Source: http://thefederalregister.com/2012/09/12/2012-20866.html
Timestamp: 2018-03-23 20:18:52
Document Index: 70216384

Matched Legal Cases: ['arts 9', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60', 'art 60']

Federal Register | Standards of Performance for Petroleum Refineries; Standards
40 CFR Parts 9 and 60
[EPA-HQ-OAR-2007-0011; FRL-9672-3]
ACTION: Final rule; lift stay of effective date.
DATES: The stay of the definition of "flare" in 40 CFR 60.101a, paragraph (g) of 40 CFR 60.102a, and paragraphs (d) and (e) of 40 CFR 60.107a is lifted and this final rule is effective on November 13, 2012. The incorporation by reference of certain publications listed in the final rule is approved by the Director of the Federal Register as of November 13, 2012.
ADDRESSES: The EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2007-0011. All documents in the docket are listed in thewww.regulations.govindex. Although listed in the index, some information is not publicly available,e.g.,confidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically inwww.regulations.govor in hard copy at the EPA Docket Center, Standards of Performance for Petroleum Refineries Docket, EPA West Building, Room 3334, 1301 Constitution Ave. NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Ms. Brenda Shine, Office of Air Quality Planning and Standards, Sector Policies and Programs Division, Refining and Chemicals Group (E143-01), Environmental Protection Agency, Research Triangle Park, NC 27711, telephone number: (919) 541-3608; fax number: (919) 541-0246; email address:shine.brenda@epa.gov.
I. General Information A. Does this action apply to me? B. Where can I get a copy of this document? C. Judicial Review II. Background Information A. Executive Summary B. Background of the Refinery NSPS III. Summary of the Final Rules and Changes Since Proposal A. What are the final amendments to the standards of performance for petroleum refineries (40 CFR part 60, subpart J)? B. What are the final amendments to the standards of performance for process heaters (40 CFR part 60, subpart Ja)? C. What are the final amendments to the standards of performance for flares (40 CFR part 60, subpart Ja)? D. What are the final amendments to the definitions in 40 CFR part 60, subpart Ja? E. What are the final technical corrections to 40 CFR part 60, subpart Ja? IV. Summary of Significant Comments and Responses A. Process Heaters B. Flares C. Other Comments V. Summary of Cost, Environmental, Energy and Economic Impacts A. What are the emission reduction and cost impacts for the final amendments? B. What are the economic impacts? C. What are the benefits? VI. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer and Advancement Act J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations K. Congressional Review Act I. General Information A. Does this action apply to me?
Categories and entities potentially regulated by these final rules include:
Category NAICS Code1 Examples of regulated
Industry 32411 Petroleum refiners. Federal government Not affected. State/local/tribal government Not affected. 1North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. To determine whether your facility would be regulated by this action, you should examine the applicability criteria in 40 CFR 60.100 and 40 CFR 60.100a. If you have any questions regarding the applicability of this action to a particular entity, contact the person listed in the precedingFOR FURTHER INFORMATION CONTACTsection.
In addition to being available in the docket, an electronic copy of this final action is available on the World Wide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of this final action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules athttp://www.epa.gov/ttn/oarpg. The TTN provides information and technology exchange in various areas of air pollution control.
The EPA has created a redline document comparing the existing regulatory text of 40 CFR part 60, subpart Ja and the final amendments to aid the public's ability to understand the changes to the regulatory text. This document has been placed in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2007-0011).
Under section 307(b)(1) of the Clean Air Act (CAA), judicial review of these final rules is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by November 13, 2012. Under section 307(b)(2) of the CAA, the requirements established by these final rules may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce these requirements.
II. Background Information A. Executive Summary 1. Purpose of the Regulatory Action
This action finalizes amendments that were proposed on December 22, 2008, to address reconsideration issues related to the promulgation of new source performance standards (NSPS) for flares and process heaters on June 24, 2008. This action also lifts the stay that was granted on September 26, 2008 (73 FR 55751) and extended until further notice on December 22, 2008 (73 FR 78552) on the provisions at issue.
Table 1 presents a summary of major changes to the rule since it was first promulgated on June 24, 2008. The following discussion is a summary of major provisions of this rule.
Table 1—Summary of Major Changes Since June 24, 2008, Promulgation Affected source Aspect NSPS Ja
NSPS Ja final All Process Heater NOXlimits Averaging time 24-hour rolling average 30-day rolling average. Natural Draft Process Heaters NOXEmission Limits 40 ppmv 40 ppmv or 0.04 lb/MM BTU. Forced Draft Process Heaters NOXEmission Limits 40 ppmv 60 ppmv or 0.06 lb/MM BTU. Forced Draft Process Heaters with Co-fired (oil and gas) Burners NOXEmission Limits 40 ppmv 150 ppmv or Weighted average based on oil at 0.40 lb/MM BTU and gas at 0.11 lb/MM BTU. Natural Draft Process Heaters with Co-fired (oil and gas) Burners NOXEmission Limits 40 ppmv 150 ppmv or weighted average based on oil at 0.35 lb/MM BTU and gas at 0.06 lb/MM BTU. Process Heaters Alternate Emission Standards None Case by case approval for some circumstances. Flares Applicability New or reconstructed flare systems or existing flare systems that are physically altered to increase flow or to add new connections Similar, except specific list of connections that do not trigger applicability. Fuel gas combustion devices H2S concentration limit 162 ppmv H2S (3-hour average); 60 ppmv H2S (annual rolling average) 162 ppmv H2S (3-hour average); No 60 ppmv H2S long term concentration limit for flares. Flares Compliance date for modified flares Comply with H2S limit at start-up, and all other requirements within 1 year Comply with H2S limit at start-up (except for modified flares not previously subject to the H2S limit in 40 CFR part 60, subpart J or those with monitoring alternatives, or those complying with subpart J as specified in a consent decree, which comply no later than 3 years) and all other requirements within 3 years. Flares Flow limits Flare system-wide flow limit of 250,000 scfd No limits. Flares Root Cause Analysis and Corrective Action (RCA/CA) RCA/CA required on upsets or malfunctions in excess of 500,000 scfd or 500 lbs/day SO2from SSM RCA/CA required for 500,000 scfd above base load and 500 lbs SO2in any 24-hour period. Flares Flow monitoring Continuous Continuous except for intermittent/emergency only flares with water seal monitoring and limited releases. Flares Sulfur Monitoring Continuous Total Reduced Sulfur (TRS) Continuous TRS, using reference method 15A (Total Sulfur).
Affected process heaters are those that were modified, reconstructed or constructed after May 14, 2007. For these affected sources, these final amendments include concentration-based nitrogen oxide (NOX) emissions limits and alternative heating value-based NOXemissions limits, both determined daily on a 30-day rolling average basis. These final amendments establish limits of 40 parts per million by volume (ppmv) NOX(or 0.04 pounds per million British thermal units (lb/MMBtu) and 60 ppmv NOX(or 0.06 lb/MMBtu) for natural draft and forced draft process heaters, respectively. Co-fired process heaters, designed to operate on gaseous and liquid fuel (e.g.,oil), must meet either 150 ppmv NOXor alternative heating value-based limits, weighted based on oil and gas use. The NSPS also contains an alternative compliance option that allows owners and operators to obtain EPA approval for a site-specific NOXlimit for process heaters that may have difficulty meeting the standards under certain situations. These final amendments also include monitoring, recordkeeping and reporting requirements necessary to demonstrate compliance with the NOXemission standards.
For flares, these final amendments define a flare as a separate affected facility rather than a type of fuel gas combustion device. As such, these final amendments remove requirements for flares to comply with the performance standards for sulfur dioxide (SO2) (expressed as a 162 ppmv short-term hydrogen sulfide (H2S) concentration limit) and, instead, establish a separate suite of standards for flares. We are not finalizing the requirement in the December 22, 2008, proposed amendments for flares to meet the long-term 60 ppmv H2S fuel gas concentration limit. As explained in section IV of this preamble, we determined that requiring refineries to ensure the fuel gas they send to their flares meets a long-term H2S concentration of 60 ppmv is not appropriate for flares.
Affected flares are those that were modified, reconstructed or constructed after June 24, 2008. In general, a flare is modified if a connection is made into the flare header that can increase emissions from the flare. The NSPS specifically identifies certain connections to a flare that do not constitute a modification of the flare because they do not result in emissions increases.
The final amendments for flares include a suite of standards that apply at all times. This suite of standards requires refineries to: (1) Develop and implement a flare management plan; (2) conduct root cause analyses and take corrective action when waste gas sent to the flare exceeds a flow rate of 500,000 standard cubic feet per day (scfd) above the baseline flow or contains sulfur that, upon combustion, will emit more than 500 pounds (lb) of SO2in a 24-hour period; and (3) optimize management of the fuel gas by limiting the short-term concentration of H2S to 162 ppmv during normal operating conditions.
The final amendments require that flares be equipped with flow and sulfur monitors except in cases where flares are used infrequently or are configured such that they cannot receive high sulfur gas. For flares that are configured such that they only receive inherently low sulfur gas streams, continuous sulfur monitors are not necessary because a root cause analysis will be triggered by an exceedance of the flow rate threshold long before they exceed the 500 lb SO2trigger in a 24-hour period.
For infrequently used flares, the NSPS allows for less burdensome monitoring, consisting of monitoring the differential pressure between the flare header and the flare water seal to determine if a gas release to the flare has occurred. Any instance where the pressure upstream of the water seal (expressed in inches of water) exceeds the water seal height triggers a requirement to perform a root cause analysis and corrective action analysis, unless the discharge is related to flare gas recovery system compressor cycling or a planned startup or shutdown (of a refinery process unit or ancillary equipment connected to the flare) following the procedures in the flare management plan. The NSPS also contains an alternative compliance option for refinery flares located in the South Coast Air Quality Management District (SCAQMD) or the Bay Area Air Quality Management District (BAAQMD). An affected flare subject to 40 CFR part 60, subpart Ja may elect to comply with SCAQMD Rule 1118 or both BAAQMD Regulation 12, Rule 11 and BAAQMD Regulation 12, Rule 12 as an alternative to complying with the requirements of subpart Ja.
The provisions for flares and other fuel gas combustion devices (i.e.,process heaters and boilers) from the final June 2008 standards were stayed. The analysis for this final rule includes the same unit costs for the flare provisions as the final June 2008 rule but reflects recalculated total costs using data collected in the March 2011 information collection request (ICR) to update the number of flares. For the June 2008 standards, we estimated that 40 flares would be affected. We now anticipate that there will be 400 affected flaresthat will be subject to this final rule.Table 2 includes the recalculated cost estimates based on the updated number of flares since 2008, broken out by specific flare requirements. For the other fuel gas combustion devices, the total annualized costs for those provisions were estimated at $24 million (2006 dollars) in the June 2008 rule and remain the same. As discussed below, because there are no additional incremental costs associated with the other fuel gas combustion device provisions, we consider those annual costs accounted for in the final June 2008 standards. We are presenting thesecosts and benefits here again, even though we estimate no changes to them, since these provisions will become effective upon this final action to lift the stay on certain provisions in the June 2008 rule. For the June 2008 rule, we estimated the benefits to be $220 million to $1.9 billion and $200 to $1.7 billion at a 3-percent discount rate and 7-percent discount rate, respectively.1
1It is important to note that the EPA has implemented several substantial changes to the benefits methodology since 2008, which makes it challenging to compare the benefits of the June 2008 rule to the benefits of the current rulemaking. The changes with the largest impact on the range of monetized benefits are the removal of the assumption of a threshold in the concentration-response function, the revision of the value-of-a-statistical-life, and the range of risk estimates from epidemiology studies rather than the range of risk estimates supplied by experts. See the regulatory impact analysis for the current rulemaking for more information regarding these changes, which is available in the docket.
Cost impacts for flares are presented in Table 2. The estimated total capital cost of complying with the final amendments to 40 CFR part 60, subpart Ja for flares is $460 million dollars (2006 dollars). The estimated annual cost, including annualized capital costs, is a cost savings of about $79 million (2006 dollars) due to the replacement of some natural gas purchases with recovered flare gas and the retention of intermediate and product streams due to a reduction in the number of malfunctions associated with refinery process units and ancillary equipment connected to the flare. Note that not all refiners will realize a cost savings since we only estimate that refineries with high flare flows will install vapor recovery systems. Although the rule does not specifically require installation of flare gas recovery systems, we project that owners and operators of flares receiving high waste gas flows will conclude, upon installation of monitors, implementation of their flare management plans, and implementation of root causes analyses, that installing flare gas recovery would result in fuel savings by using the recovered flare gas where purchased natural gas is now being used to fire equipment such as boilers and process heaters. The flare management plan requires refiners to conduct a thorough review of the flare system so that flare gas recovery systems are installed and used where these systems are warranted. As part of the development of the flare management plan, refinery owners and operators must provide rationale and supporting evidence regarding the flare waste gas reduction options considered. In addition, consistent with Executive Order 13563 (Improving Regulation and Regulatory Review, issued on January 18, 2011), for facilities implementing flare gas recovery, we are finalizing provisions that would allow the owner or operator to reduce monitoring costs and the number of root cause analyses, corrective actions, and corresponding recordkeeping and reporting they would need to perform. The costs calculated for this rule, however, do not account for potential savings due to these provisions (reduced monitoring, root cause analysis, etc.). We estimate that the final requirements for flares will reduce emissions of SO2by 3,200 tons per year (tons/yr), NOXby 1,100 tons/yr and volatile organic compounds (VOC) by 3,400 tons/yr from the baseline. The overall cost effectiveness is a cost savings of about $10,000 per ton of combined pollutants removed. We also estimate that the final requirements for flares will result in emissions reduction co-benefits of CO2equivalents by 1,900,000 metric tonnes per year, predominantly as a result of our estimate of the largest flares employing flare gas recovery, and to a lesser extent, as a result of the flow rate root cause analyses and corrective actions applicable to all flares.
Table 2—Cost Impacts for Petroleum Refinery Flares Subject to Amended Standards Under 40 CFR Part 60, Subpart Ja [Fifth year after the effective date of these final rule amendments] Subpart Ja requirements Total capital cost
Total annual cost without credit
Natural gas offset/product recovery credit
(tons SO2/yr)
(tons NOX/yr)
(tons VOC/yr)
($/ton emissions reduced)
Majority of flares (approximately 360 flares) Flare Monitoring 72,000 12,000 0 12,000 0 0 0 Flare gas recovery 0 0 0 0 0 0 0 Flare Management 0 790 0 790 0 0 270 2,900 SO2RCA/CA 0 1,900 0 1,900 2,600 0 0 760 Flowrate RCA/CA 900 (6,700) (5,800) 3.4 50 390 (13,000) Subtotal1 72,000 16,000 (6,700) 9,000 2,600 50 660 2,700 Largest flares (approximately 40 flares) 2 Flare Monitoring 12,000 2,000 0 2,000 0 0 0 Flare gas recovery 380,000 78,000 (170,000) (90,000) 380 1,100 2,700 (22,000) Flare Management 0 88 0 88 0 0 30 2,900 SO2RCA/CA 0 220 0 220 290 0 0 760 Flowrate RCA/CA 0 100 (740) (640) 0.4 6 43 (13,000) Subtotal1 390,000 81,000 (170,000) (88,000) 660 1,100 2,800 (20,000) Total1 460,000 96,000 (180,000) (79,000) 3,200 1,100 3,400 (10,000) 1All estimates are rounded to two significant figures so numbers may not sum down columns. 2The EPA has conducted an alternative analysis that presents the costs and benefits of the rule assuming that no refiners will opt to install flare gas recovery systems as part of their flare management strategy. This analysis is presented in the Regulatory Impact Analysis in the discussion provided in the executive summary and in Section 4.1, available in the docket for this rulemaking.
We estimate the monetized benefits of this final regulatory action for all flares to be $260 million to $580 million (3-percent discount rate) and $240 million to $520 million (7-percent discount rate for health benefits and 3-percent discount rate for climate benefits). For small flares only, we estimate the monetized benefits are $170 million to $410 million (3-percent discount rate) and $150 million to $370 million (7-percent discount rate for health benefitsand 3-percent discount rate for climate benefits). For large flares only, we estimate the monetized benefits are $93 million to $160 million (3-percent discount rate) and $88 million to $150 million (7-percent discount rate for health benefits and 3-percent discount rate for climate benefits). Several benefits categories, including direct exposure to SO2and NOXbenefits, ozone benefits, ecosystem benefits and visibility benefits are not included in these monetized benefits. All estimates are in 2006 dollars for the year 2017.
Although this final rule provides refiners with some additional compliance options and removes some requirements, such as the long-term H2S limit for flares, the cost savings due this increased flexibility have not been calculated for inclusion in the benefit-cost analysis.
B. Background of the Refinery NSPS
Section 111(b)(1)(A) of the Clean Air Act (CAA) requires the EPA to establish federal standards of performance for new, modified and reconstructed sources for source categories which cause or contribute significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. The standard of performance must reflect the application of the best system of emission reductions (BSER) that (taking into consideration the cost of achieving such emission reductions, any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated (CAA section 111(a)(1)). If it is not feasible to prescribe or enforce a standard of performance, the Administrator may instead promulgate a design, equipment, work practice or operational standard, or a combination of these types of standards (CAA section 111(h)(1)). Since 1970, the NSPS have been successful in achieving long-term emissions reductions in numerous industries by assuring cost-effective controls are installed on newly constructed, reconstructed or modified sources.
The level of control prescribed by CAA section 111 historically has been referred to as “Best Demonstrated Technology” or BDT. In order to better reflect that CAA section 111 was amended in 1990 to clarify that “best systems” may or may not be “technology,” the EPA is now using the term “best system of emission reduction” or BSER in its rulemaking packages. See,e.g.,76 FR 52738, 52740 (August 23, 2011); 76 FR 63878, 63879 (October 14, 2011). As was done previously in analyzing BDT, the EPA uses available information and considers the emissions reductions achieved by the different systems available and the costs of achieving those reductions. The EPA also considers the “other factors” prescribed by the statute in its BSER analysis. After considering all of this information, the EPA then establishes the appropriate standard representative of BSER. Sources may use whatever system meets the standard.
Section 111(b)(1)(B) of the CAA requires the EPA to periodically review and, as appropriate, revise the standards of performance to reflect improvements in methods for reducing emissions. As a result of our periodic review of the NSPS for petroleum refineries (40 CFR part 60, subpart J), we proposed amendments to the current standards of performance and separate standards of performance for new process units (40 CFR part 60, subpart Ja) (72 FR 27278, May 14, 2007) and we subsequently promulgated those amendments and new standards (73 FR 35838, June 24, 2008). Following promulgation, we received three separate petitions for reconsideration from: (1) The American Petroleum Institute (API), the National Petrochemical and Refiners Association (NPRA) and the Western States Petroleum Association (WSPA) (collectively referred to as “Industry Petitioners”); (2) HOVENSA, LLC (“HOVENSA”); and (3) the Environmental Integrity Project, Sierra Club and Natural Resources Defense Council (collectively referred to as “Environmental Petitioners”). On September 26, 2008, the EPA issued aFederal Registernotice (73 FR 55751) granting reconsideration of the following issues: (1) The newly promulgated flare modification provision2 ; (2) the “flare” definition; (3) the fuel gas combustion device sulfur limits as they apply to flares; (4) the flow limit for flares; (5) the total reduced sulfur and flow monitoring requirements for flares; and (6) the NOXlimit for process heaters. The EPA also granted Industry Petitioners' and HOVENSA's request for a 90-day stay for those same provisions under reconsideration. On December 22, 2008, threeFederal Registernotices (73 FR 78260, 73 FR 78546 and 73 FR 78549) were published to extend this stay until a final decision is reached on those issues.
2The September 26, 2008,Federal Registernotice (73 FR 55751) described the first issue for which the EPA granted reconsideration as “the definition of `modification.'” However, because what we are actually reconsidering is the specific flare modification provision that applies to flares at petroleum refineries rather than the more generally applicable definition of “modification,” we have revised the description of this issue as “the newly promulgated flare modification provision.”
In the September 26, 2008,Federal Registernotice (73 FR 55751), we also identified other issues for which Petitioners requested reconsideration. We stated that, at that time, we were “taking no action on all of the other issues raised in the petitions but will consider all of the outstanding issues in a future notice.” On December 29, 2009, we sent a letter to the Petitioners, through their counsel, stating that “[t]he Administrator has decided to grant reconsideration of all the remaining issues” and that “EPA will address the substantive aspects of the issues under reconsideration through notice and comment actions published in theFederal Register.” A copy of the letter to the Petitioners can be found in the docket for this rulemaking (Docket Item No. EPA-HQ-OAR-2007-0011-0318).
In this action, we are finalizing the amendments for which we granted reconsideration and a stay as outlined in the September 26, 2008, notice and for which we proposed amendments on December 22, 2008. We are also addressing certain other minor issues raised by Industry Petitioners in this action, as discussed later in this preamble. We will take action on all of the remaining issues raised by Petitioners for reconsideration in future notices.
We received a total of 22 comments from the following groups on the proposed amendments during the public comment period: (1) Refineries, industry trade associations and consultants; (2) state and local environmental and public health agencies; (3) environmental groups; and (4) other members of the public. These final amendments reflect our full consideration of all of the comments we received. Detailed responses to the comments not included in this preamble, as well as more detailed summaries of the comments addressed in this preamble, are contained inStandards of Performance for Petroleum Refineries: Background Information for Final Amendments—Summary of Public Comments and Responses,dated December 2011, which is included in Docket ID No. EPA-HQ-OAR-2007-0011.
In summary, major comments on the proposed process heater requirements were related to the proposed NOXconcentration limits, the alternative heating value limits, consideration of turndown (i.e.,when a process heater is operated at less than 50-percent design capacity) and other factors that influence the achievable emissionslimits. In response, we are raising the limit for new forced draft process heaters from 40 ppmv NOXat proposal to 60 ppmv NOX. For both natural draft and forced draft process heaters, we are finalizing alternative heating value limits derived from a more direct numerical conversion of the NOXconcentration limit (i.e.,0.04 lb/MMBtu for natural draft and 0.06 lb/MMBtu for forced draft). For newly constructed, modified and reconstructed natural draft and forced draft process heaters, we are reducing the averaging time for compliance from a 365-day rolling average to a 30-day rolling average applicable during periods of normal operation. We are also finalizing an alternative case-specific compliance option that allows owners and operators to obtain EPA approval for a site-specific NOXlimit in certain conditions such as turndown.
Major comments on the proposed requirements for flares were related to the definition of flare modification for purposes of triggering applicability to this rule, the proposed removal of the flare flow limit, clarification of flare monitoring requirements and clarification of the differences between the requirement for flares and the requirements for other fuel gas combustion devices. We address these comments by clarifying the definition of flare modification and by expanding the list included in the December 22, 2008, proposal, which specifies certain connections that do not constitute a modification of the flare because they do not result in emissions increases. We are finalizing the proposed removal of the flare flow limit and instead, we are promulgating a suite of work practice standards that apply to affected flares. Based on comments received on the December 22, 2008 proposal, we are finalizing definitions of “fuel gas combustion device” and “flare” to specify that a flare is a separate affected facility rather than a type of fuel gas combustion device. We are also finalizing amendments to clarify certain monitoring requirements and to provide additional monitoring alternatives under certain circumstances.
III. Summary of the Final Rules and Changes Since Proposal
NSPS for petroleum refineries (40 CFR part 60, subpart J) apply to the affected facilities at the refinery, such as fuel gas combustion devices (which include process heaters, boilers and flares), that commence construction, reconstruction or modification after June 11, 1973, but on or before May 14, 2007 (on or before June 24, 2008 for flares). The NSPS were originally promulgated on March 8, 1974, and have been amended several times. In this action, we are promulgating technical clarifications and corrections to subpart J.
New standards of performance for petroleum refineries (40 CFR part 60, subpart Ja) apply to flares that commence construction, reconstruction or modification after June 24, 2008, and other affected facilities at petroleum refineries, including process heaters and other fuel gas combustion devices that commence construction, reconstruction or modification after May 14, 2007. In this action, we are finalizing amendments to subpart Ja to address the issues raised by Petitioners regarding flares and process heaters. We are also finalizing technical corrections to subpart Ja for certain issues that were identified by Industry Petitioners in their August 21, 2008, supplement to their original administrative reconsideration request (Docket Item No. EPA-HQ-OAR-2007-0011-0246).
The following sections summarize the amendments in both 40 CFR part 60, subpart J and 40 CFR part 60, subpart Ja. Section IV contains the rationale for these amendments, while the amendments themselves follow the preamble.
A. What are the final amendments to the standards of performance for petroleum refineries (40 CFR part 60, subpart J)?
The final amendments add a new paragraph to 40 CFR 60.100 to allow 40 CFR part 60, subpart J affected sources the option of complying with subpart J by following the requirements in 40 CFR part 60, subpart Ja. The subpart Ja requirements are at least as stringent as those in subpart J, so providing this option will allow all process units in a refinery to follow the same requirements and simplify compliance. We are also removing the reference to 40 CFR 60.101a from the description of the applicability dates in 40 CFR 60.100(b) so as not to cause confusion over the definition of “flare” in subpart J. We are finalizing a correction to the value and units (in the metric system) for the allowable incremental rate of particulate matter (PM) emissions in 40 CFR 60.106(c)(1). We amended the units for this constant in 40 CFR 60.102(b) on June 24, 2008, and we are now correcting 40 CFR 60.106(c)(1) accordingly. Finally, we are finalizing a definition of “fuel gas” that incorporates the same clarifications regarding vapors from wastewater treatment units and marine tank vessel loading operations identified in the subpart Ja definition of “fuel gas” (described later in this preamble).
B. What are the final amendments to the standards of performance for process heaters (40 CFR part 60, subpart Ja)?
We proposed several amendments to the standards of performance for process heaters, including adding emission limits in units of lb/MMBtu, extending the emission limit averaging time from 24 hours to 365 days, raising the emission limit for modified and reconstructed forced draft process heaters and raising the emission limit for co-fired process heaters. After consideration of all of the public comments and our own additional analyses, we are finalizing the process heater requirements, as described in this section.
Table 3 presents a comparison of the proposed and final 40 CFR part 60, subpart Ja amendments for process heaters. The final amendments include four subcategories of process heaters: (1) Natural draft process heaters; (2) forced draft process heaters; (3) co-fired natural draft process heaters; and (4) co-fired forced draft process heaters. At proposal, all co-fired process heaters were included in one subcategory, for a total of three process heater subcategories, but, based on emissions data from co-fired process heaters, we divided natural draft and forced draft co-fired process heaters into separate subcategories with different emissions limits.
For each of the first two subcategories, the final amendments include a concentration-based NOXemissions limit and a heating value-based NOXemissions limit, both determined daily on a 30-day rolling average basis. For the natural draft process heater subcategory, the concentration-based NOXemissions limit for newly constructed, modified and reconstructed natural draft process heaters is 40 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30-day rolling average basis. The heating value-based NOXemissions limit for newly constructed, modified and reconstructed natural draft process heaters is 0.040 lb/MMBtu higher heating value basis determined daily on a 30-day rolling average basis. The averaging time for both of these limits is shorter than the 365-day averaging time that was proposed, and the heating value-based NOXemissions limit differs from the proposed limit in that it is a more direct numerical conversion from 40 ppmv NOX. At proposal, we provided a longer averaging time so that short periods of turndown (i.e.,when a process heater is operating at less than 50-percent designcapacity) would not significantly affect the overall performance of the unit. Our analysis of the additional data that we obtained following the proposal supported revising all NOXemissions limits to be on a 30-day rolling average basis, which is achievable for process heaters during periods of normal operation. These data indicate that process heaters equipped with ultra low NOXburners meet the emission limits described above if compliance is determined on a 30-day rolling average basis. We are finalizing alternative compliance options that allow the owners and operator to establish site-specific limits applicable during certain conditions such as turndown. Section IV.A of this preamble provides additional information regarding the rationale and analyses leading to these final amendments.
For the second subcategory, forced draft process heaters, the concentration-based NOXemissions limit for newly constructed, modified and reconstructed forced draft process heaters is 60 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30-day rolling average basis. The heating value-based NOXemissions limit for newly constructed, modified and reconstructed forced draft process heaters is 0.060 lb/MMBtu higher heating value basis determined daily on a 30-day rolling average basis. The higher limit for new forced draft process heaters (at proposal, the limit was 40 ppmv) is based on additional data and a re-evaluation of BSER, as described later in this preamble. As with natural draft process heaters, the averaging time for both of these limits is shorter than proposed, and the final heating value-based NOXemissions limit is a more direct numerical conversion from 60 ppmv NOX. Section IV.A of this preamble provides additional information regarding the rationale and analyses leading to these final amendments.
For each of these subcategories, a process heater need only meet either the concentration-based NOXemissions limit or the heating value-based NOXemissions limit. The refinery owner or operator may choose to comply with either limit at any time, provided that they are monitoring the appropriate variables to assess the heating value-based NOXemissions limit. If the refinery owner or operator does not choose to monitor fuel composition, then they must comply with the concentration-based NOXemissions limit.
Table 3—Proposed and Final Amendments for Process Heaters Proposal
Final Averaging time 365-day rolling average 30-day rolling average. Natural Draft NOXEmission Limits 40 ppmv or 0.035 lb/MM BTU 40 ppmv or 0.04 lb/MM BTU. Forced Draft NOXEmission Limits New:40 ppmv or 0.035 lb/MM BTU
M/R:60 ppmv or 0.055 lb/MM BTU
60 ppmv or 0.06 lb/MM BTU. Co-fired Burner (oil and gas) NOXEmission Limits 150 ppmv or Weighted average based on oil at 0.27 lb/MM BTU and gas at 0.08 lb/MM BTU 150 ppmv or Weighted average based on oil at 0.40 lb/MM BTU and gas at 0.11 lb/MM BTU forced draft and weighted average based on oil at 0.35 lb/MM BTU and gas at 0.06 lb/MM BTU for natural draft.
As proposed, initial compliance with the heating value-based emissions limits will be demonstrated by conducting a performance evaluation of the continuous emission monitoring system (CEMS) in accordance with Performance Specification 2 in appendix B to 40 CFR part 60, with EPA Method 7 of 40 CFR part 60, appendix A-4 as the Reference Method, along with fuel flow measurements and fuel gas compositional analysis. The NOXemission rate is calculated using the oxygen (O2)-based F factor, dry basis according to EPA Method 19 of 40 CFR part 60, appendix A-7. Ongoing compliance with this NOXemissions limit is determined using a NOXCEMS and at least daily sampling of fuel gas heat content or composition to calculate a daily average heating value-based emissions rate, which is subsequently used to determine the 30-day average.
The third and fourth subcategories of process heaters are co-fired process heaters. A co-fired process heater is a process heater that employs burners that are designed to be supplied by both gaseous and liquid fuels. As described in more detail in section IV.A of this preamble, co-fired process heaters do not include gas-fired process heaters that have emergency oil back-up burners. There are two compliance options for each subcategory of co-fired process heaters: (1) 150 ppmv (dry basis, corrected to 0-percent excess air) determined daily on a 30 successive operating day rolling average basis; and (2) a source-specific daily average emissions limit. Unlike gas-fired process heaters, the owner or operator of a co-fired process heater must choose one emissions limit and show compliance with that limit. For co-fired natural draft process heaters, the daily average emissions limit is based on a limit of 0.06 lb/MMBtu for the gas portion of the firing and 0.35 lb/MMBtu for the oil portion of the firing. For co-fired forced draft process heaters, the daily average emissions limit is based on a limit of 0.11 lb/MMBtu for the gas portion of the firing and 0.40 lb/MMBtu for the oil portion of the firing. These limits are different than proposed, based on a re-evaluation of BSER with new data received during the public comment period. All of the requirements for emissions monitoring, recordkeeping and reporting for co-fired process heaters are the same as for the other process heater subcategories.
We are also finalizing an alternative compliance option that allows owners and operators to obtain EPA approval for a site-specific NOXlimit for certain process heaters. This compliance option was provided in the proposed amendments, but it was limited to (1) natural draft and forced draft modified or reconstructed process heaters that lack sufficient space to accommodate combustion modification-based technology and (2) natural draft and forced draft co-fired process heaters. In the final amendments, we are finalizing this compliance option for those process heaters mentioned above while also providing this compliance option for the following additional types of process heaters: (3) modified or reconstructed induced draft process heaters that have downwardly firing burners and (4) forced draft and natural draft process heaters that operate at low firing rates, or turndown, for an extended period of time. As we noted in the preamble to the proposed amendments, in limited cases, existing natural draft or forced draft process heaters have limited firebox size or other constraints suchthat they cannot apply the BSER of ultra-low NOXburners or otherwise meet the applicable limit and some co-fired units may not be able to achieve the NOXlimitations even with ultra-low NOXburner control technology. In addition, commenters noted that downwardly fired process heaters with induced draft fans have similar NOXcontrol issues as forced draft heaters, but the definition of forced draft heater does not include these induced draft heaters (these are defined as natural draft process heaters). Therefore, we added a provision to allow induced draft process heaters with downwardly-firing burners to use the alternative compliance option.
Finally, we note that the emissions limits for forced draft and natural draft gas-fired process heaters are based on the performance of ultra-low NOXburner control technologies. The ultra-low NOXburner technology suppliers recommend operating with higher excess air rates at low firing rates (at or below approximately one-half of the maximum firing capacity), which causes higher NOXconcentrations at low firing rates. Therefore, all types of process heaters with ultra-low NOXburner control technologies may be unable to meet the emissions limits if they are operated at low firing rates for an extended period of time. Requesting a site-specific emissions limit requires a detailed demonstration that the application of the ultra-low NOXburner technology is not feasible or that the technology cannot meet the NOXemissions limits given the conditions of the process heater (downward fired induced draft, co-fired or prolonged turndown); the refinery must also conduct source tests in developing a site-specific emissions limit for its process heater. This analysis must be submitted to and approved by the Administrator.
We are finalizing the proposed clarification that owners and operators of process heaters in any subcategory with a rated heating capacity of less than 100 million British thermal units per hour (MMBtu/hr) have the option of using CEMS. The final rule states that owners and operators of process heaters subject to 40 CFR part 60, subpart Ja should use CEMS to demonstrate compliance unless the heater is equipped with combustion modification-based technology (low-NOXburners or ultra-low NOXburners) with a rated heating capacity of less than 100 MMBtu/hr; owners and operators of those specific process heaters have the alternative option of biennial source testing to determine compliance. As requested by commenters, we have provided additional detail in the final rule regarding how to develop the O2operating limit, including provisions on how to develop an O2operating curve to ensure compliance with the NOXemission limit at different process heater firing rates. We are requiring that owners and operators with process heaters in any subcategory that are complying using biennial source testing establish a maximum excess O2concentration operating limit or operating curve that can be met at all times, even during turndown, and comply with the O2monitoring requirements for ongoing compliance demonstration.
C. What are the final amendments to the standards of performance for flares (40 CFR part 60, subpart Ja)?
We proposed several amendments to the standards of performance for flares, including, but not limited to, amending the flare modification provision, removing the numerical limit on the flow rate to the flare, revising the flare management plan requirements to include a list of connections to the flare and an identification of baseline conditions, clarifying when a root cause analysis is required, revising the sulfur and flow monitoring requirements and providing additional time for compliance. After consideration of all of the public comments, and our own additional analyses, we are finalizing the flare requirements, as described in this section.
We did not propose to revise the definitions of “fuel gas combustion device” and “flare” on December 22, 2008. However, based on public comment and changes to the flare requirements, as described later in this section, we have decided to finalize revisions to these definitions to specify that, for purposes of 40 CFR part 60, subpart Ja, a flare is a separate affected facility rather than a type of fuel gas combustion device. This change makes clearer the differences between the requirements for flares and the requirements for fuel gas combustion devices, particularly in terms of sulfur and flow rate monitoring requirements and thresholds for root cause analyses and corrective action analyses. We are also making corrections, as needed, in numerous paragraphs throughout subpart Ja for consistency with the amended definitions (e.g.,adding “and flares,” where applicable, to paragraphs with requirements for “fuel gas combustion devices”).
We are finalizing the flare modification provision in 40 CFR 60.100a(c), as described below, to specify certain connections to a flare that do not constitute a modification of the flare because they do not result in emissions increases. On December 22, 2008, we proposed that the following types of connections to a flare would not be considered a modification of the flare: (1) Connections made to install monitoring systems to the flares; (2) connections made to install a flare gas recovery system; (3) connections made to replace or upgrade existing pressure relief or safety valves, provided the new pressure relief or safety valve has a set point opening pressure no lower and an internal diameter no greater than the existing equipment being replaced or upgraded; and (4) replacing piping or moving an existing connection from a refinery process unit to a new location in the same flare, provided the new pipe diameter is less than or equal to the diameter of the pipe/connection being replaced/moved. We are finalizing those proposed amendments and also adding the following types of connections to the list of connections to flares that are not modifications of flares: (1) Connections between flares; (2) connections for flare gas sulfur removal; and (3) connections made to install redundant flare equipment (such as a back-up compressor). We are also clarifying one of the proposed exemptions to indicate that connections made to upgrade or enhance components of flare gas recovery systems (e.g.,additional compressors or recycle lines) are not modifications.
We are not finalizing the proposed amendment to provide additional time for flares that need to install additional amine scrubbing and amine stripping columns to meet the requirement to limit the long-term concentration of H2S to 60 ppmv (determined daily on a 365 successive calendar day rolling average basis) (hereafter referred to as the long-term 60 ppmv H2S fuel gas concentration limit). Instead, based on comments received during the public comment period for the proposed amendments and our own additional analyses, we are removing the requirement for flares to meet the long-term 60 ppmv H2S fuel gas concentration limit. As explained in section IV, we determined that requiring refineries to ensure the fuel gas they send to their flares meets a long-term H2S concentration of 60 ppmv is not appropriate for flares.
We are promulgating final amendments for flares that include a suite of standards that apply at all times that are aimed at reducing SO2emissions from flares. These amendments include several provisions that were proposed on December 22,2008, as well as others that differ from those proposed, but are a logical outgrowth of the proposed amendments. This suite of standards requires refineries to: (1) Develop and implement a flare management plan; (2) conduct root cause analyses and take corrective action when waste gas sent to the flare exceeds a flow rate of 500,000 standard cubic feet (scf) above the baseline flow to a flare in any 24-hour period (rather than the proposed threshold of 500,000 scf in any 24-hour period without considering the baseline); (3) conduct root cause analyses and take corrective action when the emissions from the flare exceed 500 lb of SO2in a 24-hour period (instead of 500 lb SO2above the emissions limit); and (4) optimize management of the fuel gas by limiting the short-term concentration of H2S to 162 ppmv during normal operating conditions (determined hourly on a 3-hour rolling average basis). As explained further in preamble section IV.B, 40 CFR part 60, subpart J sets a performance standard for SO2(expressed as a 162 ppmv short-term H2S concentration limit) in fuel gas entering fuel gas combustion devices. However, for this final rule, we have determined that flares should be treated separately from other fuel gas combustion devices because they meet the criteria set forth in CAA section 111(h)(2)(A) since emissions from a flare do not occur “through a conveyance designed and constructed to emit or capture such pollutant.” The flare itself is not a “conveyance” that is ”emitting” or “capturing” these pollutants. Instead, pollutants such as SO2are created in the flame that burns outside the flare tip. Therefore, we have determined that this suite of work practice standards, which includes optimization of fuel gas management (based on limiting concentration of H2S to 160 ppmv) is more appropriate for flares, as opposed to the H2S performance standard in subpart J, applicable to fuel gas systems. See section IV.B of this preamble for a more detailed explanation of these requirements. In this rule, we are using the term “normal operating conditions” to describe situations where the process is operating in a routine, predictable manner, such that the gases from the process are predictable, as opposed to less-predictable swings related to emergency situations during which the flare begins to operate as a safety device. All of these requirements will apply during the vast majority of the time. Under a very narrow and limited set of circumstances, such as when a flare is used as a safety device under emergency conditions,3 the flare will be subject to all of these requirements except for the requirement to optimize management of the fuel gas.
3 Background Information for New Source Performance Standards,Vol. 3, Promulgated Standards (APTD-1352c; Publication No. EPA 450/2-74-003), pg 127 (February 1974) (NSPS BID Vol. 3).
In addition, we are specifying that, if a discharge exceeding either or both of the SO2or flow thresholds described above is the result of a planned startup or shutdown of a refinery process unit or ancillary equipment connected