... Yes.

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TABLE 2 TO SUBPART HH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH— Continued

Applicable to General provisions reference subpart HH Explanation

§ 63.7(a)(1) ...... Yes. § 63.7(a)(2) ...... Yes ...... But the performance test results must be submitted within 180 days after the com- pliance date. § 63.7(a)(3) ...... Yes. § 63.7(b) ...... Yes. § 63.7(c) ...... Yes. § 63.7(d) ...... Yes. § 63.7(e)(1) ...... No. § 63.7(e)(2) ...... Yes. § 63.7(e)(3) ...... Yes. § 63.7(e)(4) ...... Yes. § 63.7(f) ...... Yes. § 63.7(g) ...... Yes. § 63.7(h) ...... Yes. § 63.8(a)(1) ...... Yes. § 63.8(a)(2) ...... Yes. § 63.8(a)(3) ...... No ...... Section reserved. § 63.8(a)(4) ...... Yes. § 63.8(b)(1) ...... Yes. § 63.8(b)(2) ...... Yes. § 63.8(b)(3) ...... Yes. § 63.8(c)(1) ...... No. § 63.8(c)(1)(i) ...... No. § 63.8(c)(1)(ii) ...... Yes. § 63.8(c)(1)(iii) ...... Pending. § 63.8(c)(2) ...... Yes. § 63.8(c)(3) ...... Yes. § 63.8(c)(4) ...... Yes. § 63.8(c)(4)(i) ...... No ...... Subpart HH does not require continuous opacity monitors. § 63.8(c)(4)(ii) ...... Yes. § 63.8(c)(5) through (c)(8) ...... Yes. § 63.8(d) ...... Yes. § 63.8(d)(3) ...... Yes ...... Except for last sentence, which refers to an SSM plan. SSM plans are not required. § 63.8(e) ...... Yes ...... Subpart HH does not specifically require continuous emissions monitor perform- ance evaluation, however, the Administrator can request that one be conducted. § 63.8(f)(1) through (f)(5) ...... Yes. § 63.8(f)(6) ...... Yes. § 63.8(g) ...... No ...... Subpart HH specifies continuous monitoring system data reduction requirements. § 63.9(a) ...... Yes. § 63.9(b)(1) ...... Yes. § 63.9(b)(2) ...... Yes ...... Existing sources are given 1 year (rather than 120 days) to submit this notification. Major and area sources that meet § 63.764(e) do not have to submit initial notifi- cations. § 63.9(b)(3) ...... No ...... Section reserved. § 63.9(b)(4) ...... Yes. § 63.9(b)(5) ...... Yes. § 63.9(c) ...... Yes. § 63.9(d) ...... Yes. § 63.9(e) ...... Yes. § 63.9(f) ...... No ...... Subpart HH does not have opacity or visible emission standards. § 63.9(g)(1) ...... Yes. § 63.9(g)(2) ...... No ...... Subpart HH does not have opacity or visible emission standards. § 63.9(g)(3) ...... Yes. § 63.9(h)(1) through (h)(3) ...... Yes ...... Area sources located outside UA plus offset and UC boundaries are not required to submit notifications of compliance status. § 63.9(h)(4) ...... No ...... Section reserved. § 63.9(h)(5) through (h)(6) ...... Yes. § 63.9(i) ...... Yes. § 63.9(j) ...... Yes. § 63.10(a) ...... Yes. § 63.10(b)(1) ...... Yes ...... § 63.774(b)(1) requires sources to maintain the most recent 12 months of data on- site and allows offsite storage for the remaining 4 years of data. § 63.10(b)(2) ...... Yes. § 63.10(b)(2)(i) ...... No ...... § 63.10(b)(2)(ii) ...... No ...... See § 63.774(g) for recordkeeping of occurrence, duration, and actions taken dur- ing malfunctions. § 63.10(b)(2)(iii) ...... Yes. § 63.10(b)(2)(iv) through (b)(2)(v) ...... No. § 63.10(b)(2)(vi) through (b)(2)(xiv) ...... Yes.

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TABLE 2 TO SUBPART HH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HH— Continued

Applicable to General provisions reference subpart HH Explanation

§ 63.10(b)(3) ...... Yes ...... § 63.774(b)(1) requires sources to maintain the most recent 12 months of data on- site and allows offsite storage for the remaining 4 years of data. § 63.10(c)(1) ...... Yes. § 63.10(c)(2) through (c)(4) ...... No ...... Sections reserved. § 63.10(c)(5) through (8)(c)(8) ...... Yes. § 63.10(c)(9) ...... No ...... Section reserved. § 63.10(c)(10) through (11) ...... No ...... See § 63.774(g) for recordkeeping of malfunctions. § 63.10(c)(12) through (14) ...... Yes. § 63.10(c)(15) ...... No. § 63.10(d)(1) ...... Yes. § 63.10(d)(2) ...... Yes ...... Area sources located outside UA plus offset and UC boundaries do not have to submit performance test reports. § 63.10(d)(3) ...... Yes. § 63.10(d)(4) ...... Yes. § 63.10(d)(5) ...... No ...... See § 63.775(b)(6) or (c)(6) for reporting of malfunctions. § 63.10(e)(1) ...... Yes ...... Area sources located outside UA plus offset and UC boundaries are not required to submit reports. § 63.10(e)(2) ...... Yes ...... Area sources located outside UA plus offset and UC boundaries are not required to submit reports. § 63.10(e)(3)(i) ...... Yes ...... Subpart HH requires major sources to submit Periodic Reports semi-annually. Area sources are required to submit Periodic Reports annually. Area sources located outside UA plus offset and UC boundaries are not required to submit reports. § 63.10(e)(3)(i)(A) ...... Yes. § 63.10(e)(3)(i)(B) ...... Yes. § 63.10(e)(3)(i)(C) ...... No ...... Section reserved. § 63.10(e)(3)(ii) through (viii) ...... Yes. § 63.10(f) ...... Yes. § 63.11(a) and (b) ...... Yes. § 63.11(c), (d), and (e) ...... Yes. § 63.12(a) through (c) ...... Yes. § 63.13(a) through (c) ...... Yes. § 63.14(a) and (b) ...... Yes. § 63.15(a) and (b) ...... Yes. § 63.16 ...... Yes.

Subpart HHH—[Amended] the owner or operator of a new or source from limiting its potential to emit existing source may use the facility through other appropriate mechanisms 23. Section 63.1270 is amended by: design maximum natural gas throughput that may be available through the a. Revising paragraph (a) introductory to estimate the maximum potential permitting authority. text; emissions. Other means to determine * * * * * b. Revising paragraph (a)(4); the facility’s major source status are (4) The owner or operator shall c. Revising paragraphs (d)(1) and allowed, provided the information is determine the maximum values for (d)(2); and documented and recorded to the other parameters used to calculate d. Adding paragraphs (d)(3), (4) and Administrator’s satisfaction in potential emissions as the maximum (5) to read as follows: accordance with § 63.10(b)(3). A over the same period for which § 63.1270 Applicability and designation of compressor station that transports maximum throughput is determined as affected source. natural gas prior to the point of custody specified in paragraph (a)(1) or (a)(2) of (a) This subpart applies to owners and transfer or to a natural gas processing this section. These parameters shall be operators of natural gas transmission plant (if present) is not considered a based on an annual average or the and storage facilities that transport or part of the natural gas transmission and highest single measured value. For store natural gas prior to entering the storage source category. A facility that is estimating maximum potential pipeline to a local distribution company determined to be an area source, but emissions from glycol dehydration or to a final end user (if there is no local subsequently increases its emissions or units, the glycol circulation rate used in distribution company), and that are its potential to emit above the major the calculation shall be the unit’s major sources of hazardous air source levels (without obtaining and maximum rate under its physical and pollutants (HAP) emissions as defined complying with other limitations that operational design consistent with the in § 63.1271. Emissions for major source keep its potential to emit HAP below definition of potential to emit in § 63.2. determination purposes can be major source levels), and becomes a * * * * * estimated using the maximum natural major source, must comply thereafter (d) * * * gas throughput calculated in either with all applicable provisions of this (1) Except as specified in paragraphs paragraph (a)(1) or (2) of this section subpart starting on the applicable (d)(3) through (5) of this section, the and paragraphs (a)(3) and (4) of this compliance date specified in paragraph owner or operator of an affected source, section. As an alternative to calculating (d) of this section. Nothing in this the construction or reconstruction of the maximum natural gas throughput, paragraph is intended to preclude a which commenced before February 6,

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1998, shall achieve compliance with the Affirmative defense means, in the § 63.1272 Startups and shutdowns. provisions of this subpart no later than context of an enforcement proceeding, a (a) The provisions set forth in this June 17, 2002 except as provided for in response or defense put forward by a subpart shall apply at all times. § 63.6(i). The owner or operator of an defendant, regarding which the (b) The owner or operator shall not area source, the construction or defendant has the burden of proof, and shut down items of equipment that are reconstruction of which commenced the merits of which are independently required or utilized for compliance with before February 6, 1998, that increases and objectively evaluated in a judicial the provisions of this subpart during its emissions of (or its potential to emit) or administrative proceeding. times when emissions are being routed HAP such that the source becomes a * * * * * to such items of equipment, if the major source that is subject to this BTEX means benzene, toluene, ethyl shutdown would contravene subpart shall comply with this subpart benzene and xylene. requirements of this subpart applicable 3 years after becoming a major source. * * * * * to such items of equipment. This (2) Except as specified in paragraphs Flare means a thermal oxidation paragraph does not apply if the owner (d)(3) through (5) of this section, the system using an open flame (i.e., or operator must shut down the owner or operator of an affected source, without enclosure). equipment to avoid damage due to a the construction or reconstruction of * * * * * contemporaneous startup or shutdown which commences on or after February Glycol dehydration unit baseline of the affected source or a portion 6, 1998, shall achieve compliance with operations means operations thereof. the provisions of this subpart representative of the large glycol (c) During startups and shutdowns, immediately upon initial startup or June dehydration unit operations as of June the owner or operator shall implement 17, 1999, whichever date is later. Area 17, 1999 and the small glycol measures to prevent or minimize excess sources, the construction or dehydration unit operations as of emissions to the maximum extent reconstruction of which commences on August 23, 2011. For the purposes of practical. or after February 6, 1998, that become this subpart, for determining the (d) In response to an action to enforce major sources shall comply with the percentage of overall HAP emission the standards set forth in this subpart, provisions of this standard immediately reduction attributable to process you may assert an affirmative defense to upon becoming a major source. modifications, glycol dehydration unit a claim for civil penalties for (3) Each affected small glycol baseline operations shall be parameter exceedances of such standards that are dehydration unit, as defined in values (including, but not limited to, caused by malfunction, as defined in § 63.1271, located at a major source, that glycol circulation rate or glycol-HAP § 63.2. Appropriate penalties may be commenced construction before August absorbency) that represent actual long- assessed, however, if you fail to meet 23, 2011 must achieve compliance no term conditions (i.e., at least 1 year). your burden of proving all the later than 3 years after the date of Glycol dehydration units in operation requirements in the affirmative defense. publication of the final rule in the for less than 1 year shall document that The affirmative defense shall not be Federal Register, except as provided in the parameter values represent expected available for claims for injunctive relief. § 63.6(i). long-term operating conditions had (1) To establish the affirmative (4) Each affected small glycol process modifications not been made. dehydration unit, as defined in defense in any action to enforce such a § 63.1271, located at a major source, that * * * * * limit, the owner or operator must timely Large glycol dehydration unit means a commenced construction on or after meet the notification requirements in glycol dehydration unit with an actual August 23, 2011 must achieve paragraph (d)(2) of this section, and annual average natural gas flowrate compliance immediately upon initial must prove by a preponderance of equal to or greater than 283.0 thousand startup or the date of publication of the evidence that: standard cubic meters per day and final rule in the Federal Register, (i) The excess emissions: actual annual average benzene whichever is later. (A) Were caused by a sudden, (5) Each large glycol dehydration unit, emissions equal to or greater than 0.90 infrequent, and unavoidable failure of as defined in § 63.1271, that has Mg/yr, determined according to air pollution control and monitoring complied with the provisions of this § 63.1282(a). equipment, process equipment, or a subpart prior to August 23, 2011 by * * * * * process to operate in a normal or usual reducing its benzene emissions to less Small glycol dehydration unit means manner; and than 0.9 megagrams per year must a glycol dehydration unit, located at a (B) Could not have been prevented achieve compliance no later than major source, with an actual annual through careful planning, proper design 90 days after the date of publication of average natural gas flowrate less than or better operation and maintenance the final rule in the Federal Register, 283.0 thousand standard cubic meters practices; and except as provided in § 63.6(i). per day or actual annual average (C) Did not stem from any activity or benzene emissions less than 0.90 Mg/yr, event that could have been foreseen and * * * * * 24. Section 63.1271 is amended by: determined according to § 63.1282(a). avoided, or planned for; and a. Adding, in alphabetical order, new Temperature monitoring device (D) Were not part of a recurring definitions for the terms ‘‘affirmative means an instrument used to monitor pattern indicative of inadequate design, temperature and having a minimum operation, or maintenance; and defense,’’ ‘‘BTEX,’’ ‘‘flare,’’ ‘‘large glycol ± dehydration units,’’ ‘‘small glycol accuracy of 1 percent of the (ii) Repairs were made as temperature being monitored expressed expeditiously as possible when the dehydration units’’; and ° ± ° b. Revising the definitions for ‘‘glycol in C, or 2.5 C, whichever is greater. applicable emission limitations were dehydration unit baseline operations’’ The temperature monitoring device may being exceeded. Off-shift and overtime and ‘‘temperature monitoring device’’ to measure temperature in degrees labor were used, to the extent read as follows: Fahrenheit or degrees Celsius, or both. practicable to make these repairs; and * * * * * (iii) The frequency, amount and § 63.1271 Definitions. 25. Section 63.1272 is revised to read duration of the excess emissions * * * * * as follows: (including any bypass) were minimized

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to the maximum extent practicable met the requirements set forth in consistent with safety and good air during periods of such emissions; and paragraph (d)(1) of this section. The pollution control practices for (iv) If the excess emissions resulted owner or operator may seek an minimizing emissions. Determination of from a bypass of control equipment or extension of this deadline for up to 30 whether such operation and a process, then the bypass was additional days by submitting a written maintenance procedures are being used unavoidable to prevent loss of life, request to the Administrator before the will be based on information available personal injury, or severe property expiration of the 45 day period. Until a to the Administrator which may damage; and request for an extension has been include, but is not limited to, (v) All possible steps were taken to approved by the Administrator, the monitoring results, review of operation minimize the impact of the excess owner or operator is subject to the and maintenance procedures, review of emissions on ambient air quality, the requirement to submit such report operation and maintenance records, and environment, and human health; and within 45 days of the initial occurrence inspection of the source. (vi) All emissions monitoring and of the exceedance. 27. Section 63.1275 is amended by: control systems were kept in operation 26. Section 63.1274 is amended by: a. Revising paragraph (a); if at all possible, consistent with safety a. Revising paragraph (c) introductory b. Revising paragraph (b)(1); and good air pollution control practices; text; and b. Removing and reserving paragraph c. Revising paragraph (c)(2); and (vii) All of the actions in response to (d); d. Revising paragraph (c)(3) to read as the excess emissions were documented c. Revising paragraph (g); and follows: by properly signed, contemporaneous d. Adding paragraph (h) to read as § 63.1275 Glycol dehydration unit process operating logs; and follows: (viii) At all times, the affected source vent standards. was operated in a manner consistent § 63.1274 General standards. (a) This section applies to each glycol with good practices for minimizing * * * * * dehydration unit subject to this subpart emissions; and (c) The owner or operator of an that must be controlled for air emissions (ix) A written root cause analysis has affected source (i.e., glycol dehydration as specified in paragraph (c)(1) of been prepared to determine, correct, and unit) located at an existing or new major § 63.1274. eliminate the primary causes of the source of HAP emissions shall comply (b) * * * malfunction and the excess emissions with the requirements in this subpart as (1) For each glycol dehydration unit resulting from the malfunction event at follows: process vent, the owner or operator issue. The analysis shall also specify, * * * * * shall control air emissions by either using best monitoring methods and (d) [Reserved] paragraph (b)(1)(i) or (b)(1)(iii) of this engineering judgment, the amount of section. excess emissions that were the result of * * * * * (i) The owner or operator of a large the malfunction. (g) In all cases where the provisions (2) Notification. The owner or of this subpart require an owner or glycol dehydration unit, as defined in operator of the affected source operator to repair leaks by a specified § 63.1271, shall connect the process experiencing an exceedance of its time after the leak is detected, it is a vent to a control device or a emission limit(s) during a malfunction violation of this standard to fail to take combination of control devices through shall notify the Administrator by action to repair the leak(s) within the a closed-vent system. The closed-vent telephone or facsimile transmission as specified time. If action is taken to system shall be designed and operated soon as possible, but no later than two repair the leak(s) within the specified in accordance with the requirements of business days after the initial time, failure of that action to § 63.1281(c). The control device(s) shall occurrence of the malfunction, if it successfully repair the leak(s) is not a be designed and operated in accordance wishes to avail itself of an affirmative violation of this standard. However, if with the requirements of § 63.1281(d). defense to civil penalties for that the repairs are unsuccessful, and a leak (ii) [Reserved] malfunction. The owner or operator is detected, the owner or operator shall (iii) You must limit BTEX emissions seeking to assert an affirmative defense take further action as required by the from each small glycol dehydration shall also submit a written report to the applicable provisions of this subpart. unit, as defined in § 63.1271, to the limit Administrator within 45 days of the (h) At all times the owner or operator determined in Equation 1 of this initial occurrence of the exceedance of must operate and maintain any affected section. The limit must be met in the standard in this subpart to source, including associated air accordance with one of the alternatives demonstrate, with all necessary pollution control equipment and specified in paragraphs (b)(i)(iii)(A) supporting documentation, that it has monitoring equipment, in a manner through (D) of this section.

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Where: level less than the limit calculated in (i) Each control device used to comply ELBTEX = Unit-specific BTEX emission limit, paragraph (b)(1)(iii) of this section. with this subpart shall be operating at megagrams per year; 28. Section 63.1281 is amended by: all times when gases, vapors, and fumes ¥ 6.42 × 10 5 = BTEX emission limit, grams a. Revising paragraph (c)(1); are vented from the emissions unit or BTEX/standard cubic meter -ppmv; b. Revising the heading of paragraph units through the closed vent system to Throughput = Annual average daily natural (d). gas throughput, standard cubic meters the control device as required under per day c. Adding paragraph (d) introductory § 63.1275. An owner or operator may Ci,BTEX = BTEX concentration of the natural text; vent more than one unit to a control gas at the inlet to the glycol dehydration d. Revising paragraph (d)(1)(i) device used to comply with this unit, ppmv. introductory text; subpart. (A) Connect the process vent to a e. Revising paragraph (d)(1)(i)(C); * * * * * control device or combination of control f. Revising paragraphs (d)(1)(ii) and (5) * * * devices through a closed-vent system. (iii); (i) Following the initial startup of the The closed vent system shall be g. Revising paragraph (d)(4)(i); control device, all carbon in the control designed and operated in accordance h. Revising paragraph (d)(5)(i); device shall be replaced with fresh with the requirements of § 63.1281(c). i. Revising paragraph (e)(2); carbon on a regular, predetermined time The control device(s) shall be designed j. Revising paragraph (e)(3) interval that is no longer than the and operated in accordance with the introductory text; carbon service life established for the requirements of § 63.1281(f). k. Revising paragraph (e)(3)(ii); and carbon adsorption system. Records (B) Meet the emissions limit through l. Adding paragraph (f) to read as identifying the schedule for replacement process modifications in accordance follows: and records of each carbon replacement with the requirements specified in § 63.1281 Control equipment shall be maintained as required in § 63.1281(e). requirements. § 63.1284(b)(7)(ix). The schedule for (C) Meet the emission limit for each replacement shall be submitted with the small glycol dehydration unit using a * * * * * (c) * * * Notification of Compliance Status combination of process modifications Report as specified in and one or more control devices through (1) The closed-vent system shall route all gases, vapors, and fumes emitted § 63.1285(d)(4)(iv). Each carbon the requirements specified in replacement must be reported in the paragraphs (b)(1)(iii)(A) and (B) of this from the material in an emissions unit to a control device that meets the Periodic Reports as specified in section. § 63.1285(e)(2)(xi). (D) Demonstrate that the emissions requirements specified in paragraph (d) * * * * * limit is met through actual uncontrolled of this section. * * * * * (e) * * * operation of the small glycol (2) The owner or operator shall dehydration unit. Document operational (d) Control device requirements for document, to the Administrator’s parameters in accordance with the sources except small glycol dehydration satisfaction, the conditions for which requirements specified in § 63.1281(e) units. Owners and operators of small glycol dehydration unit baseline and emissions in accordance with the glycol dehydration units shall comply operations shall be modified to achieve requirements specified in with the control requirements in the 95.0 percent overall HAP emission § 63.1282(a)(3). paragraph (f) of this section. reduction, or BTEX limit determined in * * * * * (1) * * * (i) An enclosed combustion device § 63.1275(b)(1)(iii), as applicable, either (c) * * * through process modifications or (2) The owner or operator shall (e.g., thermal vapor incinerator, catalytic through a combination of process demonstrate, to the Administrator’s vapor incinerator, boiler, or process modifications and one or more control satisfaction, that the total HAP heater) that is designed and operated in devices. If a combination of process emissions to the atmosphere from the accordance with one of the following modifications and one or more control large glycol dehydration unit process performance requirements: devices are used, the owner or operator vent are reduced by 95.0 percent * * * * * shall also establish the emission through process modifications or a (C) For a control device that can combination of process modifications reduction to be achieved by the control demonstrate a uniform combustion zone device to achieve an overall HAP and one or more control devices, in temperature during the performance test accordance with the requirements emission reduction of 95.0 percent for conducted under § 63.1282(d), operates the glycol dehydration unit process vent specified in § 63.1281(e). at a minimum temperature of 760 °C. (3) Control of HAP emissions from a or, if applicable, the BTEX limit * * * * * GCG separator (flash tank) vent is not determined in § 63.1275(b)(1)(iii) for the (ii) A vapor recovery device (e.g., required if the owner or operator small glycol dehydration unit process carbon adsorption system or condenser) demonstrates, to the Administrator’s vent. Only modifications in glycol or other non-destructive control device satisfaction, that total emissions to the dehydration unit operations directly that is designed and operated to reduce atmosphere from the glycol dehydration related to process changes, including the mass content of either TOC or total unit process vent are reduced by one of but not limited to changes in glycol HAP in the gases vented to the device the levels specified in paragraph (c)(3)(i) circulation rate or glycol-HAP by 95.0 percent by weight or greater as or (iii) through the installation and absorbency, shall be allowed. Changes determined in accordance with the operation of controls as specified in in the inlet gas characteristics or natural requirements of § 63.1282(d). paragraph (b)(1) of this section. gas throughput rate shall not be (i) For any large glycol dehydration (iii) A flare, as defined in § 63.1271, considered in determining the overall unit, HAP emissions are reduced by that is designed and operated in emission reduction due to process 95.0 percent or more. accordance with the requirements of modifications. (ii) [Reserved] § 63.11(b). (3) The owner or operator that (iii) For each small glycol dehydration * * * * * achieves a 95.0 percent HAP emission unit, BTEX emissions are reduced to a (4) * * * reduction or meets the BTEX limit

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determined in § 63.1275(b)(1)(iii), as the requirements of either § 63.1282(e) (i) The owner or operator shall applicable, using process modifications or (h). determine actual average benzene or alone shall comply with paragraph (3) For each carbon adsorption system BTEX emissions using the model GRI– (e)(3)(i) of this section. The owner or used as a control device to meet the GLYCalcTM, Version 3.0 or higher, and operator that achieves a 95.0 percent requirements of paragraph (f)(1) of this the procedures presented in the HAP emission reduction or meets the section, the owner or operator shall associated GRI–GLYCalcTM Technical BTEX limit determined in manage the carbon as required under Reference Manual. Inputs to the model § 63.1275(b)(1)(iii), as applicable, using (d)(5)(i) and (ii) of this section. shall be representative of actual a combination of process modifications 29. Section 63.1282 is amended by: operating conditions of the glycol and one or more control devices shall a. Revising paragraph (a) introductory dehydration unit and may be comply with paragraphs (e)(3)(i) and text; determined using the procedures (e)(3)(ii) of this section. b. Revising paragraph (a)(1)(ii); documented in the Gas Research c. Revising paragraph (a)(2); * * * * * Institute (GRI) report entitled d. Adding paragraph (c); ‘‘Atmospheric Rich/Lean Method for (ii) The owner or operator shall e. Revising paragraph (d) introductory comply with the control device Determining Glycol Dehydrator text; Emissions’’ (GRI–95/0368.1); or requirements specified in paragraph (d) f. Revising paragraphs (d)(1)(i) or (f) of this section, as applicable, (ii) The owner or operator shall through (v); determine an average mass rate of except that the emission reduction or g. Revising paragraph (d)(2); limit achieved shall be the emission benzene or BTEX emissions in h. Revising paragraph (d)(3) kilograms per hour through direct reduction or limit specified for the introductory text; measurement by performing three runs control device(s) in paragraph (e)(2) of i. Revising paragraph (d)(3)(i)(B); of Method 18 in 40 CFR part 60, this section. j. Revising paragraph (d)(3)(iv)(C)(1); appendix A (or an equivalent method), (f) Control device requirements for k. Adding paragraphs (d)(3)(v) and and averaging the results of the three small glycol dehydration units. (1) The (vi); runs. Annual emissions in kilograms per control device used to meet BTEX the l. Revising paragraph (d)(4) year shall be determined by multiplying emission limit calculated in introductory text; the mass rate by the number of hours § 63.1275(b)(1)(iii) shall be one of the m. Revising paragraph (d)(4)(i); the unit is operated per year. This result control devices specified in paragraphs n. Revising paragraph (d)(5); shall be converted to megagrams per o. Revising paragraph (e) introductory (f)(1)(i) through (iii) of this section. year. (i) An enclosed combustion device text; (e.g., thermal vapor incinerator, catalytic p. Revising paragraphs (e)(2) and * * * * * (c) Test procedures and compliance vapor incinerator, boiler, or process (e)(3); demonstrations for small glycol heater) that is designed and operated to q. Adding paragraphs (e)(4) through dehydration units. This paragraph reduce the mass content of BTEX in the (e)(6); applies to the test procedures for small gases vented to the device as r. Revising paragraph (f) introductory dehydration units. determined in accordance with the text; s. Revising paragraph (f)(1); (1) If the owner or operator is using requirements of § 63.1282(d). If a boiler a control device to comply with the or process heater is used as the control t. Revising paragraph (f)(2) introductory text; emission limit in § 63.1275(b)(1)(iii), the device, then the vent stream shall be requirements of paragraph (d) of this introduced into the flame zone of the u. Revising paragraph (f)(2)(iii); v. Revising paragraph (f)(3); and section apply. Compliance is boiler or process heater; or demonstrated using the methods (ii) A vapor recovery device (e.g., w. Adding paragraphs (g) and (h) to read as follows: specified in paragraph (e) of this carbon adsorption system or condenser) section. or other non-destructive control device § 63.1282 Test methods, compliance (2) If no control device is used to that is designed and operated to reduce procedures, and compliance comply with the emission limit in the mass content of BTEX in the gases demonstrations. § 63.1275(b)(1)(iii), the owner or vented to the device as determined in (a) Determination of glycol operator must determine the glycol accordance with the requirements of dehydration unit flowrate, benzene dehydration unit BTEX emissions as § 63.1282(d); or emissions, or BTEX emissions. The specified in paragraphs (c)(2)(i) through (iii) A flare, as defined in § 63.1271, procedures of this paragraph shall be (iii) of this section. Compliance is that is designed and operated in used by an owner or operator to demonstrated if the BTEX emissions accordance with the requirements of determine glycol dehydration unit determined as specified in paragraphs § 63.11(b). natural gas flowrate, benzene emissions, (c)(2)(i) through (iii) are less than the (2) The owner or operator shall or BTEX emissions. emission limit calculated using the operate each control device in (1) * * * equation in § 63.1275(b)(1)(iii). accordance with the requirements (ii) The owner or operator shall (i) Method 1 or 1A, 40 CFR part 60, specified in paragraphs (f)(2)(i) and (ii) document, to the Administrator’s appendix A, as appropriate, shall be of this section. satisfaction, the actual annual average used for selection of the sampling sites (i) Each control device used to comply natural gas flowrate to the glycol at the outlet of the glycol dehydration with this subpart shall be operating at dehydration unit. unit process vent. Any references to all times. An owner or operator may (2) The determination of actual particulate mentioned in Methods 1 and vent more than one unit to a control average benzene or BTEX emissions 1A do not apply to this section. device used to comply with this from a glycol dehydration unit shall be (ii) The gas volumetric flowrate shall subpart. made using the procedures of either be determined using Method 2, 2A, 2C, (ii) For each control device monitored paragraph (a)(2)(i) or (a)(2)(ii) of this or 2D, 40 CFR part 60, appendix A, as in accordance with the requirements of section. Emissions shall be determined appropriate. § 63.1283(d), the owner or operator shall either uncontrolled or with federally (iii) The BTEX emissions from the demonstrate compliance according to enforceable controls in place. outlet of the glycol dehydration unit

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process vent shall be determined using (iv) Except for control devices used Method 18, 40 CFR part 60, appendix A; the procedures specified in paragraph for small glycol dehydration units, a ASTM D6420–99 (2004), as specified in (d)(3)(v) of this section. As an boiler or process heater burning § 63.772(a)(1)(ii); or any other method or alternative, the mass rate of BTEX at the hazardous waste for which the owner or data that have been validated according outlet of the glycol dehydration unit operator has either been issued a final to the applicable procedures in Method process vent may be calculated using permit under 40 CFR part 270 and 301, 40 CFR part 63, appendix A. The the model GRI–GLYCalcTM, Version 3.0 complies with the requirements of 40 following procedures shall be used to or higher, and the procedures presented CFR part 266, subpart H, or has certified calculate BTEX emissions: in the associated GRI–GLYCalcTM compliance with the interim status (A) The minimum sampling time for Technical Reference Manual. Inputs to requirements of 40 CFR part 266, each run shall be 1 hour in which either the model shall be representative of subpart H; an integrated sample or a minimum of actual operating conditions of the glycol (v) Except for control devices used for four grab samples shall be taken. If grab dehydration unit and shall be small glycol dehydration units, a sampling is used, then the samples shall determined using the procedures hazardous waste incinerator for which be taken at approximately equal documented in the Gas Research the owner or operator has been issued intervals in time, such as 15-minute Institute (GRI) report entitled a final permit under 40 CFR part 270 intervals during the run. ‘‘Atmospheric Rich/Lean Method for and complies with the requirements of (B) The mass rate of BTEX (Eo) shall Determining Glycol Dehydrator 40 CFR part 264, subpart O, or has be computed using the equations and Emissions’’ (GRI–95/0368.1). When the certified compliance with the interim procedures specified in paragraphs BTEX mass rate is calculated for glycol status requirements of 40 CFR part 265, (d)(3)(v)(B)(1) and (2) of this section. dehydration units using the model GRI– subpart O. (1) The following equation shall be GLYCalcTM, all BTEX measured by * * * * * used: Method 18, 40 CFR part 60, appendix A, (2) An owner or operator shall design shall be summed. and operate each flare, as defined in (d) Control device performance test § 63.1271, in accordance with the procedures. This paragraph applies to requirements specified in § 63.11(b) and the performance testing of control the compliance determination shall be Where: devices. The owners or operators shall conducted using Method 22 of 40 CFR Eo = Mass rate of BTEX at the outlet of the demonstrate that a control device part 60, appendix A, to determine control device, dry basis, kilogram per achieves the performance requirements visible emissions. hour. of § 63.1281(d)(1), (e)(3)(ii), or (f)(1) (3) For a performance test conducted Coj = Concentration of sample component j of using a performance test as specified in to demonstrate that a control device the gas stream at the outlet of the control device, dry basis, parts per million by paragraph (d)(3) of this section. Owners meets the requirements of volume. or operators using a condenser have the § 63.1281(d)(1), (e)(3)(ii), or (f)(1) the Moj = Molecular weight of sample component option to use a design analysis as owner or operator shall use the test j of the gas stream at the outlet of the specified in paragraph (d)(4) of this methods and procedures specified in control device, gram/gram-mole. section. The owner or operator may paragraphs (d)(3)(i) through (v) of this Qo = Flowrate of gas stream at the outlet of elect to use the alternative procedures in section. The initial and periodic the control device, dry standard cubic paragraph (d)(5) of this section for performance tests shall be conducted meter per minute. × ¥6 performance testing of a condenser used according to the schedule specified in K2 = Constant, 2.494 10 (parts per million) (gram-mole per standard cubic to control emissions from a glycol paragraph (d)(3)(vi) of this section. meter) (kilogram/gram) (minute/hour), dehydration unit process vent. As an (i) * * * where standard temperature (gram-mole alternative to conducting a performance (B) To determine compliance with the per standard cubic meter) is 20 degrees test under this section for combustion enclosed combustion device total HAP C. control devices, a control device that concentration limit specified in n = Number of components in sample. can be demonstrated to meet the § 63.1281(d)(1)(i)(B), or the BTEX (2) When the BTEX mass rate is performance requirements of emission limit specified in calculated, only BTEX compounds § 63.1281(d)(1), (e)(3)(ii), or (f)(1) § 63.1275(b)(1)(iii), the sampling site measured by Method 18, 40 CFR part through a performance test conducted shall be located at the outlet of the 60, appendix A, or ASTM D6420–99 by the manufacturer, as specified in combustion device. (2004) as specified in § 63.772(a)(1)(ii), paragraph (g) of this section, can be * * * * * shall be summed using the equations in used. (iv) * * * paragraph (d)(3)(v)(B)(1) of this section. (1) * * * (C) * * * (vi) The owner or operator shall (i) Except as specified in paragraph (1) The emission rate correction factor conduct performance tests according to (d)(2) of this section, a flare, as defined for excess air, integrated sampling and the schedule specified in paragraphs in § 63.1271, that is designed and analysis procedures of Method 3A or (d)(3)(vi)(A) and (B) of this section. operated in accordance with § 63.11(b); 3B, 40 CFR part 60, appendix A, shall (A) An initial performance test shall (ii) Except for control devices used for be used to determine the oxygen be conducted within 180 days after the small glycol dehydration units, a boiler concentration (%O2d). The samples shall compliance date that is specified for or process heater with a design heat be taken during the same time that the each affected source in § 63.1270(d)(3) input capacity of 44 megawatts or samples are taken for determining TOC and (4) except that the initial greater; concentration or total HAP performance test for existing (iii) Except for control devices used concentration. combustion control devices at existing for small glycol dehydration units, a * * * * * major sources shall be conducted no boiler or process heater into which the (v) To determine compliance with the later than 3 years after the date of vent stream is introduced with the BTEX emission limit specified in publication of the final rule in the primary fuel or is used as the primary § 63.1281(f)(1) the owner or operator Federal Register. If the owner or fuel; shall use one of the following methods: operator of an existing combustion

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control device at an existing major As an alternative to the condenser assurance or quality control activities source chooses to replace such device design analysis, an owner or operator (including, as applicable, system with a control device whose model is may elect to use the procedures accuracy audits and required zero and tested under § 63.1282(g), then the specified in paragraph (d)(5) of this span adjustments), the CMS required in newly installed device shall comply section. § 63.1283(d) must be operated at all with all provisions of this subpart no * * * * * times the affected source is operating. A later than 3 years after the date of (5) As an alternative to the procedures monitoring system malfunction is any publication of the final rule in the in paragraph (d)(4)(i) of this section, an sudden, infrequent, not reasonably Federal Register. The performance test owner or operator may elect to use the preventable failure of the monitoring results shall be submitted in the procedures documented in the GRI system to provide valid data. Notification of Compliance Status report entitled, ‘‘Atmospheric Rich/Lean Monitoring system failures that are Report as required in § 63.1285(d)(1)(ii). Method for Determining Glycol caused in part by poor maintenance or (B) Periodic performance tests shall be Dehydrator Emissions,’’ (GRI–95/ careless operation are not malfunctions. conducted for all control devices 0368.1) as inputs for the model GRI– Monitoring system repairs are required required to conduct initial performance GLYCalcTM, Version 3.0 or higher, to to be completed in response to tests except as specified in paragraphs generate a condenser performance monitoring system malfunctions and to (e)(3)(vi)(B)(1) and (2) of this section. curve. return the monitoring system to The first periodic performance test shall (e) Compliance demonstration for operation as expeditiously as be conducted no later than 60 months control devices performance practicable. after the initial performance test requirements. This paragraph applies to (5) Data recorded during monitoring required in paragraph (d)(3)(vi)(A) of the demonstration of compliance with system malfunctions, repairs associated this section. Subsequent periodic the control device performance with monitoring system malfunctions, performance tests shall be conducted at requirements specified in or required monitoring system quality intervals no longer than 60 months § 63.1281(d)(1), (e)(3)(ii), and (f)(1). assurance or control activities may not following the previous periodic Compliance shall be demonstrated using be used in calculations used to report performance test or whenever a source the requirements in paragraphs (e)(1) emissions or operating levels. All the desires to establish a new operating through (3) of this section. As an data collected during all other required limit. The periodic performance test alternative, an owner or operator that data collection periods must be used in results must be submitted in the next installs a condenser as the control assessing the operation of the control Periodic Report as specified in device to achieve the requirements device and associated control system. § 63.1285(e)(2)(x). Combustion control specified in § 63.1281(d)(1)(ii), (e)(3)(ii), (6) Except for periods of monitoring devices meeting the criteria in either or (f)(1) may demonstrate compliance system malfunctions, repairs associated paragraph (e)(3)(vi)(B)(1) or (2) of this according to paragraph (f) of this with monitoring system malfunctions, section are not required to conduct section. An owner or operator may and required quality monitoring system periodic performance tests. switch between compliance with quality assurance or quality control (1) A control device whose model is paragraph (e) of this section and activities (including, as applicable, tested under, and meets the criteria of, compliance with paragraph (f) of this system accuracy audits and required § 63.1282(g), or section only after at least 1 year of zero and span adjustments), failure to (2) A combustion control device operation in compliance with the collect required data is a deviation of tested under § 63.1282(d) that meets the selected approach. Notification of such the monitoring requirements. outlet TOC or HAP performance level a change in the compliance method (f) Compliance demonstration with specified in § 63.1281(d)(1)(i)(B) and shall be reported in the next Periodic percent reduction or emission limit that establishes a correlation between Report, as required in § 63.1285(e), performance requirements—condensers. firebox or combustion chamber following the change. This paragraph applies to the temperature and the TOC or HAP * * * * * demonstration of compliance with the performance level. (2) The owner or operator shall performance requirements specified in * * * * * calculate the daily average of the § 63.1281(d)(1)(ii), (e)(3) or (f)(1) for (4) For a condenser design analysis applicable monitored parameter in condensers. Compliance shall be conducted to meet the requirements of accordance with § 63.1283(d)(4) except demonstrated using the procedures in § 63.1281(d)(1), (e)(3)(ii), or (f)(1), the that the inlet gas flowrate to the control paragraphs (f)(1) through (f)(3) of this owner or operator shall meet the device shall not be averaged. section. requirements specified in paragraphs (3) Compliance is achieved when the (1) The owner or operator shall (d)(4)(i) and (d)(4)(ii) of this section. daily average of the monitoring establish a site-specific condenser Documentation of the design analysis parameter value calculated under performance curve according to the shall be submitted as a part of the paragraph (e)(2) of this section is either procedures specified in Notification of Compliance Status equal to or greater than the minimum or § 63.1283(d)(5)(ii). For sources required Report as required in § 63.1285(d)(1)(i). equal to or less than the maximum to meet the BTEX limit in accordance (i) The condenser design analysis monitoring value established under with § 63.1281(e) or (f)(1) the owner or shall include an analysis of the vent paragraph (e)(1) of this section. For inlet operator shall identify the minimum stream composition, constituent gas flowrate, compliance with the percent reduction necessary to meet the concentrations, flowrate, relative operating parameter limit is achieved BTEX limit. humidity, and temperature, and shall when the value is equal to or less than (2) Compliance with the percent establish the design outlet organic the value established under reduction requirement in compound concentration level, design § 63.1282(g). § 63.1281(d)(1)(ii), (e)(3), or (f)(1) shall average temperature of the condenser (4) Except for periods of monitoring be demonstrated by the procedures in exhaust vent stream, and the design system malfunctions, repairs associated paragraphs (f)(2)(i) through (iii) of this average temperatures of the coolant with monitoring system malfunctions, section. fluid at the condenser inlet and outlet. and required monitoring system quality * * * * *

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(iii) Except as provided in paragraphs (g) Performance testing for with the test report in accordance with (f)(2)(iii)(A), (B), and (D) of this section, combustion control devices— paragraph (g)(8)(iii) of this section. at the end of each operating day the manufacturers’ performance test. (1) (4) Inlet testing shall be conducted as owner or operator shall calculate the 30- This paragraph applies to the specified in paragraphs (g)(4)(i) through day average HAP, or BTEX, emission performance testing of a combustion (iii) of this section. reduction, as appropriate, from the control device conducted by the device (i) The fuel flow metering system condenser efficiencies as determined in manufacturer. The manufacturer shall shall be located in accordance with paragraph (f)(2)(ii) of this section for the demonstrate that a specific model of Method 2A, 40 CFR part 60, appendix preceding 30 operating days. If the control device achieves the performance A–1, (or other approved procedure) to owner or operator uses a combination of requirements in (g)(7) of this section by measure fuel flow rate at the control process modifications and a condenser conducting a performance test as device inlet location. The fitting for in accordance with the requirements of specified in paragraphs (g)(2) through filling fuel sample containers shall be § 63.1281(e), the 30-day average HAP (6) of this section. located a minimum of 8 pipe diameters emission, or BTEX, emission reduction, (2) Performance testing shall consist upstream of any inlet fuel flow shall be calculated using the emission of three one-hour (or longer) test runs monitoring meter. reduction achieved through process for each of the four following firing rate (ii) Inlet flow rate shall be determined modifications and the condenser settings making a total of 12 test runs using Method 2A, 40 CFR part 60, efficiency as determined in paragraph per test. Propene (propylene) gas shall appendix A–1. Record the start and stop (f)(2)(ii) of this section, both for the be used for the testing fuel. All fuel reading for each 60-minute THC test. preceding 30 operating days. analyses shall be performed by an Record the gas pressure and temperature (A) After the compliance date independent third-party laboratory (not at 5-minute intervals throughout each specified in § 63.1270(d), an owner or affiliated with the control device 60-minute THC test. operator of a facility that stores natural manufacturer or fuel supplier). (iii) Inlet fuel sampling shall be gas that has less than 30 days of data for (i) 90–100 percent of maximum conducted in accordance with the determining the average HAP, or BTEX, design rate (fixed rate). criteria in paragraphs (g)(4)(iii)(A) and emission reduction, as appropriate, (ii) 70–100–70 percent (ramp up, (B) of this section. shall calculate the cumulative average at ramp down). Begin the test at 70 percent (A) At the inlet fuel sampling the end of the withdrawal season, each of the maximum design rate. Within the location, securely connect a Silonite- season, until 30 days of condenser first 5 minutes, ramp the firing rate to coated stainless steel evacuated canister operating data are accumulated. For a 100 percent of the maximum design fitted with a flow controller sufficient to facility that does not store natural gas, rate. Hold at 100 percent for 5 minutes. fill the canister over a 1 hour period. the owner or operator that has less than In the 10–15 minute time range, ramp Filling shall be conducted as specified 30 days of data for determining average back down to 70 percent of the in the following: HAP, or BTEX, emission reduction, as maximum design rate. Repeat three (1) Open the canister sampling valve appropriate, shall calculate the more times for a total of 60 minutes of at the beginning of the total cumulative average at the end of the sampling. hydrocarbon (THC) test, and close the calendar year, each year, until 30 days (iii) 30–70–30 percent (ramp up, ramp canister at the end of the THC test. (2) Fill one canister for each THC test of condenser operating data are down). Begin the test at 30 percent of run. accumulated. the maximum design rate. Within the (3) Label the canisters individually (B) After the compliance date first 5 minutes, ramp the firing rate to and record on a chain of custody form. specified in § 63.1270(d), for an owner 70 percent of the maximum design rate. or operator that has less than 30 days of (B) Each fuel sample shall be analyzed Hold at 70 percent for 5 minutes. In the using the following methods. The data for determining the average HAP, 10–15 minute time range, ramp back or BTEX, emission reduction, as results shall be included in the test down to 30 percent of the maximum report. appropriate, compliance is achieved if design rate. Repeat three more times for the average HAP, or BTEX, emission (1) Hydrocarbon compounds a total of 60 minutes of sampling. containing between one and five atoms reduction, as appropriate, calculated in (iv) 0–30–0 percent (ramp up, ramp paragraph (f)(2)(iii)(A) of this section is of carbon plus benzene using ASTM down). Begin the test at 0 percent of the D1945–03. equal to or greater than 95.0 percent. maximum design rate. Within the first 5 (2) Hydrogen (H2), carbon monoxide * * * * * minutes, ramp the firing rate to 100 (CO), carbon dioxide (CO2), nitrogen (3) Compliance is achieved based on percent of the maximum design rate. (N2), oxygen (O2) using ASTM D1945– the applicable criteria in paragraphs Hold at 30 percent for 5 minutes. In the 03. (f)(3)(i) or (ii) of this section. 10–15 minute time range, ramp back (3) Carbonyl sulfide, carbon disulfide (i) For sources meeting the HAP down to 0 percent of the maximum plus mercaptans using ASTM D5504. emission reduction specified in design rate. Repeat three more times for (4) Higher heating value using ASTM § 63.1281(d)(1)(ii) or (e)(3) if the average a total of 60 minutes of sampling. D3588–98 or ASTM D4891–89. HAP emission reduction calculated in (3) All models employing multiple (5) Outlet testing shall be conducted paragraph (f)(2)(iii) of this section is enclosures shall be tested in accordance with the criteria in equal to or greater than 95.0 percent. simultaneously and with all burners paragraphs (g)(5)(i) through (v) of this (ii) For sources required to meet the operational. Results shall be reported for section. BTEX limit under § 63.1281(e)(3) or the each enclosure individually and for (i) Sampling and flowrate measured in (f)(1), compliance is achieved if the the average of the emissions from all accordance with the following: average BTEX emission reduction interconnected combustion enclosures/ (A) The outlet sampling location shall calculated in paragraph (f)(2)(iii) of this chambers. Control device operating data be a minimum of 4 equivalent stack section is equal to or greater than the shall be collected continuously diameters downstream from the highest minimum percent reduction identified throughout the performance test using peak flame or any other flow in paragraph (f)(1) of this section. an electronic Data Acquisition System disturbance, and a minimum of one * * * * * and strip chart. Data shall be submitted equivalent stack diameter upstream of

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the exit or any other flow disturbance. testing. An instrument range of 0–10 per shall not be exceeded for each control A minimum of two sample ports shall million by volume-dry (ppmvd) shall be device model to achieve the criteria in be used. used. paragraph (g)(7)(i) of this section. (B) Flow rate shall be measured using (v) Visible emissions shall be (iii) A control device meeting the Method 1, 40 CFR part 60, Appendix 1, determined using Method 22, 40 CFR criteria in paragraph (g)(7)(i)(A) through for determining flow measurement part 60, Appendix A. The test shall be (C) of this section will have traverse point location; and Method 2, performed continuously during each demonstrated a destruction efficiency of 40 CFR part 60, Appendix 1, shall be test run. A digital color photograph of 98.0 percent for HAP regulated under used to measure duct velocity. If low the exhaust point, taken from the this subpart. flow conditions are encountered (i.e., position of the observer and annotated (8) The owner or operator of a velocity pressure differentials less than with date and time, will be taken once combustion control device model tested 0.05 inches of water) during the per test run and the four photos under this section shall submit the performance test, a more sensitive included in the test report. information listed in paragraphs (g)(8)(i) manometer shall be used to obtain an (6) Total hydrocarbons (THC) shall be through (iii) in the test report required accurate flow profile. determined as specified by the under § 63.775(d)(1)(iii). (ii) Molecular weight shall be following criteria: (i) Full schematic of the control determined as specified in paragraphs (i) Conduct THC sampling using device and dimensions of the device (g)(4)(iii)(B), and (g)(5)(ii)(A) and (B) of Method 25A, 40 CFR part 60, Appendix components. this section. A, except the option for locating the (ii) Design net heating value (A) An integrated bag sample shall be probe in the center 10 percent of the (minimum and maximum) of the device. collected during the Method 4, 40 CFR stack shall not be allowed. The THC (iii) Test fuel gas flow range (in both part 60, Appendix A, moisture test. probe must be traversed to 16.7 percent, mass and volume). Include the Analyze the bag sample using a gas 50 percent, and 83.3 percent of the stack minimum and maximum allowable inlet chromatograph-thermal conductivity diameter during the testing. gas flow rate. detector (GC–TCD) analysis meeting the (ii) A valid test shall consist of three (iv) Air/stream injection/assist ranges, following criteria: Method 25A, 40 CFR part 60, Appendix if used. (1) Collect the integrated sample A, tests, each no less than 60 minutes (v) The test parameter ranges listed in throughout the entire test, and collect in duration. paragraphs (g)(8)(v)(A) through (O) of representative volumes from each (iii) A 0–10 parts per million by this section, as applicable for the tested traverse location. volume-wet (ppmvw) (as propane) model. (2) The sampling line shall be purged measurement range is preferred; as an (A) Fuel gas delivery pressure and with stack gas before opening the valve alternative a 0–30 ppmvw (as carbon) temperature. and beginning to fill the bag. measurement range may be used. (B) Fuel gas moisture range. (3) The bag contents shall be kneaded (iv) Calibration gases will be propane (C) Purge gas usage range. or otherwise vigorously mixed prior to in air and be certified through EPA (D) Condensate (liquid fuel) the GC analysis. Protocol 1—‘‘EPA Traceability Protocol separation range. (4) The GC–TCD calibration for Assay and Certification of Gaseous (E) Combustion zone temperature procedure in Method 3C, 40 CFR part Calibration Standards,’’ September range. This is required for all devices 60, Appendix A, shall be modified by 1997, as amended August 25, 1999, that measure this parameter. using EPAAlt-045 as follows: For the EPA–600/R–97/121 (or more recent if (F) Excess combustion air range. initial calibration, triplicate injections of updated since 1999). (G) Flame arrestor(s). any single concentration must agree (v) THC measurements shall be (H) Burner manifold pressure. within 5 percent of their mean to be reported in terms of ppmvw as propane. (I) Pilot flame sensor. valid. The calibration response factor for (vi) THC results shall be corrected to (J) Pilot flame design fuel and fuel a single concentration re-check must be 3 percent CO2, as measured by Method usage. within 10 percent of the original 3C, 40 CFR part 60, Appendix A. (K) Tip velocity range. calibration response factor for that (vii) Subtraction of methane/ethane (L) Momentum flux ratio. concentration. If this criterion is not from the THC data is not allowed in (M) Exit temperature range. met, the initial calibration using at least determining results. (N) Exit flow rate. three concentration levels shall be (7) Performance test criteria: (O) Wind velocity and direction. repeated. (i) The control device model tested (vi) The test report shall include all (B) Report the molecular weight of: must meet the criteria in paragraphs calibration quality assurance/quality O2, CO2, methane (CH4), and N2 and (g)(7)(i)(A) through (C) of this section: control data, calibration gas values, gas include in the test report submitted (A) Method 22, 40 CFR part 60, cylinder certification, and strip charts under § 63.775(d)(iii). Moisture shall be Appendix A, results under paragraph annotated with test times and determined using Method 4, 40 CFR (g)(5)(v) of this section with no calibration values. part 60, Appendix A. Traverse both indication of visible emissions, and (h) Compliance demonstration for ports with the Method 4, 40 CFR part (B) Average Method 25A, 40 CFR part combustion control devices— 60, Appendix A, sampling train during 60, Appendix A, results under manufacturers’ performance test. This each test run. Ambient air shall not be paragraph (g)(6) of this section equal to paragraph applies to the demonstration introduced into the Method 3C, 40 CFR or less than 10.0 ppmvw THC as of compliance for a combustion control part 60, Appendix A, integrated bag propane corrected to 3.0 percent CO2, device tested under the provisions in sample during the port change. and paragraph (g) of this section. Owners or (iv) Carbon monoxide shall be (C) Average CO emissions determined operators shall demonstrate that a determined using Method 10, 40 CFR under paragraph (g)(5)(iv) of this section control device achieves the performance part 60, Appendix A. The test shall be equal to or less than 10 parts ppmvd, requirements of § 63.1281(d)(1), (e)(3)(ii) run at the same time and with the corrected to 3.0 percent CO2. or (f)(1), by installing a device tested sample points used for the EPA Method (ii) The manufacturer shall determine under paragraph (g) of this section and 25A, 40 CFR part 60, Appendix A, a maximum inlet gas flow rate which complying with the following criteria:

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(1) The inlet gas flow rate shall meet n. Revising paragraph (d)(6)(ii); interface, detector signal analyzer, and the range specified by the manufacturer. o. Adding paragraph (d)(6)(v); data acquisition and calculations; Flow rate shall be measured as specified p. Revising paragraph (d)(8)(i)(A); and (B) Sampling interface (e.g., in § 63.1283(d)(3)(i)(H)(1). q. Revising paragraph (d)(8)(ii) to read thermocouple) location such that the (2) A pilot flame shall be present at all as follows: monitoring system will provide times of operation. The pilot flame shall representative measurements; be monitored in accordance with § 63.1283 Inspection and monitoring (C) Equipment performance checks, § 63.1283(d)(3)(i)(H)(2). requirements. system accuracy audits, or other audit (3) Devices shall be operated with no * * * * * procedures; visible emissions, except for periods not (b) The owner or operator of a control (D) Ongoing operation and to exceed a total of 5 minutes during device whose model was tested under maintenance procedures in accordance any 2 consecutive hours. A visible 63.1282(g) shall develop an inspection with provisions in § 63.8(c)(1) and emissions test using Method 22, 40 CFR and maintenance plan for each control (c)(3); and part 60, Appendix A, shall be performed device. At a minimum, the plan shall (E) Ongoing reporting and monthly. The observation period shall contain the control device recordkeeping procedures in accordance be 2 hours and shall be used according manufacturer’s recommendations for with provisions in § 63.10(c), (e)(1), and to Method 22. ensuring proper operation of the device. (e)(2)(i). (4) Compliance with the operating Semi-annual inspections shall be (iii) The owner or operator must parameter limit is achieved when the conducted for each control device with conduct the CPMS equipment following criteria are met: maintenance and replacement of control performance checks, system accuracy (i) The inlet gas flow rate monitored device components made in accordance audits, or other audit procedures under paragraph (h)(1) of this section is with the plan. specified in the site-specific monitoring equal to or below the maximum * * * * * plan at least once every 12 months. established by the manufacturer; and (d) Control device monitoring (iv) The owner or operator must (ii) The pilot flame is present at all requirements. (1) For each control conduct a performance evaluation of times; and device except as provided for in each CPMS in accordance with the site- (iii) During the visible emissions test paragraph (d)(2) of this section, the specific monitoring plan. performed under paragraph (h)(3) of this owner or operator shall install and (2) * * * section the duration of visible emissions (i) Except for control devices for small operate a continuous parameter does not exceed a total of 5 minutes glycol dehydration units, a boiler or monitoring system in accordance with during the observation period. Devices process heater in which all vent streams the requirements of paragraphs (d)(3) failing the visible emissions test shall are introduced with the primary fuel or through (9) of this section. Owners or follow the requirements in paragraphs are used as the primary fuel; operators that install and operate a flare (h)(4)(iii)(A) and (B) of this section. (ii) Except for control devices for (A) Following the first failure, the fuel in accordance with § 63.1281(d)(1)(iii) small glycol dehydration units, a boiler nozzle(s) and burner tubes shall be or (f)(1)(iii) are exempt from the or process heater with a design heat replaced. requirements of paragraphs (d)(4) and input capacity equal to or greater than (B) If, following replacement of the (5) of this section. The continuous 44 megawatts. fuel nozzle(s) and burner tubes as monitoring system shall be designed (3) * * * specified in paragraph (h)(4)(iii)(A), the and operated so that a determination (i) * * * visible emissions test is not passed in can be made on whether the control (A) For a thermal vapor incinerator the next scheduled test, either a device is achieving the applicable that demonstrates during the performance test shall be performed performance requirements of performance test conducted under under paragraph (d) of this section, or § 63.1281(d), (e)(3), or (f)(1). Each § 63.1282(d) that combustion zone the device shall be replaced with continuous parameter monitoring temperature is an accurate indicator of another control device whose model system shall meet the following performance, a temperature monitoring was tested, and meets, the requirements specifications and requirements: device equipped with a continuous in paragraph (g) of this section. * * * * * recorder. The monitoring device shall 30. Section 63.1283 is amended by: (ii) A site-specific monitoring plan have a minimum accuracy of ± 1 percent a. Adding paragraph (b); must be prepared that addresses the of the temperature being monitored in b. Revising paragraph (d)(1) monitoring system design, data degrees C, or ± 2.5 degrees C, whichever introductory text; collection, and the quality assurance value is greater. The temperature sensor c. Revising paragraph (d)(1)(ii) and and quality control elements outlined in shall be installed at a location adding paragraphs (d)(1)(iii) and (iv); paragraph (d) of this section and in representative of the combustion zone d. Revising paragraph (d)(2)(i) and § 63.8(d). Each CPMS must be installed, temperature. (d)(2)(ii); calibrated, operated, and maintained in (B) For a catalytic vapor incinerator, e. Revising paragraphs (d)(3)(i)(A) and accordance with the procedures in your a temperature monitoring device (B); approved site-specific monitoring plan. equipped with a continuous recorder. f. Revising paragraphs (d)(3)(i)(D) and Using the process described in The device shall be capable of (E); § 63.8(f)(4), you may request approval of monitoring temperatures at two g. Revising paragraphs (d)(3)(i)(F)(1) monitoring system quality assurance locations and have a minimum accuracy and (2); and quality control procedures of ± 1 percent of the temperatures being h. Revising paragraph (d)(3)(i)(G); ± i. Adding paragraph (d)(3)(i)(H); alternative to those specified in monitored in degrees C, or 2.5 degrees j. Revising paragraph (d)(4); paragraphs (d)(1)(ii)(A) through (E) of C, whichever value is greater. One k. Revising paragraph (d)(5)(i); this section in your site-specific temperature sensor shall be installed in l. Revising paragraphs (d)(5)(ii)(A) monitoring plan. the vent stream at the nearest feasible through (C); (A) The performance criteria and point to the catalyst bed inlet and a m. Revising paragraph (d)(6) design specifications for the monitoring second temperature sensor shall be introductory text; system equipment, including the sample installed in the vent stream at the

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nearest feasible point to the catalyst bed (1) A continuous monitoring system (C) If the owner or operator operates outlet. that measures gas flow rate at the inlet a control device where the performance * * * * * to the control device. The monitoring test requirement was met under (D) For a boiler or process heater, a instrument shall have an accuracy of § 63.1282(g) to demonstrate that the temperature monitoring device plus or minus 2 percent or better. control device achieves the applicable equipped with a continuous recorder. (2) A heat sensing monitoring device performance requirements specified in The temperature monitoring device equipped with a continuous recorder § 63.1281(d)(1), (e)(3)(ii) or (f)(1), then shall have a minimum accuracy of ± 1 that indicates the continuous ignition of the maximum inlet gas flow rate shall be percent of the temperature being the pilot flame. established based on the performance monitored in degrees C, or ± 2.5 degrees * * * * * test and supplemented, as necessary, by C, whichever value is greater. The (4) Using the data recorded by the the manufacturer recommendations. temperature sensor shall be installed at monitoring system, except for inlet gas (ii) * * * a location representative of the flowrate, the owner or operator must (A) If the owner or operator conducts combustion zone temperature. calculate the daily average value for a performance test in accordance with (E) For a condenser, a temperature each monitored operating parameter for the requirements of § 63.1282(d)(3) to monitoring device equipped with a each operating day. If the emissions unit demonstrate that the condenser achieves continuous recorder. The temperature operation is continuous, the operating the applicable performance monitoring device shall have a requirements in § 63.1281(d)(1), ± day is a 24-hour period. If the emissions minimum accuracy of 1 percent of the unit operation is not continuous, the (e)(3)(ii), or (f)(1), then the condenser temperature being monitored in degrees performance curve shall be based on ± operating day is the total number of C, or 2.8 degrees C, whichever value hours of control device operation per values measured during the is greater. The temperature sensor shall 24-hour period. Valid data points must performance test and supplemented as be installed at a location in the exhaust be available for 75 percent of the necessary by control device design vent stream from the condenser. operating hours in an operating day to analysis, or control device (F) * * * compute the daily average. manufacturer’s recommendations, or a (1) A continuous parameter (5) * * * combination or both. monitoring system to measure and (i) The owner or operator shall (B) If the owner or operator uses a record the average total regeneration control device design analysis in stream mass flow or volumetric flow establish a minimum operating parameter value or a maximum accordance with the requirements of during each carbon bed regeneration § 63.1282(d)(4)(i) to demonstrate that cycle. The flow sensor must have a operating parameter value, as appropriate for the control device, to the condenser achieves the applicable measurement sensitivity of 5 percent of performance requirements specified in the flow rate or 10 cubic feet per define the conditions at which the control device must be operated to § 63.1281(d)(1), (e)(3)(ii), or (f)(1), then minute, whichever is greater. The the condenser performance curve shall mechanical connections for leakage continuously achieve the applicable performance requirements of be based on the condenser design must be checked at least every month, analysis and may be supplemented by and a visual inspection must be § 63.1281(d)(1), (e)(3)(ii), or (f)(1). Each minimum or maximum operating the control device manufacturer’s performed at least every 3 months of all recommendations. components of the flow CPMS for parameter value shall be established as (C) As an alternative to paragraph physical and operational integrity and follows: (d)(5)(ii)(B) of this section, the owner or all electrical connections for oxidation (A) If the owner or operator conducts operator may elect to use the procedures and galvanic corrosion if your flow performance tests in accordance with documented in the GRI report entitled, CPMS is not equipped with a redundant the requirements of § 63.1282(d)(3) to ‘‘Atmospheric Rich/Lean Method for flow sensor; and demonstrate that the control device (2) A continuous parameter achieves the applicable performance Determining Glycol Dehydrator requirements specified in Emissions’’ (GRI–95/0368.1) as inputs monitoring system to measure and TM record the average carbon bed § 63.1281(d)(1), (e)(3)(ii), or (f)(1), then for the model GRI–GLYCalc , Version temperature for the duration of the the minimum operating parameter value 3.0 or higher, to generate a condenser carbon bed steaming cycle and to or the maximum operating parameter performance curve. measure the actual carbon bed value shall be established based on (6) An excursion for a given control temperature after regeneration and values measured during the device is determined to have occurred within 15 minutes of completing the performance test and supplemented, as when the monitoring data or lack of cooling cycle. The temperature necessary, by a condenser design monitoring data result in any one of the monitoring device shall have a analysis or control device criteria specified in paragraphs (d)(6)(i) minimum accuracy of ± 1 percent of the manufacturer’s recommendations or a through (d)(6)(v) of this section being temperature being monitored in degrees combination of both. met. When multiple operating C, or ± 2.5 degrees C, whichever value (B) If the owner or operator uses a parameters are monitored for the same is greater. condenser design analysis in accordance control device and during the same (G) For a nonregenerative-type carbon with the requirements of § 63.1282(d)(4) operating day, and more than one of adsorption system, the owner or to demonstrate that the control device these operating parameters meets an operator shall monitor the design carbon achieves the applicable performance excursion criterion specified in replacement interval established using a requirements specified in paragraphs (d)(6)(i) through (d)(6)(iv) of performance test performed in § 63.1281(d)(1), (e)(3)(ii), or (f)(1), then this section, then a single excursion is accordance with § 63.1282(d)(3) and the minimum operating parameter value determined to have occurred for the shall be based on the total carbon or the maximum operating parameter control device for that operating day. working capacity of the control device value shall be established based on the * * * * * and source operating schedule. condenser design analysis and may be (ii) For sources meeting (H) For a control device whose model supplemented by the condenser § 63.1281(d)(1)(ii), an excursion occurs is tested under § 63.1282(g): manufacturer’s recommendations. when average condenser efficiency

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calculated according to the (ii) [Reserved] e. Revising paragraph (d)(1)(i); requirements specified in * * * * * f. Revising paragraph (d)(1)(ii) § 63.1282(f)(2)(iii) is less than 95.0 (4) * * * introductory text; percent, as specified in § 63.1282(f)(3). (ii) Records of the daily average value g. Revising paragraph (d)(2) For sources meeting § 63.1281(f)(1), an of each continuously monitored introductory text; excursion occurs when the 30-day parameter for each operating day h. Revising paragraph (d)(4)(ii); average condenser efficiency calculated determined according to the procedures i. Adding paragraph (d)(4)(iv); according to the requirements of specified in § 63.1283(d)(4) of this j. Revising paragraph (d)(10); § 63.1282(f)(2)(iii) is less than the subpart, except as specified in k. Adding paragraphs (d)(11) and identified 30-day required percent paragraphs (b)(4)(ii)(A) through (C) of (d)(12); reduction. this section. l. Revising paragraph (e)(2) introductory text; * * * * * (A) For flares, the records required in (v) For control device whose model is paragraph (e) of this section. m. Revising paragraph (e)(2)(ii)(B); n. Adding paragraphs (e)(2)(ii)(D) and tested under § 63.1282(g) an excursion (B) For condensers installed to (E); occurs when: comply with § 63.1275, records of the (A) The inlet gas flow rate exceeds the annual 30-day rolling average condenser o. Adding paragraphs (e)(2)(x), (xi) maximum established during the test efficiency determined under § 63.1282(f) and (xii); and p. Adding paragraph (g) to read as conducted under § 63.1282(g). shall be kept in addition to the daily (B) Failure of the monthly visible averages. follows: emissions test conducted under (C) For a control device whose model § 63.1285 Reporting requirements. is tested under § 63.1282(g), the records § 63.1282(h)(3) occurs. * * * * * (8) * * * required in paragraph (g) of this section. (b) * * * (i) * * * * * * * * (1) The initial notifications required (A) During a malfunction when the (7) * * * for existing affected sources under affected facility is operated during such (ix) Records identifying the carbon § 63.9(b)(2) shall be submitted as period in accordance with § 63.6(e)(1); replacement schedule under provided in paragraphs (b)(1)(i) and (ii) or § 63.1281(d)(5) and records of each of this section. * * * * * carbon replacement. (i) Except as otherwise provided in (ii) For each control device, or * * * * * paragraph (b)(1)(ii) of this section, the combinations of control devices, (f) The owner or operator of an initial notification shall be submitted by installed on the same emissions unit, affected source subject to this subpart 1 year after an affected source becomes one excused excursion is allowed per shall maintain records of the occurrence subject to the provisions of this subpart semiannual period for any reason. The and duration of each malfunction of or by June 17, 2000, whichever is later. initial semiannual period is the 6-month operation (i.e., process equipment) or Affected sources that are major sources reporting period addressed by the first the air pollution control equipment and on or before June 17, 2000 and plan to Periodic Report submitted by the owner monitoring equipment. The owner or be area sources by June 17, 2002 shall or operator in accordance with operator shall maintain records of include in this notification a brief, § 63.1285(e) of this subpart. actions taken during periods of nonbinding description of a schedule * * * * * malfunction to minimize emissions in for the action(s) that are planned to 31. Section 63.1284 is amended by: accordance with § 63.1274(a), including achieve area source status. a. Revising paragraph (b)(3) corrective actions to restore (ii) An affected source identified introductory text; malfunctioning process and air under § 63.1270(d)(3) shall submit an b. Removing and reserving paragraph pollution control and monitoring initial notification required for existing (b)(3)(ii); equipment to its normal or usual affected sources under § 63.9(b)(2) c. Revising paragraph (b)(4)(ii); manner of operation. d. Adding paragraph (b)(7)(ix); and within 1 year after the affected source (g) Record the following when using becomes subject to the provisions of this e. Adding paragraph (f), (g) and (h) to a control device whose model is tested read as follows: subpart or by one year after publication under § 63.1282(g) to comply with of the final rule in the Federal Register, § 63.1284 Recordkeeping requirements. § 63.1281(d), (e)(3)(ii) and (f)(1): whichever is later. An affected source * * * * * (1) All visible emission readings and identified under § 63.1270(d)(3) that (b) * * * flowrate measurements made during the plans to be an area source by three years (3) Records specified in § 63.10(c) for compliance determination required by after publication of the final rule in the each monitoring system operated by the § 63.1282(h); and Federal Register, shall include in this owner or operator in accordance with (2) All hourly records and other notification a brief, nonbinding the requirements of § 63.1283(d). recorded periods when the pilot flame description of a schedule for the Notwithstanding the previous sentence, is absent. action(s) that are planned to achieve (h) The date the semi-annual monitoring data recorded during area source status. maintenance inspection required under periods identified in paragraphs (b)(3)(i) * * * * * through (iv) of this section shall not be § 63.1283(b) is performed. Include a list of any modifications or repairs made to (6) If there was a malfunction during included in any average or percent leak the reporting period, the Periodic Report rate computed under this subpart. the control device during the inspection and other maintenance performed such specified in paragraph (e) of this section Records shall be kept of the times and shall include the number, duration, and durations of all such periods and any as cleaning of the fuel nozzles. 32. Section 63.1285 is amended by: a brief description for each type of other periods during process or control a. Revising paragraph (b)(1); malfunction which occurred during the device operation when monitors are not b. Revising paragraph (b)(6); reporting period and which caused or operating or failed to collect required c. Removing paragraph (b)(7); may have caused any applicable data. d. Revising paragraph (d)(1) emission limitation to be exceeded. The * * * * * introductory text; report must also include a description of

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actions taken by an owner or operator schedule as required in (xi) For each carbon adsorber used to during a malfunction of an affected § 63.1281(d)(5)(i). meet the control device requirements of source to minimize emissions in * * * * * § 63.1281(d)(1), records of each carbon accordance with § 63.1274(h), including (10) The owner or operator shall replacement that occurred during the actions taken to correct a malfunction. submit the analysis prepared under reporting period. * * * * * § 63.1281(e)(2) to demonstrate that the (xii) For combustion control device (d) * * * conditions by which the facility will be inspections conducted in accordance operated to achieve the HAP emission (1) If a closed-vent system and a with § 63.1283(b) the records specified reduction of 95.0 percent, or the BTEX control device other than a flare are in § 63.1284(h). limit in § 63.1275(b)(1)(iii) through used to comply with § 63.1274, the * * * * * process modifications or a combination owner or operator shall submit the of process modifications and one or (g) Electronic reporting. (1) As of information in paragraph (d)(1)(iii) of more control devices. January 1, 2012, and within 60 days this section and the information in (11) If the owner or operator installs after the date of completing each either paragraph (d)(1)(i) or (ii) of this a combustion control device model performance test, as defined in § 63.2 section. tested under the procedures in and as required in this subpart, you (i) The condenser design analysis § 63.1282(g), the data listed under must submit performance test data, documentation specified in § 63.1282(g)(8). except opacity data, electronically to the § 63.1282(d)(4) of this subpart if the (12) For each combustion control EPA’s Central Data Exchange (CDX) by owner or operator elects to prepare a device model tested under § 63.1282(g), using the Electronic Reporting Tool design analysis; or the information listed in paragraphs (ERT) (see http://www.epa.gov/ttn/chief/ _ (ii) If the owner or operator is (d)(12)(i) through (vi) of this section. ert/ert tool.html/). Only data collected required to conduct a performance test, (i) Name, address and telephone using test methods compatible with ERT the performance test results including number of the control device are subject to this requirement to be the information specified in paragraphs manufacturer. submitted electronically into the EPA’s (d)(1)(ii)(A) and (B) of this section. (ii) Control device model number. WebFIRE database. Results of a performance test conducted (iii) Control device serial number. (2) All reports required by this (iv) Date of control device prior to the compliance date of this subpart not subject to the requirements certification test. in paragraphs (g)(1) of this section must subpart can be used provided that the (v) Manufacturer’s HAP destruction be sent to the Administrator at the test was conducted using the methods efficiency rating. specified in § 63.1282(d)(3), and that the (vi) Control device operating appropriate address listed in § 63.13. If test conditions are representative of parameters, maximum allowable inlet acceptable to both the Administrator current operating conditions. If the gas flowrate. and the owner or operator of a source, owner or operator operates a these reports may be submitted on * * * * * electronic media. The Administrator combustion control device model tested (e) * * * under § 63.1282(g), an electronic copy of (2) The owner or operator shall retains the right to require submittal of the performance test results shall be include the information specified in reports subject to paragraph (g)(1) of this submitted via e-mail to paragraphs (e)(2)(i) through (xii) of this section in paper format. _ _ _ Oil and Gas [email protected]. section, as applicable. 33. Section 63.1287 is amended by * * * * * * * * * * revising paragraph (a) to read as follows: (2) If a closed-vent system and a flare (ii) * * * § 63.1287 Alternative means of emission are used to comply with § 63.1274, the (B) For each excursion caused when limitation. owner or operator shall submit the 30-day average condenser control performance test results including the efficiency is less than the value, as (a) If, in the judgment of the information in paragraphs (d)(2)(i) and specified in § 63.1283(d)(6)(ii), the Administrator, an alternative means of (ii) of this section. The owner or report must include the 30-day average emission limitation will achieve a operator shall also submit the values of the condenser control reduction in HAP emissions at least information in paragraph (d)(2)(iii) of efficiency, and the date and duration of equivalent to the reduction in HAP this section. the period that the excursion occurred. emissions from that source achieved * * * * * under the applicable requirements in * * * * * §§ 63.1274 through 63.1281, the (4) * * * (D) For each excursion caused when the maximum inlet gas flow rate Administrator will publish a notice in (ii) An explanation of the rationale for identified under § 63.1282(g) is the Federal Register permitting the use why the owner or operator selected each exceeded, the report must include the of the alternative means for purposes of of the operating parameter values values of the inlet gas identified and the compliance with that requirement. The established in § 63.1283(d)(5) of this date and duration of the period that the notice may condition the permission on subpart. This explanation shall include excursion occurred. requirements related to the operation any data and calculations used to (E) For each excursion caused when and maintenance of the alternative develop the value, and a description of visible emissions determined under means. why the chosen value indicates that the § 63.1282(h) exceed the maximum * * * * * control device is operating in allowable duration, the report must 34. Appendix to Subpart HHH of Part accordance with the applicable include the date and duration of the 63—Table is amended by revising Table requirements of § 63.1281(d)(1), period that the excursion occurred. 2 to read as follows: (e)(3)(ii), or (f)(1). * * * * * * * * * * (x) The results of any periodic test as Appendix to Subpart HHH of Part 63— (iv) For each carbon adsorber, the required in § 63.1282(d)(3) conducted Tables predetermined carbon replacement during the reporting period. * * * * *

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TABLE 2 TO SUBPART HHH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HHH

Applicable to General provisions reference subpart HHH Explanation

§ 63.1(a)(1) ...... Yes. § 63.1(a)(2) ...... Yes. § 63.1(a)(3) ...... Yes. § 63.1(a)(4) ...... Yes. § 63.1(a)(5) ...... No ...... Section reserved. § 63.1(a)(6) through (a)(8) ...... Yes. § 63.1(a)(9) ...... No ...... Section reserved. § 63.1(a)(10) ...... Yes. § 63.1(a)(11) ...... Yes. § 63.1(a)(12) through (a)(14) ...... Yes. § 63.1(b)(1) ...... No ...... Subpart HHH specifies applicability. § 63.1(b)(2) ...... Yes. § 63.1(b)(3) ...... No. § 63.1(c)(1) ...... No ...... Subpart HHH specifies applicability. § 63.1(c)(2) ...... No. § 63.1(c)(3) ...... No ...... Section reserved. § 63.1(c)(4) ...... Yes. § 63.1(c)(5) ...... Yes. § 63.1(d) ...... No ...... Section reserved. § 63.1(e) ...... Yes. § 63.2 ...... Yes ...... Except definition of major source is unique for this source category and there are additional definitions in subpart HHH. § 63.3(a) through (c) ...... Yes. § 63.4(a)(1) through (a)(3) ...... Yes. § 63.4(a)(4) ...... No ...... Section reserved. § 63.4(a)(5) ...... Yes. § 63.4(b) ...... Yes. § 63.4(c) ...... Yes. § 63.5(a)(1) ...... Yes. § 63.5(a)(2) ...... No ...... Preconstruction review required only for major sources that commence construction after promulgation of the standard. § 63.5(b)(1) ...... Yes. § 63.5(b)(2) ...... No ...... Section reserved. § 63.5(b)(3) ...... Yes. § 63.5(b)(4) ...... Yes. § 63.5(b)(5) ...... Yes. § 63.5(b)(6) ...... Yes. § 63.5(c) ...... No ...... Section reserved. § 63.5(d)(1) ...... Yes. § 63.5(d)(2) ...... Yes. § 63.5(d)(3) ...... Yes. § 63.5(d)(4) ...... Yes. § 63.5(e) ...... Yes. § 63.5(f)(1) ...... Yes. § 63.5(f)(2) ...... Yes. § 63.6(a) ...... Yes. § 63.6(b)(1) ...... Yes. § 63.6(b)(2) ...... Yes. § 63.6(b)(3) ...... Yes. § 63.6(b)(4) ...... Yes. § 63.6(b)(5) ...... Yes. § 63.6(b)(6) ...... No ...... Section reserved. § 63.6(b)(7) ...... Yes. § 63.6(c)(1) ...... Yes. § 63.6(c)(2) ...... Yes. § 63.6(c)(3) and (c)(4) ...... No ...... Section reserved. § 63.6(c)(5) ...... Yes. § 63.6(d) ...... No ...... Section reserved. § 63.6(e) ...... Yes. § 63.6(e) ...... Yes ...... Except as otherwise specified. § 63.6(e)(1)(i) ...... No ...... See § 63.1274(h) for general duty requirement. § 63.6(e)(1)(ii) ...... No. § 63.6(e)(1)(iii) ...... Yes. § 63.6(e)(2) ...... Yes. § 63.6(e)(3) ...... No. § 63.6(f)(1) ...... No. § 63.6(f)(2) ...... Yes. § 63.6(f)(3) ...... Yes. § 63.6(g) ...... Yes. § 63.6(h) ...... No ...... Subpart HHH does not contain opacity or visible emission standards. § 63.6(i)(1) through (i)(14) ...... Yes.

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TABLE 2 TO SUBPART HHH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HHH—Continued

Applicable to General provisions reference subpart HHH Explanation

§ 63.6(i)(15) ...... No ...... Section reserved. § 63.6(i)(16) ...... Yes. § 63.6(j) ...... Yes. § 63.7(a)(1) ...... Yes. § 63.7(a)(2) ...... Yes ...... But the performance test results must be submitted within 180 days after the com- pliance date. § 63.7(a)(3) ...... Yes. § 63.7(b) ...... Yes. § 63.7(c) ...... Yes. § 63.7(d) ...... Yes. § 63.7(e)(1) ...... No. § 63.7(e)(2) ...... Yes. § 63.7(e)(3) ...... Yes. § 63.7(e)(4) ...... Yes. § 63.7(f) ...... Yes. § 63.7(g) ...... Yes. § 63.7(h) ...... Yes. § 63.8(a)(1) ...... Yes. § 63.8(a)(2) ...... Yes. § 63.8(a)(3) ...... No ...... Section reserved. § 63.8(a)(4) ...... Yes. § 63.8(b)(1) ...... Yes. § 63.8(b)(2) ...... Yes. § 63.8(b)(3) ...... Yes. § 63.8(c)(1) ...... Yes. 63.8(c)(1)(i) ...... No. § 63.8(c)(1)(ii) ...... Yes. § 63.8(c)(1)(iii) ...... Pending. § 63.8(c)(2) ...... Yes. § 63.8(c)(3) ...... Yes. § 63.8(c)(4) ...... No. § 63.8(c)(5) through (c)(8) ...... Yes. § 63.8(d) ...... Yes. § 63.8(d)(3) ...... Yes ...... Except for last sentence, which refers to an SSM plan. SSM plans are not required. § 63.8(e) ...... Yes ...... Subpart HHH does not specifically require continuous emissions monitor perform- ance evaluations, however, the Administrator can request that one be conducted. § 63.8(f)(1) through (f)(5) ...... Yes. § 63.8(f)(6) ...... No ...... Subpart HHH does not require continuous emissions monitoring. § 63.8(g) ...... No ...... Subpart HHH specifies continuous monitoring system data reduction requirements. § 63.9(a) ...... Yes. § 63.9(b)(1) ...... Yes. § 63.9(b)(2) ...... Yes ...... Existing sources are given 1 year (rather than 120 days) to submit this notification. § 63.9(b)(3) ...... Yes. § 63.9(b)(4) ...... Yes. § 63.9(b)(5) ...... Yes. § 63.9(c) ...... Yes. § 63.9(d) ...... Yes. § 63.9(e) ...... Yes. § 63.9(f) ...... No. § 63.9(g) ...... Yes. § 63.9(h)(1) through (h)(3) ...... Yes. § 63.9(h)(4) ...... No ...... Section reserved. § 63.9(h)(5) and (h)(6) ...... Yes. § 63.9(i) ...... Yes. § 63.9(j) ...... Yes. § 63.10(a) ...... Yes. § 63.10(b)(1) ...... Yes ...... Section 63.1284(b)(1) requires sources to maintain the most recent 12 months of data on-site and allows offsite storage for the remaining 4 years of data. § 63.10(b)(2) ...... Yes. § 63.10(b)(2)(i) ...... No. § 63.10(b)(2)(ii) ...... No ...... See § 63.1284(f) for recordkeeping of occurrence, duration, and actions taken dur- ing malfunction. § 63.10(b)(2)(iii) ...... Yes. § 63.10(b)(2)(iv) through (b)(2)(v) ...... No. § 63.10(b)(2)(vi) through (b)(2)(xiv) ...... Yes. § 63.10(b)(3) ...... No. § 63.10(c)(1) ...... Yes. § 63.10(c)(2) through (c)(4) ...... No ...... Sections reserved. § 63.10(c)(5) through (c)(8) ...... Yes. § 63.10(c)(9) ...... No ...... Section reserved.

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TABLE 2 TO SUBPART HHH OF PART 63—APPLICABILITY OF 40 CFR PART 63 GENERAL PROVISIONS TO SUBPART HHH—Continued

Applicable to General provisions reference subpart HHH Explanation

§ 63.10(c)(10) and (c)(11) ...... No ...... See § 63.1284(f)for recordkeeping of malfunctions § 63.10(c)(12) through (c)(14) ...... Yes. § 63.10(c)(15) ...... No. § 63.10(d)(1) ...... Yes. § 63.10(d)(2) ...... Yes. § 63.10(d)(3) ...... Yes. § 63.10(d)(4) ...... Yes. § 63.10(d)(5) ...... No ...... See § 63.1285(b)(6) for reporting of malfunctions. § 63.10(e)(1) ...... Yes. § 63.10(e)(2) ...... Yes. § 63.10(e)(3)(i) ...... Yes ...... Subpart HHH requires major sources to submit Periodic Reports semi-annually. § 63.10(e)(3)(i)(A) ...... Yes. § 63.10(e)(3)(i)(B) ...... Yes. § 63.10(e)(3)(i)(C) ...... No ...... Subpart HHH does not require quarterly reporting for excess emissions. § 63.10(e)(3)(ii) through (e)(3)(viii) ...... Yes. § 63.10(f) ...... Yes. § 63.11(a) and (b) ...... Yes. § 63.11(c), (d), and (e) ...... Yes. § 63.12(a) through (c) ...... Yes. § 63.13(a) through (c) ...... Yes. § 63.14(a) and (b) ...... Yes. § 63.15(a) and (b) ...... Yes.

[FR Doc. 2011–19899 Filed 8–22–11; 8:45 am] BILLING CODE 6560–50–P

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